Subsea 7 — Annual Report 2015

Mar 10, 2016

ANNUAL REPORT 2015 SUBSEA 7 S.A.

WHO WE ARE

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.

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.

GROUP FINANCIAL HIGHLIGHTS Overview

Revenue	By market segment1
	SURF	\$3,701m
\$4,758m (2014: \$6,870m)	Conventional and Hook-up	\$406m
	Life of Field and i-Tech	\$651m

Backlog \$6,110m (2014: \$8,239m)

By year of execution
2016	\$3,203m
2017	\$1,598m
2018+	\$1,309m

Adjusted EBITDA2

Net loss

(Including a goodwill impairment charge of \$521m)

(2014: Net loss \$(381)m, including a goodwill impairment charge of \$1.2bn)

Cash and cash equivalents

\$947m

(2014: Cash and cash equivalents \$573m)

Diluted earnings per share

\$(0.05) (2014: \$(1.02) diluted earnings per share) Adjusted diluted earnings per share3 \$1.45 (2014: \$2.32)

1. For explanations of market segments, refer to pages 6 and 7. 2. For explanations and reconciliations of Adjusted EBITDA, refer to page 95.

2. Adjusted diluted earnings per share, excludes a goodwill impairment charge of \$521m (2014: \$1.2bn).

3. 2 Chairman's Statement

4. 3 Chief Executive Officer's Review
5. 4 What We Do
6. 6 Our Market Segments
7. 8 Where We Operate

Strategy

• 10 Our Business Model and Strategy
• 12 Our Differentiators
• 14 Corporate Responsibility

Governance

• 16 Board of Directors
• 17 Executive Management Team
• 18 Corporate Governance
• 25 Risk Management

Financials

• 30 Financial Review
• 36 Consolidated Financial Statements Contents
• 37 Report of the Réviseur d'Entreprises Agréé
• 38 Consolidated Financial Statements
• 44 Notes to the Consolidated Financial Statements 95 Additional Information
• 98 Glossary

CHAIRMAN'S STATEMENT

"We are committed to strengthening our business through the downturn, and remain confident in the longterm fundamentals for our industry."

Kristian Siem Chairman

To the shareholders of Subsea 7 S.A.

Subsea 7 reported good results in 2015, achieved in a challenging business environment. Group revenue fell by 31%, compared to 2014, to \$4.8 billion reflecting significant declines in market activity driven by our clients' reduced expenditure and the lower price of oil. Adjusted EBITDA of \$1.2 billion resulted in an Adjusted EBITDA margin of 26%, five percentage points higher than the prior year, driven by excellent project execution by our organisation, cost control initiatives and the timing of completion of several large projects.

Net income, excluding the impact of the goodwill impairment charge of \$521 million, amounted to \$484 million or \$1.45 per share. This impairment charge was a non-cash item that was recorded in the fourth quarter; it largely reflected the impact of market activity projected for the next few years and gave rise to a net loss for the year of \$37 million.

We ended 2015 with an order backlog of \$6.1 billion, having won \$3.4 billion of new orders and escalations during the year.

Decisive action taken to adapt to the downturn

Throughout 2015 our clients reduced investment and held back on discretionary expenditure due to the low oil and gas prices. Subsea 7 identified this trend early and acted decisively by simplifying our organisation structure and implementing substantial cost reduction plans. This was accomplished while retaining the capability and expertise required to remain competitive and execute projects consistently well.

Long-term fundamentals remain intact

While we position the Group for much reduced activity for some time ahead, we remain confident in the future for our industry. Global demand for oil and gas is growing and our clients will need to invest to maintain production as supply from existing fields depletes. According to the International Energy Agency (IEA) World Energy Outlook 2015 report, annual investment in worldwide oil and gas needs to meet the average five year spend just to keep future output at today's levels, making a prolonged period of lower prices progressively less likely. Furthermore, in response to the challenges caused by the dramatic fall in the price of oil, our industry is developing new solutions to lower the cost base such that more projects become viable at a lower oil price.

Positioning Subsea 7 to outperform

Subsea 7 is in a good position to face the present market challenges and is strengthening the business to optimise performance when the market activity recovers. The strength of our project management and engineering expertise remains intact and our balance sheet is robust. Our fleet renewal programme comprising six sophisticated and versatile vessels, of which two have already been delivered, is on track to be completed, within our cost targets, in 2016.

Subsea 7 has led initiatives with its clients and suppliers to adapt to the current business environment, developing new ways of working to lower field development costs. During 2015 we have formed two new alliances with leading industry partners, which are supporting earlier engagement with our clients to deliver innovative solutions, better planning and sustainable savings.

Living our values

Subsea 7 is committed to the core values that define the way we work and the culture of our Company: Safety, Integrity, Innovation, Performance and Collaboration. They are at the heart of everything we do, both offshore and onshore, and I am proud of Subsea 7's track record of living by them. Through these values we aim to set the benchmark for responsible and reliable behaviour in our industry. They are what make us an attractive employer for our people, and a preferred supplier to our clients, and they support our strong, long-lasting relationships with our business partners.

Returns to shareholders

We have remained disciplined in our approach to investments and shareholder returns. During 2015 the Group re-purchased 816,000 shares at a cost of \$8 million and extended the \$200 million share repurchase programme to July 2017. We also re-purchased \$70 million of the \$700 million convertible bonds outstanding, taking the total face value of bonds held by the Group to \$152 million, thereby reducing the bonds redeemable at maturity in October 2017 to \$548 million. In order to preserve the Group's financial flexibility during the sustained industry downturn, the Board of Directors will recommend to the shareholders at the Annual General Meeting that no dividend be paid in respect of 2015.

