Subsea 7 — Annual Report 2017

Mar 8, 2018

SUBSEA 7 S.A.

A year of strong financial performance

REVENUE \$3,986m

(2016: \$3,567m)

ADJUSTED EBITDA \$1,035m

(2016: \$1,142m)

NET INCOME \$455m

(2016: \$418m)

DILUTED EARNINGS PER SHARE

\$1.36

(2016: \$1.27)

CONTENTS

OVERVIEW

• 2 Chairman's Statement
• 4 Chief Executive Officer's Review
• 6 Our Activities
• 8 Our Business Units
• 12 Our Global Operations

STRATEGY

• 14 Our Business Model
• 16 Our Strategy
• 18 Corporate Responsibility

GOVERNANCE

• 20 Risk Management
• 27 Governance Overview
• 28 Board of Directors
• 30 Executive Management Team
• 32 Corporate Governance Report

FINANCIALS

• 42 Financial Review
• 48 Consolidated Financial Statements Contents
• 49 Report of the Réviseur d'Entreprises Agréé
• 55 Consolidated Financial Statements
• 61 Notes to the Consolidated Financial Statements
• 119 Additional Information
• 122 Glossary

GET THE LATEST INVESTOR INFORMATION ONLINE: WWW.SUBSEA7.COM

1

Delivering value for our stakeholders

Subsea 7 is a world-leading seabed-to-surface engineering, construction and services contractor to the offshore energy industry.

We provide cost-effective technical solutions to enable the delivery of complex projects in all water depths and challenging environments.

Our vision is to be acknowledged by our clients, our people and our shareholders as the leading strategic partner in our market.

"In 2017, we took advantage of cyclicality in some of our target markets to grow and strengthen our business for the future, and positioned ourselves for the next phase in the cycle."

Kristian Siem Chairman

TO THE SHAREHOLDERS OF SUBSEA 7 S.A.

Subsea 7 achieved good financial and operational results in 2017, reflecting our ability to consistently deliver through the downturn. In a difficult market our robust financial performance was driven by disciplined cost management and strong project execution. Our strategic actions helped to lower the cost of projects for our clients, differentiated our services and increased our ability to win market share, driving superior shareholder returns irrespective of oil price fluctuation.

POSITIONING OURSELVES FOR THE FUTURE

2017 was the third consecutive year of challenging market conditions resulting from the steep decline in energy prices. We responded quickly to the reduction in oil and gas project awards, cutting our capacity but maintaining the capability that defines our market-leading position. Our strategy to improve our competitiveness in the current lower oil price paradigm, by enhancing our offering and investing through the cycle, differentiated us in a cash constrained market.

This cost-sensitive environment has driven innovation, collaboration and better ways of working across the oilfield services sector. Our ability to offer our clients solutions that include early engagement and vertical integration has become fundamental in our approach to reducing the cost of projects. Subsea 7 has been proactive in encompassing this new approach, redesigning and retendering projects, resulting in substantial reductions in price for our clients. Our changes have enabled clients to proceed profitably with new developments and we have begun to see a slow and gradual recovery in award activity, supported by an increase in energy prices in the second half of 2017.

Our market-leading position and financial strength enabled us to look ahead and grasp once-in-a-cycle opportunities to grow and develop our business.

BUILDING A STRONGER SUBSEA 7

We remain confident in the long-term outlook for offshore energy and have invested in a disciplined way to enhance our fleet, develop new technology and strengthen our market position. As we look to the future, we believe Subsea 7 has an important role as a strategic partner to our clients, developing innovative solutions that help offshore energy to defend its position on the supply curve.

We are ready for the recovery in activity that is forecast in oil and gas projects over the medium term. We have enabling technology, teams of experienced engineers and project managers, and the right vessels to deliver cost-effective results. We have maintained focus on our Life of Field offering, ensuring we remain competitive across the field lifecycle in the current market. We have also strengthened our presence in the renewable energy and conventional oil and gas markets that are less sensitive to fluctuations in energy pricing, giving us a more robust business long term.

Our acquisition of the remaining 50% of Seaway Heavy Lifting that we did not already own not only doubled our exposure to the offshore renewable wind market, but allowed full control of our strategic planning in a market where we are confident about future growth. This is a market where the trend towards large fixed-price turnkey projects is aligned with our project management and engineering capability, as well as our experience with foundation installations and heavy lifting vessels.

We accelerated our strategy to grow in the Middle East conventional oil and gas market with the acquisition of certain businesses of EMAS Chiyoda Subsea (ECS) from Chapter 11. We have a long track record of conventional oil and gas projects offshore West Africa, and seized this opportunity to acquire an established position in conventional projects offshore Saudi Arabia.

Subsea 7 has strengthened its ability to offer clients integrated solutions. We are developing our competitive position with early engagement, combined technology development and innovation, that will improve flow assurance and lower costs. Subsea Integration Alliance, our alliance with OneSubsea progressed well in 2017 with the award of key integrated projects that demonstrated the potential benefits of integrated solutions for our clients. In February 2018 we built on this strong position and announced our intent to form a joint venture with Schlumberger for full field lifecycle services.

A STRONG FINANCIAL FOUNDATION

We have a disciplined approach to capital management, prioritising investment in our business and maintaining an investment grade profile. In addition to the investments to grow and strengthen our business in 2017, we also repaid the outstanding amount on our convertible bond, which matured in October. The Group did not repurchase any shares in 2017. Nevertheless, the share repurchase programme was extended to July 2019. In light of the Group's strong financial and liquidity position and an improved outlook for new awards, the Board of Directors will recommend to the shareholders at the Annual General Meeting that a special dividend of NOK 5.00 per share be paid, equating to a total dividend of approximately \$200 million.

MY THANKS

On behalf of the Board of Directors, I would like to thank our people and our alliance partners for enabling us to provide our clients with a differentiated service and excellent execution that have contributed to good operational and financial performance. I would also like to thank our shareholders and clients for their ongoing confidence in Subsea 7 and their support for our strategy.

Kristian Siem

Chairman

OFFSHORE ENERGY MARKET DYNAMICS

OIL AND GAS MARKET ACTIVITY IS IMPROVING

In 2017 the prices of oil and gas rose as the supply and demand imbalance tightened and global inventory levels decreased. This supported an increase in project activity for offshore development as more projects were sanctioned and awarded. The supply from lower cost onshore production has resulted in a long-term oil price below historic highs. Offshore energy has successfully reduced its costs, through the use of innovation, technology and partnerships to improve efficiency and productivity. This, along with increased production discipline by OPEC, has allowed the offshore energy sector to re-establish its position as a core source of supply on the energy cost of supply curve.

Offshore greenfield project sanctioning by sanction year (USD billion)

Source: Rystad Energy, January 2018

OFFSHORE WIND IS A GROWING GLOBAL MARKET

Offshore wind farms are part of a fast changing and growing market. Advances in technology have resulted in larger turbines and bigger wind farms, leading to offshore developments that can achieve economic energy production independent of government subsidy. As a result, market analysts forecast 11% compound annual growth rate in offshore renewables installation, most of which is in Europe, but which also includes Taiwan and the US. Large offshore wind developments are few in number and activity levels may be volatile year on year.

Offshore wind installation market (USD billion)

3

"Our value-driven strategy and strong financial position have enabled us to grow and strengthen our business and invest in technology and innovation through the downturn."

Jean Cahuzac Chief Executive Officer

LOOKING BACK

Subsea 7 performed well in 2017, executing projects to a high standard and delivering good operational and financial results, despite the persistently challenging conditions in the offshore oil and gas markets. Group revenue was \$4.0 billion, an increase of 12% on the prior year as incremental revenue from renewable and conventional energy projects more than offset the lower activity in deepwater projects and Life of Field activities. Adjusted EBITDA was \$1.0 billion, 9% lower than the prior year due to the change in mix of our activity as larger projects awarded prior to the downturn reached completion. Net income of \$455 million included a \$32 million impairment charge relating to our onshore and offshore assets. Our financial and liquidity position remained strong despite an expected decrease of net operating liabilities in line with various project completions. As at 31 December 2017 our net cash balance was \$826 million, a decrease of \$423 million from the position 12 months earlier, and our \$656 million revolving credit facility remained undrawn.

Order backlog was \$5.2 billion at the end of the year. We added \$1.1 billion to the backlog through acquisition, as we expanded our renewable energy and conventional oil and gas businesses. In addition, we were awarded \$2.2 billion of new work during the year, including the award to the alliance with OneSubsea of the industry's largest integrated project, and the first award to include an integrated long-term Life of Field solution. Awards to market remained subdued for most of the year. However, a combination of lower costs and higher oil and gas prices encouraged an increase in awards to market towards the end of 2017. Subsea 7's value-driven strategy and differentiated capability positioned us well and helped us to continue to maintain market share. We kept a disciplined approach with respect to the appropriate level of project risk exposure.

DELIVERING OUR STRATEGY

The safety and wellbeing of our people, both offshore and onshore, is the first priority and we work together with clients and partners to minimise risk of harm and aim for a perfect safety performance. Our daily operations can be complex and potentially hazardous and we put in place safety measures to mitigate the additional risks these present. (2017 safety metrics are presented in more detail on page 18). Effective safety, health and environmental leadership is essential in everything that we do.

We are committed to treating all stakeholders fairly, transparently and with respect. By applying the highest standards of integrity we develop relationships based on trust and safeguard our business from wrong-doing. Subsea 7's governance structures and controls help to ensure that the same high standards are applied everywhere we operate.

Our focus on innovation has promoted better, faster and lower cost solutions that help establish the long-term position of offshore production as a key source of global energy. Oil and gas developments are being enabled by innovation such as long-distance tie-backs that eliminate the need for new topside processing units, Life of Field services that use data and automation to reduce vessel days and offshore wind turbines getting larger and generating more power per unit. In 2017 we installed three Pipeline Bundles, an innovative solution using lower cost tow-lay methods, and were awarded our first project to implement Electrically Heat Traced Flowline (EHTF) technology for long-distance tie-backs.

We aim to deliver a predictable and reliable performance for clients, completing projects safely, on schedule and within cost expectations. Our decades of experience and quality of people helped us to execute well, with 49 projects successfully completed in 2017. Our reliable performance helped us to build client partnerships and enabled us directly to secure work with clients. Our good financial performance in 2017 was reflected in excellent execution and ongoing cost discipline.

Our industry has developed a wide range of solutions to enable projects to be sanctioned and develop sustainable cost-efficiencies. Many of these solutions result from industry-wide collaboration. In 2017 Subsea 7 and OneSubsea collaborated to progress and develop Subsea Integration Alliance, a leading provider of integrated SURF and SPS solutions for offshore oil and gas. As a result of this successful collaboration, Subsea Integration Alliance has been awarded four projects and has many more at design and tender stage. We have further evolved client partnerships, collaborating to deliver the Oda project under a partnership agreement with Centrica and the Volund project with Aker BP.

LOOKING AHEAD

Subsea 7's differentiated capability and values-driven strategy are central to our ability to create value for all stakeholders through the cycle. Building on this strategy, in February 2018, Subsea 7 announced targeted investments enhancing its early engineering expertise, extending its renewables capability and affirming its commitment to integrated solutions.

Market award activity in offshore oil and gas has begun to gradually recover from the very low levels experienced in recent years. We look forward to the year ahead with confidence in our ability to provide clients in all our markets with cost-effective solutions that contribute to the long-term sustainability of offshore energy.

Jean Cahuzac Chief Executive Officer

LIVING OUR VALUES

SAFETY

We are committed to an incident-free workplace, every day, everywhere. We continue to minimise the impact of our activities on the environment.

INTEGRITY

We apply the highest ethical standards to everything we do. We believe that by treating our clients, people and suppliers fairly and with respect, we will earn their trust and build sustainable success together.

INNOVATION

We constantly strive to improve the efficiency of our business by investing in the development of our people and through innovation in technology, operations and processes.

PERFORMANCE

We are predictable and reliable in our performance. We always strive for excellence in everything we do in order to achieve superior business results.

COLLABORATION

We are locally sensitive and globally aware. Our people work together, leveraging our global know-how and capabilities to build sustainable local businesses.

Strategic report

6 OUR ACTIVITIES

Spoolbase facilities

S-Lay and J-Lay installation

Our capabilities across the field development lifecycle

Controlled Depth Tow Method

Subsea 7 S.A. Annual Report and Consolidated Financial Statements 2017

CONCEPT DESIGN ENGINEER PROCURE & FABRICATE

Subsea Processing Facilities

Input at conception allows for optimisation of later cycle stages.

Robust design ensuring minimal change and accurate forecasting at the engineering stage.

Detailed engineering by experienced personnel to deliver the best solution.

Efficient procurement and high quality fabrication delivered on time.

Delivering across our segments

Subsea 7 structures itself around its diversified strengths, reporting across three core business units: SURF and Conventional, i-Tech Services, and Renewables and Heavy Lifting. Through these business units we are able to provide full field development lifecycle services.

Key

• SURF and Conventional
• Renewables and Heavy Lifting
• i-Tech Services

SURF AND CONVENTIONAL

SUBSEA 7 IS A WORLD-LEADING SEABED-TO-SURFACE ENGINEERING, CONSTRUCTION AND SERVICES CONTRACTOR TO THE OFFSHORE ENERGY INDUSTRY.

Subsea 7 delivers and adds value to our clients across the lifecycle of Subsea Umbilicals, Risers and Flowlines (SURF) and Conventional projects. Subsea 7 is able to offer full lifecycle support to our clients; from conceiving concepts at an early stage in field development, to completing detailed engineering which allows for bespoke solutions, through to installation with experienced personnel.

Subsea 7 has a market-leading presence in the SURF and Conventional construction industry in all major oil and gas regions globally. Engineering is at the core of our business. We are experts in the design, fabrication, installation and commissioning of seabed-to-surface projects. Our projects range from large greenfield installations in remote environments in water depths of up to 3,000 metres, to smaller, shallower brownfield tie-backs requiring divers. Our track record in this segment includes over 1,000 projects successfully executed for our clients to date. Our diverse fleet of vessels enables us to match project specific needs to exact vessel capability.

Included within our SURF segment is our long-standing presence in Brazil with our 550 tonne top tension Pipe Lay Support Vessels (PLSVs). The PLSV contracts governing our activities offshore Brazil were extended in 2017, showing our continued presence and commitment to developing deepwater fields for Petrobras.

With the acquisition of certain businesses of EMAS Chiyoda Subsea (ECS) in 2017, Subsea 7 has become a stronger player in the conventional market in the Middle East. Conventional services include the fabrication, installation, extension, hook-up and refurbishment of fixed and floating platforms. Subsea 7 has a long track record in conventional work, particularly in the shallow waters offshore Nigeria. Vessels, Seven Inagha and Seven Antares, previously used there, can be redeployed to the Middle East as they are well suited for this type of construction.

We are pushing the technological boundaries of subsea engineering, allowing us to offer more efficient solutions to our clients' challenges. This is particularly evident in the development of long-distance tie-backs where technology is transforming the economics of field infrastructures, in particular the use of Electrically Heat Traced Flowlines (EHTF) and Cold Flow Technology. This enabling technology is contributing to final investment decisions on marginal fields. Along with developing this technology, Subsea 7 is investing in the associated enabling assets. The announcement of our new high specification reel-lay vessel, which is scheduled for delivery in 2020, is one of these investments.

BROADENING OUR PRESENCE IN THE MIDDLE EAST

The Middle East houses almost half of the world's proven oil resources; Subsea 7 therefore placed focus on strategic growth in the region. This strategy has been expedited with the acquisition of ECS in 2017.

Saudi Aramco continued to sanction capital expenditure on projects, despite the recent challenging market conditions. The existing long-term agreement (LTA) contract with Saudi Aramco, which is in consortium with L&T Hydrocarbon Engineering, will allow for Subsea 7 to seize these opportunities. Saudi Aramco is also turning its attention to the Red Sea, with seismic surveys recommencing. With water depths in the Red Sea of over 1,000 metres, Subsea 7 is well positioned to develop these deeper fields with our SURF expertise.

This regional operation now completes the global presence of Subsea 7. Subsea 7 has the capacity to deliver SURF and Conventional work in the Middle East, utilising its local presence and well established relationships developed by ECS. With three current projects being executed in the region, Subsea 7 has succeeded in deep-rooting its presence.

Enhance production with reduced cost and risk, a new perspective on project delivery with focus on pore-to-shore.

Subsea 7 and OneSubsea founded Subsea Integration Alliance in 2015. Its goal is to deliver complementary technology and expertise that help customers extend field life and lower production costs, ensuring greater certainty of recovery and return on investment. Our integrated technology teams are making significant advances in increasing long-distance tie-backs by combining Subsea 7's EHTF technology with multiphase boost pumps, and incorporating Subsea Production Systems (SPS) into our unique Pipeline Bundle technology.

Our clients are supportive of this alliance, witnessing how we can deliver projects through early engagement, standardised solutions and versatile contract models. 2017 has shown this to be a winning formula, with the announcement of the Mad Dog 2 project for BP in the US Gulf of Mexico, the Fortuna FLNG project for Ophir in Equatorial Guinea and the Otter project for TAQA in the UK North Sea. Mad Dog 2 is the largest integrated project to be awarded to the market. Execution is placed with the centralised Global Project Centre, continually showcasing our ability to execute locally with global support. The Fortuna FLNG project demonstrated how Subsea Integration Alliance can support fields through the entire lifecycle, with the Life of Field contract forming part of the award. The Otter project shows how the technological synergies in the alliance are allowing for the longest subsea multiphase boosting tie-back in the UK North Sea, enabling our client to improve recovery from an existing asset.

DEVELOPING STRONG PARTNERSHIPS

Subsea 7 recognises the need to develop strong partnerships to aid our global operations and deliver cost effective solutions for our leaders in front end engineering.

Our collaborative partnership with Aker BP shows how we are working hard at evolving successful long-term relationships. The Volund Infill project for Aker BP, which was completed in July 2017, With project management and engineering hours reduced by 30%, Subsea 7 can add to our clients when working in partnership.

The ability to engage early is key in adding value to the full lifecycle of energy field developments. In February 2018, Subsea 7 agreed to acquiring a 60% holding in Xodus Group, from Chiyoda. Xodus Group are a leading energy consultancy. The joint venture partnership, with Chiyoda, will enhance the Group's early engineering engagement in the offshore energy industry.

9

i-TECH SERVICES

i-TECH SERVICES IS A LEADING LIFE OF FIELD PARTNER FOR THE OIL AND GAS INDUSTRY.

For more than 35 years, we have provided both standard and bespoke suites of offshore Life of Field engineering products and services, becoming an all-inclusive supplier for our clients.

i-Tech Services' solutions are built on our core strengths: Remotely Operated Vehicles (ROVs), survey and inspection, drill rig support, performance monitoring, data management, tooling and repair solutions, engineering, and production sampling.

With access to 166 ROVs, our fleet is one of the largest and most advanced in the world, able to work in the deepest waters. By combining our cutting edge technologies with a diverse fleet of advanced vessels and highly skilled personnel, we provide engineered solutions that create real value for our clients through integrated product and service packages.

The amalgamation of our former Life of Field activities business into i-Tech Services provided a more comprehensive tool kit, strengthened capability, and assembled a dedicated group able to focus on clients' needs. It has focused the technology programme on becoming more efficient, expanding our overall capabilities to lower the total cost of ownership of new and existing fields through the development and deployment of enabling technologies.

These capabilities were demonstrated through the award of the Fortuna FLNG project, which includes an i-Tech Services Life of Field solution, in alliance with OneSubsea.

For greenfield developments, like the Fortuna FLNG project, designing for monitoring, maintenance, intervention and system reliability is a critical element in enabling i-Tech Services to align with Subsea 7's

technological and operational expertise. For brownfield developments, being more responsive, lowering the cost of inspections, collecting the right data to determine equipment health and having the capabilities to intervene, repair, extend and dispose of assets are equally important.

The Life of Field sector is turning towards data and digitisation, adapting solutions used in the automotive and aerospace industry for subsea use. i-Tech Services is investing in research and development to ensure we are at the forefront of this digital evolution.

Along with technology focused on operating expense (OPEX) reduction, i-Tech Services has continued to lead the field in rapid response repair. This was showcased by the Emergency Pipeline Repair System (EPRS) project offshore Australia for Chevron and Inpex, which was completed in late 2017.

DEVELOPING OUR LIFE OF FIELD TECHNOLOGY FOR A DIGITAL FUTURE

Innovation is a core value for Subsea 7. Part of innovation is technology, specifically business driven technology. The total cost of ownership our technology development. i-Tech Services is inspection repair and maintenance (IRM) more intelligent and ultimately reduce the cost of ownership. Intelligent tooling will allow IRM to be more responsive through diagnostics rather Services is focused on delivering an aggressive technology development plan that utilises big data, digitalisation and artificial intelligence to provide an intelligent asset management service.

By utilising design data, as-builts, actual operating data, packaged in a digital viewer, management that can provide real-time equipment health and condition ratings. These maintenance based on client goals, needs

RENEWABLES AND HEAVY LIFTING

OFFSHORE RENEWABLE ENERGY IS AN IMPORTANT FOCUS AREA FOR SUBSEA 7. THE INDUSTRY IS RAPIDLY GROWING WITH CERTAIN PROJECTS SANCTIONED WITHOUT THE NEED FOR GOVERNMENT SUBSIDY.

Renewables and heavy lifting comprises three specialist segments: the installation of offshore wind farm foundations, heavy lifting operations for oil and gas structures, and decommissioning. Subsea 7's historical SURF segment is exposed to the cyclical nature of oil and gas market demands; this business unit allows for assets and personnel to be reallocated during times of fluctuation.

The renewables market is growing and with two EPCI projects, Beatrice and Borkum II, being awarded to Subsea 7, we have positioned ourselves as one of the leading EPCI contractors in this sector. In 2017, Subsea 7 acquired the remaining 50% of the joint venture Seaway Heavy Lifting, becoming a wholly-owned subsidiary of Subsea 7, further showing our commitment to this core segment. Few contractors have the capabilities to install these heavy foundations; with large offshore wind developments being sporadic in number the market is competitive for the near term.

With the acquisition, the two specialist heavy lifting vessels Stanislav Yudin and Oleg Strashnov became fully owned Subsea 7 vessels. It is not only offshore wind farm construction where we see these vessels' capabilities utilised, with Oleg Strashnov having recently completed heavy lifting work on the Zohr Gas Field project offshore Egypt.

Renewable projects have historically focused on shallow waters. We are now starting to see opportunities in deeper waters. Within Europe, 80% of offshore wind energy is located in water depths of over 60 metres. To harness this energy the industry has widened its focus to include floating offshore wind farms. Subsea 7 is differentiated from other competitors in this sector due to our long history in deep water construction.

Until now, offshore wind farm development has been concentrated within Europe. Recently, however, other regions have seen the opportunity to capitalise on this green energy. Taiwan has set a target of 3 gigawatts of offshore wind capacity by 2030, that is five times the size of the Beatrice project.

The step change in technology within the renewables industry is allowing for larger and more innovative installations. Broad marine management and engineering capabilities are required to deliver these projects. Our global presence and capability to deliver services throughout the entire lifecycle of these EPCI projects places Subsea 7 well in supporting this industry as it develops.

• Renewables and Heavy Lifting

i-Tech Services

33 Offshore wind turbine foundations installed in 2017

DELIVERING SUSTAINABLE ENERGY ON BEATRICE PROJECT

The Beatrice Offshore Windfarm Ltd. (BOWL) project, which in the North Sea, is the largest project executed by Subsea 7 in this region. The combination of Subsea 7 experience and expertise in project management and engineering, in conjunction with the installation expertise of Seaway Heavy Lifting, has resulted in a strong execution. Subsea 7's involvement as an EPCI contractor, rather than our historical T&I contractor role in this segment, has allowed Subsea 7 to bring output 588 megawatts, powering approximately 450,000 homes with sustainable power.

Strategic report

Our global presence

We recognise our industry is global and we have capabilities to operate in all offshore provinces. We add value to our clients by managing our people and assets so that a local delivery can be achieved worldwide in challenging environments.

Our clients' global reach is reflected in our own global presence; we have the ability to deliver all of our services worldwide. To do this successfully we place value on having a local presence.

Our project management and engineering teams continuously deliver value-adding solutions. Global Project Centres centralise this core knowledge whilst allowing for the flexibility to respond locally.

Subsea 7 is aware of how vital our local capability is and we continually strive to build and develop our local presence. Our onshore and offshore people are some of the most experienced this industry has to offer, constantly collaborating with clients, ensuring execution in a safe and timely manner.

KEY STATISTICS

the UK* and the US*

* The Group has more than one facility in these countries

GULF OF MEXICO

2017 saw the award of a Subsea Integration Alliance solution for the Mad Dog 2 project for BP. The award of the Mad Dog 2 project further develops the ways of working cultivated with BP on recent projects offshore Egypt, demonstrating the benefits of effective collaboration.

In line with the integration plan for the ECS business in Houston, the Gulf of Mexico (GOM) team was reorganised. A focus was placed on establishing teams dedicated to Mooring systems, the continued delivery of the TVEX project, growing Field Development, and enabling the Business Development, and Sales and Marketing teams to concentrate on supporting our clients.

BRAZIL

Continuing our strong history of deep water construction for Petrobras, in 2017 three of our PLSVs day-rate contracts were extended. The ultra-deep 550 tonne top tension flex lay vessels, Seven Waves, Seven Rio and Seven Sun, had contract extensions until Q2 2021, Q3 2021 and Q2 2022, respectively. Subsea 7 operated up to nine PLSVs offshore Brazil in 2017, four of which had 550 tonne top tension capability.

The outlook for SURF projects offshore Brazil is focused on the upcoming Libra projects where tendering activity will commence shortly. The Libra field is pre-salt and located in ultra-deep water. It requires the capability and technical expertise that Subsea 7 is able to provide.

13

NORTH SEA AND CANADA

Our largest North Sea project, the Beatrice Offshore windfarm (BOWL) project, made significant progress in 2017. Future wind farm projects being evaluated in Europe include projects offshore Germany, France, the UK and the Netherlands.

Subsea 7's Pipeline Bundle solution on the Callater project offshore the UK was recognised at the Oil & Gas UK Awards for maximising economic recovery in the UK. This was one of three Pipeline Bundle projects completed by Subsea 7 in 2017. Offshore Norway, the Maria project was completed for Wintershall, culminating in over one million worked hours free of lost-time incident, and was able to showcase the capabilities of our new heavy construction vessel Seven Arctic.

Canada continued with the Hebron Offshore Loading System (OLS) project for ExxonMobil, completing several complex trips installing the OLS hose to the platform. The successful installation contributed to achieving first oil from the Hebron field in November 2017.

AFRICA

In Egypt the West Nile Delta phase one project was successfully concluded and first gas was achieved on time and within cost expectations. The West Nile Delta phase two project on the Giza Fayoum Raven (GFR) fields commenced offshore activity with the completion of the shore approach of three pipelines installed with the vessel Seven Antares. In 2018 construction will resume in deeper water with the vessel Seven Borealis. The OCTP SURF project offshore Ghana progressed well with a short-term charter vessel completing a successful campaign.

ASIA PACIFIC

Subsea 7 celebrated 40 years of operations in Australia where it continued excellent execution on the Greater Western Flank project for Woodside and was awarded the Sole project by Cooper Energy. Also in Australia, i-Tech Services completed the Emergency Pipeline Repair project for Chevron and Inpex. Subsea 7 is proposing Pipeline Bundle solutions for future developments offshore Australia.

MIDDLE EAST

Subsea 7 was able to accelerate its strategy for growth in the conventional market in the Middle East with the acquisition of certain businesses of ECS. This resulted in Subsea 7 taking on a long-term agreement in consortium with L&T Hydrocarbon Engineering to work for Saudi Aramco offshore Saudi Arabia until at least 2021. Three projects were added to the Subsea 7 portfolio in the Middle East as a result of the transaction: Hasbah, Four Decks and 17 Cranes. With continued growth in the conventional market, the outlook for Subsea 7 in the Middle East is positive.

Our value proposition

Our business model is built upon our differentiators, which are underpinned by our Values. From this base, our activities across full project lifecycles create value for our stakeholders and make us a trusted strategic partner.

PEOPLE

Our skilled and experienced engineers, project managers, onshore and offshore construction and support staff are the key to ensuring safe and reliable delivery. Our people are the foundation of our business.

TECHNOLOGY

Our enabling and proprietary technology helps our clients to develop offshore energy assets cost-effectively and extend the life of their existing offshore infrastructure.

ASSETS

Our modern and diverse fleet of vessels and Remotely Operated Vehicles (ROVs) has the scale, capability and versatility to give us a significant advantage and enable us to deploy vessels efficiently and effectively.

ALLIANCES & PARTNERSHIPS

Our global alliances and partnerships with our clients and leading industry partners support early engagement and integrated designs, optimising the solutions we can provide.

LOCAL PRESENCE

We have an established local presence in all the major offshore energy regions worldwide. Our local joint ventures and partnerships support sustainable development of the energy industry in the countries in which we operate.

enable us to deliver FULL LIFECYCLE ACTIVITIES for our clients… Our DIFFERENTIATORS…

FULL LIFECYCLE SERVICES

Subsea 7 provides services across the full lifecycle of energy field developments. These services are provided across all three of our core business units.

Our engineering capability, enhanced by alliances, supports early engagement with clients to produce a concept that adds value to the full field development lifecycle. The Front End Engineering and Design (FEED) stage allows for market-led technology to be integrated into the design, optimising operational efficiency and minimising the cost to clients. Our concept and FEED work develop into cost-efficient solutions during the detailed engineering stage. Supply Chain Management teams ensure subcontractors are aligned with Subsea 7's Values, ensuring quality is of prime focus. Our extensive track record, along with high-specification vessels, enables on-schedule fabrication, installation and commissioning. Our expertise in IRM services, products and tooling enables us to be a long-term partner for clients through field maintenance. Technology, including Electrically Heat Traced Flowlines and Cold Flow Technology, is increasing the length of tie-backs, further extending the life of fields. Finally, heavy lifting capabilities allow decommissioning of energy fields at the end of the lifecycle.

SURF AND CONVENTIONAL

Generating significant cost savings in installation by engaging early and delivering the right solutions for our clients with safe and on-time execution.

i-TECH SERVICES

Reducing cost of ownership through effective maintenance using innovative data technology advances.

RENEWABLES AND HEAVY LIFTING

World-class heavy lifting vessels enabling decommissioning at the end of the lifecycle.

15

as a LEADING STRATEGIC PARTNER and…

EXPERIENCE

Subsea 7 is one of the most experienced providers of seabed-to-surface services to the energy industry, with offshore operations spanning five decades and over 1,000 projects successfully completed.

EXPERTISE

We work in all water depths across all energy hubs. Our engineering expertise, alliances and specialist technology enable us to engage early to design and deliver the right solutions for our clients. Multi-disciplined engineering teams can propose a range of comprehensive solutions to complex problems.

SCALE

Subsea 7 has over 10,500 people, a fleet of 35 vessels and an active presence in 36 countries. Our worldwide scale enables us to execute numerous projects of various sizes simultaneously.

RELIABILITY

We have a strong track record of safe and reliable delivery of projects for our clients. Our reputation for being a good service provider in long-lasting client relationships makes us one of the most trusted contractors in our market.

FINANCIAL PROFILE

Our strong financial and liquidity position gives our clients confidence in our ability to deliver large multi-year projects and enables Subsea 7 to invest to strengthen and grow the business for the long term.

RELATIONSHIPS

We have strong relationships with our clients and understand the value they bring. We specialise in forming collaborative partnerships with our clients and have strong alliances with other top tier companies.

create long-term value for all our STAKEHOLDERS

OUR CLIENTS

We focus on working with our clients and investing in developing strong relationships. Our people are dedicated to delivering value for our clients through early engagement, alliances and excellent execution.

104 clients worked with Subsea 7 in 2017

OUR SHAREHOLDERS

Our strategy to cut capacity and maintain capability in the downturn has been effective in driving value for our shareholders. This has enabled us to pay a dividend in 2017 and invest for the future while maintaining a strong financial position.

17% Total Shareholder Return generated in 2017

OUR PEOPLE

We have expanded our workforce with the integration of people from acquired businesses, SHL and ECS. The safety and security of our people is our highest priority and we are dedicated to continually investing in core skills training and development.

102,000 training hours delivered to employees in 2017

SOCIETY

We aim to engage with and respect the environment and communities we work in worldwide. We are working to control our impact on the environment with our actions to minimise carbon emissions and support biodiversity through alliances with academic institutions.

32 community assistance events delivered in 2017

Delivering our strategy

We acted on once-in-a-cycle strategic pursuits, helping accomplish our objectives. In 2017 we delivered increased exposure to the offshore renewables energy market, we fast tracked our entrance into the Middle East and we committed to business led technology advances.

OUR DIFFERENTIATORS

PEOPLE

Project delivery based on our expertise and know-how

MARKET CONTEXT

• Our teams of experts include specialist engineers, capable project managers and experienced offshore crews.
• With 80 different nationalities working throughout the Group, we think globally and deliver locally.
• Our workforce has the capability and competence that make us a leading global provider of services to the offshore energy industry.
• Our workforce is located across onshore and offshore work sites, with approximately 4,400 onshore and 6,100 offshore employees.

TECHNOLOGY

Developing market-driven and cost-effective solutions

• Our strong portfolio of technologies meets current and future subsea development challenges.
• We own one of the largest and most recent groups of patents in the SURF and Life of Field market segments.
• We will continue to invest through the cycle to develop new enabling and cost-reducing technologies.

ASSETS

A diverse fleet of vessels and strategically positioned onshore assets

• We have one of the most capable and diverse fleets of vessels in our market segment. Our fleet of ROVs is one of the largest and most advanced in the world.
• Our modern and versatile fleet includes chartered and highspecification owned vessels. This balance gives us operational flexibility and retains full control of the capabilities that differentiate our services.
• Our onshore facilities are located to allow for global operations.

ALLIANCES AND PARTNERSHIPS

Collaborating to deliver optimal field development solutions

• Our alliance with OneSubsea provides integrated SPS and SURF solutions, and innovative joint technology.
• Our client partnerships have evolved from our collaborative approach to developing optimal long-term working relationships with our clients.

LOCAL PRESENCE

Building local business and embedding local capability

• Our local presence ensures we have in-country leadership teams and the capability to respond to our clients' needs in the world's primary offshore energy regions.
• Our 18 local associates, joint ventures and non-wholly owned subsidiaries give us a well-established local presence that complements our network of local offices and facilities.

17

2017 DELIVERY

• We preserved our capability to operate globally, ensuring our personnel are suitability trained and qualified to execute the most complex of projects.
• We broadened our expertise with personnel from SHL and ECS strengthening our resource levels in renewable wind energy and the Middle East.
• We have welcomed 41 newly qualified engineers into our company through our graduate training scheme.
• We have focused on business driven technology and innovation to create real value for our clients.
• We acquired a minority interest in Airborne Oil and Gas, the world's leading manufacturer of thermoplastic composite pipe for oil and gas applications.
• We are currently offering technology that enables longer tie-backs to the market, removing the need for expensive topside processing facilities.
• We continue to work with strategic partners to develop integrated intelligent asset management services, reducing the cost of ownership for our clients.
• We realised future needs for deploying our new technologies and invested in a new reel-lay vessel. Scheduled for delivery in 2020, this vessel will be able to install Electrically Heat Traced Flowline and Pipe-in-Pipe solutions in water depths of up to 3,000 metres.
• We removed five vessels from our fleet to ensure we have the right balance of capabilities to meet our future needs.
• We delivered the final two vessels, Seven Arctic and Seven Kestrel, from our multiyear fleet investment programme, which started in 2012.
• We won several awards with Subsea Integrated Alliance, including the Mad Dog 2 project, the largest integrated award in the market to date.
• We demonstrated, with the award of the Fortuna FLNG project, not only that this alliance is a solution for EPCI contracts, but how value can be added by working in alliance with i-Tech Services.
• The benefits of our partnership with Aker BP were manifested in the efficiently managed delivery of the Volund Infill project.
• We fast tracked our local presence in the Middle East with the acquisition of certain businesses of ECS.
• We maintained and invested in our presence in Brazil, in preparation for increased activity.
• We strengthened our local presence in emerging markets, introducing the new role of Senegal Country Manager, demonstrating how we continually put focus on delivering locally.

2018 OBJECTIVES

• Maintain an appropriately sized workforce for the market conditions.
• Increase focus on development programmes to retain and develop our skilled people in key areas of competence.
• Reinforce core values with particular emphasis on safety and integrity, and how they can help reduce our recorded incidents and promote a culture of reporting and learning.
• Invest in cost-effective technology development to support lower total capital and operating expense for energy fields offshore.
• Expand and commercialise our extensive portfolio of technology solutions through innovation and partnerships with industryleading manufacturers and suppliers.
• Promote integrated solutions and early engagement to support application of our technology and efficiently optimise production for our clients.
• Maintain a diverse fleet of vessels to ensure sufficient capacity and capability for the market conditions.
• Invest in vessel and equipment capability to support installation and maintenance of our portfolio of technology solutions.
• Maintain our footprint of local operational bases and offices in key strategic locations worldwide.
• Explore potential Pipeline Bundle fabrication sites in Australia to allow for this proprietary technology to be offered as a solution in Australian waters.
• Engage earlier with clients through our alliances to provide our clients with the right choices for cost-efficient solutions at the concept and design phase.
• Promote integrated SURF and SPS full lifecycle solutions where there are substantial cost reductions or productivity enhancements that can be achieved through integrated solutions.
• Deepen client partnership agreements and engage with clients on a range of contracting models.
• Maintain our local presence with strategic local partnerships and local supply chain capability supporting the projects we are executing worldwide.
• Focus on establishing a local presence in locations with the greatest potential for offshore energy growth in the medium term.

Committed to safe, ethical and responsible operations

Our goals are: to protect the health and safety of our people and others who work on our sites and vessels; to take robust steps to ensure we conduct business with integrity and in compliance with applicable laws; to invest in the communities in which we operate; and to minimise our impact on the environment.

HEALTH AND SAFETY IS OUR FIRST PRIORITY

We believe that all our people are entitled to the same level of protection regardless of where in the world they work. This attitude is embedded at the core of our culture and the way we work. Our aim is to achieve an incident-free workplace, every day, everywhere. We believe this aim can become a reality. Where we fail to meet this aim, senior resources are allocated to understand the failing, ensure future mitigation and share our learnings with the industry. We are all responsible for our own and each other's safety. This is entrenched in Subsea 7 daily life through the Business Management System which dictates the reporting, procedural, training and risk assessment processes which are carried out to ensure a safe work site.

In 2017 no fatalities were recorded and we maintained our performance in key incident rate indicators. To ensure we reduce our incident rates we recognise that we must re-energise our efforts and have reinforced the need for continued focus. We will maintain this focus through safety training, culture and leadership schemes.

Lost-time incident frequency rate (%)

0.05

per 200,000 hours worked.

Recordable incident frequency rate (%)

0.28

per 200,000 hours worked.

DIVERSITY ENHANCES OUR PERFORMANCE

Subsea 7's Equal Opportunities and Diversity in Employment policy is in place to promote equality of opportunity and address unfair discrimination in every aspect of our operations. The Executive Management Team and Corporate HR are responsible for developing the corporate objective and policy.

Subsea 7 recognises that diversity and inclusion are key to ensuring a holistic perspective and the contribution of varying ideas which engenders innovation and growth. An example of this is with the multitude of cultures that make up Subsea 7; with 80 nationalities working throughout the Group, they all bring valuable ideas, beliefs and skills. Subsea 7 recognises that it has a gender imbalance. Subsea 7 aims to improve its diversity, with a Group level focus on increasing our nationality and gender mix at the leadership level.

Underpinning our approach to equality is our belief that everyone has a right to be treated with dignity and respect and Subsea 7 is committed to providing an inclusive working environment free from all forms of discrimination, including harassment and bullying.

ENERGY EFFICIENCY IS A PRIME OBJECTIVE

Our Environmental Management System is in full compliance with, and certified to, the environment management standard ISO 14001. We focus on ensuring full compliance with all applicable international and local environmental legislation. To track our performance we monitor data such as energy efficiency, emissions and waste management. We actively participate in the annual Carbon Disclosure Project, ensuring we measure and manage our environmental impact. For 2018 Subsea 7 has established a new environmental target, to emit less than 25 litres of unplanned, uncontained environmentally harmful fluid spills to the environment per 200,000 hours worked.

Our Clean Operations programme continues to drive down emissions and ensure efficient energy management. The programme started in 2011 with the key objective to raise the awareness of energy efficiency and to save fuel without compromising, or being in conflict with, safety or the execution of projects. In 2017, we recorded, approximately

19

5,000 Clean Operations activities relating to our own vessels, compared to approximately 3,300 recorded in 2016.

Carbon dioxide emissions reported for our fleet of owned and chartered vessels for 2017 was 404,499 tonnes of carbon dioxide similar to 404,000 tonnes in 2016. The emissions data reflect a combination of the work schedules of the vessels throughout the year and the impact of our Clean Operations programme.

Replacing our older vessels will provide us with a more efficient and cleaner fleet. The removal of vessels from our fleet is completed in accordance with the Hong Kong International Convention for the safe and environmentally sound recycling of ships, and in line with our Values, ensuring no unnecessary risks to health and safety, or to the environment. Our new vessels are built incorporating technology to improve environmental performance. This was evident with the vessels delivered during our recent fleet investment programme. Our four new PLSVs, as well as Seven Arctic and Seven Kestrel, all have nitrogen oxide and sulphur oxide emission reducing technologies, helping to reduce harm to the environment. Our new-build vessel, due for delivery in 2020, will not only have these improvements but will feature shore-to-ship power systems allowing the vessel to be powered from the onshore power grid whilst in port rather than by the vessel engines.

Carbon dioxide emissions (tonnes)

404,499

Carbon dioxide emissions from fuel consumed by operational owned and chartered vessels.

2017	404,499
2016	404,000
2015		469,000

Clean Operations

5,000

Clean Operations data based on Subsea7 owned vessels only.

ETHICS, COMPLIANCE AND INTEGRITY ARE KEY TO OUR BUSINESS

Subsea 7 is committed to carrying out its business in an ethical manner and in strict compliance with applicable laws wherever we operate. Integrity is a core value and we aim to act fairly, honestly and with integrity at all times, and earn the trust of our clients, business partners, suppliers and other stakeholders by acting consistently and reliably in accordance with these principles. We regularly survey the opinions of our employees, allowing a platform for open and honest communication with management. All employees are required to uphold our Code of Conduct, which is underpinned by an annual Compliance and Ethics e-learning campaign. In 2017 the focus of this e-learning was on what integrity means to us as individuals and as a company, and how to apply this understanding to ethical dilemmas that employees may face.

Number of employees completing compliance and ethics e-learning

3,699

Over 98% completion rate for targeted personnel undertaking compliance and ethics e-learning.

We have a Group-wide anti-bribery and anti-corruption compliance and ethics programme, which is grounded in our Values and is designed in accordance with international best practice (including the International Anti-Bribery Management System Standard ISO37001). During 2017 we again engaged an independent, external organisation to benchmark our programme against best practice in our sector and across sectors, with the aim of continually improving our programme. Building on a similar assessment conducted by that organisation in 2015 at a Group level, in 2017 this assessment focused on our programmes in high-risk locations where we have significant levels of activity.

Management is accountable for compliance, which is the responsibility of everyone who works for us. One of the key roles of our compliance and ethics function is to ensure management understands, accepts and fulfils that accountability.

Our Group Head of Compliance and Ethics is responsible for the design and oversight of our compliance and ethics programme, which includes frameworks for assessing risks, and provides reports to the Corporate Governance and Nominations Committee and to the Executive Ethics Committee. The Ethics Committee meets at least once each quarter, and once a year a joint session of the Audit Committee and the Corporate Governance and Nominations Committee agrees compliance and ethics objectives and reviews progress in implementing the programme.

Subsea 7 engages with thousands of suppliers worldwide, and our Supply Chain Management procedures include rigorous selection and appointment criteria. Approved supplier status requires prequalification of suppliers from a quality, safety, environment, ethics and anti-corruption perspective. Where pre-approved suppliers are not available, we have procedures for verifying that such suppliers can operate to our standards. All suppliers are required to comply with Subsea 7's Code of Conduct for Suppliers.

We are committed to treating our employees, clients, suppliers and other stakeholders fairly and with respect, and to upholding and respecting human rights. In 2017 we published a Slavery and Human Trafficking Statement, as part of our efforts to respond to the UK Modern Slavery Act and, more broadly, to improve our understanding and management of the potential human rights impacts of our global business impact.

Under the oversight of a cross-functional working group, established at the direction of the Executive Ethics Committee, we have:

• Engaged an external leading organisation to provide independent, expert advice, to help us deliver training.
• Integrated human rights and modern slavery questions and compliance clauses in our supplier due diligence and contracts, and included human rights risks in the tool that we use to screen suppliers.
• Started to consolidate our existing policies, procedures and statements into one coherent human rights policy that includes modern slavery and human trafficking.

Managing risks and uncertainties

Effective risk management is fundamental to how the Group operates its business, delivers sustainable shareholder value and protects its reputation.

The Group's approach is to identify key risks at an early stage and develop actions to measure, monitor and mitigate their likelihood and impact. This approach is embedded throughout the Group and is an integral part of our day-to-day activities.

The SURF and Conventional business unit, which represents the majority of the Group's revenue, executes projects which, with the exception of long-term contracts for PLSVs offshore Brazil, are generally contracted on a fixed-price basis. These projects involve the engineering, procurement, installation and commissioning of offshore infrastructure on behalf of clients. Offshore systems can be large, highly complex and technologically rich solutions and the environments in which the Group operates can be harsh and challenging. The costs and margins realised on such projects can vary from the original estimated amounts because of a number of factors and could result in the Group achieving a reduced margin or loss on such projects. The Group assesses the risks involved in fixed-price contracts and uses the terms of the contracts to mitigate certain aspects of these risks. The long-term contracts for PLSVs, executed offshore Brazil, have a less challenging risk profile with services contracted on a day-rate basis.

The i-Tech Services business unit has a lower, less complex risk profile but does involve working and planning around the operations of existing, sometimes ageing, infrastructure, to provide ROV and Life of Field services around the globe. Contracts are typically negotiated on a reimbursable day-rate basis using industry standard contracting terms which offer a balanced risk profile.

The Group's Renewables and Heavy Lifting business is largely undertaken by Seaway Heavy Lifting, a wholly owned subsidiary of the Group. The Group is one of a few operators that can provide engineering, procurement, construction and installation expertise for the execution of offshore renewable energy projects, which are usually contracted on a fixed-price lump sum basis. As well as managing the offshore operational risk, this business unit can be exposed to additional risks including political factors, such as direct local or national government engagement, and increased media attention.

The Group operates in a cyclical industry whose activity is strongly influenced by the current and forecast price of oil and gas as well as the impact following decisions taken by governing petroleum production bodies. The Group's risk management processes assist the Group to respond to changes in activity levels and apply appropriate measures to adjust its cost base as far as practical whilst at the same time ensuring that an acceptable risk profile is maintained.

ROLES AND RESPONSIBILITIES

The Board of Directors has oversight of the Group's risk management activities and internal control processes. The Executive Management Team is responsible for monitoring and managing operational and enterprise risk in pursuit of the Group's business objectives. The Executive Management Team is responsible for designing and implementing appropriate systems and procedures for the identification and management of risks, while ensuring that, within a given risk appetite, the business is able to optimise shareholder value.

The CEO determines the level of risk which can be taken by the business units and by region, country and functional management. This is managed through Group policies and delegated authority levels which provide the means by which risks are reviewed and then escalated to the appropriate management level within the Group up to and including the Board of Directors for review and approval.

PRINCIPAL RISKS AND UNCERTAINTIES

Principal risks are those risks that, given the Group's current position, could materially threaten its business model, future performance, prospects, solvency, liquidity, reputation, or prevent the Group from delivering its strategic objectives.

The means which the Group employs to mitigate or eliminate these risks are set out below.

Additional risks and uncertainties that the Group is unaware of, or that it currently deems immaterial, may in the future have a material adverse effect on the Group's reputation, operations, financial performance and position. However, the Board of Directors believes that the Group's risk management and internal control systems have assisted, and will continue to assist, the Group to identify and respond to such risks.

MARKET RISKS

Strategic

The Group recognises the need to provide certain clients with comprehensive service packages and is committed to offering solutions whereby the Group engages earlier in the engineering and design stage as well as offering vertically integrated solutions in alliance with other companies. Vertical integration of SURF and SPS services is achieved through Subsea Integrated Alliance, the Group's alliance with OneSubsea and other collaborative partnerships. Integrated solutions consolidate risk into one shared contractual framework, meaning that the risk profile to the Group is wider. There is a risk that the Group does not have the knowledge or ability to manage, protect or mitigate the risks associated with vertically integrated solutions that were previously managed by other parties.

The Group, in maintaining its position as a market leader and its commitment to invest in technology and capability, may from time to time engage in strategic mergers and acquisitions. This brings risk in the form of incorrect assessment of market, new and inherited legal and contractual liabilities as well as financial risk. It also carries the risk of failure to integrate the new businesses and their people into the Group and the failure to deliver on its strategic objectives.

Economic

The Group's business depends on the level of activity in the segments of the energy industry in which it operates and, consequently, any significant change in the level, timing or nature of clients' expenditure plans could adversely impact the Group's order intake, financial performance and position.

Our clients' financial strength and the economic viability of their projects can be impacted by fluctuating energy prices which in turn can be driven by political conditions and technological development as well as decisions taken by OPEC and non-OPEC members on production levels.

A rapid increase or decrease in demand for the Group's services could outpace the Group's ability to resize its capacity for service provision.

Competition

The Group faces competition to win contracts needed to assure a sustainable backlog of future work. This competition may result in pricing pressures or a change to a contractor's risk profile, as our competitors strive to win contracts and secure work. This can have an adverse impact on the Group's financial performance and position.

Furthermore, the competitive landscape has reacted to the lower oil price environment in the form of alliances and vertical and horizontal consolidation to achieve economies of scale and wider control of the value chain. Such initiatives could represent a threat to the Group's profile as a specialised offshore service provider.

Risk Mitigation

These risks are mitigated through considered selection of alliance and collaborative partners and pre-identified ways of working. In addition, the Group has a procedure to establish, at tender stage, a risk sharing methodology to complement the project. The Group also continues to maintain disciplined contracting principles to mitigate increased risk.

The Group has internal resources and external advisors to engage in thorough due diligence and also ensures that an experienced project management team is deployed to manage acquisition or merger opportunities. The project team ensures operational management is engaged in the integration process from an early stage after an acquisition or merger to ensure it is successfully executed.

The Group collaborates closely with its clients to understand their future project and expenditure plans. The financial strength and solvency of our clients is a specific area of focus before entering into contracts. The Group has successfully reduced costs and continues to look for ways to improve efficiency and productivity to respond to market demand to optimise costs. It also seeks to diversify selectively into new markets which allow the Group to leverage its resources and competencies, as well as into other geographies requiring its services. In addition, the Group has reviewed, adjusted and continues to adjust its capacity, as necessary, to reflect the current uncertainties in the market, whilst retaining and investing in capability.

Governance

21

The Group endeavours to reduce its exposure to competition by differentiating itself from competitors. The Group's experience and resources, in particular its people, versatile and modern fleet and proprietary technology offerings, help it respond effectively to challenges from competitors. The Group seeks, within the framework of the businesses' contractual risk profile, to support and maintain industry recognised balanced contracting forms.

A further differentiator is the Group's ability and experience in partnering with clients and forming alliances with other oilfield services companies to offer packaged solutions and to contribute to the early development stages of projects, as well as offering cost-effective and efficient technical solutions to its clients.

BUSINESS ENVIRONMENT RISKS

Geographic

The Group operates in several countries worldwide, each with specific political, economic and social characteristics which can give rise to various risks and uncertainties that can adversely impact project execution and financial performance, including but not limited to:

• Economic instability
• Legal, fiscal and regulatory uncertainty and change
• Sanctions and export controls
• Civil or political unrest, including war
• Regime change

Technological innovation

The Group's clients seek cost effective solutions to develop energy resources, particularly in deep waters and challenging offshore environments. This may require the implementation of new technologies. Any failure by the Group to anticipate or respond appropriately to changing technology, market demands and client requirements could adversely affect the Group's ability to compete effectively for, and win, new work.

Similarly, introducing technology which is insufficiently mature or unsatisfactorily implemented or adopted by our clients as a valid solution could also have an adverse impact.

ORGANISATION AND MANAGEMENT RISKS

People

Failure to attract and retain suitably skilled and capable personnel could adversely impact the Group's ability to execute projects and its future growth prospects. Increased competition from other offshore service companies for skilled personnel as the market improves could result in rising employee attrition and create a lack of resources and/or increased compensation costs for the Group.

In addition, there is a risk of failure to integrate business cultures and personnel following business growth through acquisition activities.

Risk Mitigation

Country or regional risks are identified and evaluated before and during Group operations in such markets. Appropriate risk responses are developed and implemented to mitigate the likelihood and impact of identified risks. The Group adopts a proactive and rigorous approach to assessing and mitigating these risks.

The Group monitors industry trends and collaborates with clients to understand their technology requirements.

This allows the Group to effectively invest in developing differentiated and cost effective technologies to meet current and anticipated client demand.

In developing new technologies, the risks associated with selecting and pursuing appropriate technological solutions, technical completion, commercialisation and successful implementation are carefully considered and addressed through 'gate controls' operated by knowledgeable and experienced Subsea 7 personnel.

Risk Mitigation

The Group utilises medium-term business projections to assess resource requirements which allows timely, corrective intervention to appropriately resource the organisation in terms of size, profile, competency mix and location.

The Group monitors attrition by function and geography and has developed appropriate remuneration and incentive packages to help attract and retain key employees.

Performance management and succession planning processes are in place to help develop staff and identify high-potential individuals for key roles in the business.

Integration plans, including training and ongoing communication programmes covering all operational functions and business activities, are adopted at acquisition.

ORGANISATION AND MANAGEMENT RISKS CONTINUED

Compliance and ethics

The Group is committed to conducting business in a legal and ethical manner. However, there is a risk that its employees, representatives or other persons associated with it may take actions that breach the Group's Code of Conduct or applicable laws, including but not limited to anti-bribery and anti-corruption laws, particularly in countries perceived to be at high risk of bribery and corruption. Any such breach could result in monetary penalties, convictions, debarring and damage to the Group's reputation and could therefore impact its ability to do business.

Risk Mitigation

Integrity is one of the Group's core values and the Group also has an Ethics Policy Statement and Code of Conduct, which clearly sets out the behaviours expected of its employees and those who work with it.

The Group has a compliance and ethics programme underpinned by its values and designed in accordance with international best practice to embed the Code of Conduct and to prevent bribery and corruption. The programme includes financial controls, supply chain management procedures, and procedures for managing third party risks. Mandatory annual compliance and ethics e-learning for employees raises awareness, highlights the whole range of consequences and encourages compliance.

A committee comprising members of the Executive Management Team sets objectives for the implementation of the compliance and ethics programme and monitors progress. Regular reports are provided to the Board on matters of significance.

The Group has engaged an independent third party assurance provider to benchmark the compliance and ethics programme against best practice including International Standard ISO 37001.

Information technology, cyber risks and security

The Group's operations depend on the availability and security of a number of key information technology (IT) systems. These systems could be disrupted or compromised by a general IT failure or cyber crime risks including but not limited to:

• Unauthorised system access
• Malware (including computer viruses)
• Theft and misappropriation of data and sensitive information
• Targeted fraud attacks

Such breaches in IT security could adversely impact the Group's ability to maintain ongoing business operations and lead to financial and asset loss, reputational damage, loss of client and shareholder confidence and regulatory fines.

The Group recognises the increased incidence of cyber security threats and continually reviews its policies, procedures and defences to mitigate associated risks, engaging market-leading specialists where appropriate.

The Group has a number of IT policies, including a policy on information security, designed to protect its systems and ensure their availability and integrity as well as combating attempted fraud. These policies are regularly reviewed to ensure they continue to address existing and emerging information security, cyber maritime and cyber crime risks.

Internal e-learning courses are used to raise awareness among employees of IT security risks and of the Group's procedures to manage them.

Furthermore, the Group maintains a programme of regular investment in new hardware, software and systems to ensure the integrity of IT security defences.

DELIVERY AND OPERATIONAL RISKS

Bidding

The Group wins most of its work through a competitive tendering process. A significant proportion of the Group's work is undertaken by way of fixed-price contracts. Failure to understand and respond to operational and contractual risks or accurately estimate project costs could have an adverse impact on the Group's legal liability and financial performance and position.

Risk Mitigation

All bids are subject to the Group's estimating and tendering processes and authority levels. Cost estimates are prepared on the basis of a detailed standard costing analysis, and the selling price and contract terms are based on the Group's commercial contracting standards and market conditions.

Before the tender is submitted, a formal review process is performed. Tenders are first reviewed at a region level where the technical, operational, legal and financial aspects of the proposal are considered in detail. Completion of the region review process requires the formal approval of the appropriate level of management. Dependent on the tender value, there is an escalating level of approval required. Tenders meeting specific financial and risk criteria are reviewed and approved by a Committee of the Board of Directors.

23

DELIVERY AND OPERATIONAL RISKS CONTINUED

Risk	Mitigation
Realisation and renewal of backlog Delays, suspensions, cancellations and scope changes to awarded projects in backlog could materially impact the financial performance and position of the Group in current and future years.	The Group works to mitigate these risks through its contract terms, including, where possible, provision for cancellation fees or early termination payments.
Joint ventures The Group may engage in joint ventures with selected partners to obtain the necessary expertise or local knowledge. A failure by a joint venture partner to perform to the standards required by the joint venture agreement could result in negative financial and reputational impact to the Group. In addition, the failure of a joint venture partner to meet its financial obligations could result in an adverse impact on the Group's financial performance and position.	The Group seeks to ensure that selected joint venture partners not only have the necessary expertise, local knowledge and suitable financial profile but are also able to meet the Group's health, safety, security, environmental and quality standards (HSSEQ) and its Code of Conduct obligations. The Group endeavours to establish appropriate governance and oversight mechanisms to monitor the performance of its joint ventures and joint venture partners in regards to the matters mentioned.
Project execution The Group executes complex projects and a failure to meet contractual requirements could have several adverse consequences, including contract disputes, non-agreed claims and cost overruns, which could adversely impact the Group's financial performance, position and reputation. For most contracts, the offshore execution phase, which generally involves the use of either single or multiple vessels, is usually the most hazardous as this phase is exposed, among other risks, to adverse weather conditions or the risk of loss or damage to the contractor works. These can result in unforeseen delays to the project; damage to vessels and equipment; repair or rework; injury to those working offshore; or increased financial loss associated with delay.	The Group assigns a project management team to every project. Every project is assessed using the Project Monthly Status Report review process. These reviews cover project progress, risk management, cost management, financial performance and sensitivity analysis. Detailed assessments of costs and revenues are estimated and reported upon, taking into account project performance, planning schedules, contract variations, claims, allowances and contingency analysis. The Group factors the risk of adverse weather conditions into the design of its vessels, equipment and procedures and project scheduling, as well as the training of its offshore workforce. It also works to mitigate potential adverse financial consequences when negotiating contractual terms with its clients.
Supply chain Failure of a key supplier could result in disruption to the Group's ability to complete a project in a timely manner. Unexpected increases in supply chain costs could result in higher project costs that impact margin. The resultant time delays or increased costs could lead to irrecoverable costs to the Group and the imposition of financial penalties by clients as well as reputational damage and reduced competitiveness.	The financial profile and outlook of the Group's key suppliers is reviewed during the pre-qualification process for vendors and is considered prior to signing project-related contracts. If necessary, appropriate guarantees or performance-related bonds are requested from our key suppliers. In addition, the Group seeks to develop strong long-term relationships with high-quality and competent suppliers, working to balance costs at a sustainable level and not only engage on a lowest bid basis.
Health, safety, security, environmental and quality The Group's projects are occasionally complex and are sometimes performed in unfamiliar environments in varied conditions. This requires continuous monitoring and management of health, safety,	The Group is focused on continuous HSSEQ performance at all levels and actively motivates, influences and guides employees' individual and collective behaviour. The Group is committed to

security, environmental and quality (HSSEQ) risks associated with the project specification and installation method but also to address the location and assets utilised. A failure to manage these risks could expose our people and those who work with us to injury or harm. It could result in an environmental event or cause injury or damage to other parties. It could result in significant commercial, legal and reputational damage or potential disbarment from the affected country.

protecting the health and safety of its people and those working on its sites and vessels as well as minimising our impact on the environment. The Group has an HSSEQ policy and detailed HSSEQ procedures designed to identify, assess and reduce such risks while ensuring compliance with relevant laws and regulations. The policy and procedures are subject to review, monitoring and certification

by an independent third party, Det Norske Veritas.

DELIVERY AND OPERATIONAL RISKS CONTINUED

Fleet management

The Group has a fleet of vessels which are required for the successful delivery of its projects. These vessels operate in a number of regions which are subject to political, fiscal, legal and regulatory risks. This also includes regulatory requirements around the crewing of the vessels in the territories where they are operating. Failure to manage such risks could lead to an adverse impact to the Group's financial performance and position.

Vessel availability could be negatively impacted by delays to vessel construction, completion of maintenance, vessel upgrading and dry-docking activities.

In extreme circumstances, the non-availability of a vessel or multiple vessels through loss or irreparable damage could compromise the Group's ability to meet its contractual obligations and cause financial loss.

To maintain the competitiveness of the fleet, the Group from time to time makes significant investments in the construction or acquisition of new vessels. If the anticipated demand for those vessels does not materialise, such investments may not generate the intended financial return.

Risk Mitigation

The Group considers carefully the political, fiscal, legal and regulatory risks associated with the deployment of its vessels and crew into regions in which it operates, and monitors developments to ensure it is able to respond appropriately.

Vessel construction, maintenance, upgrading and dry-docking activities are subject to detailed planning and controls are deployed to mitigate the risk of completion delays.

The design and operational capabilities of a vessel are carefully assessed before its deployment to a particular project and are then closely monitored during the project's execution. The impact of potential non-availability of a vessel is mitigated by both the size and flexibility of the Group's fleet and its ability to access the vessel charter market.

Before initiating the construction or acquisition of new vessels, the Group conducts detailed analyses of the potential market and seeks to ensure that the vessels' technical specifications and projected capital and operating costs are appropriate for the anticipated market.

In addition, the Group actively pursues long-term contracts with clients to underpin the investment in new vessels with a view to generating the intended financial returns.

FINANCIAL RISKS

Revenue and margin recognition

Individual period performance may be significantly affected by the timing of contract completion, at which point the final outcome of a project may be fully assessed. Until then, the Group, in common with other companies in the sector, uses the percentage-ofcompletion method of accounting for revenue and margin recognition. This method relies on the Group's ability to estimate future costs in an accurate manner over the remaining life of a project. As projects may take a number of years to execute, this process requires a significant degree of judgement, with changes to estimates or unexpected costs or recoveries potentially resulting in significant fluctuations in revenue and profitability.

Inaccurate forecasting of the costs to complete a project and of the revenues which can be earned from the client for changes to contract scope could have a negative impact on the Group's management of its liquidity and weaken its financial position.

As a result of the recent challenging business environment, some projects have been won at very low or negative margins. As these projects progress there may be more volatility in the accounting for project performance as forecast losses on loss-making projects are recognised in full as soon as they are identified.

Cash flow and liquidity

The Group's working capital position will be affected by the timing of contract cash flows where the timing of receipts from clients, typically based on completion of milestones, may not necessarily match the timing of payments the Group makes to its suppliers. In executing some of its contracts the Group is often required by its clients in the normal course of business to issue performance-related bonds and guarantees. Access to credit from financial institutions in support of these instruments is fundamental to the Group's ability to compete, particularly for large EPIC contracts.

The availability of short-term and long-term external financing is required to help meet the Group's financial obligations as they fall due. In the event that such financing were to be unavailable or withdrawn, the Group's activities would be significantly constrained.

Risk Mitigation

Project performance is monitored by means of Project Monthly Status Reports (PMSRs) which record actual costs of work performed, the estimated cost to complete a project and the estimated full-life project revenue. The PMSR allows management to reliably estimate the likely outcome in terms of profitability of each project. These PMSRs are subject to rigorous review and challenge at all key levels of management within the Group. Note 4 "Critical accounting judgements and key sources of estimation uncertainty" to the consolidated financial statements provides more detail of the Group's approach to revenue recognition on long-term contracts.

The Group seeks, through committed banking facilities, to meet its working capital needs and to finance the acquisition or construction of new assets. The Group's cash position, access to liquidity and debt leverage are monitored closely by both the Executive Management Team and the Board of Directors.

25

INTERNAL CONTROL

The Board of Directors is responsible for oversight of the Group's system of internal controls and for reviewing its effectiveness. The Board of Directors recognises that any system of internal controls can only provide reasonable and not absolute assurance that material financial misstatement and/or fraud will be detected or that the risk of failure to achieve business objectives is eliminated.

The Group's systems of internal controls operate through a number of processes. The more significant include:

• Delegated authority level matrices with certain matters being reserved by the Board of Directors
• Annual review of the strategy, plans and budgets of individual business units to identify the key risks to the achievement of the Group's objectives
• Monthly financial and operational performance reviews against budget
• Individual tender and contract reviews at various levels throughout the Group
• Capital expenditure and investment reviews and authorisation
• Regular reviews and reporting on the effectiveness of the Group's health, safety, security, environmental and quality (HSSEQ) processes
• Group Treasury policies
• Group Taxation compliance and reporting policies and systems
• The Group's whistleblowing policy, which allows individuals to raise concerns in confidence about potential breaches of the Code of Conduct
• Quarterly reporting to the Executive Management from the Global Applications and Systems Steering Committee (GASSC) on the integrity and security of our business and IT systems including cyber risk.

The Group's internal audit function, which reports directly to the Audit Committee, performs independent reviews of key business financial processes and controls and other areas considered to be of high business risk. The Audit Committee annually reviews and approves the internal audit plan and receives regular updates on internal audit's findings and the actions taken by management to address them.

Governance overview

"Good corporate governance breeds long-term value creation."

Sir Peter Mason

Chairman of the Corporate Governance and Nominations Committee

Senior Independent Director

At Subsea 7, our attitude towards corporate governance goes beyond pure compliance. We believe high quality governance is essential for long-term value creation for the benefit of all shareholders, employees, creditors and other Subsea 7 stakeholders. This is why we have worked hard in recent years to ensure our corporate governance procedures reflect the high standards our stakeholders expect of us.

During the year the Company has been active in improving corporate governance procedures. Below is a snapshot of activities undertaken during 2017 which emphasise the Company's commitment to improving its already high standard of corporate governance:

• The Articles of Incorporation of Subsea 7 S.A. were amended in April 2017 in response to an update in the Luxembourg Company Law.

• The Group views compliance and ethics as an essential element of good corporate governance. To improve efficiency and communication between Board Sub-Committees, the Board again organised a joint session of the Audit Committee and the Corporate Governance and Nominations Committee to discuss the Group's compliance and ethics programme, as well as other issues affecting both Committees. During the year, the Group conducted a review of its subsidiary companies located in jurisdictions associated with tax evasion. The Group does not engage in tax evasion but, where practical, is reducing exposure in jurisdictions that have been associated with tax evasion and aggressive tax avoidance, to reduce any perception of such behaviour. The Group also released its inaugural Slavery and Human Trafficking Statement as required by the UK Modern Slavery Act 2015. The Group continues to monitor developments in the legislative landscape to ensure the Group remains compliant.
• The acquisitions of the remaining 50% of Seaway Heavy Lifting, and certain businesses of EMAS Chiyoda Subsea, illustrate the Board and managements' ability to quickly and effectively take advantage of growth opportunities within the market. Management has worked hard to integrate these businesses into the Subsea 7 Group which, amongst other things, has involved adopting, and providing education and training in relation to, Group policies and procedures.

As illustrated above, governance is not just a matter for the Board. Corporate governance structures and principles distribute rights and responsibilities among directors, managers, employees, shareholders, and other stakeholders. We are proud of the work we have done on corporate governance and we will continue to build upon and improve our governance structures to run our business for the benefit of all stakeholders.

GOVERNANCE AT A GLANCE

The areas listed below, on which we report on the pages indicated, are aligned with the Norwegian Code of Practice for Corporate Governance.

• Implementation and reporting on corporate governance (see page 36).
• Business (see page 32).
• Equity and dividends (see page 36).
• Equal treatment of shareholders and transactions with close associates (see page 37).
• Freely negotiable shares (see page 37).
• General meetings (see page 36).
• Nominations Committee (see page 38).
• Corporate assembly and Board of Directors (see page 33).
• The work of the Board of Directors (see page 34).
• Risk management and internal control (see page 35).
• Remuneration of the Board of Directors (see page 39).
• Remuneration of executive personnel (see page 39).
• Information and communications (see page 41).
• Take-overs (see page 41).
• Auditor (see page 40).

Board of Directors

Kristian Siem

	Chairman	Senior Independent Director*	Director and Chief Executive Officer
Skills and experience	Mr Siem brings an extensive knowledge of the offshore oil and gas services business worldwide from previous senior executive and non-executive roles combined with long-standing experience as chairman of public companies listed in Norway. Mr Siem is the founder of the Siem Industries Group and has been Director and Chairman of Siem Industries since 1982. Prior to joining the Group, he held several management positions with the Fred. Olsen Group in the US and Norway. Mr Siem has previously held directorships at Kvaerner ASA and Transocean Inc. He holds a degree in Business Economics.	Sir Peter, in addition to his engineering expertise, has extensive prior experience in the onshore and offshore international engineering and construction industry both as a chief executive and as a senior non-executive director. He served as Chief Executive of AMEC from 1996 until September 2006. Prior management positions include Executive Director of BICC plc and Chairman and Chief Executive of Balfour Beatty. He was Non Executive Director of BAE Systems plc from January 2003 until May 2013. He is a Fellow of the Institution of Civil Engineers and a Fellow of the Royal Academy of Engineering, and holds a Bachelor of Science degree in Engineering.	Mr Cahuzac has wide multi-country technical, commercial and general management experience in senior executive roles in the oil and gas services sector spanning a period of 35 years. He worked at Transocean in Houston, USA, from 2000 until April 2008 where he held the positions of Chief Operating Officer and then President. Prior to this, he worked at Schlumberger from 1979 to 2000 where he served in various positions. He holds a Master's degree in Engineering from École des Mines de St-Étienne and is a graduate of the French Petroleum Institute in Paris.
Date of appointment	Appointed Director and Chairman from January 2011. Prior to the merger of Acergy S.A. and Subsea 7 Inc. in January 2011 Mr Siem was Chairman of Subsea 7 Inc. from January 2002.	Appointed a Director from October 2006 (then named Acergy S.A.) and Senior Independent Director from January 2011. Prior to being Senior Independent Director he was Chairman from May 2009 until the merger of Acergy S.A. and Subsea 7 Inc. in January 2011.	Appointed a Director from May 2008 (then named Acergy S.A.) and has held the position of Chief Executive Officer since April 2008.
Committee membership	C G	G	None
Key external appointments	Chairman of Siem Industries Inc. and Siem Capital AB. Director of Siem Offshore Inc.,	Non-Executive Director of Spie S.A. since 2011. Chairman of AGS Airport Limited	None
	Siem Shipping Inc. (formerly Star Reefers Inc.), Flensburger Schiffbau Gesellschaft mbH & Co. KG, North Atlantic Smaller Companies Investment Trust plc and Frupor S.A.	since December 2014.
Nationality and date of birth	1949	1946	1954
Tenure	Re-elected by shareholders on 12 April 2017 and expiring at the 2019 AGM.	Re-elected by shareholders on 14 April 2016 and expiring at the 2018 AGM.	Re-elected by shareholders on 14 April 2016 and expiring at the 2018 AGM.

Sir Peter Mason KBE

Jean Cahuzac

Committee key

• Chairman
• Compensation Committee Corporate Governance and G C
• Nominations Committee
• Audit Committee A

Eystein Eriksrud Director

Mr Eriksrud brings to his role extensive legal expertise in commercial and corporate affairs combined with senior executive experience in the offshore energy and shipping industries. He was previously a partner of Norwegian law firm Wiersholm Mellbye & Bech, from 2005 to 2011. He joined Siem Industries in October 2011 and is currently Deputy Chief Executive Officer of the Siem Industries Group and holds a number of Directorships within the Siem Industries Group. He is a Candidate of Jurisprudence from the University of Oslo.

Dod Fraser Independent Director*

Mr Fraser brings comprehensive experience in corporate finance and investment banking both internationally and in the United States. This is supplemented by extensive knowledge of corporate governance in his current and prior appointments as audit committee member. Mr Fraser served as a Managing Director and Group Executive with Chase Manhattan Bank, now JP Morgan Chase, leading the global oil and gas group from 1995 until 2000. Until 1995 he was a General Partner of Lazard Frères & Co. Mr Fraser has been a trustee of Resources for the Future, a Washington-based environmental policy think-tank. He is a graduate of Princeton University.

Robert Long Independent Director*

Mr Long brings a wealth of financial and operational expertise specific to the oil and gas sector. Mr Long has held various financial and executive roles in the offshore drilling industry culminating in that of Chief Executive Officer and Director of Transocean Ltd from 2002 to 2010, the largest international drilling contractor listed on the New York Stock Exchange. Prior to this Mr Long served as President of Transocean from 2001 to 2006, Chief Financial Officer from 1996 to 2001 and Senior VP from 1990 until the merger with Sedco Forex in 2000, at which time he assumed the position of Executive VP. Mr Long is a graduate of the U.S. Naval Academy and Harvard Business School.

Allen Stevens

Independent Director*

Mr Stevens brings to the role many years of experience in shipping, finance and management. Mr Stevens started in the shipping industry in financial planning at Sea-Land Service Inc., and subsequently served as Treasurer of McLean Industries Inc. from 1972 to 1988. Mr Stevens served as a Chairman and Director of Erie Shipbuilding from 2006 to 2009, and Chairman of Trailer Bridge Inc. from 2008 until 2012. He has also held senior executive and management positions with Great Lakes Transport Limited. He is a graduate of Harvard Law School and holds a degree in Industrial Engineering from the University of Michigan.

Appointed a Non-Executive Director from March 2012.

Deputy Chief Executive Officer

Appointed a Non-Executive Independent Director from December 2009 (then named Acergy S.A.).

Director of Rayonier Inc.

Appointed a Non-Executive Independent Director from January 2011.

Appointed a Non-Executive
Independent Director from
January 2011.

Prior to the merger of Acergy S.A. and Subsea 7 Inc. in January 2011 Mr Stevens was Independent Director of Subsea 7 Inc. from December 2005.

None Vice President and director of Masterworks Development

* As used above, 'independent' is defined by the rules and codes of corporate governance of the Oslo Børs on which Subsea 7 S.A. is listed, which the Board must satisfy, in particular the Norwegian Code of Practice for Corporate Governance. Under the terms of the Company's Articles of Incorporation, Directors may be elected for terms of up to two years and serve until their successors are elected. Under the Company's Articles of Incorporation, the Board must consist of not fewer than three Directors

Governance

Executive Management Team

	Jean Cahuzac Chief Executive Officer	John Evans Chief Operating Officer	Nathalie Louys General Counsel
Skills and experience	Jean's full biography is included under Board of Directors on page 28.	John started his career in the oil and gas engineering and contracting sector in 1986, working with Kellogg Brown & Root (KBR).	Nathalie began her legal career in 1986, working with Saint-Gobain and Eurotunnel, gaining extensive legal experience across a number
		During 18 years with KBR he gained a successful record in general management, commercial and operational roles in the offshore	of industries. In 1996 she joined Technip, based in Paris, progressing to the role of Vice President Legal – Offshore.
		oil and gas industry. Prior to joining Subsea 7, between 2002 and mid-2005 John was Chief Operating Officer for KBR's Defence and Infrastructure business in Europe and Africa. John has a Bachelor of	In 2006 Nathalie joined Subsea 7 and subsequently worked in a number of senior corporate and operational legal roles. Prior to her current appointment Nathalie was Vice President Legal – Commercial.
		Engineering degree in Mechanical Engineering from Cardiff University, is a Chartered Mechanical and Marine Engineer and a Chartered Director.	Nathalie has been admitted to the Paris Bar and has legal qualifications from University Paris I – Panthéon Sorbonne and Paris XI in France and the University of Kent in the UK.
Date of appointment	Jean has been Chief Executive Officer of Subsea 7 since April 2008 and became an Executive member of the Board of Subsea 7 S.A. in May 2008.	John has been Chief Operating Officer of Subsea 7 since July 2005.	Nathalie has been General Counsel of Subsea 7 since April 2012.
Nationality and date of birth	1954	1963	1963

Stuart Fitzgerald

Executive Vice President Strategy and Commercial

Stuart began his career with a specialist marine engineering consultancy, progressing to Worley Engineering in Australia and Brunei.

Stuart began his career with Subsea 7 in 1998. In 2007 Stuart was appointed as head of Sales and Marketing for Norway and Denmark, and in 2009 became Vice President for Norway. In 2014 he was appointed Vice President Sales and Marketing for the Northern Hemisphere and Life of Field business. In June 2016 Stuart was appointed Vice President Strategy and Technology for the Group which he held until his current appointment.

Stuart has a Bachelor of Engineering degree in Mechanical Engineering and a Bachelor of Science degree in Applied Mathematics from Monash University in Melbourne, Australia.

Ricardo Rosa

Chief Financial Officer

Ricardo started his career in 1977 with Price Waterhouse in London and transferred in 1981 to Rio de Janeiro. In 1983 he joined Schlumberger where he held various financial positions within the Schlumberger Group, working in Paris, Jakarta, Rio de Janeiro, Caracas, Milan and London. In 2000 he joined Transocean as Vice President and Controller in Houston, subsequently becoming Senior Vice President for Asia Pacific and Middle East in Singapore and then for Europe and Africa, in Paris. Prior to joining Subsea 7, he was Transocean's Executive Vice President and CFO. Ricardo holds an MA in Modern Languages from Oxford University and is a member of the Institute of Chartered Accountants in England and Wales.

Keith Tipson

Executive Vice President – Human Resources

Keith began his career in the engineering and construction project sectors in 1980, working with the Dowty Group. In 1988 he moved to Alstom where he held a number of roles based in Belgium, France, Switzerland and the UK, including the positions of Human Resources Director for the Industrial Equipment Division, the International Network and the Steam and Hydro segments of the ABB Alstom Power joint venture. Prior to joining Subsea 7 he held the position of Senior Vice President Human Resources, Power Sector, based in Paris. Keith has a business degree from the University of West London.

Stuart was appointed Executive Vice President Strategy and Commercial in January 2018.

Ricardo has been Chief Financial Officer of Subsea 7 since July 2012. Keith has been Executive Vice President – Human Resources of Subsea 7 since November 2003.

Note

Roles in Subsea 7 are referred to here as the amalgamation of respective roles in the legacy entities i.e. Acergy S.A. and Subsea 7 Inc. including roles prior to or after the Combination of the two businesses in January 2011.

31

2017 Corporate Governance Report Regulatory compliance

This section sets out the arrangements the Board has put in place to help ensure that it fulfils its corporate governance obligations, including the application of the principles of the Norwegian Code of Practice for Corporate Governance.

LEGAL AND REGULATORY FRAMEWORK

Subsea 7 S.A. is a 'société anonyme' organised in the Grand Duchy of Luxembourg under the Company Law of 1915, as amended, being incorporated in Luxembourg in 1993, and acts as the holding company for all of the Group's entities.

Subsea 7 S.A.'s registered office is located at 412F, route d'Esch, L-2086 Luxembourg. The Company is registered with the Luxembourg Register of Commerce and Companies under the designation 'R.C.S. Luxembourg B 43172'. As a company incorporated in Luxembourg and with shares traded on the Oslo Børs and ADRs traded over-thecounter in the US, Subsea 7 S.A. is subject to Luxembourg laws and regulations with respect to corporate governance.

As a company listed on the Oslo Børs, where its shares are actively traded, the Company follows the Norwegian Code of Practice for Corporate Governance on a 'comply or explain' basis, where this does not contradict Luxembourg laws and regulations. The Norwegian Code of Practice for Corporate Governance is available at http://www.nues.no/en/.

The Group's corporate governance policies and procedures are explained below, with reference to the principles of corporate governance as set out in the sections identified in the Norwegian Code of Practice for Corporate Governance dated 30 October 2014.

ARTICLES OF INCORPORATION – NATURE OF THE GROUP'S BUSINESS

As stated in its Articles of Incorporation, Subsea 7 S.A.'s business activities are as follows:

"The objects of the Company are to invest in subsidiaries which predominantly will provide subsea construction, maintenance, inspection, survey and engineering services, in particular for the offshore oil and gas and related industries. The Company may further itself provide such subsea construction, maintenance, inspection, survey and engineering services, and services ancillary to such services.

The Company may, without restriction, carry out any and all acts and do any and all things that are not prohibited by law in connection with its corporate objects and to do such things in any part of the world whether as principal, agent, contractor or otherwise. More generally, the Company may participate in any manner in all commercial, industrial, financial and other enterprises of Luxembourg or foreign nationality through the acquisition by participation, subscription, purchase, option or by any other means of all shares, stocks, debentures, bonds or securities; the acquisition of patents and licences which it will administer and exploit; it may lend or borrow with or without security, provided that any monies so borrowed may only be used for the purposes of the Company, or companies which are subsidiaries of or associated with or affiliated to the Company; in general it may undertake any operations directly or indirectly connected with these objects."

The full text of the Company's Articles of Incorporation, as amended, is available on Subsea 7's website: www.subsea7.com.

BUSINESS

The Board of Directors has set strategies and targets for the Company's business.

The Group provides all the products and services required for subsea field development, including project management, design and engineering, procurement, fabrication, survey, installation and commissioning of production facilities on the seabed and the tie-back of these facilities to fixed or floating platforms or to the shore.

Through its i-Tech Services business unit, the Group offers the full spectrum of products and capabilities to deliver Life of Field services to its clients and provides ROVs and intervention tooling services to support exploration, production and drilling activities.

The Group also provides services in offshore wind farm installations, heavy lifting and decommissioning services, utilising the capability of Seaway Heavy Lifting, a wholly owned subsidiary of Subsea 7.

Further details of the Group's business are outlined in the 'Overview' and 'Strategy' sections on pages 2 to 19.

BOARD OF DIRECTORS

KRISTIAN SIEM

Chairman

SIR PETER MASON KBE

Senior Independent Director

JEAN CAHUZAC

Director

33

EYSTEIN ERIKSRUD

Director

DOD FRASER

Independent Director

ROBERT LONG

Independent Director

ALLEN STEVENS

Independent Director

CORPORATE ASSEMBLY AND BOARD OF DIRECTORS: COMPOSITION AND INDEPENDENCE

As a Luxembourg incorporated entity, the Company does not have a corporate assembly.

The Board of Directors comprises seven Directors. The majority of the Directors were, during the financial year 2017, considered independent in accordance with the rules of the Oslo Børs on which Subsea 7 S.A. is listed and the independence criteria of the Norwegian Code of Practice for Corporate Governance.

Biographies of the individual Directors are detailed on pages 28 to 29.

Mr Cahuzac, the Chief Executive Officer (CEO), was first appointed to the Board of Directors in May 2008. The Board of Directors operates controls to ensure that no conflicts of interest exist with respect to his position on the Board of Directors. The charters of the permanent committees do not permit executive management to be members. Accordingly, Mr Cahuzac does not sit on any of the committees. The composition of the Company's Board of Directors and the controls to avoid conflicts of interest are in accordance with both Luxembourg company law and good corporate governance practice.

The Board of Directors endeavours to ensure that it is constituted by Directors with a varied background and with the necessary expertise, diversity and capacity to ensure that it can effectively function as a cohesive body. Prior to proposing candidates to the relevant general meeting for election to the Board of Directors, the Corporate Governance and Nominations Committee seeks to consult with the Company's major shareholders before recommending candidates to the Board of Directors.

Directors are elected by a general meeting for a term not exceeding two years and may be re-elected. Directors need not be shareholders. At a general meeting the shareholders may dismiss any Director, with or without cause, at any time notwithstanding any agreement between the Company and the Director. Such dismissal may not prejudice the claims that a Director may have for indemnification as provided for in the Articles of Incorporation or for a breach of any contract existing between him or her and the Company.

If there is a vacancy on the Board of Directors, the remaining Directors appointed at a general meeting have the right to appoint a replacement Director until the next meeting of shareholders who will be asked to confirm such appointment.

With the exception of a candidate recommended by the Board of Directors, or a Director whose term of office expires at a general meeting of the Company, no candidate may be appointed unless at least three days and no more than 22 days before the date of the relevant meeting, a written proposal, signed by a duly authorised shareholder, shall have been deposited at the registered office of the Company together with a written declaration, signed by the proposed candidate, confirming his or her wish to be appointed.

The Directors of the Board are encouraged to hold shares in the Company as the Board of Directors believes it promotes a common financial interest between the members of the Board of Directors and the shareholders of the Company. Details of the Directors' shareholdings are on page 108.

Work of the Board of Directors

The Board of Directors adheres to a Board Charter which sets out the instructions for the Board.

The Board of Directors' main responsibilities are:

• 1. Setting the values used to guide the affairs of the Group. This includes the Group's commitment to achieving its health and safety vision and the Group's adherence to the highest ethical standards in all of its operations worldwide.
• 1. Integrating environmental improvement into business plans and strategies, and seeking to embed sustainability into the Group's business processes.
• 1. Overseeing the Group's compliance with its statutory and regulatory obligations and ensuring that systems and processes are in place to enable these obligations to be met.
• 1. Setting the strategy and targets of the Group.
• 1. Establishing and maintaining an effective corporate structure for the Group.
• 1. Overseeing the Group's compliance with financial reporting and disclosure obligations.
• 1. Overseeing the risk management of the Group.
• 1. Overseeing Group communications.
• 1. Determining its own composition, subject to the provisions of the Company's Articles of Incorporation.
• 1. Ensuring the effective corporate governance of the Group.
• 1. Approving the remuneration package for the CEO based upon the recommendation of the Compensation Committee.
• 1. Setting and approving policies.

The Board of Directors' Charter is available on the Subsea 7 website: www.subsea7.com

2017 MEETING ATTENDANCE

		Corporate Governance and
	Board	Audit Committee(a)	Nominations Committee(a)	Compensation Committee
Kristian Siem	7/7		3/3	4/4
Sir Peter Mason
KBE	7/7		3/3
Jean Cahuzac	7/7
Dod Fraser	7/7	6/6
Robert Long	7/7	6/6		4/4
Allen Stevens	7/7		3/3	4/4
Eystein Eriksrud	7/7	6/6

(a) Additionally, a joint session of the Audit Committee and the Corporate Governance and Nominations Committee was held on 28 February 2017 at which all members of both committees were present.

RESPONSIBILITIES DURING THE YEAR

During the year, the Board of Directors sets a plan for its work for the following year, which includes a review of strategy, objectives and their implementation, the review and approval of the annual budget and the review and monitoring of the Group's current year financial performance. In 2018, the Board of Directors is scheduled to convene on seven occasions, but the schedule is flexible to react to operational or strategic changes in the market and Group circumstances.

The Board of Directors has overall responsibility for the management of the Group and has delegated the daily management and operations of the Group to the CEO, who is appointed by and serves at the discretion of the Board of Directors. The CEO is supported by the other members of the Executive Management Team, further details of which are on page 30. The Executive Management Team has the collective duty to deliver Subsea 7's strategic, financial and other objectives, as well as to safeguard the Group's assets, organisation and reputation. The Board of Directors has internal regulations for its own operation and approves objectives for its own work, as well as the work of the Executive Management Team, with particular emphasis on clear internal allocation of responsibility and duties.

It is the duty of the Executive Management Team to provide the Board of Directors with appropriate, precise and timely information on the operations and financial performance of the Group, in order for the Board of Directors to perform its duties. The Board of Directors has established a Corporate Governance and Nominations Committee, a Compensation Committee and an Audit Committee, each of which has a charter approved by the Board of Directors. Matters are delegated to the committees as appropriate. The Directors appointed to these committees are selected based on their experience and to ensure the committees operate in an effective manner. The minutes of all committee meetings are circulated to all Directors.

The performance and expertise of the Board of Directors are monitored and reviewed annually, including an evaluation of the composition of the Board of Directors and the manner in which its members function, both individually and as a collegiate body. The evaluation of the performance of the Board of Directors during the 2017 year was conducted by an external company and the results of the evaluation were shared with the Corporate Governance and Nominations Committee. In line with best practice, the evaluation of the performance of the Board of Directors is conducted by an external facilitator every third year. The next external review is due at the end of 2020.

RISK MANAGEMENT AND INTERNAL CONTROL

The Board of Directors acknowledges its responsibility for the Group's system of internal control and for reviewing its effectiveness. The Group's system of internal control is designed to manage, rather than eliminate, the risk of failure to achieve business objectives and can only provide reasonable but not absolute assurance against material financial misstatement or loss.

The Group adopts internal controls appropriate to its business activities and geographical spread. The key components of the Group's system of internal control are described in the Risk Management section on pages 20 to 26. The Group has in place clearly defined lines of responsibility and limits of delegated authority. Comprehensive procedures provide for the appraisal, approval, control and review of capital expenditure. The Executive Management Team meets with other senior management on a regular basis to discuss particular issues, including key operational and commercial risks, health and safety performance, and legal and financial matters.

The Group has a comprehensive annual planning and management reporting process. A detailed annual budget is prepared in advance of each year and supplemented by forecasts updated during the course of the year. Financial results are reported monthly to the Executive Management Team and quarterly to the Board of Directors and compared to budget, forecasts, market consensus and prior year results.

The Board of Directors reviews reports on actual financial performance and forward-looking financial guidance.

The Board of Directors derives further assurances from the reports of the Audit Committee. The Audit Committee has been delegated responsibility to review the effectiveness of the internal financial control systems implemented by management and is assisted by the internal audit function and the external auditor where appropriate.

35

Communication with stakeholders

IMPLEMENTATION AND REPORTING ON CORPORATE GOVERNANCE

Subsea 7 S.A. acknowledges the division of roles between shareholders, the Board of Directors and the Executive Management Team. The Group further ensures good governance is adopted by holding regular Board of Directors' meetings, which the Executive Management Team attends and at which strategic, operational and financial matters are presented.

The Group's vision is:

To be acknowledged by our clients, our people and our shareholders as the leading strategic partner in seabed-to-surface engineering, construction and services.

The Group's Values focus on: Safety, Integrity, Innovation, Performance and Collaboration.