My thanks

On behalf of the Board, I would like to thank our shareholders for their confidence and continued support. I would also like to thank our clients and business partners for their confidence and collaboration as we work together to develop sustainable efficiencies for mutual benefit. Finally, I would like to thank our people for living our values and delivering a strong performance in a year of difficult market conditions.

Kristian Siem Chairman

CHIEF EXECUTIVE OFFICER'S REVIEW

"We have delivered good performance in difficult industry conditions and made significant progress on our strategic priorities."

Jean Cahuzac Chief Executive Officer

Reflecting on our 2015 performance

Subsea 7 delivered good operational and financial performance in 2015 in a very challenging market, with low levels of industry activity as our clients continued to delay new project awards and limit discretionary work.

We identified this downward market trend early, which enabled us to assertively implement a substantial cost reduction and resizing programme to adjust our capacity to reflect prevailing industry conditions. We have achieved a significant reduction in our global workforce and active fleet and the full benefit of our \$550 million forecast annualised cost saving will be achieved in 2016.

We ended the year with a robust financial position with cash and cash equivalents of \$947 million and net cash of \$423 million. This reflected significant cash generation from good overall project execution and cost discipline combined with working capital optimisation and tight control of capital investments. Capital expenditure was \$639 million, including \$499 million related to our vessel renewal programme, scheduled to be completed in 2016.

Our track record of delivering projects for our clients, reliably and safely, allowed us to maintain market share without compromising on the level of risk. We were awarded \$3.4 billion in new orders and escalations during the year. However, reflecting the current business environment, our backlog decreased to \$6.1 billion by the end of 2015.

Our achievements in 2015 demonstrate the dedication and commitment that our people have shown in a demanding year and I thank them all.

Building a more efficient and cost-effective organisation

The downsizing of the organisation announced in May 2015 was completed while preserving key engineering and project management capability and we have continued our focused investment in developing market-leading technology.

At the start of 2015 we reorganised our business and streamlined our operating model creating a two Business Unit organisation, comprising Southern Hemisphere and Global Projects, and Northern Hemisphere and Life of Field. This new organisational structure helped to drive improved project management and service delivery and enhanced our competitiveness through a more channelled allocation of our resources and capabilities.

In parallel, we streamlined our processes with a focus on proposing "fit for purpose" solutions to our clients and lowered the costs of their projects while enhancing Subsea 7's competitiveness. This was effective on new field development projects and infrastructure development projects on existing fields, as our change in approach helped our clients to progress their projects with reduced bureaucracy and tailored technical solutions.

Forming new alliances and partnerships

We are collaborating more closely than ever with our clients and suppliers to identify better ways of working. By engaging early we can engineer, project manage and execute solutions that will safely deliver complex and technology-rich projects at a lower cost. In support of this we have formed two new industry alliances in 2015, one with KBR and its wholly-owned subsidiary Granherne, and the other with OneSubsea. These strategic alliances create a formal structure which helps Subsea 7 to work more closely with industry leading partners to drive better and lower cost solutions for our clients. We believe this will not only strengthen our competitive position but also deliver sustained improvements in the economics of deepwater oil and gas which should contribute to a recovery of industry activity over time.

Furthermore, we have entered into long-term partnership agreements with several clients to work worldwide on a preferred supplier basis to facilitate closer cooperation and alignment of objectives.

Market outlook

The low oil and gas prices continue to depress industry activity as our clients delay and cancel new projects; the timing of market recovery remains very uncertain. We will continue to actively manage our business to adapt to industry conditions without losing our focus on long-term strategic priorities.

Jean Cahuzac Chief Executive Officer

We are a seabed-to-surface engineering, construction and services contractor to the offshore energy industry.

We deliver high-quality services built on our core strengths of engineering, project management, supply chain and vessel management, and supported by our commitment to invest in people, technology and assets worldwide.

Providing market leading solutions…

Designing, planning and project management

We undertake projects on a fixed-price basis for a full service solution encompassing engineering, planning and design, fabrication, construction, installation and commissioning. We also provide Life of Field and decommissioning services. Through our project management expertise we aim to add value to every phase of the project lifecycle.

Our project management processes are standardised on a global basis, drawing on best practice from every region in which we operate. Our core expertise is centralised in two Global Projects Centres to ensure our clients receive reliable and consistent project delivery. Our project managers are able to rely on experienced logistical support, strategic supply chain management and versatile global assets required to execute each project safely, on schedule, on budget, and to agreed standards, time after time.

Engineering and technical innovation

Subsea 7 possesses a substantial in-house resource capable of expanding the boundaries of subsea technologies to deliver effective and innovative solutions to our clients.

The scale of our engineering resource gives us a distinct technical advantage, not only in our overall global design and engineering capability, but also in our versatility, where we have wide-ranging experience right across the spectrum of subsea operations and technology solutions.

...through proactive collaboration from the outset.

Engaging early

To deliver cost-effective optimal solutions we engage with our clients early in the project lifecycle. This requires a collaborative approach as we work hand-in-hand with our clients to understand their needs and design fit-for-purpose solutions. We are working with our clients to drive new, simpler ways of working, aiming to be their preferred supplier for projects of all sizes.

Forming alliances

Our alliance with leading engineering company KBR and its subsidiary Granherne was launched in 2015 to collaborate in the delivery of Concept and Front End Engineering and Design (FEED) services to our clients. This alliance provides the opportunity for early engagement in the project lifecycle when value creation can be optimised at the critical concept evaluation stage.

To offer clients solutions that will substantially reduce the cost of development, Subsea 7 has teamed up with leading Subsea Production Systems (SPS) provider OneSubsea, forming an alliance that brings together Subsea 7's experience and technology in seabed-to-surface engineering, construction and Life of Field services with OneSubsea's sub-surface knowledge and subsea production and processing systems technologies. This enables the alliance to provide clients with integrated subsea development solutions across the full spectrum of services.