In pursuit of the five Values, the Group has an Ethics Policy Statement and a Code of Conduct which reflect its commitment to clients, shareholders, employees and other stakeholders to conduct business legally and with integrity and honesty. The Ethics Policy Statement and the Code of Conduct were approved by the Board of Directors and were issued to all Directors, officers and employees and are subject to periodic review and updating.

GENERAL MEETINGS

The Articles of Incorporation provide that the Annual General Meeting (AGM) shall be held within six months from the end of the financial year and this year it will be held on 17 April. The notice of meeting and agenda documents for the AGM are posted on the Group's website at least 21 days prior to the meeting and shareholders receive the information at least 21 days prior to the meeting by mail. Documentation from previous AGMs is available on the Subsea 7 website: www.subsea7.com.

All shareholders that are registered with the Norwegian Central Securities Depository System receive a written notice of the AGM. The Company will set a record date as close as practicable to the date of the AGM, taking into account the differing deadlines for ADR and common share proxies. Subject to the procedures described in the Articles of Incorporation, all shareholders holding individually or collectively at least 10% of the issued shares have the right to submit proposals or draft resolutions. All shareholders on the register as at the record date will be eligible to attend in person, or vote by proxy, at the AGM.

Proxy forms are available and may be submitted by eligible shareholders which allow separate voting instructions to be given for each proposed resolution to one of the representatives indicated on the proxy form and also allow a person to be nominated to vote on behalf of shareholders as their proxy. There will be a separate vote for each candidate nominated for election to the Board of Directors. Details will be provided in the resolutions and supporting information distributed to the shareholders ahead of the AGM.

Under Luxembourg law, there are minimum quorum requirements for EGMs but no minimum quorum requirement for AGMs. Decisions will be validly made at the AGM regardless of the number of shares represented if approval is obtained from the majority of the votes of those shareholders that are present or represented.

The Articles of Incorporation of the Company stipulate that the AGM will be chaired by the Chairman of the Board of Directors. However, the Board of Directors ordinarily delegates authority to the Company Secretary to chair the AGM. If a majority of the shareholders request an alternative independent chairman, one will be appointed.

At the AGM, the shareholders, inter alia, elect members of the Board of Directors for nominated terms of appointment, approve the Company's Annual Accounts, the Group's Annual Report and Consolidated Financial Statements, discharge the Directors from their duties for the financial year and approve the statutory auditor's appointment. In accordance with Luxembourg law and the Company's Articles of Incorporation the Chairman of the Board is elected by the Board of Directors based on their insight into who has the most suitable level of understanding of the Company to carry out the duties of the Chairman.

EQUITY AND DIVIDENDS

Shareholders' equity

Total shareholders' equity at 31 December 2017 was \$5.89 billion (2016: \$5.58 billion) which the Board of Directors believes is satisfactory given the Group's strategy, objectives and risk profile.

Dividend policy

It is Subsea 7's objective to give its shareholders a competitive return on their invested capital. The return is to be achieved through a combination of dividend payments, share repurchases and an increase in the value of the Company's shares over time through disciplined investment in value-adding growth opportunities. The Board of Directors each year, after evaluating the Company's financial position and re-investment opportunities, may decide to recommend that shareholders approve at the AGM an appropriate dividend. This dividend will normally be paid in the month following its approval at the AGM.

Equity mandates

At the extraordinary general meeting held on 27 November 2014, the Board of Directors' authority to approve the purchase of the Company's shares up to a maximum of 33,216,706 common shares (representing 10% of the issued common shares following the cancellation of 19,626,664 common shares authorised at the 27 November 2014 extraordinary general meeting), was granted until 26 November 2019. This authority is subject to certain purchase price conditions and is conditional on such purchases being made in open market transactions through the Oslo Børs, subject to certain limitations. The Board of Directors was also granted authority for a period ending on 26 May 2020 to cancel shares repurchased under such authorisation and to reduce the issued share capital through such cancellations.

An extraordinary general meeting was held on 17 April 2015 at which the Company's shareholders approved the restatement of the authorised share capital at \$900,000,000 with any authorised but unissued common shares lapsing on 4 June 2018. Additionally, the Board of Directors was authorised to issue new shares within the authorised unissued share capital. The Board of Directors was authorised to waive, suppress or limit existing shareholders' preferential subscription rights up to a maximum of 33,216,706 common shares (representing 10% of the issued common shares as at 17 April 2015). These authorisations were granted for a period of three years, expiring on 4 June 2018, to reduce inter alia the administrative burden of convening an extraordinary general meeting annually. An extraordinary general meeting will be held on 17 April of this year at which it will be proposed that the shareholders approve the renewal of these authorities.

EQUAL TREATMENT OF SHAREHOLDERS AND TRANSACTIONS WITH CLOSE ASSOCIATES

One class of shares

The Company has one class of shares which are listed on the Oslo Børs. Each share carries equal rights including an equal voting right at annual or extraordinary general meetings of shareholders of the Company. No shares carry any special control rights. The Articles of Incorporation contain no restrictions on voting rights.

Share issues

The Board of Directors is authorised to suppress the pre-emptive rights of shareholders under certain circumstances and within the limits set forth previously. This is to allow flexibility to deal with matters deemed to be in the best interest of the Company.

In the event of the Board of Directors resolving to issue new shares and waive the pre-emptive rights of existing shareholders, the Board of Directors intends to comply with the recommendation of the Norwegian Code of Practice for Corporate Governance that the justification for such waiver is noted in the Stock Exchange announcement relating to such a share issue.

Related party transactions

Any transactions between the Group and members of the Board of Directors, executive management or close associates are detailed in Note 34 'Related party transactions' to the Consolidated Financial Statements.

The Board of Directors will, from time to time, determine the necessity of obtaining third-party valuations on transactions with related parties. Under Luxembourg law, Directors may not vote on transactions in which they are directly or indirectly financially interested.

The Group's Code of Conduct requires any Director or employee to declare if they hold any direct or indirect financial interest in any transaction entered into by the Group.

FREELY NEGOTIABLE SHARES

Subsea 7 S.A.'s shares are traded as common shares on the Oslo Børs and as ADRs over-the-counter in the US.

All shares are freely negotiable. The Articles of Incorporation contain no form of restriction on the negotiability of shares in the Company.

CORPORATE GOVERNANCE AND NOMINATIONS COMMITTEE Committee members

Sir Peter Mason KBE

Committee Chairman

Kristian Siem

Allen Stevens

The Corporate Governance and Nominations Committee's main responsibilities are:

• 1. Actively seeking and evaluating individuals qualified to become Directors of the Company and nominating candidates to the Board of Directors.
• 1. Periodically reviewing the composition and duties of the Company's permanent committees and recommending any changes to the Board of Directors.
• 1. Periodically reviewing the compensation of Directors and making any recommendations to the Board of Directors.
• 1. Annually reviewing the duties and performance of the Chairman of the Board and recommending to the Board of Directors a Director for election by the Board of Directors to the position of Chairman of the Board.
• 1. Annually reviewing the Company's Corporate Governance Guidelines, procedures and policies for the Board of Directors and recommending to the Board of Directors any changes and/or additions thereto that they believe are desirable and/or required.

The Board of Directors has established a Corporate Governance and Nominations Committee. The composition of this Committee is for the Board of Directors to determine in accordance with the Company's Articles of Incorporation. The Board of Directors believes that the Committee, comprising certain members of the Board of Directors, the majority of whom are independent of the Company's main shareholders, has the most suitable level of understanding of the Company to carry out the duties of the Committee.

These governance guidelines include the following:

• How the Board of Directors is selected and compensated (for example, the size of the Board, Directors' compensation, qualifications independence, retirement and conflicts of interests).
• How the Board of Directors functions (for example, procedures for Board meetings, agendas, committee structure and format and distribution of Board materials).
• How the Board of Directors interacts with shareholders and management (for example, selection and evaluation of the CEO, succession planning, communications with shareholders and access to management).
• 1. Overseeing the annual evaluation of the Board of Directors' performance.
• 1. Overseeing all aspects of Subsea 7's compliance and ethics programme. This will include a regular review of the structure of the compliance function, the scope of its activities and the effective implementation of the programme (including procedures for employees to raise concerns about breaches of the Code of Conduct and for such concerns to be investigated and remediated).
• 1. Annually reviewing the Committee's own performance.

The Corporate Governance and Nominations Committee Charter is available on the Subsea 7 website: www.subsea7.com.

COMPENSATION COMMITTEE

Committee members

Kristian Siem Committee Chairman

Robert Long

Allen Stevens

The Compensation Committee's main responsibilities are:

• 1. Reviewing annually and approving the compensation paid to executive officers of the Company with the exception of the CEO where the Compensation Committee may make a recommendation to the Board of Directors.
• 1. Establishing annually performance objectives for the Company's CEO and annually reviewing the CEO's performance against objectives and setting the CEO's compensation based on its evaluation.
• 1. Overseeing the Company's Benefit Plans in accordance with the objectives of the Company established by the Board of Directors.
• 1. Reviewing executive compensation plans and making recommendations to the Board of Directors on the adoption of new plans or programmes.
• 1. Recommending to the Board of Directors the terms of any contractual agreements and any other similar arrangements that may be entered into with executive officers of the Company and of its subsidiaries.
• 1. Approving appointments of the CEO, the CEO's direct reports and certain other appointments.
• 1. Preparing the report on executive compensation to be included in the Company's Annual Report and Consolidated Financial Statements.
• 1. Annually reviewing the Compensation Committee's own performance.

The Compensation Committee Charter is available on the Subsea 7 website: www.subsea7.com.

REMUNERATION OF THE BOARD OF DIRECTORS

The Company's Directors receive remuneration in accordance with their individual roles and committee membership, with the exception of the CEO whose remuneration is detailed in Note 34 'Related party transactions' to the Consolidated Financial Statements. The Directors are encouraged to own shares in the Company but no longer participate in any incentive or share option schemes, with the exception of Mr Cahuzac in his capacity as CEO and as Executive Director. One non-executive Director (Sir Peter Mason) was previously awarded share options which he continues to hold. The remuneration of the Board of Directors is approved at the AGM annually as part of the Annual Report and Consolidated Financial Statements and is disclosed in Note 34 'Related party transactions' to the Consolidated Financial Statements.

Directors are not permitted to undertake specific assignments for the Group unless these have been disclosed to and approved in advance by the full Board of Directors.

REMUNERATION OF THE EXECUTIVE MANAGEMENT

The Group's remuneration policy is set by the Compensation Committee. The policy is designed to provide remuneration packages which will help to attract, retain and motivate senior management to achieve the Group's strategic objectives and to enhance shareholder value. The Compensation Committee benchmarks executive remuneration against comparable companies and seeks to ensure that the Group offers rewards and incentives which are competitive with those offered by the Group's peers. The Compensation Committee also seeks to ensure that the remuneration policy is applied consistently across the Group and that remuneration is fair and transparent, whilst encouraging high performance.

Remuneration comprises base salary, bonus, share-based payments, benefits and pension. In benchmarking elements of remuneration against Subsea 7's peers, the Compensation Committee may from time to time take advice from external consultants. Performancerelated remuneration schemes define limits in respect of the absolute awards available. These are defined within the scheme arrangements and set out limits regarding the total award in a given year and, in specific instances, the total award available to certain individuals.

Chief Executive Officer remuneration

The remuneration package of the CEO was determined by the Board of Directors on the recommendation of the Compensation Committee. The compensation of the CEO is reported in Note 34 'Related party transactions' to the Consolidated Financial Statements.

Executive Management Team remuneration

The remuneration package of the other five members of the Executive Management Team was determined by the Compensation Committee and is shown in aggregate in Note 34 'Related party transactions' to the Consolidated Financial Statements.

Share ownership of Executive Management Team

Details of share options held and other interests in the share capital of the Company by the Executive Management Team are shown in Note 34 'Related party transactions' to the Consolidated Financial Statements.

Long-term incentive arrangements

The Group currently operates a single long-term incentive arrangement, the 2013 Long-term Incentive Plan (2013 LTIP), to reward and incentivise key management. There are also former schemes which are now closed to new awards. Full details of the 2013 LTIP are set out in Note 35 'Share-based payments' to the Consolidated Financial Statements.

AUDIT COMMITTEE

Committee members

Dod Fraser Committee Chairman

Eystein Eriksrud

Robert Long

The Audit Committee's main responsibilities include:

• 1. Monitoring the financial reporting process and submitting recommendations or proposals to ensure its integrity.
• 1. Monitoring the effectiveness of the Company's and the Group's internal controls, internal audit function, financial controls framework and, where applicable, risk management systems.
• 1. Monitoring the statutory audit of the Company's Annual Accounts and the Consolidated Financial Statements of the Group, in particular its performance, taking into account any findings and conclusions by the competent authority.
• 1. Reviewing the quarterly, half-yearly and annual financial statements of the Group before their approval by the Board of Directors.
• 1. Reviewing and monitoring the independence of the external auditor, in particular with respect to the appropriateness of the provision of additional non-audit services to the Company and the Group and putting in place procedures and making recommendations with respect to the selection and the appointment of the external auditor.
• 1. Reviewing the report from the external auditor on key matters arising from the Group statutory audit.
• 1. Dealing with complaints received directly or via management, including information received confidentially and anonymously, in relation to accounting, financial reporting, internal controls and external audit issues.
• 1. Reviewing the disclosure of transactions involving related parties.
• 1. Annually reviewing the Audit Committee's own performance.

The Audit Committee Charter is available on the Subsea 7 website: www.subsea7.com.

The Audit Committee is responsible for ensuring that the Group has an independent and effective external and internal audit process. The Audit Committee supports the Board of Directors in the administration and exercise of its responsibility for supervisory oversight of financial reporting and internal control matters and to maintain appropriate relationships with the external auditor. Each of the Audit Committee members meets the independence requirements under Luxembourg law.

The terms of reference of the Audit Committee, as set out in the Audit Committee Charter, satisfy the requirements of applicable law and are in accordance with the Articles of Incorporation.

The Chairman of the Audit Committee is Dod Fraser, whose biography can be found on page 29. The Board of Directors has determined that Mr Fraser is the Audit Committee's financial expert and competent in accounting and audit practice with recent and relevant financial experience. The Audit Committee's Charter requires that the Audit Committee shall consist of not less than three Directors. The Audit Committee meets at least four times a year and its meetings are attended by representatives of the external auditor and by the head of the internal audit function.

AUDITOR

The external auditor meets the Audit Committee annually regarding the planning and preparation of the audit of the Group's Consolidated Financial Statements and the Company's Annual Accounts.

The Audit Committee members hold separate discussions with the external auditor during the year without the Executive Management Team being present. The scope, resources and level of fees proposed by the external auditor in relation to the Group's audit and related activities are approved by the Audit Committee.

The Audit Committee recognises that it is occasionally in the interest of the Group to engage its external auditor to undertake certain other non-audit assignments. Fees paid to the external auditor for audit and non-audit services are reported in the Consolidated Financial Statements of the Group, which are in turn approved at the AGM. The Audit Committee also requests the external auditor to confirm annually in writing that the external auditor is independent.

TAKE-OVERS

Subsea 7 S.A.'s Board of Directors endorses the principles concerning equal treatment of all shareholders. In the event of a take-over bid, it is obliged to act in accordance with the requirements of Luxembourg law and in accordance with the applicable principles for good corporate governance.

The Company has been notified of the following significant shareholders who control 5% or more of the voting rights of the Company:

%(a)
21.3%
9.0%

(a) Information is correct as at 31 December 2017.

INFORMATION AND COMMUNICATIONS

Subsea 7 S.A.'s Board of Directors concurs with the principles of equal treatment of all shareholders and the Group is committed to reporting financial results and other information on an accurate and timely basis. The Group provides information to the market through quarterly and annual reports, investor and analyst presentations which are available to the media and by making operational and financial information available on Subsea 7's website. Announcements are released through notification to the company disclosure systems of the Oslo Børs and the Luxembourg Commission de Surveillance du Secteur Financier and simultaneously on the Subsea 7 website. As a listed company, the Company complies with the relevant regulations regarding disclosure. Information is only provided in English.

The Company complies in all material respects with the Oslo Børs' Code of Practice for IR, which is available at www.oslobors.no/.

DIRECTORS' RESPONSIBILITY STATEMENT

We confirm that, to the best of our knowledge, the Consolidated Financial Statements for the year ended 31 December 2017 have been prepared in accordance with current applicable accounting standards and give a true and fair view of the assets, liabilities, financial position and results of the Company and the Group taken as a whole. We also confirm that, to the best of our knowledge, the 2017 Annual Report and Consolidated Financial Statements include a fair review of the development and performance of the business and the position of the Group, together with a description of the principal risks and uncertainties facing the Group.

By Order of the Board of Directors of Subsea 7 S.A.

Kristian Siem Jean Cahuzac Chairman CEO and Director

28 February 2018

FINANCIAL REVIEW

Financial highlights

For the year ended 31 December 2017 revenue was \$4.0 billion, 12% higher than the prior year. This improvement was largely attributable to an increase in renewables and conventional activity, in part due to acquisitions made during the year. Adjusted EBITDA was \$1.0 billion (2016: \$1.1 billion) and Adjusted EBITDA percentage margin was 26%, six percentage points lower than the exceptionally high level reported in 2016, reflecting fewer projects in the final stages of completion, lower offshore activity levels and reduced pricing on projects awarded during the downturn. Net operating income was \$581 million. The tax charge of \$100 million was equivalent to an effective tax rate of 18%, reflecting the change in the geographic composition of the Group's activities toward lower tax jurisdictions and a reduction of irrecoverable tax assets. Diluted earnings per share was \$1.36, an increase of 7% on the prior year.

Subsea 7 performed well during the cyclical downturn of the oil and gas markets by taking early action to cut costs and developing strategic alliances and partnerships to secure work. At the bottom of the cycle, from third quarter 2015 to second quarter 2017, Subsea 7 reported exceptionally high percentage margins as projects were successfully de-risked and costs were reduced. In the third quarter 2017 the benefit from pre-downturn awards came to an end and the Group now faces margin pressure as its order backlog is replenished with projects awarded with reduced pricing.

At 31 December 2017 order backlog was \$5.2 billion, a decrease of \$0.5 billion compared to December 2016. Order intake in 2017 was \$3.3 billion, including \$1.1 billion from acquisitions made during the year. Major awards in 2017 included the Mad Dog Phase Two project, an integrated award in the US Gulf of Mexico, the Snorre project, using proprietary Pipeline Bundle technology offshore Norway, and the Aerfugl project, also offshore Norway, awarded within the client partnership agreement with Aker BP and the first to use Subsea 7's Electrically Heat Traced Flowline technology.

The Group's liquidity and financial position remains strong. At 31 December 2017, the Group held cash and cash equivalents of \$1,109 million compared with \$1,676 million at 31 December 2016, had total borrowings of \$283 million compared with \$427 million at 31 December 2016 and unutilised credit facilities totalling \$656 million. Subsea 7 has a defined strategy to prioritise the use of its financial flexibility to grow and strengthen the business. In 2017 almost \$300 million was invested in acquiring businesses and constructing vessels that diversified and enhanced the Group's activities. In addition the Group invested in technology, taking a position in a leading composite pipeline technology company. In the first quarter of 2018 we have taken the opportunity to grow and strengthen our business. Building on existing relationships and a targeted investment approach, the Group has affirmed its commitment to integrated solutions by announcing the intention to form a joint venture with Schlumberger, it has enhanced its early engineering expertise by acquiring a strategic interest in Xodus and it has extended its renewable energy capability by acquiring a cable laying company.

In light of the Group's solid financial and liquidity position and improved market outlook, the Board of Directors will recommend to the shareholders at the Annual General Meeting on 17 April 2018 that a special dividend of NOK 5.00 per share be paid, equivalent to a total dividend of approximately \$200 million.

For the year ended (in \$ millions, except Adjusted EBITDA margin, share and per share data)	2017 31 Dec	2016 31 Dec
Revenue	3,986	3,567
Adjusted EBITDA(a) (unaudited)	1,035	1,142
Adjusted EBITDA margin(a) (unaudited)	26%	32%
Net operating income excluding goodwill impairment charge	581	611
Goodwill impairment charge	–	(90)
Net operating income	581	521
Net income excluding goodwill impairment charge	455	509
Net income	455	418
Earnings per share – in \$ per share
Basic	1.39	1.34
Diluted	1.36	1.27
Adjusted diluted(b)	1.27	1.54
		2016
As at (in \$ millions)	2017 31 Dec	31 Dec
Backlog (unaudited)	5,208	5,693
Cash and cash equivalents	1,109	1,676
Borrowings	283	427

(a) For explanations and reconciliations of Adjusted EBITDA and Adjusted EBITDA margin refer to page 119 of the Consolidated Financial Statements.

(b) For explanation and a reconciliation of diluted and Adjusted diluted earnings per share refer to Note 11 'Earnings per share' of the Consolidated Financial Statements.

Revenue

Revenue for 2017 was \$4.0 billion, an increase of \$419 million or 12% compared to 2016. The year-on-year increase in revenue was driven by a significant increase within the Renewables and Heavy Lifting Business Unit, mainly related to the Beatrice wind farm project. This was partially offset by lower activity levels within the SURF and Conventional and i-Tech Services Business Units.

Adjusted EBITDA

Adjusted EBITDA and Adjusted EBITDA margin were \$1.0 billion and 26% respectively compared to \$1.1 billion and 32% for 2016. The reduction in the Adjusted EBITDA margin in 2017 reflected a reduction in offshore activity levels and lower pricing on projects awarded during the downturn within the SURF and Conventional and i-Tech Services Business Units, partially offset by continued cost discipline and good operational performance. Share of net loss of associates and joint ventures amounted to \$43 million compared with net income of \$46 million in the prior year. The variance reflected the acquisition of Seaway Heavy Lifting in March 2017 which is now a wholly-owned subsidiary of the Group, having previously been recognised as an equity-accounted joint venture. In addition the Group's share of net income of associates and joint ventures was adversely impacted by a \$13 million impairment charge recognised in the second quarter by the Normand Oceanic joint venture in relation to the Normand Oceanic vessel and, in the third quarter, an impairment charge of \$11 million within the SapuraAcergy joint venture in relation to the disposal of the vessel, Sapura 3000.

Net operating income

Net operating income was \$581 million in 2017 compared to \$611 million in 2016, excluding the impact of the goodwill impairment charge recognised in that year. This decrease was primarily due to:

• lower activity in SURF and Conventional and i-Tech Services Business Units

partially offset by:

• increased contribution from the Renewables and Heavy Lifting Business Unit, mainly related to the Beatrice wind farm project and the consolidation of the results of Seaway Heavy Lifting, which was acquired in March 2017;
• the absence of a \$97 million restructuring charge related to resizing and cost reduction measures recognised in 2016; and
• lower impairment charges related to property, plant and equipment amounting to \$32 million recognised in 2017 compared with impairment charges of \$158 million recognised in 2016.

Net income

Net income was \$455 million for the year ended 31 December 2017, compared to \$418 million in 2016. This increase was primarily due to:

• the absence of goodwill impairment charges in 2017, compared to a charge of \$90 million recognised in 2016;
• a reduction of \$59 million in the taxation charge

partially offset by:

• a decrease of \$30 million in net operating income, excluding the impact of the goodwill impairment charge recognised in 2016; and
• net foreign currency losses of \$57 million in 2017, recognised within other gains and losses, compared to net foreign currency gains of \$43 million in 2016, largely reflecting the weakening of the US dollar against various functional currencies in the year.

The effective tax rate for 2017 was 18% compared to 24% for 2016. The decrease in the effective tax rate was driven by the change in the geographical composition of net operating income and benefitted from a reduction in withholding taxes and other irrecoverable taxes.

Earnings per share

Diluted earnings per share was \$1.36 for 2017 compared to \$1.27 for 2016, calculated using a weighted average number of shares of 338 million and 343 million respectively, with the convertible bonds having a dilutive effect in both years. Adjusted diluted earnings per share, which excludes the impact of goodwill impairment charges, remeasurement gains and losses and net bargain purchase gains on business combinations, was \$1.27 compared to \$1.54 for 2016.

Cash and cash equivalents

Cash and cash equivalents at 31 December 2017 was \$1.1 billion compared to \$1.7 billion at 31 December 2016. The movement in cash and cash equivalents during 2017 was mainly attributable to:

• \$209 million of net cash generated from operating activities, which included a net adverse movement in operating assets and liabilities of \$724 million

offset by:

• net cash used in investing activities of \$170 million, which included:
• \$145 million net cash disbursed in acquiring the remaining 50% ownership interests in Seaway Heavy Lifting and Normand Oceanic, and certain businesses of ECS;
• \$147 million related to the purchase of property, plant and equipment, including the spoolbase at Ingleside in Texas, US, and the commencement of construction of a new reel-lay vessel

partially offset by:

• \$101 million of dividends received from associates and joint ventures, mainly from SapuraAcergy following the decision to discontinue the joint venture.

• net cash used in financing activities of \$602 million, which included:
• repurchases of convertible bonds for \$77 million during the year;
• redemption of convertible bonds at maturity for \$358 million;
• dividends paid to shareholders of the parent company of \$191 million;
• repayment of borrowings of \$253 million, mainly relating to Seaway Heavy Lifting and Normand Oceanic partially offset by:
• \$301 million drawn down against the export credit agency (ECA) senior secured facility.

Allocation of net income

The net income for the year of \$455 million (2016: net income of \$418 million) was transferred to equity, of which \$455 million (2016: \$436 million) was recognised in retained earnings attributable to shareholders of the parent company and a net loss of \$0.2 million in non-controlling interests (2016: net loss of \$18 million).

Business Unit highlights

For the year ended 31 December 2017

(in \$ millions)	SURF and Conventional	i-Tech Services	Renewables and Heavy Lifting	Corporate	Total
Selected financial information:
Revenue	2,724.8	302.3	958.5	–	3,985.6
Net operating income	450.8	22.7	90.0	17.2	580.7

For the year ended 31 December 2016

(in \$ millions)	SURF and Conventional	i-Tech Services	Renewables and Heavy Lifting Re-presented(a) Re-presented(a) Re-presented(a) Re-presented(a)	Corporate	Total
Selected financial information:
Revenue	3,013.1	377.4	176.0	0.2	3,566.7
Net operating income/(loss) excluding goodwill impairment	624.9	38.0	27.8	(79.3)	611.4
Impairment of goodwill	(90.4)	–	–	–	(90.4)
Net operating income/(loss) including goodwill impairment	534.5	38.0	27.8	(79.3)	521.0

(a) Re-presented due to the reorganisation of the operating segments from 1 January 2017.

SURF and Conventional

Revenue was \$2.7 billion, a decrease of \$288 million or 10% compared to 2016, reflecting lower activity levels.

During the year the West Nile Delta Phase One and West Nile Delta platform extension and tie in projects, both offshore Egypt, the Coulomb and Stampede projects, in the US Gulf of Mexico, the Western Isles project, offshore UK, the Maria project, offshore Norway and the Atoll Field Development project, offshore Egypt, were substantially completed. There was significant progress on the Catcher and Culzean projects, offshore UK, the West Nile Delta Phase Two project, offshore Egypt, the Hasbah project, offshore Saudi Arabia, the OCTP SURF project, offshore Ghana, and the Tahiti Vertical Expansion project, in the US Gulf of Mexico. In Brazil, PLSV activity benefitted from the addition of Seven Sun and Seven Cruzeiro to the fleet in Q1 2017 and Seven Waves recommencing operations during the third quarter, following the completion of repairs to its lay-tower.

Net operating income was \$451 million, a decrease of \$174 million or 28% compared to 2016. The reduction in net operating income reflected lower activity levels compared with the prior year, fewer large projects in their commercial close-out stages and underlying margin pressure. This was partially offset by lower impairment charges of \$32 million recognised in 2017 in relation to property, plant and equipment compared with \$149 million recognised in 2016.

i-Tech Services

Revenue in 2017 was \$302 million, a decrease of \$75 million or 20% compared to 2016. ROV support activity decreased across the fleet due to a reduction in the number of active drill rigs worldwide and there was a reduction in Inspection, Repair, and Maintenance (IRM) activity in all regions compared to 2016.

Net operating income was \$23 million for 2017 compared to \$38 million in 2016. The reduction in net operating income reflected lower activity levels and underlying pricing pressure. This was partially offset by the absence of a \$9 million impairment charge, related to property, plant and equipment recognised in 2016.

Renewables and Heavy Lifting

Revenue was \$959 million compared to \$176 million in 2016, and related mainly to the Beatrice wind farm project.

Net operating income was \$90 million compared to net operating income of \$28 million in 2016. The results benefitted from high levels of activity on the Beatrice wind farm project and the consolidation of Seaway Heavy Lifting following its acquisition by the Group in March 2017.

Backlog

At 31 December 2017, order backlog was \$5.2 billion, a decrease of \$0.5 billion compared to 31 December 2016. Order intake in 2017 was \$3.3 billion, including \$1.1 billion from acquisitions made during the year. Major awards in 2017 included the Mad Dog Phase Two project, an integrated award in the US Gulf of Mexico, the Snorre project, using proprietary Pipeline Bundle technology offshore Norway, and the Aerfugl project, offshore Norway, awarded within the client partnership agreement with Aker BP and the first to use Subsea 7's Electrically Heat Traced Flowline technology.

\$4.3 billion of the backlog at 31 December 2017 related to the SURF and Conventional Business Unit, (which included \$1.3 billion related to long-term day-rate contracts for PLSV's in Brazil), \$0.3 billion related to the i-Tech Services Business Unit and \$0.6 billion related to the Renewables and Heavy Lifting Business Unit. \$3.1 billion of this backlog is expected to be executed in 2018; \$1.0 billion in 2019 and \$1.1 billion in 2020 and thereafter. Backlog related to associates and joint ventures was excluded from these figures.

Balance sheet

Goodwill

At 31 December 2017 goodwill was \$701 million, a net increase of \$73 million compared with the prior year. Goodwill of \$46 million was recognised in connection with acquisitions made by the Group during 2017, of which \$35 million related to the acquisition of the remaining 50% equity interest in Seaway Heavy Lifting and \$11 million related to the acquisition of certain businesses and assets of EMAS Chiyoda Subsea (ECS).

Property, plant and equipment

Additions to property, plant and equipment totalled \$200 million during 2017 (2016: \$267 million). Additions included \$50 million related to the final stages of construction of two new-build vessels: Seven Arctic and Seven Kestrel, and \$16 million related to the construction of a new reel-lay vessel.

Impairment charges totalling \$32 million were recognised in the year (2016: \$158 million), of which \$24 million related to vessels and vessel related equipment and \$7 million was recognised in respect of operating equipment.

Interest in associates and joint ventures

During 2017 the Group recorded a loss of \$43 million from its share of net loss of associates and joint ventures. The Group acquired the remaining equity interests in the Seaway Heavy Lifting and Normand Oceanic entities and entered into an agreement to discontinue the SapuraAcergy joint venture. The acquisition of the remaining equity interests resulted in the derecognition of \$234 million related to the previously held equity-accounted investments, recognised within 'interest in associates and joint ventures' on the Group's Consolidated Balance Sheet. During the year the Group received dividends of \$100 million from SapuraAcergy.

Borrowings

Total borrowings at 31 December 2017 were \$283 million compared with \$427 million at 31 December 2016. During the year the Group drew down \$301 million of funds against its Export Credit Agency (ECA) senior secured facility. During 2017, the Group repurchased \$78 million (par value) of the 2017 1.00% convertible bonds for \$77 million in cash, and redeemed the remaining outstanding convertible bonds with an aggregate value of \$358 million on the maturity date of 5 October 2017.

Facilities

At 31 December 2017 the Group had facilities of \$656 million relating to the Group's multi-currency revolving credit and guarantee facility, all of which remained unutilised.

Share repurchase plan

On 25 July 2017, the Board of Directors authorised a 24 month extension to the Group's share repurchase programme of up to \$200 million. During both 2017 and 2016, the Group did not repurchase any treasury shares. At 31 December 2017 cumulatively 5,272,656 shares had been repurchased under the July 2014 repurchase programme for a total consideration of \$57 million.

Shareholders

The 20 largest shareholders as at 31 December 2017, and their beneficial ownership(a) as a percentage of the total fully paid and issued common shares of the Company were:

	%
Siem Industries, Inc.	21.3
Folketrygdfondet	9.0
DNB Asset Management AS	4.3
Acadian Asset Management LLC	3.0
INVESCO Asset Management Deutschland GmbH	2.4
KLP Forsikring	2.2
Nordea Funds Oy	2.0
The Vanguard Group, Inc.	1.9
Danske Capital (Norway)	1.8
JP Morgan Asset Management U.K. Limited	1.8
Robotti & Company Advisors, LLC	1.8
Storebrand Kapitalforvaltning AS	1.8
SAFE Investment Company Limited	1.6
BlackRock Institutional Trust Company, N.A.	1.5
Alfred Berg Kapitalforvaltning AS	1.3
Pareto Forvaltning AS	1.2
INVESCO Asset Management Limited	1.0
State Street Global Advisors (US)	0.9
Marshall Wace LLP	0.9
GlobeFlex Capital L.P.	0.8

(a) The data is provided by NASDAQ OMX and is obtained through an analysis of beneficial ownership and fund manager information. This is provided in response to disclosure of ownership notices issued to all custodians on the Subsea 7 VPS share register. Whilst every reasonable effort has been made to verify the data, there may be fluctuations as a result of such events as stock lending or other non-institutional stock movements, and neither Subsea 7 nor NASDAQ OMX can guarantee the accuracy of the analysis.

Cash and cash equivalents

Movements in cash and cash equivalents are summarised as follows:

	2017	2016
For the year ended (in \$ millions)	31 Dec	31 Dec
Cash and cash equivalents at the beginning of the year	1,676	947
Net cash generated from operating activities	209	1,046
Net cash used in investing activities	(170)	(199)
Net cash used in financing activities	(602)	(121)
Increase in restricted cash	(6)	–
Effect of exchange rate changes on cash and cash equivalents	2	3
Cash and cash equivalents at the end of the year	1,109	1,676

Net cash generated from operating activities was \$209 million (2016: \$1.0 billion) which included a decrease in net operating liabilities of \$724 million (2016: increase in net operating liabilities of \$40 million).

Net cash used in investing activities was \$170 million compared with \$199 million used in 2016. This was mainly attributable to expenditure on property, plant and equipment of \$147 million (2016: \$300 million) and \$146 million related to the acquisition of businesses (net of cash and borrowings acquired) during 2017. This was partially offset by dividends received from associates and joint ventures of \$101 million (2016: \$28 million).

Net cash used in financing activities was \$602 million (2016: \$121 million), which was mainly driven by the repurchase of \$78 million (par value) of the 2017 1.00% convertible bonds for \$77 million and the redemption of \$358 million (par value) of 1.00% convertible bonds for \$358 million. The Group drew down \$301 million from the ECA senior secured facility and repaid \$253 million of borrowings, mainly relating to debt assumed on the acquisition of Seaway Heavy Lifting and the Normand Oceanic entities.

New-build vessel programme

In September 2017, the Group announced its intention to construct a new reel lay vessel and associated equipment. The cost, excluding capitalised interest, is expected to be below \$300 million.

At 31 December 2017, the Group had sufficient liquidity to meet its expected funding requirements for the next twelve months. The Group had cash and cash equivalents of \$1,109 million and unutilised committed credit and guarantee facilities of \$656 million, all of which was available for cash drawings. The Group monitors its future business opportunities on a continuous basis and actively reviews its credit and guarantee facilities and its long-term funding requirements.

Cash management constraints

The Group operates within a liquidity risk management framework which governs its management of short, medium and long-term funding and liquidity requirements. The Group manages liquidity risk by ensuring that it has access to sufficient cash, banking and borrowing facilities. This is achieved by regularly monitoring forecast and actual cash flows and matching the maturity profiles of financial assets and liabilities where appropriate.

Covenant compliance

The Group's credit facilities contain various financial covenants including, but not limited to, a minimum level of tangible net worth, a maximum level of net debt to earnings before interest, taxes, depreciation and amortisation, a maximum level of total financial debt to tangible net worth, a minimum level of cash and cash equivalents and an interest cover covenant. During the year all covenants were met. The Group expects to be able to comply with all financial covenants during 2018.

Going concern

The Consolidated Financial Statements have been prepared under the assumption of going concern. This assumption is based on the level of cash and cash equivalents at the year end, the banking and borrowing facilities in place, the forecast cash flows for the Group and the backlog position at 31 December 2017.

Outlook

Looking forward to the year ahead, Subsea 7 is confident it will continue to deliver cost-effective solutions that contribute to the long-term sustainability of offshore energy sources. The oil and gas cycle is gradually recovering from the very low levels of activity experienced in the last three years and offshore SURF and integrated awards to market are increasing, but pricing remains challenging. Projects are being awarded at lower values reflecting the cost savings that have been achieved through innovation, best practice processes and supply chain deflation as well as lower, and occasionally negative, margins while making positive cash contributions. Life of Field activity remains subdued at present but is expected to improve in 2018. There is a steady flow of projects being awarded in the Conventional oil and gas markets in the Middle East and the offshore Renewables market remains on a moderate growth trajectory.

For the full year 2018, revenue is expected to be broadly in line with 2017 and Adjusted EBITDA percentage margin is expected to be significantly lower than that achieved in 2017.

	Page
Report of the Réviseur d'Entreprises Agréé	49
Consolidated Income Statement	55
Consolidated Statement of Comprehensive Income	56
Consolidated Balance Sheet	57
Consolidated Statement of Changes in Equity	58
Consolidated Cash Flow Statement	60

Notes to the Consolidated Financial Statements	Page
1. General information	61
2. Adoption of new accounting standards	61
3. Significant accounting policies	65
4. Critical accounting judgements and key sources of estimation uncertainty	73
5. Segment information	75
6. Net operating income	77
7. Other gains and losses	78
8. Finance income and costs	79
9. Taxation	79
10. Dividends	82
11. Earnings per share	82
12. Business combinations	84
13. Goodwill	88
14. Intangible assets	90
15. Property, plant and equipment	91
16. Interest in associates and joint ventures	92
17. Advances and receivables	93
18. Inventories	93
19. Trade and other receivables	93
20. Other accrued income and prepaid expenses	94
21. Construction contracts	94
22. Cash and cash equivalents	94
23. Issued share capital	94
24. Treasury shares	95
25. Non-controlling interests	96
26. Borrowings	97
27. Convertible bonds	98
28. Other non-current liabilities	98
29. Trade and other liabilities	98
30. Provisions	99
31. Commitments and contingent liabilities	99
32. Operating lease arrangements	100
33. Financial instruments	101
34. Related party transactions	108
35. Share-based payments	110
36. Retirement benefit obligations	112
37. Deferred revenue	115
38. Cash flow from operating activities	116
39. Post balance sheet events	116
40. Wholly-owned subsidiaries	117

To the shareholders of Subsea 7 S.A. 412F, route d'Esch L-2086 Luxembourg

Report on the audit of the Consolidated Financial Statements Opinion

We have audited the Consolidated Financial Statements of Subsea 7 S.A. (the "Company") and its subsidiaries (altogether the "Group"), which comprise the Consolidated Balance Sheet as at 31 December 2017, the Consolidated Income Statement, the Consolidated Statement of Other Comprehensive Income, the Consolidated Statement of Changes in Equity and the Consolidated Statement of Cash Flows for the year then ended, and the notes to the Consolidated Financial Statements, including a summary of significant accounting policies.

In our opinion, the accompanying Consolidated Financial Statements give a true and fair view of the consolidated financial position of the Group as at 31 December 2017, and of its consolidated financial performance and consolidated cash flows for the year then ended in accordance with International Financial Reporting Standards ("IFRS") as adopted by the European Union.

Basis for opinion

We conducted our audit in accordance with EU Regulation N° 537/2014, the Law of 23 July 2016 on the audit profession (the "Law of 23 July 2016") and with International Standards on Auditing ("ISAs") as adopted for Luxembourg by the "Commission de Surveillance du Secteur Financier" ("CSSF"). Our responsibilities under the Regulation, Law and standards are further described in the "Responsibilities of the "réviseur d'entreprises agréé" for the audit of the Consolidated Financial Statements" section of our report. We are also independent of the Group in accordance with the International Ethics Standards Board for Accountants' Code of Ethics for Professional Accountants ("IESBA Code") as adopted for Luxembourg by the CSSF together with the ethical requirements that are relevant to our audit of the Consolidated Financial Statements, and have fulfilled our other ethical responsibilities under those ethical requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Key audit matters

Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the Consolidated Financial Statements of the current period. These matters were addressed in the context of the audit of the Consolidated Financial Statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.

A significant proportion of the Group's revenues and income are derived from long-term contracts. As detailed in note 3 of the Consolidated Financial Statements these contracts include complex technical and commercial risks and often specify performance milestones to be achieved throughout the contract period, which can last several years. Due to the contracting nature of the business, revenue recognition involves a significant degree of judgement,
with estimates being made to:
• assess the total contract costs;
• assess the stage of completion of the contract;
• assess the proportion of revenues, including variation orders, to recognise in line with contract completion;
• forecast the outturn profit margin on each contract incorporating appropriate allowances for technical and commercial risks related to performance milestones yet to be achieved; and
• appropriately identify, estimate and provide for onerous contracts.
There is a range of acceptable outcomes resulting from these judgements that could lead to different revenue or income being reported in the Consolidated Financial Statements.
The Group has detailed procedures and processes in place to manage the commercial, technical and financial aspects of long-term contracts. The processes include the preparation of a Project Monthly Status Report (PMSR), which includes key accounting and forecast information for the relevant contract.
The risk of material misstatement is that the accounting for the Group's significant contracts does not accurately reflect the progress made and consequently the contract revenue and margin at the reporting date.

Our response:	We evaluated and tested the relevant Information Technology systems and tested the operating effectiveness of internal controls over the accuracy and timing of long-term contract revenue and margin recognised in the Consolidated Financial Statements, including controls over:
	• the detailed contract reviews (being the PMSR process and controls) performed by Management and reviewed at the project and the Group level that included estimating total costs, stage of completion of contracts, profit margin and evaluating contract profitability; and
	• the transactional controls that underpin the production of underlying contract related cost balances including the purchase to pay, vessel costs and payroll cycles.
	For the most significant and judgmental contracts, we:
	• obtained the PMSR and gained an understanding of the performance and status of the contracts;
	• corroborated Management's positions through the examination of externally generated evidence, such as customer correspondence;
	• discussed and understood Management's estimates for total contract costs and forecast costs-to-complete, including taking into account the historical accuracy of such estimates;
	• discussed and understood Management's estimates in recognising actual or potential variation orders, including taking into account the historical accuracy of such estimates;
	• tested the reconciliation of cost models to the PMSR;
	• re-performed the percentage of completion calculation; and
	• considered whether provisions for onerous contracts reflect the expected contractual position, using the knowledge obtained from other testing.
	We read the relevant clauses within selected contracts and discussed each with Management to obtain a full understanding of the specific terms and risks, which informed our consideration of whether revenue for these contracts was appropriately recognised.
	We made enquiries to both group internal and external legal counsel and considered the positions taken by Management.
	We assessed the adequacy of the disclosures in note 3 and note 5 of the Consolidated Financial Statements in relation to revenue.
Key audit matter:	Goodwill impairment assessments
Description of key audit matter:	As detailed in note 13, the Consolidated Financial Statements include \$700.8m of goodwill at 31 December 2017.
	Goodwill is subject to an annual review for impairment. An estimate of the recoverable amount of the cash-generating units (CGU) to which goodwill is allocated is prepared. The estimated recoverable amount is calculated as the higher of the value-in-use or fair value less costs to dispose. The outcome of the impairment review could vary significantly if different assumptions were applied in the models.
	The estimated recoverable amount is subjective due to the inherent uncertainty involved in forecasting and discounting future cash flows with many of the key underlying assumptions being impacted by political and economic factors. The key assumptions include:
	• the future EBITDA assumptions taken from the Group's most recent budgets and plans for the next five years approved by Management ("the Plan");
	• the long-term growth rate used beyond the period covered by the Plan; and
	• the pre-tax discount rate applied to future cash flows.
	Our audit focused on the risk that the carrying value of goodwill could be overstated.

	assumptions used within the models to assess the recoverable amount of goodwill.
	We assessed Management's impairment testing by obtaining the supporting model and assessing the methodology and key assumptions made:
	• Future EBITDA forecasts – we evaluated Managements' EBITDA forecasts and tested the underlying values used in the calculations by comparing Managements' forecast to the latest Board approved five-year strategic plan. We assessed the actual performance in the year against the prior year budgets to evaluate historical forecasting accuracy;
	• Long term growth rate – we compared the rates applied by Management to available externally developed rates;
	• Pre-tax discount rates – we involved our valuations specialists in our evaluation of the discount rate to consider the appropriateness of the rates used; and
	• We tested the arithmetical accuracy of the models.
	As part of our testing of the revenue and EBITDA forecasts, we evaluated the 5 year plan process, focusing on expected EBITDA margins and timing of any recovery of the subsea oil and gas market assumptions in the Plan.
	Given the significance of the terminal value cash flows to the total value-in-use we paid particular attention to the assumptions as regards sustainable EBITDA levels and compared these to expected and historical levels.
	We re-performed sensitivity analysis around the key assumptions for all CGUs in order to ascertain the extent of change in those assumptions required individually or collectively to result in a further impairment of goodwill. For those CGUs which were most sensitive, we discussed the basis for these cash flows with Management and the Audit Committee.
	We examined the sensitivity disclosures presented in the Consolidated Financial Statements to consider whether reasonably possible changes to assumptions that could lead to a material impairment had been disclosed.
	We assessed the adequacy of the disclosures in note 13 of the Consolidated Financial Statements.
Key audit matter:	Acquisition of Seaway Heavy Lifting Holding Limited and certain businesses of EMAS Chiyoda Subsea
Description of key audit matter:	As detailed in note 12 of the Consolidated Financial Statements, the Group completed several business combinations in the year.
	• The Group announced the acquisition of the remaining 50% shareholding in Seaway Heavy Lifting Holding Limited from K&S Baltic Offshore (Cyprus) Limited. The acquisition was effective from 10 March 2017.
	• During the year the Group announced the acquisition of certain businesses of EMAS Chiyoda Subsea (ECS). The acquisition, under a US bankruptcy code Chapter 11 Plan of Reorganisation, was confirmed by the U.S. Bankruptcy Court for the Southern District of Texas and became effective on 29 June 2017.
	The significant risk arises because of the level of Management judgement required in assessing the fair value of net assets acquired and the impact of any adjustments to consideration in determining the level of goodwill arising on the acquisitions. This is especially focused on the identification and measurement of intangible assets on acquisition.
	Our audit focused on the risk that the fair value of net assets acquired and the resultant goodwill could be misstated.

Our response:	We have obtained an understanding of the key controls and processes in place with regards to IFRS 3 'Business Combinations' accounting.
	In our audit of the accounting for the acquisitions, we read the sale and purchase agreements (or alternative documentation) and considered whether the appropriate accounting treatment had been applied.
	As the transactions met the definition of a business combination we audited the Group's assessment of the assets and liabilities acquired; the allocation of the purchase consideration to these; and the resultant goodwill recognised by performing the following procedures:
	• We examined the consideration transferred and, where relevant, contingent consideration to assess whether it was calculated in accordance with contractual arrangements;
	• We assessed Management's judgements in respect of what arrangements should be accounted for as part of the business combination and those that should be accounted for separately from the business combination;
	• We considered the identification of the acquired assets and liabilities based on our understanding of the business of the acquired companies and the explanations and plans of Management that supported these acquisitions;
	• We assessed the recognition of intangible assets and made an evaluation of Management's key assumptions in identifying intangible assets through inquiry and inspection of supporting evidence;
	• We tested the fair values of the acquired assets and liabilities based on common valuation models; and
	• We considered the consolidation adjustments in respect of accounting for these transactions.
	We performed procedures to assess the adequacy of disclosures in note 12 of the Consolidated Financial Statements.
Key audit matter:	Property, plant and equipment (vessel fleet) impairment assessments
Description of key audit matter:	As detailed in note 15, the Consolidated Financial Statements include \$4.0 billion for the vessel fleet at 31 December 2017.
	Property, plant and equipment are subject to an impairment test where indicators of impairment exist. The continued challenging business environment has adversely impacted both current market valuations and expected future utilisation of specific vessels giving rise to indicators of impairment for the vessel fleet. Impairment charges are recognised when necessary to bring the carrying amounts of specific assets to their recoverable amount defined as the higher of value-in-use or fair value less costs to dispose.
	The process for determining the recoverable amount of the vessel fleet is complex and requires significant Management judgement. The key factors are:
	• the forecast utilisation of the vessel fleet;
	• the external broker estimates of market valuation; and
	• the determination of the cash generating units used to assess the value in use of the vessel.
	Our audit focused on the risk that the carrying amount of the vessel fleet could be misstated.
Our response:	We evaluated Management's assessment for indicators of impairment or for reversal of impairments for property, plant and equipment.
	We understood the internal financial controls for the vessel impairment process including the determination of assumptions used within the models to assess the recoverable amount.
	We obtained Management's impairment assessment for owned vessels, which included obtaining broker valuations indicating the market value of the vessels.
	For vessels where an impairment trigger was identified, we analysed the recoverable amount considering the value-in-use and broker valuations to determine the reasonableness of the carrying amount.
	We reviewed the external broker vessel valuations obtained by Management for each vessel and assessed their independence, objectivity and competence.
	For all vessels in the fleet, we evaluated the estimated remaining useful life including understanding any changes (or lack thereof) from the prior year.
	We evaluated the adequacy of the Company's disclosures in note 15 regarding the impairments of property, plant and equipment in the Consolidated Financial Statements.

Other information

The Board of Directors is responsible for the other information. The other information comprises the information included in the Consolidated Annual Report and the Corporate Governance Statement but does not include the Consolidated Financial Statements and our report of "réviseur d'entreprises agréé" thereon.

Our opinion on the Consolidated Financial Statements does not cover the other information and we do not express any form of assurance conclusion thereon.

In connection with our audit of the Consolidated Financial Statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the Consolidated Financial Statements or our knowledge obtained in the audit or otherwise appears to be materially misstated. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report this fact. We have nothing to report in this regard.

Responsibilities of the Board of Directors and of those charged with governance for the Consolidated Financial Statements

The Board of Directors is responsible for the preparation and fair presentation of the Consolidated Financial Statements in accordance with IFRS as adopted by the European Union, and for such internal control as the Board of Directors determines is necessary to enable the preparation of Consolidated Financial Statements that are free from material misstatement, whether due to fraud or error.

In preparing the Consolidated Financial Statements, the Board of Directors is responsible for assessing the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the Board of Directors either intends to liquidate the Group or to cease operations, or has no realistic alternative but to do so.

Those charged with governance are responsible for overseeing the Group's financial reporting process.

Responsibilities of the "réviseur d'entreprises agréé" for the audit of the Consolidated Financial Statements

The objectives of our audit are to obtain reasonable assurance about whether the Consolidated Financial Statements as a whole are free from material misstatement, whether due to fraud or error, and to issue a report of the "réviseur d'entreprises agréé" that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with EU Regulation N° 537/2014, the Law of 23 July 2016 and with the ISAs as adopted for Luxembourg by the CSSF will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these Consolidated Financial Statements.

As part of an audit in accordance with EU Regulation N° 537/2014, the Law of 23 July 2016 and with ISAs as adopted for Luxembourg by the CSSF, we exercise professional judgement and maintain professional scepticism throughout the audit. We also:

• Identify and assess the risks of material misstatement of the Consolidated Financial Statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group's internal control.
• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by the Board of Directors.
• Conclude on the appropriateness of the Board of Directors' use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our report of the "réviseur d'entreprises agréé" to the related disclosures in the Consolidated Financial Statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our report of the "réviseur d'entreprises agréé". However, future events or conditions may cause the Group to cease to continue as a going concern.
• Evaluate the overall presentation, structure and content of the Consolidated Financial Statements, including the disclosures, and whether the Consolidated Financial Statements represent the underlying transactions and events in a manner that achieves fair presentation.
• Obtain sufficient appropriate audit evidence regarding the financial information of the entities and business activities within the Group to express an opinion on the Consolidated Financial Statements. We are responsible for the direction, supervision and performance of the Group audit. We remain solely responsible for our audit opinion.

We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.

From the matters communicated with those charged with governance, we determine those matters that were of most significance in the audit of the Consolidated Financial Statements of the current period and are therefore the key audit matters. We describe these matters in our report unless law or regulation precludes public disclosure about the matter.

Report on other legal and regulatory requirements

We have been appointed as "réviseur d'entreprises agréé" by the General Meeting of the Shareholders on 12 April 2017 and the duration of our uninterrupted engagement, including previous renewals and reappointments, is 4 years.

The Consolidated Management Report is consistent with the Consolidated Financial Statements and has been prepared in accordance with applicable legal requirements.

The Corporate Governance Statement, included in the Consolidated Management Report, is the responsibility of the Board of Directors. The information required by article 68ter paragraph (1) letters c) and d) of the law of 19 December 2002 on the commercial and companies register and on the accounting records and annual accounts of undertakings, as amended, is consistent with the Consolidated Financial Statements and has been prepared in accordance with applicable legal requirements.

We confirm that the prohibited non-audit services referred to in EU Regulation No 537/2014 were not provided and that we remained independent of the Group in conducting the audit.

Other matter

The Corporate Governance Statement includes, where applicable, the information required by article 68ter paragraph (1) points (a), (b), (e), (f) and (g) of the law of 19 December 2002 on the commercial and companies register and on the accounting records and annual accounts of undertakings, as amended.

Ernst & Young Société anonyme Cabinet de révision agréé

Thierry Bertrand Luxembourg, 28 February 2018

For the year ended (in \$ millions, except per share data)	Notes	2017 31 Dec	2016 31 Dec
Revenue	5	3,985.6	3,566.7
Operating expenses	6	(3,118.4)	(2,759.6)
Gross profit		867.2	807.1
Administrative expenses	6	(243.8)	(242.1)
Impairment of goodwill	13	–	(90.4)
Share of net (loss)/income of associates and joint ventures	16	(42.7)	46.4
Net operating income		580.7	521.0
Finance income	8	24.6	17.9
Remeasurement gain on business combinations	12	25.0	–
Other gains and losses	7	(54.8)	44.9
Finance costs	8	(21.0)	(7.1)
Income before taxes		554.5	576.7
Taxation	9	(99.9)	(158.4)
Net income		454.6	418.3
Net income attributable to:
Shareholders of the parent company		454.8	436.0
Non-controlling interests	25	(0.2)	(17.7)
		454.6	418.3
		\$	\$
Earnings per share	Notes	per share	per share
Basic	11	1.39	1.34
Diluted(a)	11	1.36	1.27

(a) For explanation and a reconciliation of diluted earnings per share please refer to Note 11 'Earnings per share' within Notes to the Consolidated Financial Statements.

For the year ended (in \$ millions)	Notes	2017 31 Dec	2016 31 Dec
Net income		454.6	418.3
Items that may be reclassified to the income statement in subsequent periods:
Foreign currency translation gains/(losses)		124.9	(232.4)
Cash flow hedges:
Net fair value gains arising	33	–	7.3
Reclassification adjustments for amounts recognised in the Consolidated Income Statement	33	–	(10.0)
Share of other comprehensive income of associates and joint ventures	16	0.5	2.2
Reclassification adjustment relating to business combinations		9.0	–
Tax relating to components of other comprehensive income which may be reclassified	9	(0.5)	0.8
Items that will not be reclassified to the income statement in subsequent periods:
Remeasurement gains on defined benefit pension schemes	36	0.4	1.0
Tax relating to remeasurement gains on defined benefit pension schemes	9	–	(0.5)
Other comprehensive income/(loss)		134.3	(231.6)
Total comprehensive income		588.9	186.7
Total comprehensive income attributable to:
Shareholders of the parent company		589.5	200.2
Non-controlling interests		(0.6)	(13.5)
		588.9	186.7

As at (in \$ millions)	Notes	2017 31 Dec	2016 31 Dec
Assets
Non-current assets
Goodwill	13	700.8	627.7
Intangible assets	14	81.0	34.9
Property, plant and equipment	15	4,688.1	4,123.5
Interest in associates and joint ventures	16	28.7	378.5
Advances and receivables	17	35.2	34.4
Derivative financial instruments	33	5.8	25.2
Financial investments		5.5	–
Retirement benefit assets	36	–	0.3
Deferred tax assets	9	17.2	13.2
Current assets		5,562.3	5,237.7
Inventories	18	36.7	39.0
Trade and other receivables	19	497.3	499.6
Derivative financial instruments	33	36.9	53.2
Assets classified as held for sale		0.7	0.7
Construction contracts – assets	21	319.1	79.7
Other accrued income and prepaid expenses	20	176.3	216.7
Restricted cash		6.3	–
Cash and cash equivalents	22	1,109.1	1,676.4
		2,182.4	2,565.3
Total assets		7,744.7	7,803.0
Equity
Issued share capital	23	654.7	654.7
Treasury shares	24	(19.7)	(31.5)
Paid in surplus		3,033.7	3,227.5
Equity reserve	27	–	50.2
Translation reserve		(523.6)	(689.1)
Other reserves		(29.3)	(40.2)
Retained earnings		2,776.8	2,411.9
Equity attributable to shareholders of the parent company		5,892.6	5,583.5
Non-controlling interests	25	48.4	(46.9)
Total equity		5,941.0	5,536.6
Liabilities
Non-current liabilities
Non-current portion of borrowings	26	258.2	–
Retirement benefit obligations	36	30.9	9.9
Deferred tax liabilities	9	78.4	60.7
Provisions	30	67.6	61.9
Contingent liability recognised	31	7.8	7.5
Derivative financial instruments	33	0.5	12.2
Other non-current liabilities	28	49.9	51.6
		493.3	203.8
Current liabilities
Trade and other liabilities	29	892.9	823.7
Derivative financial instruments	33	24.3	40.7
Current tax liabilities		87.7	120.0
Current portion of borrowings	26	24.5	427.3
Provisions	30	76.8	108.6
Construction contracts – liabilities	21	200.0	536.2
Deferred revenue	37	4.2	6.1
		1,310.4	2,062.6
Total liabilities		1,803.7	2,266.4
Total equity and liabilities		7,744.7	7,803.0

58 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY For the year ended 31 December 2017

	Issued share	Treasury	Paid in	Equity	Translation	Other	Retained		Non controlling	Total
(in \$ millions)	capital	shares	surplus	reserve	reserve	reserves	earnings	Total	interests	equity
Balance at 1 January 2017	654.7	(31.5)	3,227.5	50.2	(689.1)		(40.2) 2,411.9 5,583.5		(46.9)	5,536.6
Comprehensive income/(loss)
Net income/(loss)	–	–	–	–	–	–	454.8	454.8	(0.2)	454.6
Foreign currency translation gain/(loss)	–	–	–	–	125.3	–	–	125.3	(0.4)	124.9
Share of other comprehensive income of associates and joint ventures	–	–	–	–	–	0.5	–	0.5	–	0.5
Remeasurement gains on defined
benefit pension schemes	–	–	–	–	–	0.4	–	0.4	–	0.4
Reclassification adjustment due to business combination	–	–	–	–	4.5	4.5	–	9.0	–	9.0
Tax relating to components of other comprehensive income	–	–	–	–	(0.5)	–	–	(0.5)	–	(0.5)
Total comprehensive income/(loss)	–	–	–	–	129.3	5.4	454.8	589.5	(0.6)	588.9
Transactions with owners
Dividends declared	–	–	(191.1)	–	–	–	–	(191.1)	–	(191.1)
Equity component of convertible bonds	–	–	–	(50.2)	–	–	50.1	(0.1)	–	(0.1)
Addition of non-controlling interest	–	–	–	–	–	–	–	–	0.2	0.2
Share-based payments	–	–	6.0	–	–	–	–	6.0	–	6.0
Vesting of share-based payments	–	–	(8.7)	–	–	–	8.7	–	–	–
Shares reallocated relating to share based payments	–	11.8	–	–	–	–	–	11.8	–	11.8
Loss on reissuance of treasury shares	–	–	–	–	–	–	(11.3)	(11.3)	–	(11.3)
Reclassification adjustment relating to business combination	–	–	–	–	–	5.5	(5.5)	–	–	–
Reclassification adjustment relating to non-controlling interest	–	–	–	–	36.2	–	(131.9)	(95.7)	95.7	–
Total transactions with owners	–	11.8	(193.8)	(50.2)	36.2	5.5	(89.9)	(280.4)	95.9	(184.5)
Balance at 31 December 2017	654.7	(19.7)	3,033.7	–	(523.6)		(29.3) 2,776.8 5,892.6		48.4	5,941.0

	Issued share	Treasury	Paid in	Equity	Translation	Other	Retained		Non controlling	Total
(in \$ millions) Balance at 1 January 2016	capital 654.7	shares (31.7)	surplus 3,223.0	reserve 63.2	reserve (452.8)	reserves	earnings	Total (55.8) 1,976.5 5,377.1	interests (30.9)	equity 5,346.2
Comprehensive income/(loss)
Net income/(loss)	–	–	–	–	–	–	436.0	436.0	(17.7)	418.3
Foreign currency translation (loss)/gain	–	–	–	–	(236.6)	–	–	(236.6)	4.2	(232.4)
Cash flow hedges	–	–	–	–	–	(2.7)	–	(2.7)	–	(2.7)
Share of other comprehensive income of associates and joint ventures	–	–	–	–	–	2.2	–	2.2	–	2.2
Remeasurement gains on defined benefit pension schemes	–	–	–	–	–	1.0	–	1.0	–	1.0
Tax relating to components of other comprehensive income	–	–	–	–	0.3	–	–	0.3	–	0.3
Total comprehensive (loss)/income	–	–	–	–	(236.3)	0.5	436.0	200.2	(13.5)	186.7
Transactions with owners
Dividends declared	–	–	–	–	–	–	–	–	(2.5)	(2.5)
Equity component of convertible bonds	–	–	–	(13.0)	–	–	12.6	(0.4)	–	(0.4)
Share-based payments	–	–	6.6	–	–	–	–	6.6	–	6.6
Vesting of share-based payments	–	–	(2.1)	–	–	–	2.1	–	–	–
Reclassification of remeasurement loss on defined benefit pension scheme	–	–	–	–	–	15.1	(15.1)	–	–	–
Shares reallocated relating to share
based payments	–	0.2	–	–	–	–	–	0.2	–	0.2
Loss on reissuance of treasury shares	–	–	–	–	–	–	(0.2)	(0.2)	–	(0.2)
Total transactions with owners	–	0.2	4.5	(13.0)	–	15.1	(0.6)	6.2	(2.5)	3.7
Balance at 31 December 2016	654.7	(31.5)	3,227.5	50.2	(689.1)			(40.2) 2,411.9 5,583.5	(46.9)	5,536.6

For the year ended (in \$ millions)	Notes	2017 31 Dec	2016 31 Dec
Net cash generated from operating activities	38	209.3	1,045.6
Cash flows from investing activities
Proceeds from disposal of property, plant and equipment		0.8	16.8
Purchases of property, plant and equipment		(146.7)	(300.3)
Purchases of intangible assets		(7.4)	(4.1)
Loans to third parties		(25.0)	–
Loan repayments from third parties		25.0	–
Loan repayments from joint venture		1.1	69.6
Loans to joint venture		(0.6)	(8.5)
Advances from joint venture		10.0	–
Loans to non-controlling interests		(0.2)	–
Interest received		24.6	17.9
Dividends received from associates and joint ventures		100.7	27.7
Acquisition of businesses (net of cash and borrowings acquired)		(146.5)	(18.0)
Investment in financial assets		(5.5)	–
Net cash used in investing activities		(169.7)	(198.9)
Cash flows from financing activities
Interest paid		(15.9)	(11.8)
Proceeds from borrowings		301.2	–
Repayments of borrowings		(252.9)	–
Repayment of derivative financial instrument		(8.0)	–
Repurchase of convertible bonds		(77.3)	(106.0)
Redemption of convertible bonds		(358.0)	–
Proceeds from reallocation of ordinary shares		0.5	–
Dividends paid to shareholders of the parent company		(191.1)	–
Dividends paid to non-controlling interests		(0.5)	(3.4)
Net cash used in financing activities		(602.0)	(121.2)
Net (decrease)/increase in cash and cash equivalents		(562.4)	725.5
Cash and cash equivalents at beginning of year	22	1,676.4	946.8
(Increase)/decrease in restricted cash		(6.3)	–
Effect of foreign exchange rate movements on cash and cash equivalents		1.4	4.1
Cash and cash equivalents at end of year	22	1,109.1	1,676.4

1. General information

Subsea 7 S.A. is a company registered in Luxembourg whose common shares trade on the Oslo Børs and as American Depositary Receipts (ADRs) over-the-counter in the US. The address of the registered office is 412F, route d'Esch, L-2086 Luxembourg.

Subsea 7 is a seabed-to-surface engineering, construction and services contractor to the offshore energy industry worldwide. The 'Group' consists of Subsea 7 S.A. and its subsidiaries at 31 December 2017.

The Group provides products and services required for subsea field development, including project management, design and engineering, procurement, fabrication, survey, installation, and commissioning of production facilities on the seabed and the tie-back of these facilities to fixed or floating platforms or to the shore. Through its i-Tech Services Business Unit, the Group offers a full spectrum of products and capabilities including remotely operated vehicles and tooling services to support exploration and production activities and to deliver full Life of Field services to its clients. Through its Renewables and Heavy Lifting Business Unit, the Group offers expertise in three specialist segments of the offshore energy market: the installation of offshore wind farm foundations; heavy lifting operations for oil and gas structures; and the decommissioning of redundant offshore structures.

Authorisation of Consolidated Financial Statements

Under Luxembourg law, the Consolidated Financial Statements are approved by the shareholders at the Annual General Meeting. The Consolidated Financial Statements were authorised for issue by the Board of Directors on 28 February 2018.

Presentation of Consolidated Financial Statements

The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU). The Consolidated Financial Statements comply with Article 4 of the EU IAS Regulation.

Amounts in the Consolidated Financial Statements are stated in US Dollars (\$), the currency of the primary economic environment in which the Group operates. Group entities whose functional currency is not the US Dollar are consolidated in accordance with the policies set out in Note 3 'Significant accounting policies'.

The Consolidated Financial Statements have been prepared on the going concern basis. This assumption is based on the level of cash and cash equivalents at the year end, the credit facilities in place, the forecast cash flows for the Group and the backlog position at 31 December 2017.

The Consolidated Financial Statements have been prepared on the historical cost basis except for the revaluation of certain financial instruments and balances required to be measured at fair value. The principal accounting policies adopted are consistent with the Consolidated Financial Statements for the year ended 31 December 2016, except where noted in Note 2 'Adoption of new accounting standards'.

2. Adoption of new accounting standards

(i) Effective new accounting standards

The Group adopted the following EU-endorsed International Financial Reporting Standards (IFRS), amendments and interpretations which were effective for the reporting period beginning on 1 January 2017. These amended standards and interpretations did not have a significant impact on the reporting of the Group's financial position or performance:

• Amendments to IAS 7 'Statement of Cash Flows'
• Amendments to IAS 12 'Recognition of Deferred Tax Assets for Unrealised Losses'
• Annual Improvements to IFRS 2014-2016 Cycle

(ii) Accounting standards, amendments and interpretations issued but not yet effective

The following new or amended IFRS standards, amendments and interpretations may be of significance to the Group but have not yet been fully assessed or early adopted:

IFRS 9 'Financial Instruments' (including amendments)

IFRS 9 replaces IAS 39 'Financial Instruments: Recognition and Measurement' and applies to three aspects of accounting for financial instruments: classification and measurement of financial assets, impairment and hedge accounting. IFRS 9 is effective for reporting periods beginning on or after 1 January 2018. With the exception of hedge accounting, retrospective application is required but provision of comparative information is not compulsory. The Group will adopt IFRS 9 for the reporting period commencing 1 January 2018 and will not restate comparative information.

2. Adoption of new accounting standards continued

During 2017 the Group completed a detailed assessment of the impacts of IFRS 9. This assessment was based on available information and may be subject to changes arising from further information which becomes available during the implementation of IFRS 9 in 2018. The Group does not expect the implementation to have a significant impact on its Consolidated Balance Sheet or Consolidated Statement of Comprehensive Income. The Implementation of IFRS 9 will result in changes in the following areas:

(i) Classification and measurement

IFRS 9 replaces the multiple classification and measurement models in IAS 39 with four different measurement models; amortised cost, fair value through profit and loss, fair value through other comprehensive income with recycling of accumulated gains and losses and fair value through other comprehensive income without recycling of accumulated gains and losses. The Group does not expect that there will be a significant impact on applying the new reporting requirements. Financial assets will continue to be initially measured at fair value with those assets classified as measured at amortised cost being measured net of transaction costs.

For debt instruments, subsequent measurement will be based on the composition of contractual cash flows and the business model under which the debt instruments are managed.

The Group's financial assets include cash and cash equivalents, derivative financial instruments measured at fair value through profit and loss, trade receivables, amounts due from associates and joint ventures and other receivables. Trade receivables, amounts due from associates and joint ventures and other receivables give rise to cash flows which are solely representative of principal and interest and therefore continue to be measured at amortised cost. Derivative financial assets continue to be measured at fair value through profit and loss. The Group holds equity shares in non-listed companies which are intended to be held for the foreseeable future, as a result the Group has made an irrevocable election to measure financial investments at fair value through other comprehensive income. Any dividends generated by the investment will be recognised in the Consolidated Income Statement.

IFRS 9 amends the accounting requirements for financial liabilities optionally designated at fair value through profit and loss and now requires the change in fair value attributable to changes in the Group's own credit risk to be recognised directly in other comprehensive income. This requirement will not impact the Group as all financial liabilities are either measured at amortised cost or, in the case of derivative financial instruments, mandatorily measured at fair value through profit and loss.

(ii) Hedge accounting

IFRS 9 introduces new principle-based hedge accounting rules aimed at creating improved alignment with risk management practices. IFRS 9 does not change the general principles of how an entity accounts for effective hedges but it does result in more economic hedging strategies becoming eligible for hedge accounting. Hedge effectiveness testing will change to being fully prospective and largely qualitative in nature and there will be changes to what qualifies for designation as a hedged item. The Group does not currently apply hedge accounting and as a result the implementation of IFRS 9 will not have an impact on the Group's Consolidated Financial Statements. Should the Group hedge account in the future the requirements of IFRS 9 are not expected to result in significant changes to the Group's hedge accounting strategy.

(iii) Impairment

The implementation of IFRS 9 demands a change from an incurred loss impairment model to an expected credit loss (ECL) impairment model and requires the Group to record allowances for expected credit losses, either on a 12-month or lifetime perspective. The ECL model will apply to debt instruments, certain loan commitments and construction contract assets under IFRS 15 ' Revenue from Contracts with Customers' and lease receivables under both IAS 17 'Leases' and IFRS 16 'Leases'.

IFRS 9 permits the application of a simplified approach for specific balances with allowances for lifetime expected credit losses recognised upon initial recognition. Where allowances for expected credit losses are material, the Group intends to apply the simplified approach on trade receivables and construction contract assets. For all other balances to which IFRS 9 applies, the Group will apply the general 'three stage' approach and where material will recognise allowances for credit losses on a 12-month perspective.

A review of the historic occurrence of credit losses indicates that annual credit losses are not material to the Consolidated Financial Statements. The outlook for the oil and gas and renewable energy industries are not expected to result in a significant change in the Group's exposure to credit losses. Credit losses are expected to be insignificant due to the nature of the Group's clients and the services provided. Based on the work performed the Group is satisfied that on initial implementation of IFRS 9 expected credit losses will not be material to the Consolidated Financial Statements.

IFRS 15 'Revenue from Contracts with Customers' (including amendments)

IFRS 15 establishes a five-step model to account for revenue arising from contracts with clients. Under IFRS 15, revenue is recognised at an amount that reflects the consideration to which an entity expects to be entitled in exchange for transferring goods or services to a client. IFRS 15 replaces IAS 18 'Revenue' and IAS 11 'Construction Contracts' upon which the Group's current revenue recognition policies are based. Either a full retrospective application or a modified retrospective application for IFRS 15 is permitted for reporting periods beginning on or after 1 January 2018 with early adoption permitted. Management intend to adopt IFRS 15 for the period commencing 1 January 2018 using the modified retrospective approach.

During 2016, the Group performed a preliminary assessment of the impacts of IFRS 15, and a more detailed analysis was completed in 2017. Management have concluded that the majority of lump-sum EPIC contracts will be assessed to have one distinct performance obligation, treated as bundled, due to the significant integration and customisation and the highly related promises within each contract, with revenue being recognised over time. The Group's day-rate projects, which include PLSV contracts, will also be one distinct performance obligation, treated as a series, due to the overall promise to deliver a series of days that are substantially the same and have the same pattern of transfer to the client, with revenue being recognised over time.

Management have assessed the impact that IFRS 15 will have on the Group, taking into account the range of contractual terms and conditions. In preparation for the adoption of IFRS 15, Management have concluded the following:

(i) Onerous contract provisions

Following the implementation of IFRS 15 all onerous contract provisions effective from 1 January 2018 have been calculated in accordance with IAS 37, 'Provisions, Contingent Liabilities and Contingent Assets'. At present, within the Group, only day-rate contracts are governed by the requirements of IAS 37. As a result of the implementation of IFRS 15 all lump-sum projects have been reassessed and onerous contract provisions restated, where required, at 1 January 2018. The requirements of IAS 37 prescribe that an onerous provision must be calculated on a least net cost basis, which only includes unavoidable costs, and comparing these costs to the cost of cancelling a contract and incurring early termination fees.

As a result of the reassessment and restatement of lump-sum onerous contract provisions the Group expects to increase retained earnings at 1 January 2018 by \$3.9 million. This adjustment represents a reduction in two specific lump-sum project onerous provisions as a result of the application of IFRS 15.

In addition the onerous contract provision of \$95.0 million, which at 31 December 2017 is included on the Consolidated Balance Sheet within 'Construction contract – liabilities', will be reallocated to 'Provisions'. There will be no impact on retained earnings as a result of this reallocation.

(ii) Combination or separation of contract amendments

Under the requirements of IFRS 15, subsequent modifications to contracts or scope amendments are regarded as separate contracts to the initial main contract unless the combining criteria are met. During 2017 an analysis was performed on a contractby-contract basis on all contracts, from inception, not considered to be 'completed' at 31 December 2017, as defined by IFRS 15. Detailed considerations were undertaken in relation to contractual arrangements, variation orders and work performed under frame agreements.

As a result of the implementation of IFRS 15, in respect of combination or separation of contract amendments, the Group does not anticipate any adjustments to retained earnings.

(iii) Variable consideration

Certain contracts with clients include clauses in relation to performance bonuses, liquidated damages and provisional sums. Management have concluded that, under the new standard, these sums will be included within the total contract price once they can be reasonably estimated and will not result in a 'significant revenue reversal' as defined in IFRS 15. This is consistent with the approach currently adopted by the Group.

As such the Group does not anticipate any adjustments to retained earnings as a result of variable consideration requirements. Project reporting terminology, as utilised by management, on variable consideration will be amended to ensure external and internal reporting align.

(iv) Contracts with significant procurement

Under IFRS 15, in circumstances where there is significant procurement of items which are not customised or specifically designed for that contract, recognising a contract-wide margin before the offshore phase commences may overstate revenue. During 2017 the Group assessed whether the removal of such procured items from the principal percentage-of-completion calculation was required and whether this would have a significant impact on revenue recognition. Management has concluded that the majority of lump-sum contracts will be unaffected by this requirement as procured items are generally customised for individual contracts. It is anticipated that there may be instances in the future where non-customised procurement may require to be excluded from the principal percentage-of-completion calculation in order to prevent the overstatement of revenue during the early stages of contract execution.

(v) Practical expedient

The Group has evaluated whether the practical expedient permitted under IFRS 15, allowing the recognition of revenue equivalent to the amount invoiced, may be adopted in relation to certain contracts where, typically, monthly invoices are issued according to the number of days worked. The Group has concluded that this practical expedient will be adopted in relation to certain day-rate contracts, which include PLSV contracts.

(vi) Other matters

Management has considered the requirements of IFRS 15 specifically in relation to significant financing, inefficiencies, warranties and principal/ agent considerations and do not consider that these will result in a material amendment to the revenue and margin recognised for each accounting period when compared with the current application of IAS 18 and IAS 11.

(vii) Presentation and disclosure requirements

IFRS 15 includes detailed presentation and disclosure requirements. The presentation requirements significantly increase the level of disclosures required within the Group's Consolidated Financial Statements. During 2016 and 2017 the Group formulated a plan to develop appropriate systems, internal controls, policies and procedures to collate and disclose the required information. From 1 January 2018 the Group is well positioned to meet the presentation and disclosure requirements of IFRS 15 and will disclose disaggregated revenue as part of the current segmental reporting requirements in the Group's 2018 quarterly earnings releases. Full IFRS 15 disclosure will be presented in the Group's 2018 Consolidated Financial Statements and thereafter.

The impact on the Consolidated Balance Sheet as of 1 January 2018 ((increase)/decrease) was as follows:

(in \$ millions)	Retained earnings	Construction contracts – liabilities	Provisions
Onerous contract provisions	(3.9)	95.0	(91.1)

IFRS 16 'Leases'

IFRS 16 replaces IAS 17 'Leases' and establishes new recognition, measurement and disclosure requirements for both parties to a lease contract. IFRS 16 is effective for reporting periods beginning on or after 1 January 2019. The Group plans to adopt the new standard on the required effective date and will not restate comparative information. The Group is in the process of finalising its evaluation of the impact of IFRS 16.

Under IFRS 16 a lease is defined as a contract, or part of a contract, that conveys the right to use an asset for a period of time in exchange for consideration. IFRS 16 eliminates the classification of a lease as either an operating lease or finance lease for lessees and introduces a single model for all leases with the exception of leases for low-value assets or for periods of less than twelve months.

The single model will require lessees to recognise most leases on the balance sheet as lease liabilities. A corresponding asset will be recognised which represents the right to use the leased asset.

These requirements will result in significant changes to the accounting model applied for the lessee, however lessor accounting will, in substance, remain unchanged. The new method will not result in significant changes where leases were previously accounted for as finance leases. Where leases were previously accounted for as operating leases there will be significant changes. The balance sheet will be impacted by increased financial liabilities and corresponding leased assets, and the income statement will also be impacted with operating lease expenses being replaced with interest and depreciation charges.

At 31 December 2017 the Group had \$339.8 million of commitments under operating leases for vessels, land and buildings and equipment. The adoption of IFRS 16 will result in a number of these leases being recognised on the balance sheet as lease liabilities with equivalent right-of-use assets recognised within property, plant and equipment. Application of the revised model will have an impact on both the balance sheet, where total assets and total liabilities will increase, and the income statement, where the lease expense recognition pattern will generally be accelerated compared to the current treatment. Balance sheet and income statement metrics including debt leverage, finance ratios and Adjusted EBITDA will also be impacted. The cash flow statement for leases could be affected with principal payments being presented within financing activities as opposed to operating activities.

IFRIC Interpretation 22 – Foreign Currency Transactions and Advance Consideration

This interpretation provides clarification on the spot exchange rate to be used on both the initial recognition, and subsequent derecognition (including any associated income or expense), of a non-monetary asset or liability related to advance consideration in a foreign currency. The interpretation clarifies that the date of the transaction is the date on which the non-monetary asset or liability resulting from advance consideration should be recognised. It also clarifies that individual transaction dates must be identified when there are multiple payments or receipts in advance. This interpretation is effective for reporting periods beginning on or after 1 January 2018, subject to endorsement for EU entities, with early adoption permitted. The Group does not expect this interpretation to have a significant impact on its Consolidated Financial Statements.

IFRIC Interpretation 23 – Uncertainty over Income Tax Treatments

This interpretation provides clarification on accounting for income taxes when tax treatments involve uncertainty which affects the recognition and measurement requirements within IAS 12 'Income Taxes'. The interpretation addresses whether an entity considers uncertain tax treatments separately, the assumptions an entity makes about the examination of tax treatment by taxation authorities, how an entity determines taxable income, tax bases, unutilised tax losses, tax credits and tax rates and how an entity considers changes in facts and circumstances. An entity has to determine whether to consider each uncertain tax treatment separately or together and should follow the approach that more appropriately predicts the resolution of the uncertainty. This interpretation is effective for reporting periods beginning on or after 1 January 2019 but certain transitional reliefs are available. The Group does not expect this interpretation to have a significant impact on its Consolidated Financial Statements.

Annual improvements cycle to IFRS 2015 – 2017

The annual improvements project provides a mechanism for making necessary, but non-urgent amendments to IFRS. None of these amendments are expected to have a significant impact on the Group's financial position or performance.

65

3. Significant accounting policies

Basis of consolidation

The Consolidated Financial Statements incorporate the financial statements of Subsea 7 S.A. ('the Company') and entities controlled by the Company (its subsidiaries). Control is assumed to exist where the Group is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee.

The Group reassesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the elements of control. If the Group loses control over a subsidiary it derecognises related assets, liabilities and non-controlling interests and other components of equity, while any resultant gain or loss is recognised in income or loss. Any investment retained is recognised at fair value.

The Group consolidates non-wholly-owned subsidiaries where it holds less than 50% of the voting rights when the remaining voting rights are held by multiple shareholders and there is no history of the other shareholders collaborating to exercise their votes collectively or to outvote the Group.

Subsidiaries

Assets, liabilities, income and expenses of a subsidiary are included in the Consolidated Financial Statements from the date the Group obtains control over the subsidiary until the date the Group ceases to control the subsidiary. Changes in the Group's interest in a subsidiary that do not result in the Group ceasing to control that subsidiary are accounted for as equity transactions.

Where necessary, adjustments are made to the financial statements of subsidiaries to align these with the accounting policies of the Group. All intra-group transactions, balances, income and expenses are eliminated on consolidation.

Note 40 'Wholly-owned subsidiaries' includes information related to wholly-owned subsidiaries which are included in the Consolidated Financial Statements of the Group.

All subsidiaries are wholly-owned (100%) except those listed in Note 25 'Non-controlling interests'. Non-controlling interests comprise equity interests in subsidiaries which are not attributable, directly or indirectly to the Company. Non-controlling interests in the net assets or liabilities of subsidiaries are identified separately from the equity attributable to shareholders of the parent company. Noncontrolling interests consist of the amount of those interests at the date that the Group obtains control over the subsidiary together with the non-controlling shareholders' share of net income or loss and other comprehensive income or loss since that date.

Interests in associates and joint arrangements

An associate is an entity over which the Group has significant influence, but not control, and which is neither a subsidiary nor a joint venture. Significant influence is defined as the right to participate in the financial and operating policy decisions of the investee, but is not control or joint control over those policies.

A joint arrangement is an arrangement of which two or more parties have joint control. A joint arrangement is classified as either a joint venture or a joint operation depending upon the rights and obligations of the parties to the arrangement.

A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement.

A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement.

Interests in associates and joint ventures are accounted for using the equity method. Under this method, the investment is carried in the Consolidated Balance Sheet at cost plus post-acquisition changes in the Group's share of net assets of the associate or joint venture, less any provisions for impairment. The Consolidated Income Statement reflects the Group's share of net income of the associate or joint venture. Losses in excess of the Group's interest (which includes any long-term interests that, in substance, form part of the Group's net investment) are only recognised to the extent that the Group has incurred legal or constructive obligations or made payments on behalf of the associate or joint venture. Where there has been a change recognised directly in the equity of the associate or joint venture, the Group recognises its share in the Consolidated Statement of Comprehensive Income.

Interests in joint operations are accounted for in line with the Group's proportional interest in the joint operations. As a joint operator the Group recognises its interest in; assets (including its share of any assets held jointly); liabilities (including its share of any liabilities incurred jointly); revenue from the sale of its share of output by the joint operation and expenses (including its share of any expenses incurred jointly).

Revenue recognition

Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods and services provided by the Group in the normal course of business, net of discounts and sales-related taxes.

Service revenues

Revenues received for the provision of services under charter agreements, day-rate contracts, reimbursable contracts, cost-plus contracts and similar contracts are recognised on the accrual basis as services are provided.

Long-term construction contracts – general

The Group accounts for long-term construction contracts, including engineering, procurement, installation and commissioning (EPIC) contracts, using the percentage-of-completion method. Revenue and gross profit are recognised in each period based upon the advancement of the work-in-progress. Provisions for anticipated losses are made in full in the period in which they become known.

If the stage of completion is insufficient to enable a reliable estimate of gross profit to be established (typically when less than 5% completion has been achieved), revenues are recognised to the extent of contract costs incurred where it is probable that these costs will be recoverable.

3. Significant accounting policies continued

Revenue recognition continued

A significant portion of the Group's revenue is invoiced under fixed-price contracts. However, due to the nature of the services performed, variation orders and claims are commonly invoiced to clients in the normal course of business.

Additional contract revenue arising from variation orders is recognised when it is probable that the client will approve the variation and the amount of revenue arising from the variation can be reliably measured. A claim is an amount that may be collected as reimbursement for costs not included in the contract price. A claim may arise from delays caused by clients, errors in specifications or design, and disputed variations in contract work. Additional contract revenue resulting from claims is recognised only when negotiations have reached an advanced stage such that it is virtually certain that the client will accept the claim and that the amount can be measured reliably.

During the course of multi-year projects accounting estimates may change. The effects of such changes are accounted for in the period of change and the cumulative income recognised to date is adjusted to reflect the latest estimates. Such revisions to estimates do not result in restating amounts in previous periods.

Long-term construction contracts are presented in the Consolidated Balance Sheet as 'Construction contracts – assets' when project revenues plus any full-life project onerous contract provisions recognised exceed progress billings, or as 'Construction contracts – liabilities' when progress billings exceed project revenues plus any full-life project onerous contract provision recognised.

Long-term construction contracts – SURF and Conventional contracts

The Group's SURF and Conventional EPIC contracts are accounted for by applying the cost-to-cost percentage-of-completion method based on the ratio of costs incurred to date to total estimated costs at completion. The application of this cost based percentage-of-completion method is considered to most accurately represent the advancement of work-in-progress for SURF and Conventional contracts where the phasing of expenditure is closely linked to the stage of completion of contract activity. Contract revenues and total cost estimates at completion are reviewed by Management on a monthly basis. This percentage cost progression is then applied to full-project forecasts of revenue to determine revenue recognised in a particular period.

Long-term Construction Contracts – Renewable contracts

In certain specific cases the Group's renewable engineering, procurement, construction and installation (EPCI) contracts are accounted for by applying the physical progression percentage-of-completion method which reliably measures work performed and the associated recognition of revenue and profit for these types of contract. In these particular projects the application of the cost-to-cost method rather than physical progression method of percentage-of-completion may accelerate revenue and profit recognition due to the typically high proportion of procurement costs, within total project costs. Advancement against individual work scopes and contractual performance obligations are reviewed by Management on a monthly basis.

Dry-dock, mobilisation and decommissioning expenditure

Dry-dock expenditure incurred to maintain a vessel's classification is capitalised in the Consolidated Balance Sheet as a distinct component of the asset and amortised over the period until the next scheduled dry-docking (usually between two-and-a-half years and five years). At the date of the next dry-docking, the previous dry-dock asset and accumulated amortisation is derecognised. All other repair and maintenance costs are recognised in the Consolidated Income Statement as incurred.

Mobilisation expenditure, which consists of expenditure incurred prior to the deployment of vessels or equipment, is classified as prepayments and amortised over the project life.

A provision is recognised for decommissioning expenditures required to restore a leased vessel to its original or agreed condition, together with a corresponding amount capitalised as property, plant and equipment, when the Group recognises it has a present obligation and a reliable estimate can be made of the amount of the obligation.

Leasing

The determination of whether an arrangement is or contains a lease is based on the substance of the arrangement at inception date, whether the fulfilment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys a right to use an asset. Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases.

The Group as lessee

Operating lease payments are recognised as an expense in the Consolidated Income Statement on a straight-line basis over the lease term. Initial direct costs incurred in negotiating and arranging an operating lease are aggregated and recognised on a straight-line basis over the lease term. Benefits received and receivable as an incentive to enter into an operating lease are recognised on the same basis as the related lease.

Improvements to leased assets are expensed in the Consolidated Income Statement unless they significantly increase the value of the leased asset, under which circumstance this expenditure is capitalised in the Consolidated Balance Sheet and subsequently recognised as an expense in the Consolidated Income Statement on a straight-line basis over the lease term applicable to the leased asset.

The Group as lessor

Assets leased to third parties are presented in the Consolidated Balance Sheet as a finance lease receivable at an amount equal to the net investment in the lease.

Foreign currency translation

Each entity in the Group determines its own functional currency and items included in the financial statements of each entity are measured using that functional currency. Functional currency is defined as the currency of the primary economic environment in which the entity operates. While this is usually the local currency, the US Dollar is designated as the functional currency of certain entities where transactions and cash flows are predominantly in US Dollars.

All transactions in non-functional currencies are initially translated into the functional currency of each entity at the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in non-functional currencies are translated to the functional currency at the exchange rate prevailing at the balance sheet date.

All resulting exchange rate differences are recognised in the Consolidated Income Statement. Non-monetary items which are measured at historic cost in a non-functional currency are translated into the functional currency using the exchange rates prevailing at the dates of the initial transactions. Non-monetary items which are measured at fair value in a non-functional currency are translated to the functional currency using the exchange rate prevailing at the date when the fair value was determined.

Foreign exchange revaluations of short-term intra-group balances denominated in non-functional currencies are recognised in the Consolidated Income Statement. Revaluations of long-term intra-group loans are recognised in the translation reserve in equity.

The assets and liabilities of operations which have a non-US Dollar functional currency are translated into the Group's reporting currency, US Dollar, at the exchange rate prevailing at the balance sheet date. The exchange rate differences arising on the translation are recognised in the translation reserve in equity. Income and expenditure items are translated at the weighted average exchange rates for the year. On disposal of an entity with a non-US Dollar functional currency the cumulative translation adjustment previously recognised in the translation reserve in equity is reclassified to the Consolidated Income Statement. At 31 December 2017, the exchange rates of the main currencies used throughout the Group, compared to the US Dollar, were as follows:

GBP 0.747 EUR 0.842 NOK 8.410 BRL 3.291

Borrowing costs

Borrowing costs attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to prepare for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use. These amounts are calculated using the effective interest rate related to the period of the expenditure. All other borrowing costs are recognised in the Consolidated Income Statement in the period in which they are incurred.

Finance costs

Finance costs or charges, including premiums on settlement or redemption and direct issue costs, are accounted for on an accruals basis using the effective interest rate method.