We work collaboratively with our clients to develop more efficient project design and execution. With certain clients we have taken this one step further, engaging in long-term agreements to work on a preferred partner arrangement, facilitating a more transparent and cost-effective relationship.

Overview

Delivering projects in harsh and challenging environments…

Best-in-class execution

Subsea 7's offshore operations are managed, crewed and operated by some of the most experienced onshore and offshore marine and construction personnel in the industry. We have the flexibility to respond quickly and sensitively to client demands, leveraging the full strength of our global resources and know-how.

Our projects are undertaken in remote and harsh environments, which present their own set of challenges and risks. We have the experience and expertise to consistently deliver successful outcomes in safe and sustainable ways. Our clients can depend on us to deliver large and complex projects, as evidenced by our strong track record of best-in-class execution.

...with a highly capable and versatile fleet.

We have a fleet of highly capable and versatile vessels providing a wide range of pipeline installation techniques – Pipeline Bundles, Reel-lay, S-lay, J-lay and Flex-lay. These enable us to operate in all major offshore oil and gas producing regions worldwide, working in depths of up to 3,000 metres and in some of the world's harshest environments.

Our offshore operations are supported by our global infrastructure of spoolbases, fabrication yards and offices situated in key strategic locations around the world. These facilities, combined with our versatile fleet of highly capable vessels, enable us to respond efficiently to client requirements with fit-for-purpose solutions, and accommodate changes to work scopes, when required, to minimise downtime and keep projects on track. This flexibility is highly valued in our market.

Safety is one of our core values, and our commitment to effective safety management and leadership underpins everything we do.

Similar principles of versatility and global capability underpin the operation of the Group's fleet of over 175 Remotely Operated Vehicles (ROVs). Our fleet is one of the largest and most advanced in the world, capable of working in ultra-deep waters of up to 4,000 metres and across a wide range of challenging subsea environments.

OUR MARKET SEGMENTS

Buoy-supported riser

Reel-lay installation

ROV – Inspection, survey and construction

Flexible pipeline and riser

installation

Flexible pipeline installation

Hybrid riser tower

SURF

We are a global market leader in the Subsea Umbilicals, Risers and Flowlines (SURF) sector. In every major offshore region we safely execute projects which connect seabed wellhead infrastructures to surface facilities such as platforms and floating production systems. Most SURF projects are contracted on a fixed-price basis and involve Engineering, Procurement, Installation and Commissioning (EPIC) services.

Life of Field and i-Tech

We provide inspection, maintenance and repair (IMR) services, integrity management of subsea infrastructure and remote intervention support. With over 30 years' experience in Life of Field, we are an acknowledged world leader in this long-term market. i-Tech operates one of the largest and most technologically advanced fleets of ROVs in the subsea energy industry.

Pipeline Bundles: Fabrication and installation

Diving services

Pipeline production: Engineering, welding and fabrication

Engineering and Project Management: Local expertise, integrated through global networks, to support all segments of our business

Platform and topside installation and removal

Offshore wind turbine installation Overview

Bundle-lay installation

Conventional and Hook-up

Our Conventional services involve the fabrication, installation, extension and refurbishment of fixed and floating platforms and associated pipelines in shallow water environments, mainly in West Africa. Our Hook-up services comprise the installation of modules on new platforms and the refurbishment of topsides of existing fixed and floating production facilities.

Renewables and Heavy Lift

Our joint venture Seaway Heavy Lifting (SHL) operates two world-class heavy lift vessels and is active in three specialist segments of the offshore energy market: the installation of offshore wind turbines, structures and substations; the transport and installation of large offshore oil and gas structures and the decommissioning of redundant offshore structures.

WHERE WE OPERATE

We deliver services in all water depths worldwide, including harsh and challenging environments.

Our global footprint, combined with the technical expertise of our people, our technology and world-class assets, both on and offshore, enables us to deliver market leading subsea engineering services worldwide.

Northern Hemisphere and Life of Field Business Unit

Key facts

• Northern Hemisphere comprises: Canada, Gulf of Mexico, Norway, and the UK
• Life of Field business line provides experienced specialist services to improve the full life cycle reliability of subsea infrastructures and includes i-Tech's ROV services
• Spoolbases in the Gulf of Mexico, Norway and the UK; Pipeline Bundle fabrication facility in the UK; operational support yards in Norway and the UK; and offices in Canada, Mexico, Norway, the UK, and the US

2015 Highlights

• Substantially completed Knarr, Enochdu and Heidelberg projects
• Significant progress on the Catcher, Montrose, Mariner, Aasta Hansteen, Martin Linge and Stampede projects
• Delivered cost-effective solutions with our 75th Pipeline Bundle installed and 5 more Pipeline Bundles fabricated
• Developed innovative Life of Field Emergency Pipeline Repair System (EPRS) to reduce shutdown time
• \$1.4 billion order intake in 2015, including Maria, offshore Norway and Culzean, offshore UK

2015 Summary

In the Northern Hemisphere and Life of Field Business Unit strong execution drove good operational progress on all projects. During the year we executed various projects including the installation of the world's longest high voltage AC cable on the Martin Linge project and the world's first wet gas compressor on the Gullfaks project, both offshore Norway. Offshore UK, the largest new offshore field development in over a decade, the Mariner project, made good progress with trenching, pipelay and structure installation and was supported from our offices in both Stavanger, Norway, and Aberdeen, UK. We have continued to develop and refine our Pipeline Bundle technology, evolving its use as a cost-effective solution for North Sea developments. Our Bundle fabrication facility in Wick, UK, was very active in 2015, with seven Pipeline Bundles fabricated and two launched and installed.

In Life of Field we extended two underwater service contracts offshore UK and we were awarded an Emergency Pipeline Repair System contract offshore Australia, using an ROV system to provide permanent repairs with significantly reduced shut-down time.