Retirement benefit costs

The Group administers several defined contribution pension plans. Obligations in respect of such plans are charged to the Consolidated Income Statement as they fall due.

In addition, the Group administers a small number of defined benefit pension plans. The cost of providing benefits under the defined benefit plans is determined separately for each plan using the projected unit credit actuarial valuation method.

Remeasurements, comprising actuarial gains and losses and the return on plan assets, (excluding net interest), are recognised immediately through the Consolidated Statement of Comprehensive Income in the period in which they occur with a corresponding adjustment in the Consolidated Balance Sheet. Remeasurements are not reclassified to the Consolidated Income Statement in subsequent periods.

Past service costs are recognised in the Consolidated Income Statement on the earlier of the date of the plan amendment or curtailment, and the date that the Group recognises restructuring related costs.

Net interest is calculated by applying the discount rate to the net defined benefit liability or asset. The Group recognises portions of the service cost (comprising current and past service costs) gains and losses on curtailments, non-routine settlements and net interest expense or income in the net defined benefit obligation under both operating expenses and administration expenses in the Consolidated Income Statement. The Group is also committed to providing lump-sum bonuses to employees upon retirement in certain countries. These retirement bonuses are unfunded, and are recorded in the Consolidated Balance Sheet at their actuarial valuation.

Taxation

Taxation expense or income recorded in the Consolidated Income Statement or Consolidated Statement of Other Comprehensive Income represents the sum of the current tax and deferred tax charge or credit for the year.

3. Significant accounting policies continued

Current tax

Current tax is based on the taxable income for the year, together with any adjustments to tax payable in respect of prior years. Taxable income differs from income before taxes as reported in the Consolidated Income Statement because it excludes items of income or expense that are taxable or deductible in other periods and further excludes items that are never taxable or deductible. The tax laws and rates used to compute the amount of current tax payable are those that are enacted or substantively enacted at the balance sheet date. Current tax relating to items recognised directly in equity is recognised in equity and not the Consolidated Statement of Other Comprehensive Income.

Current tax assets or liabilities are representative of taxes being owed by, or owing to, local tax authorities. In determining current tax assets or liabilities the Group takes into account the impact of uncertain tax positions and whether additional taxes or penalties may be due.

Deferred tax

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amount of assets and liabilities in the Consolidated Financial Statements and the corresponding tax bases used in the computation of taxable income, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable income will be available against which deductible temporary differences can be utilised. Such assets or liabilities are not recognised if the temporary difference arises from the initial recognition of goodwill or from the initial recognition of other assets or liabilities in a transaction (other than in a business combination) that does not affect either the taxable income or the accounting income before taxes.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and interests in associates, and joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

The carrying amount of deferred tax assets is reviewed at each reporting date. Deferred tax assets are only recognised to the extent that it is probable that taxable income will be available against which deductible temporary differences can be utilised. Deferred tax assets are derecognised or reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered.

Deferred tax is calculated at the tax rates that are substantively enacted and expected to apply in the period when the asset is realised or the liability is settled. Deferred tax is charged or credited to the Consolidated Income Statement, except when it relates to items charged or credited directly in the Consolidated Statement of Comprehensive Income in which case the deferred tax is also recognised within the Consolidated Statement of Comprehensive Income.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to set-off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current income tax assets and liabilities on a net basis.

Tax contingencies and provisions

A provision for an uncertain tax position is made where the ultimate outcome of a particular tax matter is uncertain. In calculating a provision the Group assesses the probability of the liability arising and, where a reasonable estimate can be made, provides for the liability it considers probable to be required to settle the present obligation. Provisions are based on experience of similar transactions, internal estimates and appropriate external advice.

Business combinations and goodwill

Acquisitions of subsidiaries and businesses, including business combinations completed in stages, are accounted for using the acquisition method. The consideration for each acquisition is measured as the aggregate of the fair values (at the date of exchange) of cash and other assets given, liabilities incurred or assumed, and equity instruments issued by the Group in exchange for control of the acquiree. Where an acquisition qualifies as a business combination completed in stages, consideration includes the fair value of the Group's equity interest prior to the combination. Any gain or loss associated with the remeasurement of the equity accounted investment to fair value is recognised as a remeasurement gain or loss. Acquisition-related costs are recognised in the Consolidated Income Statement as incurred.

Where applicable, the consideration for the acquisition includes any asset or liability resulting from a contingent consideration arrangement, measured at its acquisition date fair value. Subsequent changes in such fair values are adjusted against the cost of acquisition where they qualify as measurement period adjustments. All other subsequent changes in the fair value of contingent consideration classified as an asset or liability are accounted for in accordance with relevant IFRSs. Changes in the fair value of contingent consideration classified as equity are not recognised. The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 'Business Combinations' are recognised at fair value on the acquisition date, except that:

• deferred tax assets or liabilities are recognised and measured in accordance with IAS 12 'Income Taxes'
• liabilities or assets related to employee benefit arrangements are recognised and measured in accordance with IAS 19 'Employee Benefits'
• liabilities or equity instruments related to the replacement by the Group of an acquiree's share-based payment awards are measured in accordance with IFRS 2 'Share-based Payments'
• assets (or disposal groups) that are classified as held for sale in accordance with IFRS 5 'Non-current Assets Held for Sale and Discontinued Operations', are measured in accordance with that standard.

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Group reports provisional amounts for the items for which the accounting is incomplete, to the extent that the amounts can be reasonably calculated. These provisional amounts are adjusted during the measurement period, or additional assets or liabilities are recognised, to reflect new information obtained regarding facts and circumstances that existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date.

69

The measurement period is the period from the date of acquisition to the date the Group obtains complete information regarding facts and circumstances that existed as of the acquisition date and is subject to a maximum period of one year.

Goodwill

Goodwill arising in a business combination is recognised as an asset at the date that control is acquired (the acquisition date). Goodwill is measured as the sum of the consideration and either, the amount of any non-controlling interests in the acquiree or, the fair value of the acquirer's previously held equity interest in the entity less the net fair value of the identifiable assets acquired and the liabilities assumed at the acquisition date. If the Group's interest in the fair value of the acquiree's identifiable net assets exceeds the sum of the consideration and either, the amount of any non-controlling interests in the acquiree or, the fair value of the acquirer's previously held equity interest in the acquiree, the excess is recognised immediately in the Consolidated Income Statement. Goodwill is reviewed for impairment at least annually.

Gain on a bargain purchase

A gain arising on a bargain purchase is recognised in the Consolidated Income Statement on the date that control is acquired (the acquisition date). The gain is measured as the net fair value of the identifiable assets acquired and liabilities assumed at the acquisition date less the sum of the consideration.

Intangible assets other than goodwill

Overview

Intangible assets acquired separately are measured at cost at the date of initial acquisition. Following initial recognition, intangible assets are measured at cost less amortisation and impairment charges.

Intangible assets acquired as part of a business combination are measured at fair value at the date of acquisition. Following initial recognition, intangible assets acquired in a business combination are measured at acquisition date fair value less amortisation and impairment charges.

Internally generated intangible assets are not capitalised, with the exception of development expenditure which meets the criteria for capitalisation.

Intangible assets with finite lives are amortised over their useful economic life and are assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortisation period and the amortisation method for intangible assets with finite useful lives are reviewed at least annually. Changes in the expected useful lives are accounted for by changing the amortisation period or method, and are treated as changes in accounting estimates. The amortisation expense related to intangible assets with finite lives is recognised in the Consolidated Income Statement in the expense category consistent with the function of the intangible asset.

Research and development costs

Research costs are expensed as incurred. The Group recognises development expenditure as an internally generated intangible asset when the criteria for recognition specified in IAS 38 'Intangible Assets' are met.

Amortisation of the asset over the period of the expected future benefit begins when development is complete and the asset is available for use. The asset is tested for impairment whenever there is an indication that the asset may be impaired.

Property, plant and equipment

Property, plant and equipment acquired separately, including critical spare parts acquired and held for future use, are measured at cost less accumulated depreciation and accumulated impairment charges.

Assets under construction are carried at cost, less any recognised impairment charge. Depreciation of these assets commences when the assets become operational and either commence activities or are deemed available for service.

Depreciation is calculated on a straight-line basis over the useful life of the asset as follows:

Vessels	10 to 25 years
Operating equipment	3 to 10 years
Buildings	20 to 25 years
Other assets	3 to 7 years

Land is not depreciated.

Vessels are depreciated to their estimated residual value. Residual values, useful economic lives and methods of depreciation are reviewed at least annually and adjusted if appropriate.

Gains or losses arising on disposal of property, plant and equipment are determined as the difference between any disposal proceeds and the carrying amount of the asset at the date of the transaction. Gains and losses on disposal are recognised in the Consolidated Income Statement in the period in which the asset is disposed.

Tendering costs

Costs incurred in the tendering process are expensed in the Consolidated Income Statement as incurred.

3. Significant accounting policies continued

Impairment of non-financial assets

At each reporting date the Group assesses whether there is any indication that non-financial assets may be impaired. If any such indication exists, or when annual impairment testing for an asset is required, the Group estimates the asset's recoverable amount. An asset's recoverable amount is the higher of the asset's fair value less costs of disposal and its value-in-use. Where an asset does not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the cash-generating unit (CGU) to which the asset is allocated. Where the carrying amount of an asset exceeds its recoverable amount, the asset is considered impaired and is written down to its recoverable amount. In assessing value-in-use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and risks specific to the asset. In determining fair value less costs of disposal, an appropriate valuation model is used.

Impairment charges are recognised in the Consolidated Income Statement in the expense category consistent with the function of the impaired asset.

An assessment is made at each reporting date as to whether there is any indication that previously recognised impairment charges may no longer exist or may have decreased. If such an indication exists the Group makes an estimate of the recoverable amount. A previously recognised impairment charge is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment charge was recognised. If that is the case the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment charge been recognised for the asset in prior periods. Any such reversal is recognised in the Consolidated Income Statement. The following criteria are also applied in assessing impairment of specific assets:

Goodwill

An assessment is made at each reporting date as to whether there is an indication of impairment. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that the carrying amount may be impaired. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group's CGUs, or groups of CGUs, that are expected to benefit from the combination.

Each unit or group of units to which the goodwill is allocated initially represents the lowest level within the Group at which the goodwill is monitored for internal management purposes and is not larger than an operating segment determined in accordance with IFRS 8 'Operating Segments'. If circumstances give rise to a change in the composition of CGUs and a reallocation is justified, goodwill is reallocated based on relative value at the time of the change in composition. Following any reorganisation the CGU cannot be larger than an operating segment determined in accordance with IFRS 8 'Operating Segments'. Impairment is determined by assessing the recoverable amount of the CGU (or group of CGUs), to which the goodwill relates. Recoverable amounts are determined based on value-in-use calculations using discounted pre-tax cash flow projections based on risk adjusted financial forecasts approved by the Executive Management Team.

As cash flow projections are risk adjusted for CGU specific risks, risk premiums are not applied to the discount rate which is applied to all CGUs. The discount rate applied to the cash flow projections is a pre-tax rate and reflects current market assessments of the time value of money, risks specific to the asset and a normalised capital structure for the industry. Where the recoverable amount of the CGU (or group of CGUs) is less than the carrying amount, an impairment charge is recognised in the Consolidated Income Statement.

Where goodwill forms part of a CGU (or group of CGUs) and part of the operation within that unit is disposed, the goodwill associated with the operation disposed is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation. Goodwill disposed in this circumstance is measured based on the relative values of the operation disposed and the portion of the CGU retained.

Associates and joint ventures

At each reporting date the Group determines whether there is any objective evidence that the investment in an associate or joint venture is impaired. If this is the case, the Group calculates the amount of impairment as being the difference between the estimated fair value of the associate or joint venture and its carrying amount. The resultant impairment charge is recognised in the Consolidated Income Statement.

Inventories

Inventories comprise consumables, materials and non-critical spares and are valued at the lower of cost and net realisable value.

Financial instruments

The Group's financial assets include cash and short-term deposits, trade and other receivables, loans and other receivables and derivative financial instruments and equity investments.

The Group's financial liabilities include trade and other payables, contingent consideration, borrowings and derivative financial instruments.

All financial instruments are initially measured at fair value net of transaction costs, with the exception of those classified as fair value through profit or loss and all derivative financial instruments which are measured at fair value.

Derivative financial instruments

The Group enters into both derivative financial instruments and non-derivative financial instruments in order to manage its foreign currency exposures. The principal derivative financial instruments used are forward foreign currency contracts.

All derivative transactions are undertaken and maintained in order to manage the foreign currency and interest rate risks associated with the Group's underlying business activities and the financing of those activities.

Derivative financial instruments embedded in other financial instruments or other host contracts are treated as separate derivative financial instruments when their risks and characteristics are not closely related to those of the host contracts and the host contracts are not carried at fair value. Unrealised gains or losses are reported in the Consolidated Income Statement and are included within derivative financial instruments in the Consolidated Balance Sheet. The Group will only reassess the existence of an embedded derivative if the terms of the host financial instrument change significantly.

71

After initial recognition the fair values of derivative financial instruments are measured on bid prices for assets held and offer prices for issued liabilities based on values quoted in active markets. Changes in the fair value of derivative financial instruments that do not qualify for hedge accounting (including embedded derivative financial instruments) are recognised in the Consolidated Income Statement within other gains and losses.

Hedge accounting

At the inception of the hedge relationship, the Group documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents its assessment as to whether the hedging instrument that is used in a hedging relationship is highly effective in offsetting changes in fair values or cash flows of the hedged item.

Changes in the carrying amount of financial instruments that are designated as hedges of future cash flows (cash flow hedges) and are found to be effective are recognised directly in equity. Any portion of the derivative that is excluded from the hedging relationship, together with any ineffectiveness, is recognised immediately in other gains and losses in the Consolidated Income Statement. Where a non-financial asset or a non-financial liability results from a forecast transaction or firm commitment being hedged, the amount deferred in equity is included in the initial measurement of that non-monetary asset or liability. Any cumulative gains or losses relating to cash flow hedges recognised in equity are retained in equity and subsequently recognised in the Consolidated Income Statement in the same period in which the previously hedged item affects the Consolidated Income Statement.

Hedge accounting is discontinued when the hedging instrument expires or is sold, terminated, exercised, or no longer qualifies for hedge accounting and the net cumulative gains or losses recognised in equity are immediately recognised in the Consolidated Income Statement.

Financial investments

The Group's financial investments comprise strategic shareholdings in technology companies. These investments are held at cost, deemed an appropriate estimate of fair value, due to the uncertainty over technical milestones and the wide range of possible fair value measurements. These investments are reviewed for indicators of impairment at each reporting date.

Cash and cash equivalents

Cash and cash equivalents in the Consolidated Balance Sheet comprise cash at bank, cash on hand, money market funds, and shortterm highly liquid assets with an original maturity of three months or less and readily convertible to known amounts of cash. Utilised revolving credit facilities are included within current borrowings.

Trade receivables and other receivables

The Group assesses at each reporting date whether any indicators exist that a financial asset or group of financial assets is impaired.

In relation to trade receivables, a provision for impairment is made when there is objective evidence that the Group may not be able to collect all, or part, of the amounts due. Impaired trade receivables are derecognised when they are assessed as uncollectible.

Loans receivable and other receivables are carried at amortised cost using the effective interest rate method. Interest income, together with gains and losses when the loans and receivables are derecognised or impaired, is recognised in the Consolidated Income Statement.

Convertible bonds

The components of the convertible bonds issued by the Group that exhibit characteristics of a liability are recognised as a liability, net of transaction costs, in the Consolidated Balance Sheet. On issuance of convertible bonds, the fair value of the liability component is determined using a market rate for equivalent non-convertible bonds. This amount is classified as a financial liability measured at amortised cost using the effective interest rate method until it is extinguished on conversion, repurchase or redemption.

The fair value of the instrument, which is generally the net proceeds less the fair value of the liability, net of transaction costs, is allocated to the conversion option which is recognised and included in the equity reserve within shareholders' equity. The carrying amount of the conversion option is not remeasured.

Transaction costs are apportioned between the liability and equity components of the convertible bonds based on the allocation of proceeds to the liability and equity components when the instruments are first recognised.

Bonds which are repurchased by the Group are accounted for as an extinguishment of the associated financial liability and repurchase of the associated conversion option. An amount equivalent to the proportional nominal par value of bonds reacquired is transferred from the equity reserve to retained earnings.

Treasury shares

Treasury shares are the Group's own equity instruments which are repurchased and deducted from equity at cost. Gains or losses realised or incurred on the purchase, sale, issue or cancellation of the Group's own equity instruments are recognised within equity. No gains or losses are recognised in the Consolidated Income Statement.

3. Significant accounting policies continued

Provisions

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past transaction or event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. The amount recognised represents the best estimate of the expenditure expected to be required to settle the present obligation. Estimates are determined by the judgement of Management supplemented by the experience of similar transactions, and in some cases, advice from independent experts. Contingent liabilities are disclosed in Note 31 'Commitments and contingent liabilities' to the Consolidated Financial Statements, but not recognised until they meet the criteria for recognition as a provision. Where the Group is virtually certain that some or all of a provision will be reimbursed, that reimbursement is recognised as a separate asset. The expense relating to any provision is reflected in the Consolidated Income Statement at an amount reflective of the risks specific to the liability. Where the provision is discounted, any increase in the provision due to the passage of time is recognised as a finance cost.

The following criteria are applied for the recognition and measurement of significant classes of provision:

Restructuring charges

The Group accounts for restructuring charges, including statutory and legal requirements to pay termination costs, when there is a legal or constructive obligation that can be reliably measured. The Group recognises a provision for termination costs when it has a detailed formal plan for the restructuring and has raised a valid expectation in those affected that it will carry out the restructuring. Provisions are measured at the best estimate of the expenditure required to settle estimated statutory redundancy costs and discretionary payments at the reporting date.

Onerous contracts

The Group recognises provisions for onerous contracts once the underlying event or conditions leading to the contract becoming onerous is highly probable and a reliable estimate can be made. Provisions are measured at the best estimate of unavoidable costs under the contract which reflect the least net cost of exiting the contract which is the lower of the cost of fulfilling it and any compensation or penalties resulting from failure to fulfil the contract.

Legal claims

In the ordinary course of business, the Group is subject to various claims, litigation and complaints. An associated provision is recognised if it is probable that a liability has been incurred and the amount can be reliably estimated.

Contingent consideration

The Group recognises a provision for contingent consideration resulting from earn-out arrangements as part of a business combination. The amount and timing of contingent consideration is often uncertain and is payable based on the achievement of specific targets and milestones. The liability is initially measured at its acquisition date fair value, determined using the discounted cash flows method and unobservable inputs and is remeasured at each reporting date. Changes in fair value are recognised in the Consolidated Income Statement.

Share-based payments

Certain employees of the Group receive part of their remuneration in the form of share options and conditional awards of shares based on the performance of the Group. Equity-settled transactions with employees are measured at fair value at the date on which they are granted. The fair value is determined using a Monte Carlo simulation model. The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become entitled to the award (the vesting date). The cumulative expense recognised for equity-settled transactions at each balance sheet date, until the vesting date, reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The cumulative expense also includes the estimated future charge to be borne by the Group in respect of social security contributions, based on the intrinsic unrealised value of the awards using the share price at the balance sheet date. The net income or expense for a period represents the difference in cumulative expense recognised at the beginning and end of that period.

Where the terms of an equity-settled award are modified, as a minimum, an expense is recognised as if the terms had not been modified. In addition, an expense is recognised for any modification which increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employee as measured at the date of modification.

Where an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. However, if a new award is substituted for the cancelled award and designated as a replacement award on the date that it is granted, the cancelled and new awards are treated as if they were a modification of the original award, as described in the previous paragraph.

Where an equity-settled award is forfeited, due to vesting conditions being unable to be met, the cumulative expense previously recognised is reversed with a credit recognised in the Consolidated Income Statement. If a new award is substituted for the cancelled award, the new award is measured at fair value at the date on which they are granted.

Earnings per share

Earnings per share is calculated using the weighted average number of common shares and common share equivalents outstanding during each period excluding treasury shares. The potentially dilutive effect of outstanding share options and performance shares is reflected as share dilution in the computation of diluted earnings per share. Convertible bonds, excluding those repurchased and held by the Group, are included in the diluted earnings per share calculation if the effect is dilutive, regardless of whether the conversion price has been met.

73

4. Critical accounting judgements and key sources of estimation uncertainty

In the application of the Group's accounting policies which are described in Note 3 'Significant accounting policies', Management is required to make judgements, estimates and assumptions regarding the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other assumptions that the Group believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised prospectively in the period in which the estimate is revised.

Revenue recognition

Revenue recognition on long-term construction contracts and renewables contracts

The Group accounts for long-term construction contracts for both engineering, procurement, installation and commissioning (EPIC) projects and renewables and heavy lifting projects using the percentage-of-completion method, which is standard practice in the industry. Contract revenues, total cost estimates and estimates of physical progression are reviewed by Management on a monthly basis. Any adjustments made as a result of these reviews are reflected in contract revenues or contract costs in the reporting period, based on the percentage-of-completion methods.

To the extent that these adjustments result in a reduction or elimination of previously reported contract revenues or costs, a charge or credit is recognised in the Consolidated Income Statement; amounts in prior periods are not restated. Such a charge or credit may be significant depending on the size and complexity of the project, the stage of project completion and the size of the adjustment. Additional information that enhances and refines the estimating process is often obtained after the balance sheet date but before the issuance of the Consolidated Financial Statements, which may result in an adjustment to the Consolidated Financial Statements based on events, favourable or unfavourable, occurring after the balance sheet date. If a condition arises after the balance sheet date which is of a non-adjusting nature, the results recognised in the Consolidated Financial Statements are not adjusted.

The percentage-of-completion method requires the Group to make reliable estimates of physical progression, costs incurred, full project contract costs and full project contract revenues. The Group's Project Monthly Status Reports (PMSRs) evaluate the likely outcome of each individual project for the purpose of making reliable estimates of cost, revenue and progression, measured either by cost or physical progression. A key element of the PMSRs is the estimate of contingency. Contingency is an estimate of the costs required to address the potential future outcome of identified project risks. The Group uses a systematic approach in estimating contingency based on project size. This approach utilises a project specific risk register in order to identify and assess the likelihood and impact of these risks. The most significant risks and uncertainties in the Group's projects typically relate to the offshore phase of operations. Identified risks that materialise may result in increased costs. Contingency associated with identified risks will be removed from the full project cost estimate throughout the remaining life of the project if the identified risks do not materialise.

Revenue recognition on variation orders and claims

A significant portion of the Group's revenue is billed under fixed-price contracts. Due to the nature of the services performed, variation orders and claims are common.

A variation order is an instruction by the client for a change in the scope of the work to be performed under the contract which may lead to an increase or a decrease in contract revenue based on changes in the specifications or design of an asset and changes in the duration of the contract. Additional contract revenue is recognised when it is probable that the client will approve the variation and the amount of revenue arising from the variation can be reliably measured.

A claim is an amount that may be collected as reimbursement for costs not included in the contract price. A claim may arise from delays caused by clients, errors in specifications or design, and disputed variations in contract work. The measurement of revenue arising from claims is subject to a high level of uncertainty and is dependent on the outcome of negotiations. Therefore, claims are only recognised in contract revenue when negotiations have reached an advanced stage such that it is virtually certain that the client will accept the claim and the amount can be measured reliably.

Recognition of revenue on variation orders and claims is governed by the Group's revenue recognition approval policy. No profit relating to any variation order or claim is recognised until revenue and scope approval is received from the client.

Allocation of goodwill to cash-generating units (CGUs)

During 2017, the Group completed two business combinations which resulted in the recognition of goodwill. Management used their judgement in the identification of the appropriate CGUs for the monitoring of Goodwill. Goodwill recognised on the acquisition of the remaining 50% equity share of Seaway Heavy Lifting Holding Limited has been allocated to the Renewables and Heavy Lifting CGU. Goodwill recognised on the acquision of certain businesses of EMAS Chiyoda Subsea has been allocated to the Asia Pacific Middle East (APME) CGU.

Goodwill carrying amount

Goodwill is reviewed at least annually to assess whether there is objective evidence to indicate that the carrying amount of goodwill is impaired at a CGU level. The impairment review is performed on a value-in-use basis which requires the estimation of future net operating cash flows. Further details relating to the impairment review can be found in Note 13 'Goodwill'.

Property, plant and equipment

Property, plant and equipment is recorded at cost and depreciation is recorded on a straight-line basis over the useful lives of the assets. Management uses its experience to estimate the remaining useful economic life and residual value of an asset.

4. Critical accounting judgements and key sources of estimation uncertainty continued

A review for indicators of impairment is performed at each reporting date. When events or changes in circumstances indicate that the carrying amount of property, plant and equipment may not be recoverable, a review for impairment is carried out by Management. Where the value-in-use method is used to determine the recoverable amount of an asset, Management uses its judgement in determining the CGU to which the assets belongs, or whether the asset can be considered a CGU in its own right. The level of aggregation of assets is a significant assumption made by Management and includes consideration of which assets generate cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Management has determined that vessels are not CGUs individually as they do not generate cash inflows independently of other Group assets. Once the CGU has been determined Management uses its judgement in determining the value-in-use of the CGU as detailed in Note 13 'Goodwill'. Where an asset is considered a CGU in its own right Management uses its judgement to estimate future asset utilisation, profitability, remaining life and the discount rate used.

Recognition of provisions and disclosure of contingent liabilities

In the ordinary course of business, the Group becomes involved in contract disputes from time-to-time due to the nature of its activities as a contracting business involved in multiple long-term projects at any given time. The Group recognises provisions to cover the expected risk of loss to the extent that negative outcomes are likely and reliable estimates can be made. The final outcomes of these contract disputes are subject to uncertainties as to whether or not they develop into a formal legal action and therefore the resulting liabilities may exceed the liability anticipated by Management.

Furthermore, the Group may be involved in legal proceedings from time-to-time; these proceedings are incidental to the ordinary conduct of its business. Litigation is subject to many uncertainties, and the outcome of individual matters is not predictable with assurance. It is reasonably possible that the final resolution of any litigation could require the Group to incur additional expenditures in excess of provisions that it may have previously recognised.

Management uses its judgement in determining whether the Group should recognise a provision or disclose a contingent liability. These judgements include whether the Group has a present obligation and the probability that an outflow of economic resource is required to settle the obligation. Management may also use its judgement to determine the amount of the obligation or contingent liability. Management uses external advisers to assist with some of these judgements. Further details relating to provisions and contingent liabilities are shown in Note 30 'Provisions' and Note 31 'Commitments and contingent liabilities'.

Taxation

The Group is subject to taxation in numerous jurisdictions and significant judgement is required in calculating the consolidated tax provision. There are transactions for which the ultimate tax determination is uncertain and for which the Group makes provisions based on an assessment of internal estimates and appropriate external advice, including decisions regarding whether to recognise deferred tax assets in respect of tax losses. Each year Management completes a detailed review of uncertain tax positions across the Group and makes provisions based on the probability of the liability arising. Where the final tax outcome of these matters differs from the amounts that were initially recorded, the difference will impact the tax charge in the period in which the outcome is determined. Details of key judgements and other issues considered are set out in Note 9 'Taxation'.

Recognition of a remeasurement gain on business combinations

The acquisitions of the remaining 50% interests in Seaway Heavy Lifting Holding Limited and the remaining 50% interest in the Normand Oceanic AS and Normand Oceanic Chartering AS entities, were recognised by the Group as business combinations' completed in stages' in compliance with IFRS 3 'Business Combinations'. This resulted in the recognition of a net remeasurement gain which arose following the remeasurement of pre-existing equity accounted investments in the acquired businesses to fair value. Management used its judgement to determine the most appropriate presentation of the net remeasurement gain in the Consolidated Income Statement. The net gain represents the recognition of previously unrecognised changes in the fair value of the net assets of the acquired businesses. The net gain did not result from the operating activities of the entities in which the investments were held and as a result has been presented individually within the Consolidated Income Statement and is not included in net operating income.

Recognition of gain on a bargain purchase on business combination

The acquisition of the remaining 50% interests in the Normand Oceanic AS and Normand Oceanic Chartering AS entities, not already owned by the Group, resulted in a bargain purchase under IFRS 3 'Business Combinations' as the fair value of the assets acquired and liabilities assumed was more than the fair value of the consideration paid. Management used its judgement to determine the most appropriate presentation of the gain in the Consolidated Income Statement. The net gain did not result from the operating activities of the entities in which the investments were held and as a result has been presented within other gains and losses in the Consolidated Income Statement and is not included in net operating income.

Measurement of other intangibles acquired on business combinations

As part of the acquisition accounting for business combinations completed during the year, it was necessary for Management to use its judgement to estimate the fair value of previously unrecognised intangible assets. Intangible assets recognised by the Group following business combinations included third party unexecuted contractual backlog and acquired customer relationships. Management used its judgement to determine the fair value and the appropriate amortisation periods for intangible assets using income-based valuation approaches. Management used external advisers to assist with some of these judgements. Further details relating to assets acquired as a result of business combinations are included in Note 12 'Business combinations'.

Measurement of contingent consideration in business combinations

As part of the sale and purchase agreement for the 50% interest in Seaway Heavy Lifting Holding Limited ('Seaway Heavy Lifting') not previously owned by the Group, a contingent consideration was agreed with the previous owners. This may result in additional cash consideration becoming payable to the previous owners should specific targets be achieved in future periods. At the acquisition date Management applied judgement to provisionally estimate the fair value of this consideration using the discounted cash flow method and certain assumptions related to expected future activity levels. These provisional amounts are adjusted during the measurement period to reflect new information obtained regarding facts and circumstances that existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date. The measurement period is the period from the date of acquisition to the date the Group obtains complete information regarding facts and circumstances that existed as of the acquisition date and is subject to a maximum period of one year.

The Group has recognised liabilities for contingent consideration related to the acquisitions of Swagelining Limited and Pioneer Lining Technology. The Group remeasures these liabilities to fair value using the discounted cash flow method and management assumptions reflecting expectations about the achievement of specific targets and future performance. Changes to the expected levels of contingent consideration resulting from adjusting events during the twelve month measurement period are reflected in the amounts recognised as part of the accounting for the business combination. Changes resulting from non-adjusting events and all changes to the expected levels of contingent consideration arising after the end of the measurement period are reflected in the Group's Consolidated Income Statement.

5. Segment information

With effect from 1 January 2017 the Group implemented a new organisational structure comprising four Business Units: SURF and Conventional, i-Tech Services, Renewables and Heavy Lifting and Corporate. These operating segments are defined below:

SURF and Conventional

The SURF and Conventional Business Unit includes:

• Subsea Umbilicals, Risers and Flowlines (SURF) activities related to the engineering, procurement, construction and installation of highly complex systems offshore, including the long-term PLSV contracts in Brazil; and
• Conventional services including the fabrication, installation, extension and refurbishment of fixed and floating platforms and associated pipelines in shallow water environments.

This segment includes costs, including depreciation and impairment charges, related to vessels, equipment and offshore personnel deployed in SURF and Conventional activities. This segment also includes activity related to the businesses of EMAS Chiyoda Subsea (ECS), acquired during 2017, and the SapuraAcergy and Subsea 7 Malaysia joint ventures. The results of the Normand Oceanic entities, which became wholly-owned subsidiaries of the Group on 31 October 2017, having previously been a 50% owned joint venture, are included within this Business Unit on an equity accounting basis up to the date of acquisition and as a wholly-owned subsidiary on a fully consolidated basis thereafter.

i-Tech Services

The i-Tech Services Business Unit includes activities associated with the provision of Inspection, Repair and Maintenance (IRM) services, integrity management of subsea infrastructure and remote intervention support. This segment includes costs, including depreciation and impairment charges, related to vessels, equipment and offshore personnel deployed in i-Tech Services activities. The Eidesvik Seven joint venture is reported within this segment.

Renewables and Heavy Lifting

The Renewables and Heavy Lifting Business Unit includes activities related to three specialist segments of the offshore energy market: the installation of offshore wind farm foundations, heavy lifting operations for oil and gas structures, and the decommissioning of redundant offshore structures. This segment includes costs, including depreciation and impairment charges, related to vessels, equipment and offshore personnel deployed in Renewables and Heavy Lifting activities. The results of Seaway Heavy Lifting, which became a wholly-owned subsidiary of the Group on 10 March 2017 having previously been a 50% owned joint venture, are included within this Business Unit on an equity accounting basis up to the date of acquisition and on a fully consolidated basis thereafter.

Corporate

The Corporate Business Unit includes group-wide activities, and associated costs, including captive insurance activities, operational support, corporate services and costs associated with discrete events such as restructuring. A significant portion of the Corporate Business Unit's costs are allocated to the other operating segments based on a percentage of their external revenue.

The accounting policies of the Business Units are the same as the Group's accounting policies, which are described in Note 3 'Significant accounting policies'. There is a percentage of central costs allocated to each segment based on external revenue.

Allocations of costs also occur between segments based on the physical location of personnel. The Chief Operating Decision Maker (CODM) is the Chief Executive Officer of the Group. The CODM is assisted by the other members of the Executive Management Team. Neither total assets nor total liabilities by operational segment are regularly provided to the CODM and consequently no such disclosure is shown. Summarised financial information concerning each operating segment is as follows:

5. Segment information continued

For the year ended 31 December 2017

			Renewables
(in \$ millions)	SURF and Conventional	i-Tech Services	and Heavy Lifting	Corporate	Total
Selected financial information:
Revenue(a,b)	2,724.8	302.3	958.5	–	3,985.6
Operating expenses	(2,095.5)	(270.7)	(837.5)	85.3	(3,118.4)
Share of net (loss)/income of associates and joint ventures	(38.0)	2.7	(7.4)	–	(42.7)
Depreciation, mobilisation and amortisation expenses	(335.5)	(37.6)	(43.7)	(5.5)	(422.3)
Impairment of property, plant and equipment and intangible assets	(31.2)	(0.3)	–	–	(31.5)
Reconciliation of net operating income to income before taxes:
Net operating income	450.8	22.7	90.0	17.2	580.7
Finance income					24.6
Remeasurement gain on business combination					25.0
Other gains and losses					(54.8)
Finance costs					(21.0)
Income before taxes					554.5

(a) Revenue represents only external revenues for each segment. An analysis of inter-segment revenues has not been included as this information is not provided to the CODM.

(b) Three clients in the year individually accounted for more than 10% of the Group's revenue. The revenue from these clients, attributable to SURF and Conventional, i-Tech Services and Renewables and Heavy Lifting operating segments, were as follows; Client A \$845.5 million (2016: \$167.4 million), Client B \$624.8 million (2016: \$501.9 million) and Client C \$616.8 million (2016: \$587.7 million).

For the year ended 31 December 2016

	SURF and	i-Tech	Renewables and Heavy
	Conventional	Services	Lifting	Corporate	Total
(in \$ millions)			Re-presented(a) Re-presented(a) Re-presented(a) Re-presented(a)
Selected financial information:
Revenue(b)	3,013.1	377.4	176.0	0.2	3,566.7
Operating expenses	(2,284.0)	(328.3)	(172.5)	25.2	(2,759.6)
Impairment of goodwill	(90.4)	–	–	–	(90.4)
Share of net income of associates and joint ventures	20.6	1.5	24.3	–	46.4
Depreciation, mobilisation and amortisation expenses	(322.4)	(41.7)	–	(7.7)	(371.8)
Impairment of property, plant and equipment and intangible assets	(149.6)	(8.9)	–	–	(158.5)
Reconciliation of net operating income to income before taxes:
Net operating income/(loss) excluding goodwill impairment	624.9	38.0	27.8	(79.3)	611.4
Net operating income/(loss) including goodwill impairment	534.5	38.0	27.8	(79.3)	521.0
Finance income					17.9
Other gains and losses					44.9
Finance costs					(7.1)
Income before taxes					576.7

(a) Re-presented due to the reorganisation of the operating segments from 1 January 2017

(b) Revenue represents only external revenues for each segment. An analysis of inter-segment revenues has not been included as this information is not provided to the CODM.

Geographic information

Revenues from external clients

Based on the country of registered office of the Group's subsidiary or branch, revenues are split as follows:

For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
United Kingdom	2,159.3	1,485.7
Egypt	410.5	296.4
Norway	327.5	500.5
United States of America	290.6	317.8
Brazil	272.0	220.5
Singapore	127.8	17.9
Cyprus	111.9	–
Australia	98.6	159.8
Angola	62.3	120.0
Canada	48.6	38.0
Saudi Arabia	36.8	–
Mexico	26.0	33.0
Other countries	13.7	377.1
	3,985.6	3,566.7

Non-current assets

Based on the country of registered office of the Group's subsidiary or branch, non-current assets excluding goodwill, derivative financial instruments, retirement benefit assets and deferred tax assets are located in the following countries:

	2017	2016
As at (in \$ millions)	31 Dec	31 Dec
United Kingdom	2,680.2	2,877.4
Isle of Man	928.8	747.0
Cyprus	590.8	–
Norway	374.0	274.3
Angola	99.0	126.6
Brazil	59.3	63.5
Saudi Arabia	38.9	–
Other countries	67.5	482.5
	4,838.5	4,571.3

6. Net operating income

Net operating income includes:

	2017	2016
For the year ended (in \$ millions)	31 Dec	31 Dec
Research and development costs	17.3	19.3
Employee benefits (excluding termination expenses)	872.6	860.8
Restructuring – termination(a)	(2.7)	67.3
Restructuring – other(b)	–	29.7
Depreciation of property, plant and equipment (Note 15)	388.5	354.5
Amortisation of intangible assets (Note 14)	26.4	7.3
Mobilisation costs	7.4	10.0
Impairment of goodwill (Note 13)	–	90.4
Impairment of intangible assets (Note 14)	–	0.6
Impairment of property, plant and equipment (Note 15)	31.5	157.9
Auditor's remuneration	2.1	2.2

(a) Includes pay in lieu of notice, statutory redundancy costs and discretionary payments

(b) Includes onerous lease charges and professional fees.

6. Net operating income continued

The total fees for the financial year chargeable to the Group by the principal auditing firm Ernst & Young S.A. and other member firms of Ernst & Young Global Limited were:

	2017	2016
For the year ended (in \$ millions)	31 Dec	31 Dec
Audit fees	2.0	1.7
Tax fees	0.1	0.5
	2.1	2.2

Audit fees constitute charges incurred for professional services rendered by the Group's principal auditor and member firms. Charges were incurred for the audit of the consolidated and statutory financial statements of Subsea 7 S.A. and certain subsidiaries. Fees were primarily incurred in connection with the financial year ended 31 December 2017 but include final settlement of charges associated with the financial year ended 31 December 2016.

Tax fees constitute charges incurred for professional services rendered by the Group's principal auditors and their member firms relating to the provision of tax advice and tax compliance services for work undertaken during the year ended 31 December 2017.

Audit Committee policy requires pre-approval of audit and non-audit services prior to the appointment of the providers of professional services together with highlighting excluded services which the Group's principal auditor cannot provide. The Audit Committee delegates approval to the Chief Financial Officer based on predetermined limits. The Audit Committee pre-approved or, in cases where pre-approval was delegated, ratified all audit and non-audit services provided to Subsea 7 S.A. and its subsidiaries during the year ended 31 December 2017.

Reconciliation of operating expenses and administrative expenses by nature

		31 Dec 2017			31 Dec 2016
For the year ended (in \$ millions)	Operating expenses	Administration expenses	Total expenses	Operating expenses	Administration expenses	Total expenses
Employee benefits (excluding termination
expenses)	726.8	145.8	872.6	725.0	135.8	860.8
Restructuring – termination(a)	(2.7)	–	(2.7)	51.2	16.1	67.3
Restructuring – other(b)	–	–	–	6.7	23.0	29.7
Depreciation, amortisation and mobilisation	401.1	21.2	422.3	354.5	17.3	371.8
Impairment of intangible assets	–	–	–	0.6	–	0.6
Impairment of property, plant and equipment	31.5	–	31.5	157.9	–	157.9
Other expenses	1,961.7	76.8	2,038.5	1,463.7	49.9	1,513.6
Total	3,118.4	243.8	3,362.2	2,759.6	242.1	3,001.7

(a) Includes pay in lieu of notice, statutory redundancy costs and discretionary payments.

(b) Includes onerous lease charges and professional fees.

7. Other gains and losses

2017 For the year ended (in \$ millions) 31 Dec	2016 31 Dec
Gains/(losses) on disposal of property, plant and equipment	0.5 (2.3)
Net gain on derivative financial instruments	0.2 1.0
Net (loss)/gain on repurchase of convertible bonds	(0.1) 3.0
Net loss on settlement of borrowings	(2.3) –
Bargain purchase gain on business combinations	3.4 –
Net foreign currency exchange (losses)/gains (56.5)	43.2
Total (54.8)	44.9

8. Finance income and costs

	2017	2016
For the year ended (in \$ millions)	31 Dec	31 Dec
Interest income	24.6	17.9
Total finance income	24.6	17.9

	2017	2016
For the year ended (in \$ millions)	31 Dec	31 Dec
Interest and fees on borrowings	13.0	6.9
Interest on convertible bonds (Note 27)	11.7	16.8
Total borrowing costs	24.7	23.7
Less: amounts capitalised and included in the cost of qualifying assets	(4.0)	(16.8)
	20.7	6.9
Interest on tax liabilities	0.3	0.2
Total finance costs	21.0	7.1

Borrowing costs included in the cost of qualifying assets during the year was calculated by applying to expenditure on such assets a capitalisation rate of between 3.5% and 3.6% dependent on the funding source (2016: between 3.5% and 3.6%).

9. Taxation

Tax recognised in the Consolidated Income Statement
	2017	2016
For the year ended (in \$ millions)	31 Dec	31 Dec
Tax charged/(credited) in the Consolidated Income Statement
Current tax:
Corporation tax on income for the year	106.3	169.8
Adjustments in respect of prior years	(7.6)	(11.9)
Total current tax	98.7	157.9
Deferred tax charge	1.2	0.5
Total	99.9	158.4
Tax recognised in the Consolidated Statement of Comprehensive Income
For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
Tax charge /(credit) relating to items recognised directly in comprehensive income
Current tax on:
Exchange differences	0.5	(0.3)
Income tax recognised directly in comprehensive income	0.5	(0.3)
Deferred tax on:
Net losses on revaluation of cash flow hedges	–	(0.5)
Actuarial gains on defined benefit pension plans	–	0.5
Deferred tax recognised directly in comprehensive income	–	–
Total	0.5	(0.3)

9. Taxation continued

Reconciliation of the total tax charge

Income taxes have been provided based on the tax laws and rates in the countries where the Group operates and generates income. The Group's tax charge is determined by applying the statutory tax rate to the net income or loss earned in each of the jurisdictions in which the Group operates in accordance with the relevant tax laws, taking account of permanent differences between taxable income or loss and accounting income or loss. The tax rate used in 2017 for the purpose of the reconciliation of the total tax charge is 27.08% (2016: 29.22%) which corresponds to the blended tax rate applicable to Luxembourg entities.

For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
Income before taxes	554.5	576.7
Tax at the blended tax rate of 27.08% (2016: 29.22%)	150.1	168.5
Effects of:
Benefit of tonnage tax regimes	(20.4)	(25.4)
Different tax rates of subsidiaries operating in other jurisdictions	(55.6)	(81.5)
Movement in unprovided deferred tax	(4.0)	38.1
Tax effect of share of net income of associates and joint ventures	17.0	(13.5)
Withholding taxes and unrelieved overseas taxes	4.8	37.6
Changes in tax rates	–	(1.4)
Other permanent differences	5.5	8.8
Goodwill impairment not deductible	–	26.4
Impairment of subsidiaries of the parent company	1.8	–
Adjustments related to prior years	0.7	0.8
Tax charge in the Consolidated Income Statement	99.9	158.4

Deferred tax

Movements in the net deferred tax balance were:

(in \$ millions)	2017	2016
At year beginning	(47.5)	(54.3)
Charged to:
Consolidated Income Statement	(1.2)	(0.5)
Recognised on acquisition of businesses	(9.9)	(4.4)
Balance sheet transfers	(1.7)	5.6
Exchange differences	(0.9)	6.1
At year end	(61.2)	(47.5)

The main categories of deferred tax assets and liabilities recognised in the Consolidated Financial Statements, before offset of balances within countries where permitted, were as follows:

At 31 December 2017

Total	19.6	(80.8)	(61.2)
Other	0.5	(5.8)	(5.3)
Tax losses	12.4	–	12.4
Share-based payments	0.7	–	0.7
Accrued expenses	6.0	(20.8)	(14.8)
Property, plant and equipment	–	(43.3)	(43.3)
Intangible assets	–	(10.9)	(10.9)
(in \$ millions)	Deferred tax asset	Deferred tax liability	Net recognised deferred tax asset/(liability)

Deferred tax continued

At 31 December 2016

Other Total	2.0 19.5	(2.1) (67.0)	(0.1) (47.5)
Tax losses	11.5	–	11.5
Share-based payments	0.5	–	0.5
Accrued expenses	5.5	(22.7)	(17.2)
Property, plant and equipment	–	(38.4)	(38.4)
Intangible assets	–	(3.8)	(3.8)
(in \$ millions)	Deferred tax asset	Deferred tax liability	Net recognised deferred tax asset/(liability)

81

Deferred tax is analysed in the Consolidated Balance Sheet, after offset of balances within countries, as:

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Deferred tax assets	17.2	13.2
Deferred tax liabilities	(78.4)	(60.7)
Total	(61.2)	(47.5)

At 31 December 2017, the Group had tax losses of \$2,078.2 million (2016: \$2,042.2 million) available for offset against future taxable income. A deferred tax asset has been recognised, using the applicable tax rates, in respect of \$36.4 million (2016: \$36.1 million) of such losses. No deferred tax asset has been recognised in respect of the remaining \$2,041.8 million (2016: \$2,006.1 million) as it is not considered probable that there will be sufficient future taxable income available for offset. In addition, the Group has other unrecognised deferred tax assets of approximately \$23.5 million (2016: \$34.4 million) in respect of other temporary differences.