New awards to market and overall activity levels were lower compared to the prior year as clients were impacted by the low oil price, resulting in lower utilisation of our fleet, particularly some of our diving vessels. Despite the challenging environment, Subsea 7's technical expertise and flexible approach to project management supported new collaborative partnership agreements with several clients and drove successful project tendering outcomes.

Southern Hemisphere and Global Projects Business Unit

Key facts

• Southern Hemisphere comprises: Africa, Asia Pacific, Brazil and Middle East
• Global Projects offices in London and Paris centralise our expertise and experience to optimise our management of large, complex and technology-rich projects worldwide
• Fabrication yards in Angola, Gabon, Ghana and Nigeria; operational support yards in Brazil and Nigeria; offices in Angola, Australia, Brazil, Egypt, Malaysia, Mozambique, Nigeria, Portugal, Republic of the Congo, and Singapore

2015 Highlights

• Substantially completed Erha North, Gorgon Heavy Lift and Tie-Ins, and OFON 2 projects
• Significant progress on the BC-10, Lianzi Surf and Topside, and TEN projects
• High levels of Pipelay Support Vessel (PLSV) activity under the long-term contracts with Petrobras
• \$1.9 billion order intake in 2015, including three contracts offshore Egypt

2015 Summary

The Southern Hemisphere and Global Projects Business Unit benefited from strong project execution. Significant progress was made on various large projects and a number of multi-year EPIC contracts were completed. Offshore Angola, the Lianzi SURF project utilised leading-edge technology for the installation of the world's deepest electrically heated pipeline. Strong project management and local presence were key in achieving a successful outcome in this complex cross-border project involving two African nations.

On the Erha North project, offshore Nigeria, local content was significant and contributed materially to its success. Our local presence in Nigeria resulted in 2.5 million hours of work on this project using Nigerian personnel.

Offshore Ghana the TEN project made significant progress with fabrication and installation. Our PLSVs on long-term contracts offshore Brazil had high levels of activity. A new contract was awarded for our PLSV Seven Seas and new-build PLSV Seven Rio joined the fleet during the year. In December 2015, an incident on PLSV Seven Waves resulted in damage to the lay-tower; the vessel has been stacked until the extensive repairs are completed.

We were awarded several new contracts in the year, with commercial success in Egypt as we strengthened our presence in this important offshore gas region and in Australia as we further developed existing client relationships.

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

We will deliver this vision by providing high-quality engineering, project management and installation services enabled by our people, technology and assets and supported by our commitment to local presence and local partners.

Our key differentiators

People

Project delivery based on our expertise and know-how

Subsea 7 has skilled, experienced engineers, project managers and onshore and offshore construction and support staff to ensure safe and reliable delivery of complex subsea engineering and construction projects.

Technology

Developing market-driven and cost-effective solutions

Subsea 7 is experienced in the development, commercialisation and application of technologies that reduce cost and improve reservoir production and recovery levels.

Challenging market environment; long-term fundamentals remain intact

The fall in oil and gas prices that began in 2014 and continued to challenge the industry throughout 2015 resulted in suppressed industry investment in new and existing fields, drove increased competitive pressure among the service companies and necessitated innovation to drive down costs. Subsea 7 built on its early response, which had commenced in 2014, by implementing new ways of working, including closer and earlier collaboration with clients to identify cost saving opportunities in engineering, technology and project management.

In addition we announced in May 2015 a cost reduction and resizing programme, that committed to reduce our headcount by 2,500 and our active fleet by 12 vessels by early 2016. The formation of two new strategic alliances with market leading partners, KBR and OneSubsea, enhanced and extended our service offering, which gave the Group the opportunity to further generate added value for our clients.

Assets

A diverse global fleet of vessels and strategically positioned onshore facilities

Subsea 7 is committed to operating a flexible fleet of highperformance vessels, capable of executing challenging subsea projects anywhere in the world. We support our global operations with onshore investment in strategically located fabrication yards, spoolbases, project offices and other facilities.

Local Presence and Local Partners

Building local businesses and embedding local capability

In all our major operating locations, we aim to build local businesses founded on local leadership, high-quality in-country personnel and support for regional supply chains.

Market context Strategic objectives

• We employ people in 22 countries, onshore and offshore, including some of the most experienced and capable of specialist engineers and project managers. With over 80 different nationalities working throughout the Group, we think globally and deliver locally.
• Subsea 7's programme to resize the organisation is focused on maintaining the capability and competency that makes us a leading provider of services to the offshore energy industry.
• To maintain a talent pool of specialist engineers and project managers and to ensure we continue to execute challenging projects safely and reliably.

Progress in 2015

During 2015 over 200 people participated in our suite of development programmes. Key retention and development programmes include: our Developing Leadership programme, Global Explorer programme and our Engineering and Commercial Graduate programmes. Subsea 7 ended 2015 with a workforce of approximately 9,800 people, a reduction of approximately 3,600 from December 2014, as we implemented plans to reduce capacity in line with lower levels of market activity.

• Subsea 7 has a strong portfolio of technologies to meet current and future subsea development challenges.
• We own a substantial Intellectual Property portfolio and lead our industry sector with one of the largest and most recent groups of patents in the SURF and Life of Field markets.
• We will continue to invest through the cycle to develop new enabling and cost-reducing technologies, which will help our clients sanction projects despite the lower oil price environment.

To differentiate ourselves by investing in and adopting new technologies which provide efficient and cost-effective subsea solutions for our clients.

Progress in 2015

Our technology investment is focused on five strategic programmes: Riser Systems, Flowline and Pipeline Systems, Pipeline Bundles, Subsea Processing, and Life of Field and Remote Intervention.

In 2015 we achieved technology advances in a number of areas, such as Electrical Heat-Trace flowlines, High Pressure / High Temperature Bundles, automatic welding, and Life of Field technology solutions.