No deferred tax has been recognised in respect of temporary differences relating to the unremitted earnings of the Group's subsidiaries and branches where remittance is not contemplated and where the timing of distribution is within the control of the Group and for those interests in associates and joint arrangements where it has been determined that no additional tax will arise. The aggregate amount of unremitted earnings giving rise to such temporary differences for which deferred tax liabilities were not recognised at 31 December 2017 was \$989.4 million (2016: \$1,059.5 million).

Tonnage tax regime

The tax charge reflected a net benefit in the year of \$20.4 million (2016: \$25.4 million) as a result of activities taxable under the current UK and Norwegian tonnage tax regimes, as compared to the tax that would be payable if those activities were not eligible.

Net operating losses (NOLs)

NOLs to carry forward in various countries will expire as follows:

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Within five years	36.7	18.7
5 to 10 years	258.0	198.0
11 to 20 years	120.9	215.7
Without time limit	1,662.6	1,609.8
Total	2,078.2	2,042.2

There were \$119.5 million (2016: \$131.2 million) of NOLs included in the above relating to Brazil on which no deferred tax asset was recognised by the Group at 31 December 2017. Cumulative losses included in the above in respect of operations in the Gulf of Mexico were \$369.5 million (2016: \$412.4 million).

Included in the above were \$1,409.9 million (2016: \$1,420.8 million) of NOLs relating to Luxembourg, which could be subject to future claw-back if certain transactions were entered into.

9. Taxation continued

Tax contingencies and provisions

Business operations are carried out in several countries, through subsidiaries and branches, and the Group is subject to the jurisdiction of a significant number of tax authorities. Furthermore, the offshore nature of the Group's operations means that the Group routinely has to manage complex international tax issues.

In the ordinary course of events operations will be subject to audit, enquiry and possible re-assessment by different tax authorities. The Group provides for the amount of taxes that it considers probable of being payable as a result of these audits and for which a reasonable estimate can be made. Each year Management completes a detailed review of uncertain tax positions across the Group and makes provisions based on the probability of the liability arising. The principal risks that arise for the Group are in respect of permanent establishment, transfer pricing and other international tax issues. In common with other international groups, the conflict between the Group's global operating model and the jurisdictional approach of tax authorities can lead to uncertainty on tax positions.

In 2017, operations in various countries were subject to enquiries, audits and disputes, including, but not limited to, those in Angola, Australia, Brazil, Canada, Gabon, Nigeria and Norway. These audits are at various stages of completion. The Group's policy is to cooperate fully with the relevant tax authorities while seeking to defend its tax positions.

In the year ended 31 December 2017, the Group recorded a net increase in respect of its tax provisions, excluding business combinations, during the year of \$7.3 million (2016: \$3.7 million) as a result of revised future potential exposures and the resolution of certain matters with the relevant tax authorities. It is possible that the ultimate resolution of these matters could result in tax charges that are materially higher or lower than the amount provided for.

10. Dividends

A special dividend of NOK 5.00 per share was approved by the shareholders of Subsea 7 S.A. at the Annual General Meeting on 12 April 2017 and recognised in shareholders' equity in April 2017. The special dividend was paid from the share premium account which in accordance with Luxembourg law is included in the distributable reserves of Subsea 7 S.A. The total dividend of \$191.1 million was paid on 26 April 2017 to shareholders of Subsea 7 S.A. recorded as of 19 April 2017.

11. Earnings per share

Basic and diluted earnings per share

Basic earnings per share is calculated by dividing the net income or loss attributable to shareholders of the parent company by the weighted average number of common shares in issue during the year, excluding shares repurchased by the Group and held as treasury shares (Note 24 'Treasury shares').

Diluted earnings per share is calculated by adjusting the weighted average number of common shares outstanding to assume conversion of all dilutive potential common shares. The Company's potentially dilutive common shares include those related to convertible bonds, share options and performance shares. The convertible bonds are assumed to have been converted into common shares and the net income or loss attributable to shareholders of the parent company is adjusted to eliminate the interest expense (net of taxation and capitalised interest). For the share options, a calculation is performed to determine the number of shares that could have been acquired at fair value (determined as the average annual market share price of the Company's shares) based on the monetary value of the subscription rights attached to outstanding share options. The number of shares calculated as above is compared with the number of shares that would have been issued assuming the exercise of the share options.

The net income or loss attributable to shareholders of the parent company and share data used in the basic and diluted earnings per share calculations were as follows:

For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
Net income attributable to shareholders of the parent company	454.8	436.0
Interest on convertible bonds (net of taxation and amounts capitalised)	4.7	–
Earnings used in the calculation of diluted earnings per share	459.5	436.0
For the year ended	2017 31 Dec Number of shares	2016 31 Dec Number of shares
Weighted average number of common shares used in the calculation of basic earnings per share	326,013,650	325,692,190
Convertible bonds	10,748,457	16,488,335
Share options and performance shares	1,728,282	705,069
Weighted average number of common shares used in the calculation of diluted earnings per share	338,490,389	342,885,594
For the year ended (in \$ per share)	2017 31 Dec	2016 31 Dec
Basic earnings per share	1.39	1.34
Diluted earnings per share	1.36	1.27

In the year the following shares, that could potentially dilute the earnings per share, were excluded from the calculation of diluted earnings per share due to being anti-dilutive:

2017	2016
31 Dec	31 Dec
Number of	Number of
For the year ended shares	shares
Share options and performance shares 1,127,927	1,187,825

Adjusted diluted earnings per share

Adjusted diluted earnings per share represents diluted earnings per share excluding the goodwill impairment charge of \$nil (2016: \$90.4 million), the remeasurement gain on business combinations of \$25.0 million (2016: \$nil) and the bargain purchase gain on business combinations of \$3.4 million (2016: \$nil). The net income or loss attributable to shareholders of the parent company and share data used in the calculation of Adjusted diluted earnings per share were as follows:

For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
Net income attributable to shareholders of the parent company	454.8	436.0
Impairment of goodwill	–	90.4
Remeasurement gain on business combination (Note 12)	(25.0)	–
Bargain purchase gain on business combination (Note 7)	(3.4)	–
Interest on convertible bonds (net of taxation and amounts capitalised)	4.7	–
Earnings used in the calculation of Adjusted diluted earnings per share	431.1	526.4
For the year ended	2017 31 Dec Number of shares	2016 31 Dec Number of shares
Weighted average number of common shares used in the calculation of basic earnings per share	326,013,650	325,692,190
Convertible bonds	10,748,457	16,488,335
Share options and performance shares	1,728,282	705,069
Weighted average number of common shares used in the calculation of Adjusted diluted earnings per share	338,490,389	342,885,594
For the year ended (in \$ per share)	2017 31 Dec	2016 31 Dec
Adjusted diluted earnings per share	1.27	1.54

12. Business combinations

(in \$ millions)

Seaway Heavy Lifting Holding Limited

On 10 March 2017 an indirect wholly-owned subsidiary of Subsea 7 S.A. acquired 50% of the voting shares of Seaway Heavy Lifting Holding Limited ('Seaway Heavy Lifting'), not previously owned by the Group. Seaway Heavy Lifting is a limited liability company incorporated and domiciled in Cyprus. Seaway Heavy Lifting, along with its subsidiaries, is a specialist offshore contractor involved in the delivery of services connected with three specialist segments of the offshore energy market: the installation of offshore wind farm foundations, heavy lifting operations for oil and gas structures, and the decommissioning of redundant offshore structures. The primary reason for the acquisition was to increase market share in growing markets and to strengthen the Group's participation in the areas of renewables, heavy lifting and decommissioning services. Stamp duty and other expenses incurred in connection with the acquisition have been accounted for separately and recorded within operating expenses in the Consolidated Income Statement.

Business combination achieved in stages

Prior to the acquisition, the Group held a 50% interest in Seaway Heavy Lifting and this transaction was therefore treated as a business combination achieved in stages. On the acquisition date, subsequent to the recognition of retrospective adjustments made following the completion of post-transaction procedures, the Group remeasured its previously held equity interest to a fair value of \$230.9 million. This resulted in the recognition of a remeasurement gain of \$40.7 million. Subsequent to remeasurement, the Group derecognised its equity interest in Seaway Heavy Lifting and recognised the separately identifiable assets and liabilities related to the acquisition as part of the calculation to determine goodwill.

The provisional fair values of identifiable assets and liabilities acquired as at 10 March 2017 are shown below. This table is inclusive of adjustments recognised between the date of the acquisition and 31 December 2017.

Assets
Intangible assets	17.4
Property, plant and equipment	599.5
Deferred tax assets	1.6
Inventories	4.1
Trade and other receivables	82.6
Construction contracts – assets	2.0
Other accrued income and prepaid expenses	1.1
Restricted cash	17.0
Cash and cash equivalents	151.1
	876.4
Liabilities
Borrowings	125.0
Retirement benefit obligation	13.7
Derivative financial instruments	9.1
Trade and other liabilities	115.0
Current tax liabilities	4.6
Construction contracts – liabilities	127.9
	395.3
Total identifiable net assets at fair value	481.1
Less: deferred tax liability recognised on intangible assets (Note 9)	(1.3)
Add: goodwill arising on acquisition (Note 13)	34.7
	514.5
Consideration comprised
Cash and cash equivalents	279.0
Contingent consideration	7.6
Fair value of the Group's equity interest prior to business combination	239.9
Dividend assigned to the Group on acquisition	(12.0)
	514.5

Receivables

Receivables are shown at fair value and represent the gross contractual amounts receivable.

Goodwill

Goodwill comprises the value of intangible assets which do not meet the criteria for separate recognition including the assembled workforce, the diversification of the fleet and complementary service capabilities. Subsequent to initial recognition of provisional amounts, retrospective adjustments to goodwill were made following the completion of certain post-transaction procedures specified at the time of the business combination. A reconciliation of the movement in goodwill from the balance initially recognised at the date of acquisition to the balance at 31 December 2017, subsequent to adjustments is shown below:

(in \$ millions)

Provisional goodwill arising on business combination	42.0
Adjustments to identifiable net assets at fair value subsequent to initial recognition	1.5
Decrease in contingent consideration subsequent to initial recognition	(8.8)
At 31 December 2017	34.7

Goodwill is allocated to the Renewables and Heavy Lifting CGU. Goodwill is not expected to be deductible for tax purposes.

Contingent consideration

As part of the sale and purchase agreement with the previous owners of the acquired interest, contingent consideration has been agreed. Additional cash payments to the previous owners may be payable should specific targets be met in future periods.

At the acquisition date, the fair value of the contingent consideration was estimated to be \$16.4 million. The fair value was determined using high level management assumptions based on forecast activity levels and associated vessel utilisation using information available at the date of acquisition. Subsequent to initial recognition, finalisation of detailed long-term forecasts for market activity indicated that a revision to the contingent consideration was required and as a result the contingent consideration was reduced by \$8.8 million to \$7.6 million. The fair value of the contingent consideration at 31 December 2017 reflects the current assessments of vessel utilisation. A reconciliation of the fair value measurement of the provision for contingent consideration is show below:

(in \$ millions)
Provisional liability arising on business combination	16.4
Decrease in contingent consideration subsequent to initial recognition	(8.8)
At 31 December 2017	7.6

A significant increase or decrease in forecast activity levels would result in a higher or lower fair value of the provision for contingent consideration. The range of potential outcomes is between \$nil and \$70.2 million.

Financial performance

From the date of acquisition, Seaway Heavy Lifting contributed \$111.9 million of revenue and \$87.4 million to income before tax of the Group. If the combination had taken place at the beginning of the year, revenue for 2017 for the Group would have been \$3,988.5 million and income before tax for 2017 for the Group would have been \$546.3 million. The figures disclosed exclude any transactions between Seaway Heavy Lifting and subsidiaries of the Group.

12. Business combinations continued

Acquisition of certain businesses and assets of EMAS Chiyoda Subsea (ECS)

On 29 June 2017 an indirect wholly-owned subsidiary of Subsea 7 S.A. acquired certain businesses and assets of EMAS Chiyoda Subsea (ECS), a subsea engineering, construction and services contractor providing services to the oil and gas industry. The transaction was completed under a US bankruptcy code Chapter 11 Plan of Reorganisation, which was confirmed by the US Bankruptcy Court of the Southern District of Texas and became effective on 29 June 2017.

The business combination included the acquisition of 100% of the share capital and voting shares of three entities: EMAS AMC Pte Ltd, EMAS Chiyoda Subsea Services Pte Ltd, both registered in Singapore, and EMAS Saudi Arabia Limited, registered in Saudi Arabia. In addition specific assets and liabilities were acquired from EMAS Chiyoda Subsea Inc. The primary reason for the acquisition was to enhance the Group's global presence and to accelerate its strategy to provide market leading services in the Middle East region. Stamp duty and other expenses incurred in connection with the acquisition have been accounted for separately and recorded within operating expenses in the Consolidated Income Statement.

The provisional fair values of the identifiable assets and liabilities acquired as at 29 June 2017 are shown below. Where required, these amounts will be adjusted retrospectively during the measurement period ending 28 July 2018. This table is inclusive of adjustments recognised between the date of acquisition and 31 December 2017.

(in \$ millions)

Assets
Intangible assets	45.9
Property, plant and equipment	2.5
Inventories	0.3
Trade and other receivables	32.1
Construction contracts – assets	21.4
Other accrued income and prepaid expenses	11.3
Restricted cash	2.4
Cash and cash equivalents	5.3
	121.2
Liabilities
Trade and other liabilities	52.9
Construction contracts – liabilities	18.3
	71.2
Total identifiable net assets at fair value	50.0
Less: deferred tax liability recognised on intangible assets (Note 9)	(8.6)
Add: goodwill arising on acquisition (Note 13)	10.9
	52.3
Consideration comprised
Cash and cash equivalents	52.3
	52.3

Receivables

Receivables are shown at fair value and represent the best estimate of amounts expected to be collected. The gross contractual amounts receivable include \$22.3 million which has been recognised at a fair value of \$nil due to uncertainty surrounding collection.

Goodwill

Goodwill comprises the value of intangible assets which do not meet the criteria for separate recognition including the assembled workforce and local presence within the Middle East region. Goodwill is allocated to the Asia Pacific and Middle East (APME) CGU. Goodwill is not expected to be deductible for tax purposes.

Financial performance

As the transaction was completed under a US bankruptcy code Chapter 11 Plan of Reorganisation, the business prior to the completion of Chapter 11 is not directly comparable to the assets and liabilities acquired by the Group. Disclosure of measurements of financial performance for the period prior to acquisition would not accurately represent the financial performance of the acquired businesses. Management has therefore concluded that it is impracticable to disclose measures of financial performance in respect of the combined entity for the current reporting period as though the acquisition date for the business combination had occurred at the beginning of the reporting period.

Normand Oceanic AS and Normand Oceanic Chartering AS

On 31 October 2017 an indirect wholly-owned subsidiary of Subsea 7 S.A. acquired 50% of the voting shares of Normand Oceanic AS and Normand Oceanic Chartering AS (collectively referred to as 'Normand Oceanic') not previously owned by the Group. Both entities are limited liability companies incorporated and domiciled in Norway. Normand Oceanic AS owns Normand Oceanic, a flex-lay and heavy construction vessel currently on long-term charter to a third party. The acquisition reflects the Group's strategy to own high specification vessels that differentiate the Group's engineering and construction services offering. The net assets acquired, the bargain purchase gain arising on acquisition and the analysis of purchase consideration are shown in the table below. Stamp duty and other expenses incurred in connection with the acquisition have been accounted for separately and recorded within operating expenses in the Consolidated Income Statement.

Business combination achieved in stages

Prior to the acquisition, the Group held a 50% interest in Normand Oceanic and this transaction was therefore treated as a business combination achieved in stages. On the acquisition date the Group remeasured its previously held equity interest to a fair value of \$3.4 million. This resulted in the recognition of a remeasurement loss of \$15.7 million. Subsequent to remeasurement, the Group derecognised its equity interest in Normand Oceanic and recognised the separately identifiable assets and liabilities related to the acquisition as part of the calculation to determine the gain on bargain purchase.

The provisional fair values of the identifiable assets and liabilities acquired as at 31 October 2017 are shown below:

(in \$ millions)
Assets
Property, plant and equipment	116.7
Trade and other receivables	5.1
Cash and cash equivalents	4.0
	125.8
Liabilities
Borrowings	101.5
Trade and other liabilities	17.5
	119.0
Total identifiable net assets at fair value	6.8
Consideration comprised
Cash and cash equivalents	–
Fair value of the Group's equity interest prior to business combination	3.4
	3.4
Bargain purchase gain on business combination	3.4

Receivables

Receivables are shown at fair value and represent the gross contractual amounts receivable.

Bargain purchase gain on business combination

The acquisition resulted in the recognition of a bargain purchase gain on business combination of \$3.4 million being recorded in the Consolidated Income Statement within 'other gains and losses'. The gain on bargain purchase arose due to the nominal amount of cash consideration paid to acquire the remaining 50% of shares that the Group did not already own at fair value.

Financial performance

From the date of acquisition, Normand Oceanic contributed \$1.5 million of revenue and \$0.1 million to income before tax of the Group. If the combination had taken place at the beginning of the year, revenue for 2017 for the Group would have been \$3,998.1 million and income before tax for 2017 for the Group would have been \$540.8 million.

13. Goodwill

Total
2,405.7
14.9
(248.4)
2,172.2
45.6
106.0
2,323.8

Accumulated impairment

At 31 December 2017	1,623.0
Exchange differences	78.5
At 31 December 2016	1,544.5
Exchange differences	(184.8)
Impairment charge	90.4
At 1 January 2016	1,638.9

Carrying amount

At 31 December 2016	627.7
At 31 December 2017	700.8

On 10 March 2017 an indirect wholly-owned subsidiary of Subsea 7 S.A. acquired 50% of the shares of Seaway Heavy Lifting Holding Limited ('Seaway Heavy Lifting'). The acquisition resulted in the recognition of goodwill of \$34.7 million. All of this goodwill is allocated to the Renewables and Heavy Lifting CGU.

On 29 June 2017 an indirect wholly-owned subsidiary of Subsea 7 S.A. acquired certain businesses of EMAS Chiyoda Subsea (ECS). The acquisition resulted in the recognition of goodwill of \$10.9 million. All of this goodwill is allocated to the Asia Pacific and Middle East (APME) CGU.

For financial management and reporting purposes, the Group is organised into management regions. Management regions are aligned with the Group's Business Units which are used by the Chief Operating Decision Maker (CODM) to allocate resources and appraise performance.

The Group has eight CGUs which are aligned with management regions; these are:

• CGUs for Asia Pacific and Middle East (APME), Brazil, Gulf of Mexico (GOM) and North Sea and Canada (NSC) include activities connected with the performance of regional projects including SURF activities (related to the engineering, procurement, construction and installation of offshore systems), Conventional services (including the fabrication, installation, extension and refurbishment of platforms and pipelines in shallow water) and the long-term PLSV contracts in Brazil. This CGU excludes projects which are delivered by the Global Project Centre.
• Africa and Global Projects CGU includes activities connected with the performance of regional SURF and Conventional services projects in Africa and activities related to the performance of global projects managed within the Global Project Centre.
• i-Tech Services CGU includes non-UK activities connected with the provision of Inspection, Maintenance and Repair (IMR) services, integrity management of subsea infrastructure and remote intervention support.
• Pipelines Group CGU includes activities connected with the fabrication and installation of polymer-lining technology for pipelines and riser systems.
• Renewables and Heavy Lifting CGU includes activities connected with three specialist segments of the offshore energy market: the installation of offshore wind farm foundations, heavy lifting operations for oil and gas structures, and the decommissioning of redundant offshore structures.

The Group performed its annual goodwill impairment test at 31 December 2017. The carrying amounts of goodwill allocated to the CGUs subsequent to this review were as follows:

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Africa and Global Projects	401.3	382.6
APME	10.9	–
i-Tech Services	64.5	62.0
NSC	174.2	169.0
Pipelines Group	15.2	14.1
Renewables and Heavy Lifting	34.7	–
Total	700.8	627.7

The recoverable amounts of the CGUs were determined based on a value-in-use calculation using pre-tax, risk adjusted cash flow projections approved by the Executive Management Team covering a five-year period from 2018 to 2022. Cash flows beyond this fiveyear period were extrapolated in perpetuity using a 2.0% (2016: 2.0%) growth rate to determine the terminal value. The pre-tax discount rate applied to risk adjusted cash flow projections was 11.0% (2016: 11.2%).

Following the annual impairment review, no impairment charges were recognised for the year ended 31 December 2017 (2016: \$90.4 million).

Key assumptions used in value-in-use calculations

The calculations of value-in-use for all CGUs are most sensitive to the following assumptions:

• EBITDA forecasts;
• discount rate; and
• the growth rate used to extrapolate cash flows.

EBITDA forecast – The EBITDA forecast for each CGU is dependent on a combination of factors including market size, market share, contractual backlog, gross margins, future project awards, asset utilisation and an assessment of the impacts of competition within the industry. Assumptions are based on a combination of internal and external studies, management judgements and historical information, adjusted for any foreseen changes in market conditions.

Discount rate – The discount rate was estimated based on the weighted average cost of capital of the Group, amended to reflect a normalised capital structure for the industry. Risk premiums were not applied to the discount rate applied to individual CGUs as the CGU cash flow projections were risk adjusted.

Growth rate estimates – The 2.0% (2016: 2.0%) growth rate used to extrapolate the cash flow projections beyond the five-year period is broadly consistent with market expectations for long-term growth in the subsea industry and assumes no significant change in the Group's market share and the range of services and products provided.

Sensitivity to changes in assumptions

In determining the value-in-use recoverable amount for each CGU, sensitivities have been applied to each of the key assumptions. In respect of EBITDA forecasts, a number of scenarios were considered. These scenarios incorporate the level of capital expenditure required for the Group to remain as a leading contractor within the subsea sector.

CGUs not impaired and not sensitive to impairment

No reasonably possible change in any of the key assumptions would, in isolation, cause the recoverable amount of the Africa and Global Projects CGU, the APME CGU, the i-Tech Services CGU, the NSC CGU, the Pipelines Group CGU to be materially less than its carrying amount.

The GOM CGU and the Brazil CGU have no goodwill, therefore any future changes in the key assumptions in isolation would not result in a further impairment charge being recognised against goodwill.

CGUs not impaired but sensitive to impairment

The only CGU where a reasonably possible change to any key assumption would, in isolation, cause the recoverable amount to be materially less than its carrying amount is the Renewables and Heavy Lifting CGU. At 31 December 2017 the recoverable amount of the Renewables and Heavy Lifting CGU exceeded the carrying amount by \$33.0 million. Changes to key assumptions used in the impairment review would, in isolation, lead to an aggregate goodwill impairment charge recognised in the year ended 31 December 2017 as follows:

(in \$ millions)	Renewables and Heavy Lifting
Pre-tax discount rate
Increase by 1 percentage point	33.9
Decrease by 1 percentage point	–
Long-term growth rate
Increase by 1 percentage point	–
Decrease by 1 percentage point	13.2
EBITDA upon which terminal values have been calculated
Decrease by 5 percent	–
Increase by 5 percent	–

14. Intangible assets

		Customer
(in \$ millions)	Software	contracts (Backlog)	Other intangibles	Total
Cost
At 1 January 2016	37.4	–	5.7	43.1
Acquisition of business	–	–	23.6	23.6
Additions	1.6	–	2.5	4.1
Disposals	(0.2)	–	–	(0.2)
Exchange differences	(5.8)	–	(1.5)	(7.3)
At 31 December 2016	33.0	–	30.3	63.3
Acquisition of businesses (Note 12)	1.1	28.1	34.1	63.3
Additions	2.7	–	4.6	7.3
Exchange differences	1.6	–	2.9	4.5
At 31 December 2017	38.4	28.1	71.9	138.4
Accumulated amortisation and impairment
At 1 January 2016	20.6	–	3.9	24.5
Charge for the year	4.5	–	2.8	7.3
Disposals	(0.2)	–	–	(0.2)
Impairments	–	–	0.6	0.6
Exchange differences	(3.7)	–	(0.1)	(3.8)
At 31 December 2016	21.2	–	7.2	28.4
Charge for the year	5.0	12.8	8.6	26.4
Exchange differences	2.4	–	0.2	2.6
At 31 December 2017	28.6	12.8	16.0	57.4
Carrying amount:
At 31 December 2016	11.8	–	23.1	34.9
At 31 December 2017	9.8	15.3	55.9	81.0

The table above includes software under development of \$0.8 million (2016: \$3.8 million).

15. Property, plant and equipment

(in \$ millions)	Vessels	Operating equipment	Land and buildings	Other assets	Total
Cost
At 1 January 2016	5,193.5	849.5	506.1	81.6	6,630.7
Acquisition of business	–	0.8	0.2	0.3	1.3
Additions	231.6	11.3	22.1	1.8	266.8
Exchange differences	(191.3)	(55.5)	(12.9)	(7.8)	(267.5)
Disposals	(164.7)	(18.2)	(0.3)	(7.8)	(191.0)
Transfer	(55.5)	53.3	0.1	2.1	–
At 31 December 2016	5,013.6	841.2	515.3	70.2	6,440.3
Acquisition of business	685.4	30.7	0.5	2.1	718.7
Additions	142.7	40.6	9.5	6.7	199.5
Reclassified as held for sale	–	–	1.4	–	1.4
Exchange differences	65.9	27.7	10.4	8.7	112.7
Disposals	(96.1)	(22.2)	(16.8)	(5.6)	(140.7)
Transfers	(47.1)	67.7	(17.0)	(3.6)	–
At 31 December 2017	5,764.4	985.7	503.3	78.5	7,331.9
Accumulated depreciation and impairment
At 1 January 2016	1,418.9	443.9	144.4	64.5	2,071.7
Charge for the year	247.7	74.0	24.2	8.6	354.5
Impairments	101.4	20.6	35.9	–	157.9
Exchange differences	(64.3)	(24.1)	(2.8)	(4.1)	(95.3)
Eliminated on disposals	(155.6)	(8.6)	(0.1)	(7.7)	(172.0)
Transfer	(13.2)	13.2	–	–	–
At 31 December 2016	1,534.9	519.0	201.6	61.3	2,316.8
Charge for the year	283.4	75.7	24.0	5.4	388.5
Impairments	23.9	7.3	0.1	0.2	31.5
Reclassified as held for sale	–	–	0.7	–	0.7
Exchange differences	25.0	14.6	3.5	3.8	46.9
Eliminated on disposals	(96.1)	(22.2)	(16.8)	(5.5)	(140.6)
Transfers	(47.1)	43.5	3.6	–	–
At 31 December 2017	1,724.0	637.9	216.7	65.2	2,643.8

Carrying amount:

At 31 December 2017	4,040.4	347.8	286.6	13.3	4,688.1
At 31 December 2016	3,478.7	322.2	313.7	8.9	4,123.5

The table above includes assets under construction of \$101.0 million at 31 December 2017 which includes the construction of a new reel-lay vessel and associated pipe lay equipment. Assets under construction at 31 December 2016 totalled \$859.0 million and included Seven Cruzeiro, Seven Kestrel and Seven Arctic vessels, these vessels commenced operations during 2017.

An impairment test was performed at 31 December 2017. Decreased expected future utilisation of specific vessels and equipment resulted in the recognition of impairment charges to reduce the carrying amounts of specific assets to their recoverable amount defined as the higher of value-in-use or fair value less costs of disposal.

Fair value less costs of disposal was estimated in line with Level 3 of the 'fair value hierarchy' contained within IFRS 13 'Fair Value Measurement' and was determined by Management, based on recent similar market transactions, an assessment of internal estimates and independent external valuations. Fair value was reduced by estimated costs of disposal where these could be reliably estimated. Value-in-use was estimated in line with Level 3 of the 'fair value hierarchy' contained within IFRS 13 'Fair Value Measurement' and was determined based on calculations using cash flow projections for the remaining estimated useful lives of the individual assets.

An impairment charge of \$20.7 million was recognised in respect of vessel related equipment and one owned vessel in order to reduce their carrying amounts to \$nil. An impairment charge of \$3.2 million was recognised to reduce the carrying amount of a number of cargo barges to a recoverable amount of \$2.2 million. An impairment charge of \$7.6 million was recognised to reduce other assets to a recoverable value of \$nil.

Of the \$31.5 million impairment charge, \$31.2 million is reported within the SURF and Conventional operating segment and \$0.3 million is reported within the i-Tech Services operating segment.

16. Interests in associates and joint arrangements

Interests in joint arrangements

At 31 December 2017 the Group had a 50% interest in an unstructured joint operation governed by a consortium agreement ('the Consortium'). The Consortium includes EMC AMC Pte Ltd (a wholly-owned subsidiary of the Group) and L&T Hydrocarbon Engineering Limited (a wholly-owned subsidiary of Larsen & Toubro Limited). The purpose of the Consortium is to tender for projects and execute contracts awarded by the Saudi Arabian Oil Company ('Saudi Aramco') under a long-term agreement. All activities of the Consortium are executed on a joint and several basis. The Consortium's activities include project management, engineering, procurement, fabrication, transportation and installation of offshore facilities and infrastructure. The principal place of business of the unincorporated joint arrangement is the Kingdom of Saudi Arabia.

Interests in associates and joint ventures

At 31 December 2017 the Group had interests in one associate and six joint ventures.

	Year end	Country of registration	Operating segment	Classification	Subsea 7 ownership %
Global Oceon	31 December	Nigeria	SURF and Conventional	Associate	40
Eidesvik Seven	31 December	Norway	i–Tech Services	Joint Venture	50
ENMAR	31 December	Mozambique	SURF and Conventional	Joint Venture	51
SapuraAcergy(a)	31 January	Malaysia	SURF and Conventional	Joint Venture	50
SIMAR	31 December	Angola	SURF and Conventional	Joint Venture	49
Subsea 7 Malaysia	31 December	Malaysia	SURF and Conventional	Joint Venture	30
Belmet 7	31 December	Ghana	SURF and Conventional	Joint Venture	49

(a) SapuraAcergy is the collective term for the Group's investments in its joint ventures SapuraAcergy Assets Pte Ltd and SapuraAcergy Sdn. Bhd. Subsea 7 has 50% equity ownership of SapuraAcergy Sdn. Bhd. Subsea 7 has 51% equity ownership in SapuraAcergy Assets Pte Ltd, however, 1% is subject to a put and call option for the benefit of its joint venture partner.

For all entities the principal place of business is consistent with the country of registration. The proportion of voting rights is consistent with the proportion of ownership interest.

All interests in associates and joint ventures are accounted for using the equity method. Financial information for the year ended 31 December 2017 is used for all entities. The movement in the balance of equity investments was as follows:

in \$ millions)	2017	2016
At year beginning	378.5	368.5
Share of net (loss)/income of associates and joint ventures	(42.7)	46.4
Dividends recognised by the Group	(100.7)	(38.2)
Disposal of investment in associate	–	(0.8)
Remeasurement of investments in joint ventures	25.0	–
Derecognition of investment in joint ventures	(234.3)	–
Net reclassification of negative investment balance	0.2	1.0
Share of other comprehensive income of associates and joint ventures	0.5	2.2
Exchange differences	2.2	(0.6)
At year end	28.7	378.5

Derecognition of investment in joint ventures

On 10 March 2017 the Group acquired the remaining 50% of shares of Seaway Heavy Lifting Holding Limited as part of a business combination completed in stages. As a result of this transaction the equity accounted investment was remeasured to fair value resulting in the recognition of a remeasurement gain of \$40.7m. Subsequent to remeasurement the investment was derecognised and formed part of the consideration for the acquisition of Seaway Heavy Lifting Holding Limited. Seaway Heavy Lifting Holding Limited and its subsidiaries became wholly-owned subsidiaries of the Group from the date of acquisition.

On 31 October 2017 the Group acquired 50% of the shares of Normand Oceanic AS and Normand Oceanic Chartering AS as part of a business combination completed in stages. As a result of this transaction the equity accounted investment was disposed of and both entities became wholly-owned subsidiaries of the Group from the date of acquisition. As a result of this transaction the equity accounted investment was remeasured to fair value resulting in the recognition of a remeasurement loss of \$15.7m. Subsequent to remeasurement the investment was derecognised and formed part of the consideration for the acquisition of Normand Oceanic AS and Normand Oceanic Chartering AS. Normand Oceanic AS and Normand Oceanic Chartering AS became wholly-owned subsidiaries of the Group from the date of acquisition.

Discontinuation of SapuraAcergy joint venture

On 17 October 2017 the Group entered into an agreement with Sapura Energy Berhad to discontinue the SapuraAcergy joint venture. During 2017 the Group received \$100.0 million of dividends and a \$10.0 million cash advance from the joint venture. At 31 December 2017 the SapuraAcergy joint venture had total equity of \$7.4 million.

Summarised financial information

At 31 December 2017 none of the Group's investments in associates or joint ventures are individually material to the Group therefore summarised financial information has not been provided.

17. Advances and receivables

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Non-current amounts due from associates and joint ventures	6.7	8.6
Capitalised fees for long-term loan facilities	2.9	4.7
Deposits held by third parties	0.9	0.8
Other receivables	24.7	20.3
Total	35.2	34.4

18. Inventories

Total	36.7	39.0
Consumables	21.5	21.5
Materials and non-critical spares	15.2	17.5
As at (in \$ millions)	2017 31 Dec	2016 31 Dec

For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
Total cost of inventory charged to the Consolidated Income Statement	52.5	43.4
Write-down of inventories charged to the Consolidated Income Statement	6.6	7.1
Reversal of provision for obsolescence credited to the Consolidated Income Statement	(1.6)	(0.1)

Inventories included a provision for obsolescence at 31 December 2017 of \$12.2 million (2016: \$9.1 million). There were no inventories pledged as security.

19. Trade and other receivables

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Trade receivables	401.2	291.1
Provision for impairment of receivables	(19.4)	(32.5)
Net trade receivables	381.8	258.6
Current amounts due from associates and joint ventures	6.7	33.6
Advances to suppliers	2.4	9.8
Other taxes receivable	58.7	90.8
Other receivables	47.7	106.8
Total	497.3	499.6

Details of how the Group manages its credit risk and further analysis of the trade receivables balance can be found in Note 33 'Financial instruments'.

Other taxes receivable related to value added tax, sales tax, withholding tax, corporation tax, social security and other indirect taxes.

Other receivables include insurance receivables, retainage and deposits.

At 31 December 2017 the provision for impairment of receivables amounted to \$19.4million (2016: \$32.5 million). The movements in the provision were as follows:

(in \$ millions)	Total
At 1 January 2016	(23.0)
Additional provision for the year	(16.2)
Utilised/released during the year	5.5
Exchange differences	1.2
At 31 December 2016	(32.5)
Additional provision for the year	(6.9)
Utilised/released during the year	20.2
Exchange differences	(0.2)
At 31 December 2017	(19.4)

Trade receivables due from associates and joint ventures are shown net of provisions for impairment of \$13.1 million (2016: \$12.4 million).

20. Other accrued income and prepaid expenses

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Unbilled revenue	107.4	94.7
Prepaid expenses	68.9	122.0
Total	176.3	216.7

Unbilled revenue related to work completed on day-rate contracts, which had not been billed to clients at the balance sheet date.

Prepaid expenses arise in the normal course of business and represent expenditure which has been deferred and which will be recognised in the Consolidated Income Statement within twelve months of the balance sheet date.

21. Construction contracts

	2017	2016
As at (in \$ millions)	31 Dec	31 Dec
Contracts in progress
Construction contracts – assets	319.1	79.7
Construction contracts – liabilities	(200.0)	(536.2)
Total	119.1	(456.5)
Contract costs incurred plus recognised net profits less recognised losses to date	5,284.5	3,370.7
Less: progress billings	(5,165.4)	(3,827.2)
Total	119.1	(456.5)

Revenue from construction contracts in the year was \$3.0 billion (2016: \$2.5 billion).

22. Cash and cash equivalents

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Cash and cash equivalents	1,109.1	1,676.4
Total	1,109.1	1,676.4

Cash and cash equivalents included amounts totalling \$103.7 million (2016: \$99.0 million) held by Group undertakings in certain countries whose exchange controls significantly restrict or delay the remittance of these amounts to foreign jurisdictions.

23. Issued share capital

Authorised shares

	2017		2016
	31 Dec	2017	31 Dec	2016
	Number of	31 Dec	Number of	31 Dec
As at	shares	in \$ millions	shares	in \$ millions
Authorised common shares, \$2.00 par value	450,000,000	900.0	450,000,000	900.0
Issued shares
	2017		2016
	31 Dec	2017	31 Dec	2016
	Number of	31 Dec	Number of	31 Dec
As at	shares	in \$ millions	shares	in \$ millions
Fully paid and issued common shares	327,367,111	654.7	327,367,111	654.7
The issued common shares consist of:
Common shares excluding treasury shares	326,509,224	653.0	325,834,107	651.7
Treasury shares at par value (Note 24)	857,887	1.7	1,533,004	3.0
Total	327,367,111	654.7	327,367,111	654.7

24. Treasury shares

Share repurchase plan

On 31 July 2014, the Group announced a share repurchase programme of up to \$200 million. The programme was approved pursuant to the standing authorisation granted to the Board of Directors at the Annual General Meeting held on 27 May 2011 (as renewed and extended by the Extraordinary General Meeting on 27 November 2014), which allows for the purchase of up to a maximum of 10% of the Group's issued share capital, net of purchases already made.

On 25 July 2017, the Board of Directors authorised a 24 month extension to the Group's share repurchase programme of up to \$200 million. During both 2017 and 2016, the Group did not repurchase any treasury shares. At 31 December 2017 cumulatively 5,272,656 shares had been repurchased under the July 2014 share repurchase programme for a total consideration of \$57.1 million.

All repurchases have been made in the open market on the Oslo Børs, pursuant to certain conditions, and are in conformity with Article 49-2 of the Luxembourg Company Law and the EU Commission Regulation 2273/2003 on exemptions for repurchase programmes and stabilisation of financial instruments. At 31 December 2017 the repurchased shares were held as treasury shares.

Summary

Movements in treasury shares are shown in the table below:

	2017 Number of shares	2017 in \$ millions	2016 Number of shares	2016 in \$ millions
At year beginning	1,533,004	31.5	1,723,259	31.7
Additional shares transferred from an employee benefit trust	5,051	0.1	–	–
Shares reallocated relating to share-based payments	(680,168)	(11.9)	(190,255)	(0.2)
Balance at year end	857,887	19.7	1,533,004	31.5
Consisting of:
As at			2017 31 Dec Number of shares	2016 31 Dec Number of shares
Common shares held as treasury shares by Subsea 7 S.A.			857,887	41,428
Common shares held as treasury shares by employee benefit trusts			–	1,491,576
Total			857,887	1,533,004

At 31 December 2017, the Group directly held 857,887 (2016: 41,428) treasury shares amounting to 0.26% (2016: 0.01%) of the total number of issued shares. During the year, 1,241,200 shares previously held by an employee benefit trust to satisfy performance shares under the Group's 2009 Long-term Incentive Plan (2009 LTIP) and 250,376 shares previously held in a separate employee benefit trust to support specified share option awards were transferred to Subsea 7 S.A.

At 31 December 2017 no common shares were held by an employee benefit trusts.

25. Non-controlling interests

The Group's respective ownership interests in subsidiaries which are non-wholly-owned were as follows:

			Subsea 7
	Year end	Country of registration	ownership %
Sonamet	31 December	Angola	55.0
Sonacergy	31 December	Portugal	55.0
Setemares Angola	31 December	Angola	49.0
Globestar Engineering Company	31 December	Nigeria	98.8
Naviera Subsea 7	31 December	Mexico	49.0
Servicios Subsea 7	31 December	Mexico	52.0
PT Subsea 7 Indonesia	31 December	Indonesia	95.0
Subsea 7 Gabon	31 December	Gabon	99.8
NigerStar 7 Limited	31 December	Nigeria	49.0
NigerStar 7 FZE	31 December	Nigeria	49.0
Subsea 7 Volta Contractors	31 December	Ghana	49.0

For all entities, the principal place of business is consistent with the country of registration. The proportion of voting rights is consistent with the proportion of ownership interest. Financial information recognised in the Group's Consolidated Financial Statements is based on financial information of the entity for the year ended 31 December 2017.

The movement in the equity attributable to non-controlling interests was as follows:

(in \$ millions)	2017	2016
At year beginning	(46.9)	(30.9)
Share of net loss for the year	(0.2)	(17.7)
Additions	0.2	–
Dividends	–	(2.5)
Reclassification of non-controlling interest to equity attributable to shareholders of Subsea 7 S.A.	95.7	–
Exchange differences	(0.4)	4.2
At year end	48.4	(46.9)

Reclassification of non-controlling interest

On 29 March 2017 the Group reached an agreement to acquire the non-controlling interest of Subsea 7 Mexico S de RL de CV for a nominal cash consideration. As a result of this transaction Subsea 7 Mexico S de RL de CV became a wholly-owned subsidiary of the Group. On acquisition the non-controlling interest of \$95.7 million was reallocated to equity attributable to the shareholders of Subsea 7 S.A. The \$95.7 million comprised accumulated losses of \$131.9 million offset by accumulated translation differences of \$36.2m.

Summarised financial information

At 31 December 2017 none of the Group's non-controlling interests are individually material to the Group therefore summarised financial information has not been provided.

Financial Statements

26. Borrowings

2017 As at (in \$ millions) 31 Dec	2016 31 Dec
\$700 million 1.00% convertible bonds due 2017 (Note 27) –	427.3
The Export Credit Agency (ECA) senior secured facility 282.7	–
Total 282.7	427.3
Consisting of:
Non-current portion of borrowings 258.2	–
Current portion of borrowings 24.5	427.3
Total 282.7	427.3

Commitment fees expensed during the year in respect of unused lines of credit totalled \$1.7 million (2016: \$3.4 million).

Facilities

The multi-currency revolving credit and guarantee facility

The Group entered into a \$500 million multi-currency revolving credit and guarantee facility on 3 September 2014 which originally matured on 3 September 2019. Effective from March 2016 the Group increased the value of this facility to \$750 million. Effective from November 2016 \$656 million of the facility was extended to mature on 2 September 2021 and during June 2017 the remaining unextended \$94 million of the facility was cancelled. The facility is with several banks and is available for the issuance of guarantees, up to a limit of \$200 million, a combination of guarantees and cash drawings, or is available in full for cash drawings. The facility is guaranteed by Subsea 7 S.A. and Subsea 7 Finance (UK) PLC. The facility was unutilised at 31 December 2017.

The Export Credit Agency (ECA) senior secured facility

In July 2015 the Group entered into a \$357 million senior term loan facility secured on two vessels under construction. The facility is provided 90% by an Export Credit Agency (ECA) and 10% by two banks and is available for general corporate purposes. The ECA tranche has a twelve-year maturity and a twelve-year amortising profile. The bank tranche has a five-year maturity and a fifteen-year amortising profile, in all cases from the date of delivery of the vessels. If the bank tranche is not refinanced satisfactorily after five years then the ECA tranche also becomes due. During the first quarter of 2017, in line with the vessel construction programme, an amount of \$301.3 million was drawn under the facility. The facility is guaranteed by Subsea 7 S.A. and Subsea 7 Finance (UK) PLC. At 31 December 2017 the amount drawn under the facility was \$282.7 million (2016: \$nil).

Seaway Heavy Lifting – Revolving credit and guarantee facility

On 10 March 2017, following the acquisition of Seaway Heavy Lifting Limited, the Group recognised a multi-currency term loan of \$129.5 million which was due to expire in March 2021. On 30 June 2017 this loan was repaid in full.

Normand Oceanic loan

On 31 October 2017, following the acquisition of Normand Oceanic AS, the Group recognised a term loan of \$101.5 million which was due to expire in October 2017. On 31 October 2017 this loan was repaid in full.

	2017 31 Dec	2017 31 Dec	2017 31 Dec	2016 31 Dec	2016 31 Dec	2016 31 Dec
As at (in \$ millions)	Utilised	Unutilised	Total	Utilised	Unutilised	Total
Committed borrowings facilities	282.7	656.0	938.7	–	1,051.3	1,051.3

Bank overdraft and short-term lines of credit

Overdraft facilities consisted of \$6.7 million (2016: \$6.5 million), of which \$nil (2016: \$nil) was drawn at 31 December 2017.

Other facilities

In addition to the above there are a number of uncommitted, unsecured bi-lateral guarantee arrangements in place in order to provide specific geographical coverage. The total utilisation of these facilities at 31 December 2017 was \$542.0 million (2016: \$451.3 million).

Guarantee arrangements with joint ventures

On 27 July 2016 Eidesvik Seven AS, a 50% owned joint venture between Eidesvik Offshore ASA and the Group, drew down NOK 572 million from a NOK 600 million bank loan facility to repay a shareholder loan from the Group. The facility, secured on Seven Viking, is fully guaranteed by Subsea 7 S.A. with a 50% counter-guarantee from Eidesvik Shipping AS and has a termination date of 31 January 2021. The outstanding balance at 31 December 2017 was NOK 513 million (\$61.0 million). (2016: NOK 561 million, (\$64.6 million).