• We have one of the most capable and diverse fleets of vessels in our market segment.
• Our highly versatile fleet is part owned and part chartered. This balance gives us flexibility and reduces the capital intensity of the fleet. Key vessels are owned to ensure full control over availability and specification.
• We have a global network of 3 spoolbases, 5 fabrication yards, 9 operational support yards and 24 local offices.
• Our fleet of over 175 ROVs is one of the largest and most advanced in the world.
• Our ability to think globally and deliver locally is a major differentiator in our market. 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.

To maintain a fleet of vessels and Remotely Operated Vehicles (ROVs), combined with our strategic onshore presence, allowing us to deploy the appropriate scale and mix of resources to meet our clients' requirements.

Progress in 2015

We reduced our capacity to meet market requirements with five owned vessels stacked by the end of 2015, one owned vessel scrapped during the year and four chartered vessels returned to their owners. In the first quarter 2016 a further chartered vessel was returned, and two more owned vessels were stacked, including PLSV Seven Waves while repairs are made to its lay-tower. One vessel joined the fleet in 2015, Seven Rio, a PLSV under long-term contract offshore Brazil.

To develop our local presence and supply chain where we have operations and, where appropriate, enter into strategic local partnerships.

Progress in 2015

A strong local presence is a competitive advantage. As well as satisfying client requirements it creates the opportunity to develop talent and expertise within the country. We formed two new local joint ventures in Ghana in 2015.

OUR DIFFERENTIATORS

People

Project delivery based on our expertise and know-how

Our skilled, experienced engineers, project managers, and onshore and offshore construction and support staff are key to ensuring safe and reliable delivery.

Our people are the foundation of our business, and are key to the ongoing creation and delivery of technical solutions for our clients. The Subsea 7 fleet is managed, crewed and operated by some of the most experienced personnel in the industry. We are able to harness and leverage the many years of technical knowledge, practical experience and process refinement acquired and built up by our engineers, technical experts and project managers to ensure delivery of projects safely, on time and within budget.

To maintain a skilled and motivated workforce, we invest in our high-calibre people and their continuous long-term professional development. During 2015 over 200 people participated in our development programmes and we delivered over 14,000 hours of online training to promote skill development and ensure adherence worldwide to our Values of Safety, Integrity, Innovation, Performance and Collaboration. Our focus

ensures that we have highly skilled and knowledgeable people who are able to deliver our projects and meet our succession needs. Everyone at Subsea 7 is supported to fulfil their potential in the workplace.

The decline in market activity resulting from the low oil price necessitated a reduction in our capacity. We recognised the downturn in activity in 2013 and acted early to reduce the workforce, ending 2014 with approximately 13,400 people, down from a peak of approximately 14,400 in 2013. During 2015 the sustained low levels of activity and uncertain outlook required further action on costs, and in May 2015 we announced plans to further reduce our workforce. We ended 2015 with a workforce of approximately 9,800 people.

We recognise the benefit of having a globally diverse employee base. Our workforce is truly global and comprises over 80 nationalities across 22 countries.

Technology

Developing market-driven and cost-effective solutions

Our technology is becoming ever more important in the costeffective development of new offshore oil and gas fields, and in extending the life of existing infrastructure.

Our technology investment is focused on five strategic technology programmes: Riser Systems, Flowline and Pipeline Systems, Pipeline Bundles, Subsea Processing, and Life of Field and Remote Intervention. Our technical experts work with our clients and key suppliers to steer the direction of research and help develop industry leading technologies. We own a substantial Intellectual Property portfolio with one of the largest and most recent groups of patents in the SURF and Life of Field markets.

New deepwater fields rely on advances in pipeline and flowline technology to overcome challenges of high operating temperatures and pressures, enhanced pipeline life expectancies, flow assurance and the transportation of corrosive fluids. Another important pipeline technology is our highly successful Pipeline Bundles product, which incorporates all the structures, valve work, pipelines and controls necessary to operate a field in one single system that is pre-assembled onshore before being towed to site. The Pipeline Bundle has proved to be a successful cost-reducing solution for many field developments and has significant future potential for seabed processing.

Advanced welding techniques are a critical element in new pipeline technology initiatives, and our integrated development facilities and technical know-how give us a significant advantage in our market. Our Global Pipeline Welding Development Centre in Glasgow, UK, simulates production environments and delivers pre-production welding trials and operator training.

Subsea 7 is a pioneer in the development of riser concepts to meet a wide range of specific field characteristics and client preferences. The continuous development of our riser technology is of strategic value to our clients as it enables them, cost-effectively, to meet the ever increasing challenges of deepwater and harsh environments. In 2015 Subsea 7 was awarded the prestigious 'OTC Brazil 2015 Distinguished Achievement Award for Companies, Organisations and Institutions' in recognition of the contribution to the industry made by the decoupled riser systems of the Guará-Lula NE project using our Buoy-Supported Riser (BSR) technology.

Advances in autonomous vehicles, ROV tooling, and scanning and visual monitoring technologies extend field life, increase production uptime and reduce operating costs. We have been pioneering the development of ROVs, tooling, inspection and repair technology for over 30 years. Our strong portfolio of technology solutions meets current and future challenges. Our innovation is marketdriven, providing relevant solutions for reducing costs in subsea field developments, and increases reliability and performance during the life of the field.

Active patent families

Containing over 350 granted patents and over 370 pending patents

Assets

A diverse fleet of vessels and strategically positioned global assets

Our fleet of vessels and Remotely Operated Vehicles (ROVs), combined with bases and yards in the primary offshore regions, allows us to deploy the scale and mix of resource that meets our clients' requirements.

The capability and versatility of our fleet give us a significant advantage and enable us to deploy vessels efficiently and effectively. Our vessel utilisation is further enhanced by having a high proportion of modern vessels, giving added reliability and minimising dry-dock requirements for upgrades and refurbishment.