Following the acquisition of Normand Oceanic AS by the Group and the subsequent repayment of the loan, the guarantees previously provided by Subsea 7 S.A. were cancelled effective 31 October 2017.

On 17 October 2017, the Group entered into an agreement with Sapura Energy Berhad to discontinue the SapuraAcergy joint venture. As such the guarantee arrangements previously in place representing 50% of the financing were cancelled.

27. Convertible bonds

\$700 million 1.00% convertible bonds due 2017 (2017 Bonds)

On 5 October 2012, the Group issued \$700 million in aggregate principal amount of 1.00% convertible bonds which were due 2017. The 2017 Bonds had an annual interest rate of 1.00% payable semi-annually in arrears on 5 April and 5 October of each year up to and including 2017. They were issued at 100% of their principal amount and, unless previously repurchased, they matured on 5 October 2017 at 100% of their principal amount.

Bond repurchases

During 2017 the Group repurchased \$77.6 million (par value) of the 2017 Bonds for \$77.3 million in cash (equivalent to an average 99.6% of the par value). Each repurchase was treated as payment for the liability and equity component of the bonds. Following the repurchases \$8.9 million of the related equity component was transferred from equity reserve to retained earnings. This treatment resulted in a loss on repurchase of the liability of \$0.1 million which was recognised within finance income in the Consolidated Income Statement. The repurchase of the convertible element of the bond resulted in a \$0.1 million debit being recognised within retained earnings. At the time of repurchase, these bonds were not cancelled but continued to be held by the Group and were available for reissue up until their redemption.

Bond redemption

On 5 October 2017, the Group cancelled convertible bonds with an aggregate nominal value of \$342 million, these bonds were held by the Group as a result of previous repurchases. The remaining outstanding convertible bonds with an aggregate nominal value of \$358 million were redeemed for cash on the maturity date of 5 October 2017. Following the redemption \$41.3 million of the related equity component was transferred from equity reserve to retained earnings.

Movements in convertible bonds

The movement in the liability components of the convertible bonds was as follows:

(in \$ millions)	2017	2016
At year beginning	427.3	523.9
Bonds repurchased	(77.0)	(108.8)
Bonds redeemed	(358.0)	–
Interest charged (Note 8)	11.7	16.8
Interest paid	(4.0)	(4.6)
At year end	–	427.3

The interest charged in the year was calculated by applying an effective interest rate of 3.5% (2016: 3.5%).

The movement in the equity reserve from the reclassification of the equity component of the convertible bonds from equity reserve to retained earnings was as follows:

For the year (in \$ millions)	2017	2016
At year beginning	50.2	63.2
Reclassification of equity component of bonds repurchased during the year	(8.9)	(13.0)
Reclassification of equity component of bonds redeemed during the year	(41.3)	–
At year end	–	50.2

28. Other non-current liabilities

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Accrued salaries and benefits	9.5	11.0
Non-current amounts due to associates and joint ventures	1.8	1.8
Other	38.6	38.8
Total	49.9	51.6

29. Trade and other liabilities

2016
31 Dec
445.8
96.4
–
132.5
19.3
78.4
51.3
823.7

30. Provisions

15.5 20.4	82.7
		21.0	139.6
5.2	97.1	37.2	145.9
	(61.0)	(6.4)	(82.8)
	(8.3)	(10.4)	(21.0)
2.1	–	–	–
	(8.2)	(2.8)	(11.2)
17.4	102.3	38.6	170.5
9.5	12.3	45.5	96.1
	(74.7)	(26.8)	(105.5)
	(15.0)	(3.6)	(22.8)
–	(0.4)	0.4	–
0.4	3.1	2.3	6.1
22.6	27.6	56.4	144.4
	6.4 (7.0) (1.7) (2.1) 1.1 12.2 28.8 (2.9) (0.6) – 0.3 37.8	(8.4) (0.6) (1.3) (1.1) (3.6)

99

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Consisting of:
Non-current provisions	67.6	61.9
Current provisions	76.8	108.6
Total	144.4	170.5

The claims provision comprises a number of claims made against the Group including disputes, personal injury cases, tax claims and lease disputes, where the timing of resolution is uncertain.

The decommissioning provision is in relation to the Group's obligation to restore leased vessels to their original, or agreed, condition. The costs related to the provision are expected to be incurred in the years the leases cease, which range from 2018 to 2022.

The restructuring provision relates to expenses associated with cost reduction and headcount resizing activities. The provision includes employee termination costs, onerous lease charges and professional fees. The provision is based on statutory requirements and discretionary arrangements for headcount reductions and the best estimate of costs associated with onerous lease contracts. Cash outflows associated with termination costs and professional fees are expected to occur within 2018. Cash outflows associated with onerous leases are expected to occur between 2018 and 2022.

Other provisions include contingent consideration of \$20.0 million (2016: \$11.5 million) and loss provisions on onerous contracts for leases, not associated with restructuring, and day-rate contracts.

31. Commitments and contingent liabilities

Commitments

The Group's commitments at 31 December 2017 consisted of:

• Commitments to purchase property, plant and equipment from external vendors of \$279.5 million (2016: \$63.3 million) mainly related to the construction of a new reel-lay vessel and associated pipelay equipment.
• Operating lease commitments as indicated in Note 32 'Operating lease arrangements'.

Contingent liabilities

A summary of the contingent liabilities is as follows:

(in \$ millions)	Contingent liability recognised		Contingent liability not recognised
	2017	2016	2017	2016
At year beginning	7.5	4.0	201.4	177.1
Contingent liability recognised on acquisition	–	2.8	–	–
New unrecognised contingent liabilities	–	–	95.0	–
Revisions to existing unrecognised contingent liabilities	–	–	18.2	21.5
Decrease in unrecognised contingent liabilities	–	–	(7.8)	(27.8)
Exchange differences	0.3	0.7	1.9	30.6
At year end	7.8	7.5	308.7	201.4

31. Commitments and contingent liabilities continued

Contingent liabilities recognised in the Consolidated Balance Sheet

As a result of the business combination between Acergy S.A. and Subsea 7 Inc. on 7 January 2011, and in accordance with IFRS 3 'Business Combinations', a contingent liability of \$9.3 million was recognised in the Consolidated Balance Sheet on 7 January 2011. This was in respect of claims made against Subsea 7 do Brasil Serviços Ltda, equivalent to \$4.8 million as at 31 December 2017 (2016: \$4.7 million). A further \$3.3 million of contingent liabilities were recognised in the Consolidated Balance Sheet on 7 January 2011 in relation to several other smaller claims. Subsequently this has been reassessed and amounted to \$0.1m at 31 December 2017 (2016: \$0.1 million).

As part of the accounting for the business combination of Pioneer Lining Technology Limited, IFRS 3 'Business Combinations' required the Group to recognise a contingent liability of £2.2 million, equivalent to \$2.8 million at the acquisition date, in respect of contingent amounts payable to a third party following the acquisition of intangible assets in 2009. The contingent liability recognised within the Consolidated Balance Sheet at 31 December 2017 was \$2.9 million (2016: \$2.7 million).

Contingent liabilities not recognised in the Consolidated Balance Sheet

Between 2009 and 2017, the Group's Brazilian businesses were audited and formally assessed for ICMS and federal taxes (including import duty) by the Brazilian state and federal tax authorities. The amount assessed, including penalties and interest, at 31 December 2017 amounted to BRL 703.3 million, equivalent to \$213.7 million (2016: BRL 670.1 million, equivalent to \$201.4 million). The Group has challenged these assessments. No provision has been made in relation to these cases. A contingent liability has been disclosed for the total amounts assessed as the disclosure criteria have been met however the Group does not believe that the likelihood of payment is probable.

The Group is subject to tax audits and receives tax assessments in a number of jurisdictions where it has, or has had, operations. The estimation of the ultimate outcome of these audits and disputed tax assessments is complex and subjective. The likely outcome of the audits and associated cash outflow, if any, may be impacted by technical uncertainty and the availability of supporting documentation.

Among these audits, the Group's Nigerian businesses were subject to audit by Rivers State, Nigeria, in respect of payroll taxes for the years 2010 to 2014. At 31 December 2017, there is a contingent liability relating to the assessments received from Rivers State, which total NGN 34,190 million, equivalent to \$95.0 million (31 December 2016: \$nil). The Group has objected to the assessments and is currently involved in court proceedings in Nigeria to protect its assets from sequestration by Rivers State authorities in respect of one of the assessments totalling NGN 3,352 million, or \$9.3 million. This contingent liability has been disclosed but the Group does not believe the likelihood of payments is probable. No provision has been recognised in the Consolidated Balance Sheet in respect of assessments resulting from the Rivers State audits.

In the ordinary course of business, various claims, legal actions and complaints have been filed against the Group in addition to those specifically referred to above. Although the final resolution of any such other matters could have a material effect on its operating results for a particular reporting period, the Group believes that it is not probable that these matters would materially impact its Consolidated Financial Statements.

32. Operating lease arrangements The Group as lessee

For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
Payments made under operating leases	163.7	186.2

The total operating lease commitments at 31 December 2017 were \$339.8 million (2016: \$373.1 million). These included vessel charter hire obligations of \$175.5 million (2016: \$184.8 million). The remaining obligations at 31 December 2017 related to office facilities and other equipment of \$164.2 million (2016: \$188.3 million).

The Group's outstanding lease commitments fall due as follows:

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Within one year	112.7	119.1
Years two to five inclusive	187.8	187.2
After five years	39.3	66.8
Total	339.8	373.1

The operating leases have various terms and future renewal options. Renewal options which have not yet been exercised are excluded from the outstanding commitments.

Derivative financial instruments recognised in the Consolidated Balance Sheet were as follows:

As at (in \$ millions)	31 Dec 2017 Assets	31 Dec 2017 Liabilities	31 Dec 2017 Total	31 Dec 2016 Assets	31 Dec 2016 Liabilities	31 Dec 2016 Total
Non-current
Forward foreign exchange contracts	5.8	(0.5)	5.3	25.2	(12.2)	13.0
Current
Forward foreign exchange contracts	36.9	(24.3)	12.6	53.2	(40.7)	12.5

Significant accounting policies

Details of the significant accounting policies adopted including the basis of measurement and recognition of income and expense in respect of each class of financial asset, financial liability and equity instrument are disclosed in Note 3 'Significant accounting policies'.

The Group's financial instruments are classified as follows:

	2017	2016
As at (in \$ millions)	31 Dec Carrying amount	31 Dec Carrying amount
Financial assets
Restricted cash	6.3	–
Cash and cash equivalents	1,109.1	1,676.4
Financial assets at fair value through profit or loss – derivative instruments	42.7	78.4
Loans and receivables:
Net trade receivables (Note 19)	381.8	258.6
Non-current amounts due from associates and joint ventures (Note 17)	6.7	8.6
Current amounts due from associates and joint ventures (Note 19)	6.7	33.6
Financial investments	5.5	–
Other receivables	22.3	84.1
Financial liabilities
Financial liabilities at fair value through profit or loss – derivative instruments	(24.8)	(52.9)
Other financial liabilities:
Trade payables (Note 29)	(142.6)	(96.4)
Non-current amounts due to associates and joint ventures (Note 28)	(1.8)	(1.8)
Current amounts due to associates and joint ventures (Note 29)	(11.4)	–
Borrowings – convertible bonds (Note 27)	–	(427.3)
Borrowings – facilities (Note 26)	(282.7)	–
Contingent consideration (Note 30)	(20.0)	(11.5)
Other payables	(8.8)	(27.2)

The carrying amounts of financial assets and financial liabilities recorded at amortised cost in the Consolidated Financial Statements approximate their fair values.

33. Financial instruments continued

Reconciliation of movements in liabilities arising from financing activities

The table below details changes in the Group's liabilities arising from financing activities, including both cash and non-cash changes. Liabilities arising from financing activities are those for which cash flows are classified in the Consolidated Cash Flow Statement as cash flows from financing activities.

	Liabilities			Equity			Other	Total
				Interest rate	Dividends	Dividends payable to
(in \$ millions)	Convertible bonds	Other borrowing	Contingent consideration	swaps used for hedging	payable to shareholders	non-controlling interests	Other equity
Balance at 1 January 2017	427.3	–	11.5	–	–	1.2	–	–	440.0
Financing cash flows
Interest paid	(4.0)	(11.9)	–	–	–	–	–	–	(15.9)
Proceeds from borrowings	–	301.2	–	–	–	–	–	–	301.2
Repayment of borrowings	–	(252.9)	–	–	–	–	–	–	(252.9)
Repayment of derivative financial instrument	–	–	–	(8.0)	–	–	–	–	(8.0)
Repurchase of convertible bonds	(77.3)	–	–	–	–	–	–	–	(77.3)
Redemption of convertible bonds	(358.0)	–	–	–	–	–	–	–	(358.0)
Proceeds from reissuance of
ordinary shares	–	–	–	–	–	–	0.5	–	0.5
Dividends paid to shareholders of
the parent company	–	–	–	–	(191.1)	–	–	–	(191.1)
Dividends paid to non-controlling								–
interests	–	–	–	–	–	(0.5)	–		(0.5)
Total financing cash flows	(439.3)	36.4	–	(8.0)	(191.1)	(0.5)	0.5		(602.0)
Non-cash changes
Acquisition of businesses	–	226.5	7.6	9.1	–	–	–	–	243.2
Dividends declared	–	–	–	–	191.1	–	–	–	191.1
Shares reissued relating to share
based payments	–	–	–	–	–	–	(11.8)	–	(11.8)
Loss on reissuance of treasury shares	–	–	–	–	–	–	11.3	–	11.3
Interest charges	11.7	12.1	–	–	–	–	–	(2.8)	21.0
Fair value adjustments	0.3	2.3	0.9	(1.1)	–	–	–	–	2.4
Foreign exchange movements	–	5.4	–	–	–	–	–	–	5.4
Total non-cash changes	12.0	246.3	8.5	8.0	191.1	–	(0.5)	(2.8)	462.6
Balance at 31 December 2017	–	282.7	20.0	–	–	0.7	–	(2.8)	300.6

Financial risk management objectives

The Group monitors and manages the financial risks relating to its financial operations through internal risk reports which analyse exposures by degree and magnitude of risks. These risks include market risk (consisting of currency risk and fair value interest rate risk), credit risk and liquidity risk.

The Group seeks to minimise the effects of these risks by using a variety of financial instruments to hedge these financial risk exposures. The use of financial instruments is governed by the Group's policies as reviewed and approved by the Board of Directors and includes policies on foreign exchange risk, interest rate risk, credit risk and the investment of excess liquidity.

The Group reviews compliance with policies and exposure limits on a regular basis and it does not enter into or trade financial instruments for speculative purposes.

Market risk

The Group's activities expose it primarily to the financial risks of changes in foreign currency exchange rates and interest rates. The Group enters into a variety of derivative financial instruments to manage its exposure to foreign currency risks, including forward foreign exchange contracts to hedge the exchange rate risk arising on future revenues, operating costs and capital expenditure.

In the year ended 31 December 2017, there was no significant change to the Group's exposure to market risks or the manner in which it manages and measures the risk.

Foreign currency risk management

The Group conducts operations in many countries and, as a result, is exposed to currency fluctuations related to revenue and expenditure in the normal course of business. The Group has in place risk management policies that seek to limit the adverse effects of fluctuations in foreign currency exchange rates on its financial performance.

The Group's reporting currency is the US Dollar. Revenue and operating expenses are principally denominated in the reporting currency of the Group. The Group also has significant operations denominated in British Pound Sterling and Euro as well as other cash flows in Angolan Kwanza, Australian Dollar, Brazilian Real, Canadian Dollar, Danish Krone, Egyptian Pound, Ghanaian Cedi, Malaysian Ringgit, Mexican Peso, Nigerian Naira, Norwegian Krone, Saudi Arabian Riyal, Singapore Dollar and UAE Dirham.

Foreign currency sensitivity analysis

The Group considers that its principal currency exposure is to movements in the US Dollar against other currencies. The US Dollar is the Group's reporting currency, the functional currency of many of its subsidiaries and the currency of a significant volume of the Group's cash flows.

The Group performed a sensitivity analysis to indicate the extent to which net income and equity would be affected by changes in the exchange rate between the US Dollar and other currencies in which the Group transacts. The analysis is based on a strengthening of the US Dollar by 10% against each of the other currencies in which the Group has significant assets and liabilities at the end of each respective period. A movement of 10% reflects a reasonably possible sensitivity when compared to historical movements over a three to five-year time-frame. The Group's analysis of the impact on net income in each year is based on monetary assets and liabilities in the Consolidated Balance Sheet at the end of each respective year.

The Group's analysis of the impact on equity includes the impacts on the translation reserve in respect of intra-group balances that form part of the net investment in a foreign operation. The amounts disclosed have not been adjusted for the impact of taxation.

A 10% strengthening in the US Dollar exchange rate against other currencies in which the Group transacts would increase net foreign currency exchange gains reported in other gains and losses by \$23.2 million (2016: \$53.8 million). The impact would be an increase in reported equity of \$11.9 million (2016: increase of \$40.4 million).

Forward foreign exchange contracts

The Group primarily enters into forward foreign exchange contracts with maturities of up to three years, to manage the risk associated with transactions with a foreign exchange exposure risk. These transactions consist of highly probable cash flow exposures relating to revenue, operating expenditure and capital expenditure.

The Group does not use derivative instruments to hedge the exposure to exchange rate fluctuations from its net investments in foreign subsidiaries.

Forward foreign exchange contracts continued

The following table details the forward foreign exchange contracts outstanding:

As at 31 December 2017

	Contracted amount by contract maturity	Fair value by contract maturity
	Buy		Sell		Maturity
(in \$ millions)	< 1 Year	1-5 Years	< 1 Year	1-5 Years	< 1 Year	1-5 Years
British Pound Sterling	19.0	36.4	89.2	–	(0.7)	2.7
Canadian Dollar	–	–	1.6	–	–	–
Danish Krone	1.1	–	–	–	–	–
Euro	162.4	21.9	–	–	9.4	2.2
Norwegian Krone	142.3	–	22.4	–	(2.8)	–
Singapore Dollar	11.0	–	3.3	–	–	–
Australian Dollar	–	–	78.1	–	0.2	–
US Dollar	93.5	6.9	–	–	6.5	0.4
Total	429.3	65.2	194.6	–	12.6	5.3

As at 31 December 2016

		Contracted amount by contract maturity
	Buy		Sell		Maturity
(in \$ millions)	< 1 Year	1-5 Years	< 1 Year	1-5 Years	< 1 Year	1-5 Years
British Pound Sterling	30.1	18.9	100.9	–	(3.0)	(1.6)
Canadian Dollar	–	–	9.6	–	–	–
Danish Krone	2.8	–	–	–	–	–
Euro	192.1	55.1	8.3	–	0.3	(0.9)
Norwegian Krone	99.6	–	2.3	–	(2.7)	–
Australian Dollar	18.6	–	6.2	–	0.1	–
US Dollar	118.6	109.6	–	–	17.8	15.5
Total	461.8	183.6	127.3	–	12.5	13.0

33. Financial instruments continued

Hedge accounting

At 31 December 2017 and at 31 December 2016 none of the Group's outstanding forward foreign exchange contracts had been designated as hedging instruments.

The hedging reserve, included within other reserves in the Consolidated Balance Sheet, represents hedging gains and losses recognised on the effective portion of cash flow hedges. The movement in the hedging reserve was as follows:

(in \$ million)	2017	2016
At year beginning	–	2.2
Gains on the effective portion of derivative financial instruments deferred to equity:
operating expenses hedging	–	7.3
income tax recognised in equity	–	0.5
Cumulative deferred gains transferred to Consolidated Income Statement (see below):
operating expenses hedging	–	(10.0)
At year end	–	–
Cumulative gains and losses transferred from the hedging reserve to the Consolidated Income Statement
For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
Cumulative deferred gains recognised in operating expenses	–	9.9
Cumulative deferred gains recognised in other gains and losses	–	0.1

Total – 10.0

Interest rate risk management

The Group places surplus funds in the money markets to generate an investment return for a range of maturities (generally less than six months) ensuring a high level of liquidity and reducing the credit risk associated with the deposits. Changes in the interest rates associated with these deposits will impact the interest income generated.

Interest rate sensitivity analysis

At 31 December 2017, the Group had significant cash deposits and borrowings at USD LIBOR plus a margin. A 1% increase in interest rates would not have a significant impact on the Group's finance costs for the current or prior year due to the net cash position the Group was in throughout these periods.

Credit risk management

Credit risk arises from the financial assets of the Group, which comprise cash and cash equivalents, trade and other receivables and derivative instruments. Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group. The Group has adopted a policy of transacting with creditworthy financial institutions as a means of mitigating the risk of financial loss from defaults. The credit ratings are supplied by independent rating agencies. The Group's exposure and the credit ratings of its counterparties are continuously monitored and the aggregate value of transactions concluded is spread among approved counterparties. Credit exposure is controlled by counterparty limits that are reviewed and approved annually and monitored daily. The Group uses credit ratings as well as other publicly available financial information and its own trading records to rate its major counterparties.

The table below shows the carrying amount of amounts on deposit (excluding cash and cash equivalents available on demand of \$348.1 million) at year end. These are graded and monitored internally by the Group based on current external credit ratings issued with 'prime' being the highest possible rating.

2017	2016
As at (in \$ millions) 31 Dec	31 Dec
Counterparties rated prime grade 246.0	100.0
Counterparties rated high grade 75.0	378.0
Counterparties rated upper medium grade 359.6	673.2
Counterparties rated lower medium grade 63.5	83.5
Counterparties rated non-investment grade 16.9	16.2
Not rated –	0.2
Total 761.0	1,251.1

Net trade receivables (Note 19 'Trade and other receivables') arise from a large number of clients, dispersed geographically. Continuous credit evaluation is performed on the recoverability of trade receivables. The following table classifies outstanding balances into three categories:

	2017 31 Dec	2016 31 Dec
As at	Category percentage	Category percentage
National oil and gas companies	25%	10%
International oil and gas companies	22%	41%
Independent oil and gas companies	53%	49%
Total	100%	100%

National oil and gas companies are either partially or fully owned by or directly controlled by the government of their respective country of incorporation. Both international and independent oil and gas companies are mainly publicly or privately owned. International oil and gas companies are generally larger in size and scope than independent oil and gas companies and have midstream and downstream activities supplementing their upstream operations.

The following details the ageing analysis for trade receivables:

As at 31 December 2017

(in \$ millions)	Less than 1 month	1-3 months	3 months to 1 year	1-5 years	Total
Net trade receivables	201.8	118.5	40.1	21.4	381.8
Trade receivables considered impaired	1.8	–	1.7	15.9	19.4
Total trade receivables (Note 19)	203.6	118.5	41.8	37.3	401.2
As at 31 December 2016
(in \$ millions)	Less than 1 month	1-3 months	3 months to 1 year	1-5 years	Total
Net trade receivables	170.1	72.1	12.6	3.8	258.6
Trade receivables considered impaired	0.3	–	5.3	26.9	32.5
Total trade receivables (Note 19)	170.4	72.1	17.9	30.7	291.1

Trade receivables balances beyond the one month ageing category are considered past due but not impaired. Trade receivables considered impaired are balances which are past due and considered not collectable.

The maximum exposure of the Group to credit-related loss of financial instruments is the aggregate of the carrying amount of the financial assets as summarised on page 101.

Concentration of credit risk

During the year ended 31 December 2017, three clients (2016: two clients) contributed individually to more than 10% of the Group's revenue. The revenue from these clients was \$2.1 billion or 52% of total Group revenue (2016: \$1.1 billion or 31%).

The five largest receivables balances by client are shown below:

As at (in \$ millions)	31 Dec 2017
Client A	71.1
Client B	53.7
Client C	53.3
Client D	41.0
Client E	36.4

As at (in \$ millions)	31 Dec 2016
Client A	34.6
Client B	34.0
Client C	32.7
Client D	20.2
Client E	14.2

The client mix for outstanding accounts receivable balances in 2017 is not the same as 2016. The Group does not have any significant credit exposure to any single counterparty at 31 December 2017. The Group defines counterparties as having similar characteristics if they are related entities.

The credit risk on liquid funds and derivative financial instruments is limited because the counterparties are primarily banks with high credit-ratings assigned by international credit-rating agencies. At 31 December 2017, 32% (2016: 26%) of cash was held at counterparties with a credit rating lower than 'upper medium grade' classification.

33. Financial instruments continued

Liquidity risk management

The Group has a framework for the management of short, medium and long-term funding and liquidity management requirements. The Group continually monitors forecast and actual cash flows and matches the maturity profiles of financial assets and liabilities. Liquidity risk is managed by maintaining adequate cash and cash equivalent balances and by ensuring available borrowing facilities are in place. Included in Note 26 'Borrowings' are details of the undrawn facilities that the Group has at its disposal.

Liquidity tables

The following table details the Group's remaining contractual maturity for its non-derivative financial liabilities. The tables have been prepared based on the undiscounted cash flows relating to financial liabilities based on the earliest date on which the payment can be required. Principal cash flows are as follows:

As at 31 December 2017

(in \$ millions)	Less than 1 month	1-3 months	3 months to 1 year	1-5 years	Total
Trade payables	134.6	8.0	–	–	142.6
Current amounts due to associates and joint ventures	11.4	–	–	–	11.4
Loan due to associates and joint ventures	–	–	–	1.8	1.8
Total	146.0	8.0	–	1.8	155.8

As at 31 December 2016

(in \$ millions)	Less than 1 month	1-3 months	3 months to 1 year	1-5 years	Total
Trade payables	92.1	4.3	–	–	96.4
Convertible bonds	–	–	440.0	–	440.0
Loan due to associates and joint ventures	–	–	–	1.8	1.8
Total	92.1	4.3	440.0	1.8	538.2

The following table details the Group's liquidity profile for its derivative financial instruments. The table has been prepared based on the undiscounted net cash payments and receipts on the derivative instruments that settle on a net basis and the undiscounted gross payments and receipts on those derivative financial instruments that require gross settlement. When the amount payable or receivable is not fixed, the amount disclosed has been determined by reference to the projected interest rates as illustrated by the yield curves existing at the balance sheet date.

As at 31 December 2017

	Less than		3 months
(in \$ millions)	1 month	1-3 months	to 1 year	1-5 years	Total
Net settled:
Foreign exchange forward contracts	–	4.9	15.5	0.5	20.9
Gross settled:
Foreign exchange forward contract payments	145.2	57.7	10.3	–	213.2
Foreign exchange forward contract receipts	(142.4)	(57.2)	(9.5)	–	(209.1)
Total	2.8	5.4	16.3	0.5	25.0
As at 31 December 2016
	Less than		3 months
(in \$ millions)	1 month	1-3 months	to 1 year	1-5 years	Total
Net settled:
Foreign exchange forward contracts	–	8.7	27.1	13.1	48.9
Gross settled:
Foreign exchange forward contract payments	263.0	–	–	–	263.0
Foreign exchange forward contract receipts	(257.6)	–	–	–	(257.6)
Total	5.4	8.7	27.1	13.1	54.3

Capital risk management

The Group manages its capital to ensure that entities in the Group will be able to continue as going concerns while maximising the return to shareholders of the parent company.

The capital structure of the Group consists of debt, which includes borrowings disclosed in Note 26 'Borrowings', cash and cash equivalents and equity attributable to shareholders of the parent company, comprising issued share capital, reserves and retained earnings.

The Group monitors capital using a debt service ratio (net debt/Adjusted EBITDA) which is evaluated against certain parameters. Net debt is calculated as the principal value of borrowings plus current year operating lease payments adjusted by a multiplier of six, less cash and cash equivalents.

Debt service

	2017	2016
As at (in \$ millions)	31 Dec	31 Dec
Export Credit Agency (ECA) senior secured facility (Note 26)	282.7	–
Principal value of convertible bonds (Note 27)	–	435.6
Estimated present value of operating lease obligations(a)	982.2	1,117.2
Restricted cash	(6.3)	–
Cash and cash equivalents	(1,109.1)	(1,676.4)
Net debt(b)	149.5	(123.6)
Adjusted EBITDA (see Additional information on page 119)	1,034.6	1,141.7
Debt service ratio(b)	0.1x	(0.1)x

(a) Estimated present value of operating lease obligations is six times current year payments made under operating leases (Note 32 'Operating lease arrangements'). (b) The above is a representation of how the Group calculates net debt and the debt service ratio for illustrative purposes only.

Fair value measurement

Assets and liabilities which are measured at fair value in the Consolidated Balance Sheet and their level of the fair value hierarchy were as follows:

	2017 31 Dec	2017 31 Dec	2016 31 Dec	2016 31 Dec
As at (in \$ millions)	Level 2	Level 3	Level 2	Level 3
Recurring fair value measurements
Financial assets:
Financial assets at fair value through profit or loss – derivative instruments	42.7	–	78.4	–
Financial liabilities:
Financial liabilities at fair value through profit or loss – derivative instruments	(24.8)	–	(52.9)	–
Contingent consideration (Note 30)	–	(20.0)	–	(11.5)

During the year ended 31 December 2017 there were no transfers between levels of the fair value hierarchy. The Group accounts for transfers between levels of the fair value hierarchy from the date of the event or change in circumstance that caused the transfer.

Recurring fair value measurements

Financial assets and financial liabilities

The fair values of financial assets and financial liabilities are determined as follows:

• the fair values of financial assets and financial liabilities with standard terms and conditions and traded on active liquid markets are determined with reference to quoted market prices
• the fair values of other financial assets and financial liabilities (excluding derivative instruments) are determined in accordance with generally accepted pricing models based on discounted cash flow analysis using prices from observable current market transactions and dealer quotes for similar instruments
• The fair value of contingent consideration is determined based on current expectations of the achievement of specific targets and milestones calculated using the discounted cash flow method and unobservable inputs
• The fair values of derivative instruments are calculated using quoted prices. Where such prices are not available, use is made of discounted cash flow analysis using the applicable yield curve for the duration of the instruments for non-optional derivative financial instruments, and option pricing models for optional derivative financial instruments.

Assumptions used in determining fair value of financial assets and financial liabilities are as follows:

Loans and receivables

The fair value of loans and receivables is based on their carrying amount which is representative of outstanding amounts owing and takes into consideration potential impairment.

Forward foreign exchange contracts

The fair value of outstanding forward foreign exchange contracts and embedded derivatives is calculated using quoted foreign exchange rates and yield curves derived from quoted interest rates matching maturities of the contract.

33. Financial instruments continued

Fair value hierarchy

The Group classifies fair value measurements using a fair value hierarchy that reflects the significance of the inputs used in making the measurements. The fair value hierarchy has the following levels:

• Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities.
• Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices).
• Level 3 Inputs for the asset or liability that are not based on observable market data (unobservable inputs).

34. Related party transactions

Key management personnel

Key management personnel include the Board of Directors and the Executive Management Team. Key management personnel at 31 December 2017 included 12 individuals (2016: 12 individuals). The remuneration of these personnel is determined by the Compensation Committee of the Board of Directors of Subsea 7 S.A.

Non-executive Directors

Details of fees paid to Non-executive Directors for the year are set out below:

Name	Annual fee \$	Member of Audit Committee \$	2017 31 Dec \$	2016 31 Dec \$
Kristian Siem	200,000	–	–(a)	–(a)
Sir Peter Mason KBE	125,000	–	125,000	125,000
Eystein Eriksrud	105,000	6,000	111,000	111,000
Dod Fraser	105,000	14,000	119,000	119,000
Robert Long	105,000	6,000	111,000	111,000
Allen Stevens	105,000	–	105,000	105,000

(a) Mr Siem's fee is included within payments to Siem Industries Inc. as detailed in 'Other related party transactions' on page 109.

Share options outstanding and shareholdings at 31 December 2017 were as follows:

Share options

None (2016: none) of the Non-executive Directors held share options in the shares of Subsea 7 S.A. at 31 December 2017.

Shareholdings

Name	Total owned shares
Kristian Siem(a)	–
Sir Peter Mason KBE	10,000
Eystein Eriksrud(b)	3,100
Dod Fraser	4,000
Robert Long	–
Allen Stevens	10,650

(a) At 31 December 2017, Siem Industries Inc. which is a company controlled through trusts where Mr Siem and certain members of his family are potential beneficiaries, owned 69,731,931 shares, representing 21.3% of total fully paid and issued common shares of the Company.

(b) Mr Eriksrud is Deputy CEO of Siem Industries Inc. which, at 31 December 2017, owned 69,731,931 shares representing 21.3% of total fully paid and issued common shares of the Company.

Key management

The remuneration of the Executive Management Team during the year was as follows:

For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
Salaries and other short-term employee benefits	7.8	6.7
Share-based payments	1.1	1.1
Post-employment benefits	0.1	0.1
Total	9.0	7.9

The compensation of the Chief Executive Officer ('CEO') for the year was \$2.5 million (2016: \$1.9 million) and included base salary, bonus and benefits-in-kind. This amount excludes the IFRS 2 'Share-based payments' charge for any incentive plans of which the CEO is a member.

Effective 1 January 2018, following his resignation, Øyvind Mikaelsen ceased to be a member of the Executive Management Team.

Financial Statements

Key management continued

Share options and performance shares outstanding and shareholdings at 31 December 2017 were as follows:

Share options

	Number
Name	Date of grant	of options	Exercise price	Date of expiry
Jean Cahuzac	14 Apr 2008	100,000	NOK 123.00	13 Apr 2018
Nathalie Louys	12 Mar 2008	8,000	\$22.52	11 Mar 2018
Keith Tipson	12 Mar 2008	15,000	NOK 114.50	11 Mar 2018
Øyvind Mikaelsen	12 Mar 2008	15,000	NOK 114.50	11 Mar 2018

Shares and performance shares

	Total
Name	performance shares(a)	Total owned shares
Jean Cahuzac	211,025	108,816
Ricardo Rosa	122,531	9,374
John Evans	152,993	40,947
Nathalie Louys	74,638	7,766
Keith Tipson	78,788	28,306
Øyvind Mikaelsen	137,531	26,767

(a) Total performance shares held represent the maximum award assuming all conditions are met.

Transactions with key management personnel

During the year, key management personnel were awarded the rights to 207,000 (2016: 228,000) performance shares under the 2013 Long-term Incentive Plan; refer to Note 35 'Share-based payments' for details of the plan.

Transactions with associates and joint ventures

The Consolidated Balance Sheet included:

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Non-current receivables due from associates and joint ventures (Note 17)	6.7	8.6
Non-current payables due to associates and joint ventures (Note 28)	(1.8)	(1.8)
Trade receivables due from associates and joint ventures (Note 19)	6.7	33.6
Trade payables due to associates and joint ventures (Note 29)	(11.4)	–
Net receivables due from associates and joint ventures	0.2	40.4

Trade receivables due from associates and joint ventures are shown net of provisions for impairment of \$13.1 million (2016: \$12.4 million).

During the year, the Group provided services to associates and joint ventures amounting to \$6.6 million (2016: \$25.9 million) and purchased goods and services from associates and joint ventures amounting to \$178.8 million (2016: \$351.4 million).

At 31 December 2017, the Group had provided long-term loans to joint ventures amounting to \$6.7 million (2016: \$8.6 million). Working capital funding of associates and joint ventures is included within trade receivables due from associates and joint ventures above.

Guarantee arrangements with joint ventures are shown within Note 26 'Borrowings'.

Other related party transactions

During the year the Group participated in related party transactions, all of which were conducted on an arm's length basis.

The Group is an associate of Siem Industries Inc. and is equity accounted for within Siem Industries Inc.'s consolidated financial statements. Payments were made to Siem Industries Inc. in relation to the services provided by Mr Siem and other services totalling \$0.2 million (2016: \$0.2 million). Dividends totalling \$40.9 million (2016: \$nil) were paid to Siem Industries Inc.

Siem Offshore Contractors GmbH is ultimately controlled by Siem Industries Inc. Purchases by the Group from Siem Offshore Contractors GmbH relating to the provision of installation of inter-array cables for the Beatrice offshore wind farm project totalling \$26.2 million (2016: \$nil), were made during the year.

Siem Offshore Inc. is an associate of Siem Industries Inc. and Mr Eriksrud is its Chairman and Mr Siem is a member of the Board of Directors. Purchases by the Group from subsidiaries of Siem Offshore Inc. including vessel charter costs, provision of crew and associated services, related to life of field activities, totalling \$21.5 million (2016: \$26.5 million), were made during the year.

The Group provides rented office accommodation to Siem Offshore Contractors GmbH and Siem Offshore do Brasil S.A. which are both ultimately controlled by Siem Industries Inc. Total rental income for 2017 was \$0.5 million (2016: \$0.2 million).

34. Related party transactions continued

The Group provides rented office accommodation to Siem Shipping UK Limited and Siem Offshore Australia Pty Limited, in which Mr Siem holds a controlling share in both companies. Total rental income for 2017 was \$0.1 million (2016: \$0.1 million).

During 2017, the Group rented office accommodation from Siem Europe Properties Sarl, a company ultimately controlled by Siem Industries inc.

DSND Bygg AS is ultimately controlled by Siem Industries Inc. Purchases from DSND Bygg AS in relation to the rental of office accommodation totalling \$nil (2016: \$0.2 million) were made during the year.

At 31 December 2017, the Group had outstanding balances payable to Siem Offshore Contractors GmbH of \$3.6 million (2016: \$nil).

At 31 December 2017, the Group had outstanding balances receivable from Siem Industries Inc, Siem Offshore Contractors GmbH and Siem Offshore do Brasil S.A. of \$0.3 million (2016: \$1.0 million).

35. Share-based payments

The Group operates two equity-settled share-based payment schemes.

The following table summarises the compensation expense recognised in the Consolidated Income Statement during the year:

For the year ended (in \$ millions)	2017 31 Dec	2016 31 Dec
Expense arising from equity-settled share-based payment transactions:
2009 Long-term Incentive Plan	0.5	0.1
2013 Long-term Incentive Plan	5.5	6.5
Total	6.0	6.6

Equity-settled share-based payment schemes

2009 Long-term Incentive Plan

The 2009 Long-term Incentive Plan (2009 LTIP) was approved by the Company's shareholders at the Extraordinary General Meeting on 17 December 2009. The 2009 LTIP had a five-year term but was replaced with the 2013 Long-term Incentive Plan during 2013. The final award made under the terms of the 2009 LTIP concluded, without vesting, on 10 September 2017.

2013 Long-term Incentive Plan

The 2013 Long-term Incentive Plan (2013 LTIP) was approved by the Company's shareholders at the Annual General Meeting on 28 June 2013. The 2013 LTIP has a five-year term with awards being made annually. The aggregate number of shares which may be granted in any calendar year is limited to 0.5% of issued and outstanding share capital on 1 January of that calendar year. Grants are determined by the Compensation Committee of the Subsea 7 S.A. Board of Directors, which is responsible for operating and administering the plan.

The 2013 LTIP is an essential component of the Group's reward strategy, and was designed to align the interests of participants with those of Subsea 7's shareholders, and enables participants to share in the success of the Group. The 2013 LTIP provides for conditional awards of shares based upon performance conditions over a performance period of at least three years.

Performance conditions are based on two measures: relative Total Shareholder Return (TSR) against a specified comparator group of companies and the level of Return on Average Invested Capital (ROAIC) achieved. Both performance conditions are determined over a three-year period.

During 2017, initial grants comprising 1,119,000 (2016: 1,021,000) conditional awards of shares were made under the terms of the 2013 LTIP: 727,350 (2016: 663,650) awards are subject to relative TSR performance measures and 391,650 (2016: 357,350) are subject to ROAIC performance measures.

On 1 October 2017, in accordance with the terms of the 2013 LTIP, shares totalling 635,955 (2016: 190,255) were unconditionally transferred to participants.

TSR based awards

The Group will have to deliver a TSR ranking above the median for any awards to vest. If the ranked TSR position of Subsea 7 during the three-year period, as converted to a percentage, is equal to 50%, 20% of the share award will vest. If the actual ranked TSR position of Subsea 7 is greater than 50% and below 90%, the vesting of the share award between 20% and 65% is determined by linear interpolation. The maximum award of 65% would only vest if the Group achieved top decile TSR ranking.

ROAIC based awards

ROAIC will be calculated for each of the three years of the performance period on a quarterly basis. If the average ROAIC achieved by the Group during the performance period is greater than 9% but less than 11%, vesting between 5% and 15% shall be determined by linear interpolation. If the actual ROAIC achieved by the Group during the performance period is greater than 11% but less than 14%, vesting between 15% and 35% shall be determined by linear interpolation. The maximum award of 35% would only vest if the Group achieved average ROAIC of 14% or greater.

Under the terms of the award 2013 LTIP participants are not entitled to receive dividend equivalent payments.

ROAIC based awards continued

Approximately 160 senior managers and key employees participate in the 2013 LTIP. Individual award caps are in place such that no senior executive or other employee may be granted shares under the 2013 LTIP in a single calendar year that have an aggregate fair market value in excess of 150%, in the case of senior executives, or 100%, in the case of other employees, of their annual base salary at the date of the award. Additionally, a holding requirement for senior executives applies where senior executives must hold 50% of all awards that vest until they have built up a shareholding with a fair value of 150% of their annual base salary which must be maintained throughout their tenure.

111

The IFRS 2 'Share-based payments' fair value of each performance share granted under the 2013 LTIP is estimated as of the grant date using a Monte Carlo simulation model with weighted average assumptions as follows:

For the year ended	2017 31 Dec	2016 31 Dec
Weighted average share price at grant date (in \$)	16.56	10.57
TSR performance – Weighted average fair value at grant date (in \$)	9.10	5.85
ROAIC performance – Weighted average fair value at grant date (in \$)	15.73	10.20
Expected volatility	43%	43%
Risk free rate	0.83%	0.79%
Dividend yield	1.3%	0.9%

The expected share price volatility over the performance period is estimated from the Company's historical volatility. The award fair values were adjusted to recognise that participants are not entitled to receive dividend equivalent payments.

The non-market ROAIC performance condition is not incorporated into the grant date fair value of the ROAIC based awards. The value of each award will be adjusted at every reporting date to reflect the Group's current expectation of the number of performance shares which will vest under the non-market ROAIC performance condition.

2003 Plan

The Group operated a share option plan which was approved in April 2003 (the 2003 Plan). This plan included an additional option plan for key employees resident in France as a sub-plan (the 'French Plan'), and additional options which were granted under the Senior Management Incentive Plan. The Compensation Committee appointed by the Board of Directors of Subsea 7 S.A. administers these plans. Options were awarded at the discretion of the Compensation Committee to Directors and key employees of Subsea 7 S.A. and its subsidiaries.

Options under the 2003 Plan (and therefore also under the French Plan) are exercisable for periods of up to ten years, at an exercise price not less than the fair market value per share at the time the option is granted. All such options had vested prior to 31 December 2017. Share option exercises are satisfied by reissuing treasury shares. Furthermore, options are generally forfeited if the option holder leaves the Group under any circumstances other than due to the option holder's death, disability, redundancy or retirement before his or her options are exercised. No further share options will be granted under the 2003 Plan or the French Plan.

Subsea 7 Inc. share option plans

As part of the Combination, the Group replaced the share options previously issued by Subsea 7 Inc. All such options have vested with the final options awarded under the plan expiring during the year ended 31 December 2017.

Share options

Option activity for the 2003 Plan and Subsea 7 Inc. share option plans was as follows:

	Number of options 2017	Weighted average exercise price in \$ 2017	Number of options 2016	Weighted average exercise price in \$ 2016
Outstanding at year beginning	527,307	16.80	947,067	16.16
Exercised	(44,213)	13.86	–	–
Expired	(44,805)	16.65	(419,760)	15.47
Outstanding at year end	438,289	17.82	527,307	16.80
Exercisable at the end of the year	438,289	17.82	527,307	16.80

The weighted average market price at exercise date of options exercised during the year ended 31 December 2017 was \$15.99. There were no options exercised during the year ended 31 December 2016.

35. Share-based payments continued

The following table summarises information regarding share options outstanding at 31 December 2017:

	Options outstanding
Common shares (range of exercise prices)	Options outstanding	Weighted average remaining contractual life (in years)	Weighted average exercise price (in \$)
\$17.01 – \$26.16	188,548	0.20	22.52
\$10.01 – \$17.00	249,741	0.23	14.28
Total	438,289	0.22	17.82

36. Retirement benefit obligations

The Group operates both defined contribution and defined benefit pension plans.

The Group's contributions under the defined contribution pension plans are determined as a percentage of individual employee gross salaries. The expense relating to these plans for the year was \$31.7 million (2016: \$38.3 million).

Defined benefit plans

The Group operates both funded and unfunded defined benefit pension plans.

France

The defined benefit plan for France is called the indemnités de fin de carrière (retirement indemnity plan) and is pursuant to applicable French legislation and labour agreements in force in the industry. A lump-sum payment is made to employees upon retirement based on length of service, employment category and the employee's final salary. The obligation is unfunded and uninsured, as is standard practice in France. Since the retirement indemnity plan is based upon specific lengths of service, categories and values set by French legislation and collective agreements there is no specific trust or internal governance in place for this plan.

Norway

There are two Norwegian defined benefit pension plans which are known as the office (onshore) plan and the sailor plan.