Our strategic management of our globally mobile vessels allows us to undertake challenging installation and construction projects on a worldwide basis. Our fleet includes high-performing global pipelay and heavy construction vessels and versatile support vessels for pipelay, light construction and diving and remote intervention activities. We are committed to maintaining our competitive advantage in fleet capability through our design expertise and our ability to sustain investment in these critical assets. The most recent addition to the fleet is PLSV Seven Rio, which entered service in 2015. Vessels under construction comprise two PLSVs for the Brazilian market, a Diving Support Vessel (DSV)

and a Heavy Construction Vessel (HCV), all four of which are due to join our active fleet in 2016.

Our asset base also includes a fleet of over 175 ROVs, ranging from compact observation-class units to purpose-built drill support vehicles and heavy-duty construction-class systems.

To support our global operations, we have invested in an infrastructure of strategically located pipeline spoolbases, fabrication and operational support yards. Onshore assets include: our Lobito fabrication yard joint venture in Angola, our logistics and fabrication facility in Takoradi, Ghana, and dedicated spoolbases to service our Reel-lay pipelay vessels in Vigra in Norway, Port Isabel in the US and Leith in the UK. Also in the UK we have production facilities at Wick for our Pipeline Bundles product.

Vessels

Including 4 under construction and 7 stacked vessels

Local Presence and Local Partners

Building local business and embedding local capability

Subsea 7 has an established local presence in the world's primary offshore oil and gas regions. Creating local businesses that contribute to the community and environment is a key differentiator and ensures we have an in-country leadership team and capability to respond to our clients' needs.

We have an established local presence in all the major offshore oil and gas regions worldwide. Building a strong local infrastructure gives us the flexibility to respond to local opportunities, and enhances our overall position as an effective global partner. Having an embedded local presence allows us to build strong partnerships, and ensures that from an early stage of a project we are fully aligned with the strategic and commercial drivers of our clients.

We establish local operational facilities and offices, and invest in strategically-located vessels, spoolbases, fabrication yards and logistics bases. These are largely resourced by local workforces, working on a long-term basis with local suppliers to the benefit of the communities in which they are located.

We develop project management and supporting technical disciplines, and encourage our local operations to expand their capabilities.

To sustain this, we recruit and develop local talent through our highly-regarded learning and development programmes and by sharing our global experience. In this way, we bring new capabilities into local economies.

We enter into partnering and joint venture agreements, which give valuable access to local people, suppliers and market knowledge. These include NigerStar7 in Nigeria, Sonamet providing high-quality fabrication for projects off the coast of Angola, two newly formed local partnerships in Ghana, and in Mozambique we have our ENMAR joint venture. We also have a Malaysian joint venture, SapuraAcergy, which has widespread experience of projects in Asia.

Local associates, joint ventures and non-wholly owned subsidiaries

At Subsea 7 we are committed to operating in a safe, ethical and responsible manner

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.

Protecting people

The health and safety of people is our first priority. We are constantly striving to improve our safety performance, to mitigate risks and to develop a strong HSSE (Health, Safety, Security and Environment) culture across our global workforce in all our operations, both offshore and onshore.

It is our objective to achieve an incident-free workplace every day, everywhere. To reinforce and support this goal we continue to focus on our Great Safety Day initiative, which provides an easily understood visual metric and target for good HSSE performance. A Great Safety Day is a day where we have had no recordable or high potential safety or environmental incidents. In addition we continue to run various safety improvement initiatives to focus on specific areas of our operations. In 2015, we had a reduction in the absolute numbers of lost-time incidents and recordable incidents; however, unfortunately there was one fatality. Linked to a reduction in the number of hours worked, there was a slight increase in our lost-time incident frequency rate and our recordable incident frequency rate towards the year end. This reinforces the need for continued focus on improved safety performance.

Protecting the environment

Our Environmental Management System is in full compliance with, and certified to, the environmental management standard ISO 14001. The management system is also focused on ensuring full compliance with all applicable international and local environmental legislation wherever we operate. Our performance management data regarding energy efficiency, emissions and waste management are monitored and used as indicators for our continual improvement.

Clean Operations

Improved energy efficiency and reduced atmospheric emissions is one of our prime environmental objectives. Our Clean Operations 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. The Clean Operations metric we use is a count of energy reducing activities during our operational activities. In 2015, we recorded over 3,800 Clean Operation activities relating to our owned vessels, up from 3,000 recorded in 2014.

Carbon dioxide emissions reported for our fleet of owned and chartered vessels for 2015 reduced to 469,000 tonnes of carbon dioxide from 486,000 tonnes in 2014. The emissions data reflect a combination of the work schedules of the vessels throughout the year and the impact of our Clean Operations programme.

Great Safety Days

315 Days without a recordable or high-potential safety incident or an environmental incident.

Clean Operations

Recordable Incident Frequency Rate (%)

0.25 The number of lost-time injuries, cases of substitute work and other injuries requiring treatment by a medical professional per 200,000 hours worked.

Carbon dioxide emissions (tonnes)

469,000 Carbon dioxide emissions from Subsea 7 owned and chartered vessels. Data is based on fuel consumed while the vessels

have been operational.

We apply the highest ethical standards to everything we do

Conducting business with integrity

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. All employees are required to uphold our Code of Conduct, which is underpinned by an annual Compliance and Ethics e-learning campaign (mandatory for all employees above a certain band or in higher-risk roles or functions). In previous years, this e-learning has covered anti-bribery/anti-corruption, competition and anti-trust, confidentiality and information security. In 2015 the focus was on what integrity means to us as individuals and as a company, and how to apply this understanding to ethical dilemmas that the Group and its employees may face. As in previous years a 100% completion rate was achieved in 2015.

We have a Group-wide anti-bribery and anti-corruption compliance and ethics programme, which is firmly grounded in our values and is designed in accordance with international best practice (including the British Anti-Bribery Management System Standard (BS 10500)). During 2015 we 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.

Compliance, like safety, is a management accountability and the responsibility of everyone who works for us. One of the key roles of our compliance and ethics function is to help management to understand, accept and fulfil 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 relevant risks, and provides reports to the Corporate Governance and Nominations Committee and to the Executive Ethics Committee. The Ethics Committee meets at least once per quarter, and once a year a joint session of the Corporate Governance and Nominations Committee and the Audit Committee agrees compliance and ethics objectives and reviews progress in implementing the programme.

The Ethics Committee

The Ethics Committee is composed of the Chief Executive Officer and four other members of the Executive Management Team. Its responsibilities, as set out in its charter, include:

• 1. Promoting a culture of integrity and ethical business conduct that fosters compliance with applicable laws;
• 1. Defining and supporting the role of the compliance and ethics function;
• 1. Assessing and monitoring compliance and ethics risks;
• 1. Overseeing the implementation of the Group's Ethics Policy Statement and Code of Conduct and associated training and communications;
• 1. Overseeing the development and implementation of an effective compliance and ethics programme;
• 1. Overseeing the Group's whistle-blowing policy, procedures, investigations and remediation;
• 1. Reviewing compliance and ethics programme reports and metrics and ensuring the programme is properly monitored, audited and subject to continual improvement.

Subsea 7 engages with thousands of suppliers worldwide, and our Supply Chain Management procedures include rigorous selection and appointment criteria and require the use of approved suppliers wherever possible. This entails the pre-qualification of suppliers for quality, safety, the environment and (for higher risks) ethics and anti-corruption. All suppliers are required to comply with the Subsea 7 Code of Conduct for Suppliers, which was launched in 2015.

We are committed to treating our employees, clients, suppliers and other stakeholders fairly and with respect, and to upholding and respecting human rights.

BOARD OF DIRECTORS

Kristian Siem, 1949

Chairman2, 3

Mr Siem became Chairman of the Board of Directors of Subsea 7 S.A. in January 2011, prior to which he was Chairman of the Board of Directors of Subsea 7 Inc. from January 2002. Mr Siem has a degree in Business Economics and has been active in the oil and gas industry since 1972. Mr Siem is the Chairman of Siem Industries Inc. and Vice Chairman of NKT Holding A/S. Mr Siem is a director of Siem Offshore Inc., Siem Shipping Inc. (formerly Star Reefers Inc.), Flensburger Schiffbau-Gesellschaft mbH & Co. KG, North Atlantic Smaller Companies Investment Trust plc and Frupor S.A. Past directorships include Kvaerner ASA and Transocean Inc. Mr Siem is a Norwegian citizen.

Sir Peter Mason KBE, 1946

Senior Independent Director*2

Sir Peter Mason KBE has been the Senior Independent Director of Subsea 7 S.A. since January 2011, prior to which he was Chairman of Subsea 7 S.A. from May 2009. Previously he served as an Independent Director of Subsea 7 S.A. from October 2006. Sir Peter brings extensive management and oil service experience, having served as Chief Executive of AMEC from 1996 until his retirement in September 2006. Prior management positions include Executive Director of BICC plc and Chairman and Chief Executive of Balfour Beatty. 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. Sir Peter was a Non-Executive Director of BAE Systems plc from January 2003 until May 2013 and has been Chairman of the Board of Directors of Thames Water Utilities Ltd since December 2006, a Non-Executive Director of Spie S.A. since 2011 and Chairman of AGS Airports Limited since December 2014. Sir Peter is a British citizen.

Jean Cahuzac, 1954

Chief Executive Officer

Mr Cahuzac has been Chief Executive Officer of Subsea 7 since April 2008 and an Executive member of the Board of Directors since May 2008. Mr Cahuzac has over 35 years' experience in the offshore oil and gas industry, having held various technical and senior management positions around the world. From 2000 until April 2008 he worked at Transocean in Houston, USA, 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, including Field Engineer, Division Manager, VP Engineering and Shipyard Manager and President of the drilling division. He is a graduate of the École des Mines de St-Étienne and the French Petroleum Institute. Mr Cahuzac is a Board member of Shelf Drilling Inc. and has no other external appointments with public companies. As an Executive Director, Mr Cahuzac is not a member of any of the Board Committees. Mr Cahuzac is a French citizen.

Eystein Eriksrud, 1970 Director1

Mr Eriksrud joined the Board of Directors of Subsea 7 S.A. in March 2012. Mr Eriksrud is the Deputy CEO and Chief Operating Officer of the Siem Industries Group. Prior to joining Siem Industries in October 2011, Mr Eriksrud was a partner in the Norwegian law firm Wiersholm Mellbye & Bech, from 2005, working as a business lawyer, particularly in the shipping, offshore and oil service sectors. Mr Eriksrud was Group Company Secretary of the Kvaerner Group from 2000–2002 and served as Group General Counsel of the Siem Industries Group from 2002–2005. He is a candidate of jurisprudence from the University of Oslo. Mr Eriksrud has served on the boards of Privatbanken ASA and Tinfos AS as well as a number of other boards. He is the Chairman of Siem Offshore Inc.,

Flensburger Schiffbau-Gesellschaft mbH & Co. KG and Electromagnetic Geoservices ASA and a director of Siem Kapital AS, VSK Holdings Ltd, Venn Partners LLP, Siem Car Carriers AS, Siem Capital UK Ltd. and Siem Europe S.à r.l. Mr Eriksrud is a Norwegian citizen.