The office (onshore) plan is a defined benefit scheme held with a life insurance company to provide pension benefits for the Group's employees. The scheme provides entitlement to benefits based on future service from the commencement date of the scheme. These benefits are principally dependent on an employee's pension qualifying period, salary at retirement age and the size of benefits from the National Insurance Scheme. The scheme also includes entitlement to disability, spouses and children's pensions. The retirement age under the scheme is 67 years. The office (onshore) plan is closed to new members.

The sailor plan is an established separate tariff rated pension scheme for offshore personnel. Pensions are paid upon retirement based on the employee's length of service and final salary. Under this scheme participants are entitled to receive a pension between 60-67 years of age. These are funded obligations.

Under the plans, pensions are paid upon retirement based on the employee's length of service and final salary. The plans have been established in accordance with Norwegian legislation and are separately administered funds. Due to Norwegian legislation the pension scheme must provide an annual guaranteed return on investment, and consequently, the plan assets have a bias toward bonds rather than equities. While the pension company is responsible for handling the plan according to Norwegian law, the Group is obligated to have a steering committee for the plan. The steering committee considers and makes recommendations to the Group on matters relating to the plan, including but not limited to: composition of the investment portfolio, amendments to the scheme, administration and enforcement of the scheme, transfer of funds to the Group, transfer of the scheme to another pension provider and termination of the scheme.

Netherlands

There are two Netherlands defined benefit pension plans which are known as the SHL-Seaway plan and the SHL-Crew plan. Both of these plans are for salaries up to the threshold of the Netherlands WIA (Disablement Insurance Act) and take into account the fixed franchise for the Netherlands AOW (Old Age pension). For employees whose gross yearly salary exceeds the legally determined WIA threshold a so-called 'excedent' pension arrangement applies. Accumulation of the retirement obligation asset commences through the deposit of a premium ranging between 4.5% and 17.9% depending on the age of the employee, calculated on the salary above the set WIA threshold. Half of the premium is paid by the employer. The retirement age under the plans is 67 years however this will increase to 68 years on 1 January 2018. These are funded obligations which are insured with a third party and are currently in a deficit position. The Group has an obligation to ensure that the benefits under these schemes, not currently fully covered by the insurance policy, can be met.

Changes in the defined benefit obligation and fair value of plan assets

The following table provides a reconciliation of the changes in retirement benefit obligations and in the fair value of plan assets:

	Norway		Netherlands		France		Total
(in \$ millions)	2017	2016	2017	2016	2017	2016	2017	2016
Defined benefit obligation
At year beginning	(18.2)	(19.0)	–	–	(7.5)	(10.4)	(25.7)	(29.4)
Acquisition of business	–	–	(53.2)	–	–	–	(53.2)	–
Pension costs charged to the Consolidated Income Statement:
Service costs	(0.4)	(0.5)	(5.2)	–	(0.7)	(0.9)	(6.3)	(1.4)
Past service costs	1.0	–	(0.2)	–	–	–	0.8	–
Interest cost	(0.4)	(0.5)	(1.1)	–	(0.1)	(0.2)	(1.6)	(0.7)
Curtailment	–	–	–	–	–	2.9	–	2.9
Liabilities extinguished on settlements	–	–	–	–	–	–	–	–
Employee taxes	(0.1)	0.1	–	–	–	–	(0.1)	0.1
Sub-total	0.1	(0.9)	(6.5)	–	(0.8)	1.8	(7.2)	0.9
Remeasurement gains/(losses) recognised in other comprehensive income:
Actuarial changes arising from changes in financial assumptions	–	(0.7)	1.9	–	(0.3)	0.4	1.6	(0.3)
Experience adjustments	(0.5)	1.8	0.4	–	(0.1)	0.3	(0.2)	2.1
Sub-total	(0.5)	1.1	2.3	–	(0.4)	0.7	1.4	1.8
Benefits paid	0.7	0.7	0.2	–	–	0.1	0.9	0.8
Exchange differences	(0.5)	(0.1)	(10.9)	–	(1.0)	0.3	(12.4)	0.2
At year end	(18.4)	(18.2)	(68.1)	–	(9.7)	(7.5)	(96.2)	(25.7)
Fair value of plan assets
At year beginning	16.1	16.9	–	–	–	–	16.1	16.9
Acquisition of business	–	–	39.4	–	–	–	39.4	–
Amounts credited/(charged) to the Consolidated Income Statement:
Past service cost	(0.9)	–	–	–	–	–	(0.9)	–
Interest income	0.3	0.4	0.9	–	–	–	1.2	0.4
Settlements	–	–	–	–	–	–	–	–
Other	–	–	(0.1)	–	–	–	(0.1)	–
Sub-total	(0.6)	0.4	0.8	–	–	–	0.2	0.4
Remeasurement gains/(losses) recognised in other comprehensive income:
Return on plan assets (excluding amounts in interest income)	(0.9)	(0.6)	(1.3)	–	–	–	(2.2)	(0.6)
Administrative expenses	(0.2)	(0.2)	–	–	–	–	(0.2)	(0.2)
Experience adjustments	–	–	0.6	–	–	–	0.6	–
Sub-total	(1.1)	(0.8)	(0.7)	–	–	–	(1.8)	(0.8)
Employer and participant contributions	0.3	0.3	2.6	–	–	–	2.9	0.3
Benefits paid	(0.7)	(0.7)	(0.2)	–	–	–	(0.9)	(0.7)
Exchange differences	1.3	–	8.1	–	–	–	9.4	–
At year end	15.3	16.1	50.0	–	–	–	65.3	16.1
Net defined benefit obligation	(3.1)	(2.1)	(18.1)	–	(9.7)	(7.5)	(30.9)	(9.6)
Presented as:
Retirement benefit assets	–	0.3	–	–	–	–	–	0.3
Retirement benefit obligations	(3.1)	(2.4)	(18.1)	–	(9.7)	(7.5)	(30.9)	(9.9)
Total	(3.1)	(2.1)	(18.1)	–	(9.7)	(7.5)	(30.9)	(9.6)

The retirement benefit obligations of \$30.9 million (2016: \$9.6 million) for pension schemes which are in deficit in Norway, the Netherlands and France, as shown above, are recognised as non-current liabilities within the Consolidated Balance Sheet.

Financial Statements

36. Retirement benefit obligations continued

Unfunded schemes

Included within the defined benefit obligation are amounts arising from unfunded French plans with a total obligation of \$9.7 million (2016: \$7.5 million).

Funded schemes

The Netherlands schemes are funded through a reinsured insurance contract based on a 5 year fixed interest rate. The fair value of the Netherlands plan assets were as follows:

As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Unquoted investments
Insurance contract	49.9	–
Cash and cash equivalents	0.1	–
Total	50.0	–
The Norwegian schemes are funded through a separately administered investment fund. The fair value of the Norwegian plan assets were as follows:
As at (in \$ millions)	2017 31 Dec	2016 31 Dec
Investments quoted in active markets
Quoted equity investments	1.9	1.5
Unquoted investments
Deposits	–	0.4
Bonds	9.0	10.7
Property	2.1	2.3
Other	2.3	1.3
Total	15.3	16.2

Future cash flows

The estimated contributions expected to be paid into the French, Dutch and Norwegian plans during 2018 total \$3.8 million.

The average remaining service periods were as follows:

2017 As at (in years) 31 Dec	2016 31 Dec
Norway office (onshore) plan 7.0	8.0
SHL-Seaway plan 18.5	–
SHL-Crew plan 16.8	–

Significant actuarial assumptions

The principal assumptions used to determine the present value of the defined benefit obligation were as follows:

Netherlands	Norway	France
–	0.4 – 2.3	–
2.0	2.3	1.3
2.5	2.5	3.0
Netherlands	Norway	France
–	0.0 – 2.3	–
–	2.1	1.5
–	2.0	3.0

Assumptions regarding future mortality are set based on advice in accordance with published statistics and experience. The average life expectancies in years of a pensioner retiring at the plan retirement age for participants in the Norway office (onshore) plan, the SHL Seaway plan and the SHL Crew plan are shown below. Life expectancy information for the sailor plan has not been provided as participants are only entitled to receive a pension between 60-67 years of age.

			As at balance sheet date
Retirement benefit plan	Retirement age	Sex	2017 31 Dec	2016 31 Dec
Norway office (onshore) plan	67 years	Male	11.7	10.8
	67 years	Female	15.8	17.2
SHL-Seaway plan	67 years	Male	20.0	–
	67 years	Female	22.0	–
SHL-Crew plan	67 years	Male	20.0	–
	67 years	Female	22.0	–

Sensitivity analysis

A quantitative sensitivity analysis for significant assumptions at 31 December 2017 is shown below. The sensitivity analysis has been determined based on a method that extrapolates the impact on the net defined benefit obligation ((increase)/decrease) as a result of reasonable changes in key assumptions occurring at the end of the reporting period.

Norway – sailor plan
(in \$ millions)		Pension increase Discount rate			Future salary increase
Sensitivity level	0.5% increase	0.5% decrease	0.5% increase	0.5% decrease	0.5% increase	0.5% decrease
Impact on the net defined benefit obligation	(0.2)	0.2	0.4	(0.5)	(0.6)	0.6
Norway – office plan
(in \$ millions)		Pension increase		Discount rate		Future salary increase
Sensitivity level	0.5% increase	0.5% decrease	0.5% increase	0.5% decrease	0.5% increase	0.5% decrease
Impact on the net defined benefit obligation	(0.7)	0.7	0.7	(0.7)	–	–
Netherlands – SHL-Seaway plan
(in \$ millions)		Life expectancy		Discount rate		Future salary increase
Sensitivity level	1 year increase	1 year decrease	0.5% increase	0.5% decrease	0.5% increase	0.5% decrease
Impact on the net defined benefit obligation	(0.5)	0.5	2.4	(3.3)	(5.2)	4.6
Netherlands – SHL Crew plan
(in \$ millions)		Life expectancy		Discount rate		Future salary increase
Sensitivity level	1 year increase	1 year decrease	0.5% increase	0.5% decrease	0.5% increase	0.5% decrease
Impact on the net defined benefit obligation	(0.1)	0.1	0.3	(0.5)	(0.8)	0.7
France
(in \$ millions)						Discount rate
Sensitivity level					0.25% increase	0.25% decrease
Impact on the net defined benefit obligation					0.3	(0.3)
37. Deferred revenue
As at (in \$ millions)					2017 31 Dec	2016 31 Dec
Advances received from clients					4.2	6.1

Advances received from clients include amounts received before the related work is performed on day-rate contracts and amounts paid by clients in advance of work commencing on construction contracts.

38. Cash flow from operating activities

For the year ended (in \$ millions)	Notes	2017 31 Dec	2016 31 Dec
Cash flow from operating activities:
Income before taxes		554.5	576.7
Adjustments for non-cash items:
Depreciation of property, plant and equipment	15	388.5	354.5
Impairment of property, plant and equipment	15	31.5	157.9
Impairment of intangible assets	14	–	0.6
Amortisation of intangible assets	14	26.4	7.3
Impairment of goodwill	13	–	90.4
Mobilisation costs	6	7.4	10.0
Adjustments for investing and financing items:
Remeasurement gain on business combination	12	(25.0)	–
Net bargain purchase gain on business combination	12	(3.4)	–
Share of net loss/(income) of associates and joint ventures	16	42.7	(46.4)
Finance income	8	(24.6)	(17.9)
Net (gain)/loss on disposal of property, plant and equipment	7	(0.5)	2.3
Net loss/(gain) on repurchase of convertible bonds and settlement of borrowings	7	2.4	(3.0)
Finance costs	8	21.0	7.1
Adjustments for equity items:
Reclassification adjustments relating to foreign subsidiaries disposed of in the year		7.4	–
Share-based payments	35	6.0	6.6
		1,034.3	1,146.1
Changes in operating assets and liabilities:
Decrease in inventories		7.4	6.3
(Increase)/decrease in operating receivables		(176.8)	126.3
Decrease in operating liabilities		(554.4)	(92.5)
		(723.8)	40.1
Income taxes paid		(101.2)	(140.6)
Net cash generated from operating activities		209.3	1,045.6

39. Post balance sheet events

Dividend

In light of the Group's solid financial and liquidity position and improved market outlook, the Board of Directors will recommend to the shareholders at the Annual General Meeting on 17 April 2018 that a special dividend of NOK 5.00 per share be paid, equivalent to a total dividend of approximately \$200 million.

Business combinations

Agreement to invest in Xodus Group

On 20 February 2018 an indirect subsidiary of Subsea 7 S.A. agreed to acquire 60% of the voting shares of Xodus Group (Holdings) Limited, a leading energy consultancy, from the Chiyoda Corporation.

The primary reason for the investment is to enhance the Group's early engineering engagement in both the oil and gas and offshore renewables industries. The business combination, which is expected to be completed during the first quarter of 2018, and subsequent to the business combination, Xodus Group (Holdings) Limited and its subsidiaries will become non-wholly owned subsidiaries of the Group.

Schlumberger and Subsea 7 announce intent to form a joint venture

On 23 February 2018 the Group announced that it has entered into exclusive negotiations with Schlumberger to form a joint venture. The Group will own 50% of the voting shares of the joint venture and its interest will be equity accounted within the Consolidated Financial Statements. The creation of the joint venture builds upon the existing Subsea Integration Alliance which has been in place between the two companies since 2015. The proposed transaction will result in both parties contributing resources related to early engagement and tendering and both parties will assign their respective Life of Field businesses to the joint venture.

The primary reason for the transaction is to strengthen the front-end engineering, design and execution of integrated projects and to create a Life of Field offering which includes autonomous subsea technology, digitally enabled remote surveillance and production monitoring, and inspection, maintenance and repair services.

Agreement to acquire certain businesses and assets of Siem Offshore Inc.

On 28 February 2018, indirect subsidiaries of Subsea 7 S.A. entered into an agreement to acquire the entire share capital of Siem Offshore Contractors GmbH ('Siem Offshore Contractors'), the inter-array cable lay vessel Siem Aimery and the support vessel Siem Moxie. The acquisition will further expand Subsea 7's presence in the renewables segment.

Siem Offshore Contractors is a well-known installer of subsea inter-array cables and provides repair and maintenance services to the global offshore renewable energy market. It employs approximately 100 people. The vessels, Siem Aimery and Siem Moxie, are owned by Siem Offshore Rederi AS. Siem Offshore Contractors GmbH and Siem Offshore Rederi AS are wholly-owned subsidiaries of Siem Offshore Inc., which is a related party to Subsea 7 S.A.

The initial consideration is EUR 140 million subject to adjustments for working capital and net cash in Siem Offshore Contractors and a deferred contingent consideration, based on the contracted volume of work achieved each year up to 2024, which is not expected to exceed EUR 40 million over the period.

The transaction is expected to be completed in the first half of 2018, subject to competition clearance in Germany. Subsequent to the business combination Siem Offshore Contractors will become a wholly-owned subsidiary of the Group with the results being recognised within the Renewables and Heavy Lifting Business Unit.

40. Wholly-owned subsidiaries

Subsea 7 S.A. had the following wholly-owned subsidiaries at 31 December 2017.

Name	Country of registration	Nature of business
Acergy (Gibraltar) Limited	Gibraltar	Corporate Service
Acergy B.V.	Netherlands	Holding
Acergy Concrete Products LLC	USA	General Trading
Acergy France SAS	France	General Trading
Acergy Holdings (Gibraltar) Limited(a)	Gibraltar	Holding
Acergy Shipping Inc.	Panama	Vessel Owning
Aquarius Solutions Inc.	Canada	General Trading
Class 3 (UK) Limited	United Kingdom	Vessel Owning
EMAS AMC PTE Limited	Singapore	General Trading
EMAS Chiyoda Subsea Services Pte Limited	Singapore	General Trading
EMAS Saudi Arabia Ltd	Saudi Arabia	General Trading
Globestar FZE (Snake Island)	Nigeria	General Trading
Normand Oceanic AS	Norway	General Trading
Normand Oceanic Chartering AS	Norway	General Trading
Pelagic Nigeria Limited	Nigeria	Holding
Pioneer Lining Technology Limited	United Kingdom	General Trading
PT. Subsea 7 Manufaktur Indonesia	Indonesia	General Trading
Seaway Heavy Lifting Limited	Cyprus	General Trading
Seaway Heavy Lifting Contracting France SAS	France	General Trading
Seaway Heavy Lifting Contracting Germany GmbH	Germany	General Trading
Seaway Heavy Lifting Contracting Limited	Cyprus	General Trading
Seaway Heavy Lifting Contracting UK Limited	United Kingdom	General Trading
Seaway Heavy Lifting Engineering B.V.	Netherlands	General Trading
Seaway Heavy Lifting Holding Limited	Cyprus	Holding
Seaway Heavy Lifting Offshore Crew B.V.	Netherlands	General Trading
Seaway Heavy Lifting Shipping Limited	Cyprus	Vessel Owning
Seaway Offshore Participações S.A.	Brazil	Holding
Sevenseas Contractors S de RL de CV	Mexico	General Trading
SHL Contracting B.V.	Netherlands	General Trading
SHL Contracting US Inc.	USA	General Trading
SHL Holding NL B.V.	Netherlands	General Trading
SHL Offshore Contractors B.V.	Netherlands	General Trading
SHL Stanislav Yudin Limited	Cyprus	Vessel Owning
SO France S.A.	France	Special Purpose
Subsea 7 Marine (US) Inc.	USA	General Trading
SO Services Inc.	USA	Special Purpose
Subsea 7 (Cyprus) Limited	Cyprus	Vessel Owning
Subsea 7 (Singapore) PTE Limited	Singapore	General Trading
Subsea 7 (UK Service Company) Limited(a)	United Kingdom	Corporate Service
Subsea 7 (US) LLC	USA	General Trading
Subsea 7 (Vessel Company) B.V.	Netherlands	Vessel Owning
Subsea 7 Angola SAS	France	Special Purpose
Subsea 7 Asia Pacific Sdn Bhd	Malaysia	Special Purpose

40. Wholly-owned subsidiaries continued

Name	Country of registration	Nature of business
Subsea 7 Australia Contracting Pty Ltd	Australia	General Trading
Subsea 7 Canada Inc.	Canada	General Trading
Subsea 7 Chartering (UK) Limited	United Kingdom	General Trading
Subsea 7 Contracting (UK) Limited	United Kingdom	General Trading
Subsea 7 Crewing Limited	United Kingdom	Special Purpose
Subsea 7 Crewing Services Pte Limited	Singapore	Special Purpose
Subsea 7 Deep Sea Limited	United Kingdom	General Trading
Subsea 7 Do Brasil Serviços Ltda	Brazil	General Trading
Subsea 7 Engineering Limited	United Kingdom	General Trading
Subsea 7 Finance (UK) PLC	United Kingdom	Special Purpose
Subsea 7 Holding Inc.	Cayman Islands	Holding
Subsea 7 Holding Norway AS	Norway	Holding
Subsea 7 Holdings (US) Inc.	USA	Holding
Subsea 7 Interim UK Holdings Limited	United Kingdom	Holding
Subsea 7 International Contracting Limited	United Kingdom	General Trading
Subsea 7 International Holdings (UK) Limited(a)	United Kingdom	Holding
Subsea 7 Investments (UK) Limited	United Kingdom	Special Purpose
Subsea 7 i-Tech Australia Pty Limited	Australia	General Trading
Subsea 7 i-Tech Limited	United Kingdom	General Trading
Subsea 7 i-Tech Mexico S de RL de CV	Mexico	General Trading
Subsea 7 i-Tech US Inc.	USA	General Trading
Subsea 7 Limited	United Kingdom	General Trading
Subsea 7 Luanda Limited	Cayman Islands	General Trading
Subsea 7 Marine LLC	USA	General Trading
Subsea 7 Moçambique Lda	Mozambique	General Trading
Subsea 7 M.S. Limited	United Kingdom	Corporate Service
Subsea 7 Navica AS	Norway	Vessel Owning
Subsea 7 Nigeria Limited	Nigeria	General Trading
Subsea 7 Nile Delta Limited	Egypt	General Trading
Subsea 7 Normand Oceanic Holding AS	Norway	Holding
Subsea 7 Norway AS	Norway	General Trading
Subsea 7 Mexico S de RL de CV	Mexico	General Trading
Subsea 7 Offshore Resources (UK) Limited	United Kingdom	Vessel Owning
Subsea 7 Pipeline Production Limited	United Kingdom	General Trading
Subsea 7 Port Isabel LLC	USA	General Trading
Subsea 7 Portugal, Limitada	Portugal	General Trading
Subsea 7 Senior Holdings (UK) Limited	United Kingdom	Holding
Subsea 7 Shipping Limited	Isle of Man	Vessel Owning
Subsea 7 Singapore Contracting Pte Limited	Singapore	General Trading
Subsea 7 Treasury (UK) Limited	United Kingdom	Special Purpose
Subsea 7 Vessel Owner AS	Norway	Vessel Owning
Subsea 7 West Africa Contracting Limited	United Kingdom	General Trading
Subsea 7 West Africa SAS	France	General Trading
Swagelining Limited	United Kingdom	General Trading
Tartaruga Insurance Limited	Isle of Man	Special Purpose
Thames International Enterprise Limited	United Kingdom	Special Purpose
ZNM Nigeria Limited	Nigeria	General Trading

(a) Wholly-owned subsidiaries directly owned by the parent company, Subsea 7 S.A.

For all entities, the principal place of business is consistent with the country of registration.

All subsidiary undertakings are included in the Consolidated Financial Statements of the Group. The proportion of the voting rights in the subsidiary undertakings held directly by the immediate parent company do not differ from the proportion of ordinary shares held. The parent company does not have any shareholdings in the preference shares of subsidiary undertakings included in the Group.

Details of the addresses of the registered office of each of the wholly-owned subsidiaries are available on request from Subsea 7 S.A., registered office, 412F, route d'Esch, L-2086 Luxembourg.

Adjusted EBITDA and Adjusted EBITDA margin

Adjusted earnings before interest, taxation, depreciation and amortisation ('Adjusted EBITDA') is a non-IFRS measure that represents net income before additional specific items that are considered to impact the comparison of the Group's performance either period-on-period or with other businesses. The Group defines Adjusted EBITDA as net income adjusted to exclude depreciation costs, amortisation of prepaid mobilisation expenses and amortisation of intangible assets, impairment charges or impairment reversals, finance income, remeasurement gains and losses on business combinations, other gains and losses (including foreign exchange gains and losses, gains on disposal of subsidiaries, gains on distributions and bargain purchase gains on business combinations), finance costs and taxation. Adjusted EBITDA margin is defined as Adjusted EBITDA divided by revenue, expressed as a percentage.

The items excluded from Adjusted EBITDA represent items which are individually or collectively material but which are not considered representative of the performance of the business during the periods presented. Other gains and losses principally relate to disposals of investments, property, plant and equipment and net foreign exchange gains or losses. Impairments of assets represent the excess of the assets' carrying amount over the amount that is expected to be recovered from their use in the future or their sale.

Adjusted EBITDA and Adjusted EBITDA margin have not been prepared in accordance with IFRS as adopted by the EU. These measures exclude items that can have a significant effect on the Group's income or loss and therefore should not be considered as an alternative to, or more meaningful than, net income (as determined in accordance with IFRS) as a measure of the Group's operating results or cash flows from operations (as determined in accordance with IFRS) as a measure of the Group's liquidity.

Management believes that Adjusted EBITDA and Adjusted EBITDA margin are important indicators of the operational strength and the performance of the business. These non-IFRS measures provide Management with a meaningful comparative for its Business Units, as they eliminate the effects of financing, depreciation, taxation and other one-off adjustments to the Consolidated Income Statement. Management believes that the presentation of Adjusted EBITDA is also useful as it is similar to measures used by companies within Subsea 7's peer group and therefore believes it to be a helpful calculation for those evaluating companies within Subsea 7's industry. Adjusted EBITDA margin may also be a useful ratio to compare performance to its competitors and is widely used by shareholders and analysts following the Group's performance. Notwithstanding the foregoing, Adjusted EBITDA and Adjusted EBITDA margin as presented by the Group may not be comparable to similarly titled measures reported by other companies.

Reconciliation of net operating income to Adjusted EBITDA and Adjusted EBITDA margin:

2017 For the year ended (in \$ millions) 31 Dec	2016 31 Dec
Net operating income 580.7	521.0
Depreciation, amortisation and mobilisation 422.3	371.8
Impairment of property, plant and equipment 31.5	157.9
Impairment of intangible assets –	0.6
Impairment of goodwill –	90.4
Adjusted EBITDA 1,034.5	1,141.7
Revenue 3,985.6	3,566.7
Adjusted EBITDA % 25.9%	32.0%

Reconciliation of net income to Adjusted EBITDA and Adjusted EBITDA margin:

	2017	2016
	31 Dec	31 Dec
Net income	454.6	418.3
Depreciation, amortisation and mobilisation	422.3	371.8
Impairment of property, plant and equipment	31.5	157.9
Impairment of intangible assets	–	0.6
Impairment of goodwill	–	90.4
Remeasurement gain on business combination	(25.0)	–
Finance income	(24.6)	(17.9)
Other gains and losses	54.8	(44.9)
Finance costs	21.0	7.1
Taxation	99.9	158.4
Adjusted EBITDA	1,034.5	1,141.7
Revenue	3,985.6	3,566.7
Adjusted EBITDA %	25.9%	32.0%

Special note regarding forward-looking statements

Certain statements made in this Report may include 'forward-looking statements'. These statements relate to our expectations, beliefs, intentions or strategies regarding the future. These statements may be identified by the use of words such as 'anticipate', 'believe', 'estimate', 'expect', 'intend', 'may', 'plan', 'project', 'should', 'will', 'seek', and similar expressions.

The forward-looking statements that we make reflect our current views and assumptions with respect to future events and are subject to risks and uncertainties. Actual and future results and trends could differ materially from those set forth in such statements due to various factors, including those discussed in this Report under 'Risk Management', 'Financial Review' and the quantitative and qualitative information disclosures about Market Risk contained in Note 33 'Financial instruments' to the Consolidated Financial Statements. The following factors are among those that may cause actual and future results and trends to differ materially from our forward-looking statements: (i) our ability to deliver fixed price projects in accordance with client expectations and the parameters of our bids and avoid cost overruns; (ii) our ability to collect receivables, negotiate variation orders and collect the related revenue; (iii) our ability to recover costs on significant projects; (iv) capital expenditures by oil and gas companies; (v) the current global economic situation and level of oil and gas prices; (vi) delays or cancellation of projects included in our backlog; (vii) competition in the markets and businesses in which we operate; (viii) prevailing prices for our products and services; (ix) the loss of, or deterioration in our relationship with, any significant clients; (x) the outcome of legal proceedings or governmental inquiries; (xi) uncertainties inherent in operating internationally, including economic, political and social instability, boycotts or embargoes, labour unrest, changes in foreign governmental regulations, corruption and currency fluctuations; (xii) liability to third parties for the failure of our joint venture partners to fulfil their obligations; (xiii) changes in, or our failure to comply with, applicable laws and regulations; (xiv) cost and availability of supplies and raw materials; (xv) operating hazards, including spills, environmental damage, personal or property damage and business interruptions caused by adverse weather; (xvi) equipment or mechanical failures, which could increase costs, impair revenue and result in penalties for failure to meet project completion requirements; (xvii) the timely delivery of vessels on order and the timely completion of ship conversion programmes; (xviii) the impact of changes to estimated future costs and revenues used in project accounting on a 'percentage-of-completion' basis, which could reduce or eliminate reported income; (xix) our ability to keep pace with technological changes; (xx) the effectiveness of our disclosure controls and procedures and internal control over financial reporting; and (xxi) actions by regulatory authorities or other third parties.

Many of these factors are beyond our ability to control or predict. Given these uncertainties, you should not place undue reliance on the forward-looking statements. We undertake no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Investor relations and press enquiries

Shareholders, securities analysts, portfolio managers, representatives of financial institutions and the press may contact:

Investor Relations Director Isabel Green Email: isabel.green@subsea7.com Telephone: +44 20 8210 5568

Financial information

Copies of Stock Exchange announcements (including the Group's quarterly and semi-annual results announcements and the Group's Annual Report and Consolidated Financial Statements) are available on the Group's website www.subsea7.com.

121

Any shareholder requiring a printed copy of the Group's Annual Report and Consolidated Financial Statements or the Company's Financial Statements can request these via the website www.subsea7.com.

Stock listings

Common shares – Traded on Oslo Børs under the symbol SUBC – www.olsobors.no.

ISIN: LU0075646355

Registrar – Common Shares

Registrar for the shares of Subsea 7 S.A., recorded in the Norwegian Central Securities Depository (Verdipapirsentralen – the 'VPS').

DNB Bank ASA Postboks 1600 Sentrum NO-0021 Oslo Norway Telephone: +47 23 26 80 16 Fax: +47 22 94 90 20 Email: sten.sundby@dnb.no

Depository Bank – ADRs

Subsea 7 S.A. has a sponsored Level 1 ADR facility, for which Deutsche Bank Trust Company Americas acts as depository. Each ADR represents one common share of the Company. The ADRs are quoted over-the-counter ('OTC') in the US under the ticker symbol SUBCY.

For enquiries, beneficial ADR holders may contact the broker service of Deutsche Bank Trust Company Americas.

Amercian Stock Transfer & Trust Company LLC 6201 15th Avenue Brooklyn, NY 11219 USA Toll free: +1 866 249 2593 (toll free for US residents only) Direct Dial: +1 718 291 8137 e-mail: db@astfinancial.com Further information is also available at: www.adr.db.com.

Financial calendar

Subsea 7 S.A. intends to publish its quarterly financial results for 2018 on the following dates:

Q1 2018 Results	26 April 2018
Q2 and H1 2018 Results	26 July 2018
Q3 2018 Results	8 November 2018
Q4 and FY 2018 Results	28 February 2019

2018 Annual General Meeting

17 April 2018 at 15.00 CET 412F, route d'Esch L-2086 Luxembourg

Registered office

412F, route d'Esch L-2086 Luxembourg

Website www.subsea7.com

Glossary

Acergy S.A.	The former name of Subsea 7 S.A. prior to the Combination which completed following the close of business on the Oslo Børs on 7 January 2011.
Active Patent Family	Family of patent applications and patents of which at least one is still active or alive. A Patent Family groups the patent applications and patent that derive from the same initial invention and claim the same priority date.
Active Vessel Utilisation	Ratio of paid days to days available for utilisation (normally assumed to be 350 days per year) excluding days when vessels are stacked, expressed as a percentage.
Adjusted EBITDA	Adjusted earnings before interest, taxation, depreciation and amortisation ('Adjusted EBITDA') is a non-IFRS measure that represents net income before additional specific items that are considered to impact the comparison of the Group's performance either period-on-period or with other businesses. The Group defines Adjusted EBITDA as net income adjusted to exclude depreciation, costs, amortisation of prepaid mobilisation expenses and amortisation of intangible assets, impairment charges or impairment reversals, finance income, remeasurement gains and losses on business combinations, other gains and losses (including foreign exchange gains and losses, gains on disposal of subsidiaries, gains on distributions and bargain purchase gains on business combinations), finance costs and taxation. Adjusted EBITDA margin is defined as Adjusted EBITDA divided by revenue, expressed as a percentage. The items excluded from Adjusted EBITDA represent items which are individually or collectively material but which are not considered representative of the performance of the business during the periods presented. Other gains and losses principally relate to disposals of investments, property, plant and equipment and net foreign exchange gains or losses. Impairments of assets represent the excess of the assets' carrying amount over the amount that is expected to be recovered from their use in the future or their sale.
AGM	Annual General Meeting
Airborne Oil and Gas	Airborne Oil and Gas are a leading manufacturer of thermoplastic composite pipes which are corrosion free and offer substantially lower total-cost of ownership.
Alliance	An association formed for mutual benefit.
Articles of Incorporation	The articles of incorporation of Subsea 7 S.A.
Backlog	Expected future revenue from in-hand projects only where an award has been formally signed. Backlog awarded to associates and joint ventures is excluded from backlog figures, unless otherwise stated.
BSR	Buoy-Supported Riser
Buoy-Supported Riser (BSR)	The BSR concept consists of a large sub-surface buoy which is anchored to the seabed by tethers. The buoy supports multiple Steel Catenary Risers which are connected to the floating production storage, and offloading unit (FPSO) by flexible jumpers.
Pipeline Bundle	A Pipeline Bundle incorporates all the structures, valve work, pipelines and control systems necessary to operate a field in one single pre-assembled product. The finished Pipeline Bundle is transported to its offshore location by a Controlled Depth Tow Method, delivering considerable value and cost savings.

Bundle-lay	The Controlled Depth Tow Bundle-lay method was pioneered and developed by Subsea 7 and involves the transportation of pre-fabricated and fully-tested pipelines, control lines and umbilicals in a Bundle configuration suspended between two tow vessels. On arrival at the field, the Bundle is lowered to the seabed, manoeuvred into location and the carrier pipe is flooded to stabilise the Bundle in its final position.
Business Management System	Our integrated Business Management System integrates all of Subsea7's systems and
(BMS)	processes into one complete framework
Cash-generating unit (CGU)	These are the separable business units on which impairment reviews are carried out.
Chapter 11	Chapter 11 is a chapter of Title 11 of the United States Bankruptcy Code, which permits
	reorganisation under the bankruptcy laws of the United States.
Chiyoda	Chiyoda Corporation
Clean operation	A clean operation is any measure beyond a normal operating practice that will save energy.
Cold Flow Technology	Technology that allows hydrocarbons to be transported under ambient sea water temperature conditions enabling ultra-long tie-backs.
Combination	The repurchase and cancellation of all of the issued and outstanding ordinary shares in the capital of Subsea 7 Inc., the issue by Subsea 7 Inc. of new ordinary shares to Acergy S.A. (now Subsea 7 S.A.) and the issue of new common shares to the Subsea 7 Inc. shareholders, which took place on 7 January 2011. Under IFRS, the Combination is accounted for as an acquisition.
Company	Subsea 7 S.A.
Consortium	Subsea 7 in an association with one or more companies with the objective of participating
	in achieving a common goal.
Conventional	Conventional services include the fabrication, installation, extension, hook-up and
	refurbishment of fixed and floating platforms in shallow water.
Day-rate contract	A contract in which the contractor is remunerated by the client at an agreed daily rate (often with agreed escalations for multi-year contracts) for each day of use of the contractor's vessels, equipment, personnel and other resources and services utilised on the contract. Such contracts may also include certain lump-sum payments e.g. for activities such as mobilisation and demobilisation of vessels and equipment.
Decommissioning	The taking out of service of production facilities at the end of their economic lives and
	their removal or partial removal from offshore for recycling and/or disposal onshore.
Diving Support Vessel (DSV)	An offshore construction vessel that has dedicated saturation diving chamber(s) and
	dive bells for subsea construction activities in water depths of up to 300 metres.
DNB	Den Norske Bank.
Dry-dock	A facility for the construction, maintenance, and repair of vessels.
EBITDA	See Adjusted EBITDA.
ECS	EMAS Chiyoda Subsea Limited
Eidesvik Seven	Eidesvik Seven AS and Eidesvik Seven Chartering AS.
ENMAR	ENMAR S.A.
EPCIC	Engineering, Procurement, Construction, Installation and Commissioning. Sometimes shortened to EPIC, EPC or EPCI
EGM	Extraordinary General meeting
EHTF	Electrically Heat Traced Flowline (EHTF) is Subsea 7's heated pipe-in-pipe technology
	solution to enhance flow assurance properties.
Executive Management Team	The Executive Management Team of Subsea 7 S.A. comprises: the Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, Executive Vice President – Human Resources, General Counsel, Executive Vice President – Commercial
Fabrication yard	Strategically positioned shore based facility to support delivery of offshore projects including fabrication of different types of steel structures e.g. jackets, modules, decks and platforms, spools, jumpers.
FEED	Front-End Engineering and Design

Flex-lay	A pipelay method for installing flexible pipelines, risers and in-line structures by spooling them from a reel, carousel or basket, bending them over a chute and guiding them onto the seabed.
Flowline	A pipeline carrying oil, gas or water that connects the subsea wellhead to a manifold or to surface production facilities.
Global Projects	Part of a new Subsea 7 organisational structure which came into effect on 1 January 2015 and regroups the major project teams based in Paris and London which manage large, complex, technology-rich global projects.
Group	Subsea 7 S.A. and its subsidiaries.
Heavy lift vessel	An offshore vessel or barge designed to lift objects greater than 1,000 tonnes for subsea construction and topside operations.
Hook-up	The process of making connections from a well to an oil and gas separator and from the separator to either the storage tanks or a flowline.
HR	Human Resources
HRT	Hybrid Riser Tower
HSSEQ	Health, Safety, Security, Environment and Quality
Integrity Management	A risk-based service supporting operators of subsea assets in the maintenance of their facilities.
IRM	Inspection, Repair and Maintenance of subsea infrastructure.
i-Tech Services	A business unit of Subsea 7 that includes activities associated with the provision of Inspection, Repair and Maintenance services, integrity management of subsea infrastructure and remote intervention support.
J-lay	A pipelay method consisting of welding lengths of steel pipe on board a pipelay vessel (into double, quadruple or hex joints) and lowering the double/quad/hex length of pipeline vertically either through the vessel's moonpool or over the side of the vessel to the seabed, then repeating the process.
Life of Field	The term used to describe the range of subsea engineering, project management and execution services related to the delivery of integrity management, intervention and construction services that are required, to ensure that the life of a producing field is maintained, enhanced or extended (also sometimes referred to as IRM).
Long-term agreement (LTA)	The LTA contracts, awarded by Saudi Aramco, have a fixed duration of six years with options to be extended for up to twelve years in total.
Lost-time incident (LTI)	An incident which results in personnel being unable to work as the result of an injury.
Lost-time injury rate	The number of work related injuries or illnesses that result in the affected person being absent from work for at least one normal shift after the shift on which the injury occurred, because they are unfit to perform any duties, per 200,000 hours worked.
Lump-sum contract	A contract in which the contractor is remunerated by the client at a fixed price which is deemed to include the contractor's costs, profit and contingency allowances for risks. Any over-run of costs experienced by the contractor arising from, for example, an over-run in schedule due to poor execution or increases in costs of goods and services procured from third parties, unless specifically agreed with the client in the contract, is for the contractor's account.
L&T Hydrocarbon Engineering	L&T Hydrocarbon Engineering, a wholly owned subsidiary of Larsen & Toubro Limited (L&T), serves the Oil and Gas sector around the world. Organised under Offshore, Onshore, Construction Services, Modular Fabrication and Engineering Services verticals, the company delivers 'design to build' engineering and construction solutions across the hydrocarbon spectrum.
NigerStar7	NigerStar7 Limited and NigerStar7 Free Zone Enterprise.
Normand Oceanic	Normand Oceanic AS and Normand Oceanic Chartering AS.

OneSubsea ®	OneSubsea is a Schlumberger company which offers a step-change in reservoir recovery
	for the subsea oil and gas industry through integration and optimisation of the entire
	production system over the life of a field.
OPEC	Organisation of the Petroleum Exporting Countries
OPEX	Operating cost or expense
Operational support yard	Strategically positioned shore based facility to provide offshore operational support.
Performance share	Performance shares are awarded under the 2009 and 2013 Long-term Incentive Plans
	and cover approximately 150 senior employees. These shares vest after at least three
	years, subject to performance conditions.
Petrobras	Petróleo Brasileiro S.A., more commonly known as Petrobras, is a semi-public Brazilian
	multinational corporation in the petroleum industry.
Pipe-in-Pipe	A Pipe-in-Pipe product consists of a production pipeline being sleeved into an outer pipe
	with the annulus being kept dry and filed with a high-performance insulation material
	delivering enhanced thermal properties.
Pipeline system	The pipeline and associated infrastructure for transporting oil and gas from the well head
	to the production facility.
PLSV	Pipelay Support Vessel.
Reel-lay	A pipelay method consisting of the onshore construction of a pipeline which is
	spooled onto a large vessel-mounted reel, transported to the field and unreeled
	down to the seabed.
Remote intervention	Provision of tooling, sampling, repair and containment solutions and services,
	including engineering, project management, autonomous intervention vehicles,
	ROVs and related tooling.
Renewables	Renewables or Offshore Renewables activity including the design and installation of
	offshore wind, tidal, wave and other related marine systems.
Riser/riser systems	A pipe through which liquid travels upward from the seabed to a surface production
	facility. Riser systems fall into two categories, those coupled directly to the host facility
	(SCRs), and un-coupled systems which in most cases are connected by flexible jumpers
	(HRTs/BSRs).
ROAIC	Return on Average Invested Capital. A key performance indicator for the Group which
	is used as a non-market performance measure in the 2013 Long-term Incentive Plan.
ROV(s)	Remotely Operated Vehicle(s).
SapuraAcergy	SapuraAcergy Assets Pte Limited and SapuraAcergy Sdn. Bhd.
Saudi Aramco	Saudi Arabian Oil Company (Saudi Aramco) is a Saudi Arabian national petroleum and
	natural gas company.
SCR	Steel catenary riser
Seaway Heavy Lifting	Seaway Heavy Lifting Holding Limited and its subsidiaries.
Seismic Surveys	Seismic Surveys are used to produce images of the various rock types and their location
	beneath the Earth's surface, allowing for accurate plans of the location and size of oil and
	gas wells.
Setemares	Setemares Angola, Limitada.
SIMAR	SIMAR – Sociedade Angolana de Inspecção, Manutenção e Reparação Maritima, Lda.
S-lay	A pipelay method consisting of continuously welding lengths of steel pipe on board a
	pipelay vessel and feeding them in a horizontal manner typically over the stern of the
	vessel on a ramp (stinger) from where the pipe, under its own weight, forms an 'S'-shaped
	catenary as it is lowered to the seabed.
Sonacergy	Sonacergy – Serviços e Construções Petroliferas Lda (Zona Franca da Madeira).
Sonamet	Sonamet Industrial S.A.

Spoolbase	A shore-based facility used to facilitate continuous pipelaying for offshore oil and gas production. A spoolbase facility allows the welding of joints of pipe, predominantly steel pipe of 4" to 18" diameter, into predetermined lengths for spooling onto a reel-lay pipelay vessel.
Stacked	Term used to describe a vessel that is not operational and is unavailable for immediate deployment. Stacked vessels usually have a significantly reduced crew and an associated decrease in operating cost.
Subsea Integration Alliance	The alliance formed between Subsea 7 and OnSubsea (a Schlumberger company) to provide clients with integrated SPS and SURF solutions for offshore oil and gas developments.
Subsea Production System (SPS)	The equipment placed on the seabed that is connected to subsea pipeline networks and riser systems to produce the reservoir to a host facility
Subsea 7	Subsea 7 S.A. and its subsidiaries.
Subsea 7 Inc.	Subsea 7 Inc., a company incorporated under the laws of the Cayman Islands registered number MC-115107 with registered offices at Ugland House, South Church Street, George Town, Grand Cayman, KY1-1104, Cayman Islands.
Subsea 7 S.A.	Subsea 7 S.A. (formerly Acergy S.A.), a company incorporated under the laws of Luxembourg registered with the Registre de Commerce et des Sociétés in Luxembourg under number B 43 172 with a registered office at 412F, route d'Esch, L-2086, Luxembourg.
Subsea 7 Malaysia	Subsea 7 Malaysia Sdn. Bhd.
Subsea 7 Mexico	Subsea 7 Mexico S de RL de CV, Servicios Subsea 7 S de RL de CV and Naviera Subsea 7 S de RL de CV.
Subsea Field Development	The range of subsea engineering, design, project management, fabrication and installation services related to the development of new subsea oil and gas fields. The principal services relate to rigid and flexible pipelines, risers, umbilicals and associated construction activities.

SURF	Subsea Umbilicals, Risers and Flowlines, which includes infrastructure related to subsea trees or floating production platforms, regardless of water depth, such as pipelines, risers, umbilicals, moorings, and other subsea structures such as Pipeline End Manifolds and Pipeline End Terminations.
Tie-back	A connection between a new oil and gas discovery and an existing production facility, improving the economics of marginal fields into profitable assets.
Tonnage tax	An optional tax regime for shipping companies offered by tax authorities including the UK and Norway.
Total recordable incident rate	The number of lost-time injuries, cases of substitute work and other injuries requiring treatment by a medical professional per 200,000 hours worked.
Total Shareholder Return	Total shareholder return is a measure of the performance of shares. It combines share price appreciation and dividends paid to show the total return to the shareholder expressed as an annualized percentage.
Total Vessel Utilisation	Ratio of paid days to days available for utilisation (normally assumed to be 350 days per year) expressed as a percentage.
T&I	Transport and Installation. Sometimes shortened to T&I.
Umbilical	An assembly of hydraulic hoses, which can also include electrical cables or optic fibres, used to control subsea structures from an offshore platform or a floating vessel.
Values	Subsea 7 has five Values which are embedded at all levels in the organisation and which guide our behaviours: Safety, Integrity, Innovation, Performance, and Collaboration.
Variation Order	An instruction by the client for a change in the scope of the work to be performed under the contract which may lead to an increase or a decrease in contract revenue based on changes in the specifications or design of an asset and changes in the duration of the contract.
VPS	Verdipapirsentralen, the Norwegian central securities depository.

This report is printed utilising vegetable based inks on Heaven 42 & Printspeed, both of which are sourced from well managed forests independently certified according to the rules of the Forest Stewardship Council (FSC®). This report was printed by an FSC and carbon neutral printing company. Both materials are manufactured at a mill that is certified to the ISO14001 and EMAS environmental standards.

Designed and produced by Black Sun Plc.

Printed by Pureprint.

www.subsea7.com