Dod Fraser, 1950 Independent Director*1

Mr Fraser joined the Board of Directors of Subsea 7 S.A. in December 2009. Mr Fraser is President of Sackett Partners, a consulting company, and he is a member of various corporate boards. 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 Washingtonbased environmental policy think-tank. He is a graduate of Princeton University. Mr Fraser is a Board member of Rayonier Inc. and a Board member of OCI GP LLC, which is the general partner of OCI Partners LP. Mr Fraser is a US citizen.

Robert Long, 1946

Independent Director*1,3

Mr Long joined the Board of Directors of Subsea 7 S.A. in January 2011. Mr Long served as Chief Executive Officer and a member of the Board of Directors of Transocean Ltd. from October 2002 until his retirement in February 2010. Mr Long served as President from 2001 to 2006, Chief Financial Officer from 1996 to 2001 and Senior VP of Transocean from May 1990 until the merger with Sedco Forex in 2000, at which time he assumed the position of Executive VP. During his 35-year career with Transocean, his international assignments included the UK, Egypt, West Africa, Spain and Italy. Mr Long is a graduate of the U.S. Naval Academy and Harvard Business School, and he served five years in the Naval Nuclear Power Programme before joining SONAT Inc., the parent company of The Offshore Company (which subsequently became Transocean Ltd.), in 1975. Mr Long has no other external appointments with public companies. Mr Long is a US citizen.

Allen Stevens, 1943

Independent Director*2,3

Mr Stevens joined the Board of Directors of Subsea 7 S.A. in January 2011. Prior to this he was a member of the Board of Directors of Subsea 7 Inc. from December 2005. Mr Stevens gained extensive marine industry and maritime financing experience holding senior executive and management positions with Great Lakes Transport Limited, McLean Industries Inc. and Sea-Land Service Inc. A graduate of the University of Michigan and Harvard Law School, Mr Stevens brings to the role many years of experience in shipping, finance and management. Mr Stevens is a Vice President and director of Masterworks Development Corporation, a hotel developer and operator. Mr Stevens is a US citizen.

Independent Directors

* As used above, 'independence' is defined as per 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. There will be four Directors standing for re-election at the 2016 Annual General Meeting: Mr Kristian Siem, Sir Peter Mason KBE, Mr Jean Cahuzac and Mr Eystein Eriksrud whose term will expire at that meeting. The current term of the remaining Directors, Mr Dod Fraser, Mr Robert Long and Mr Allen Stevens, will expire in 2017. Under the Company's Articles of Incorporation, the Board must consist of not fewer than three Directors.

Committee membership

• 1. Audit Committee
• 1. Corporate Governance and Nominations Committee
• 1. Compensation Committee

EXECUTIVE MANAGEMENT TEAM

Jean Cahuzac, 1954

Chief Executive Officer

Jean Cahuzac 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. Jean's full biography is included under Board of Directors on the previous page.

John Evans, 1963

Chief Operating Officer

John Evans has been Chief Operating Officer of Subsea 7 since July 2005. John started his career in the oil and gas engineering and contracting sector in 1986, working with Kellogg Brown & Root (KBR). During 18 years with KBR he gained a successful record in general management, commercial and operational roles in the 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 Engineering degree in Mechanical Engineering from Cardiff University, is a Chartered Mechanical and Marine Engineer and a Chartered Director. John Evans is a British citizen.

Nathalie Louys, 1963

General Counsel

Nathalie Louys has been General Counsel of Subsea 7 since April 2012. Nathalie began her legal career in 1986, working with Saint-Gobain and Eurotunnel, gaining extensive legal experience across a number of industries. In 1996 she joined Technip, based in Paris, progressing to the role of Vice President Legal – Offshore. 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. Nathalie is admitted to the Paris Bar and has legal qualifications from University Paris 1 – Panthéon Sorbonne and Paris XI in France and the University of Kent in the UK. Nathalie Louys is a Belgian citizen.

Øyvind Mikaelsen, 1963

Executive Vice President – Southern Hemisphere and Global Projects

Øyvind Mikaelsen was appointed a member of the Executive Management Team in his capacity as Executive Vice President – Southern Hemisphere and Global Projects, with effect from 1 January 2015. Øyvind began his career in the oil and gas industry with Kvaerner Rosenberg A/S in 1988. He then moved to Norske Shell before joining Subsea 7 in 1992 where he held a variety of positions until he was appointed Vice President Subsea Construction product line in 2001, based in Aberdeen. In 2003, Øyvind was appointed Vice President of the Northern Europe and Canada Region and, in 2009, Senior Vice President for Subsea 7 Asia and Middle East and Northern Europe and Canada. In 2011, he became Senior Vice President for the combined region of North Sea, Mediterranean and Canada. Øyvind holds a Master of Science degree from the University of Trondheim in Norway. Øyvind Mikaelsen is a Norwegian citizen.

Ricardo Rosa, 1956

Chief Financial Officer

Ricardo Rosa has been Chief Financial Officer of Subsea 7 since July 2012. 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 in the 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. Ricardo Rosa has dual British and Brazilian citizenship.

Keith Tipson, 1958

Executive Vice President – Human Resources

Keith Tipson has been Executive Vice President – Human Resources of Subsea 7 since November 2003. 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. Keith Tipson is a British citizen.

Steve Wisely, 1962

Executive Vice President – Northern Hemisphere and Life of Field

Steve Wisely was appointed Executive Vice President – Northern Hemisphere and Life of Field on 1 January 2015. Prior to this, Steve was Executive Vice President – Commercial. Steve started his career in the oil and gas industry with Wharton Williams (2W) in Aberdeen in 1987. Since then he has held a number of commercial and operational positions with Subsea 7 and its predecessor companies in the UK and overseas, including Norway and Singapore. In 1997 Steve was appointed Vice President Asia Pacific, based in Singapore. He returned to the UK in 2006 as Vice President UK and then Vice President Global Business Acquisition. During 2009 Steve spent a further period in the Asia Pacific before taking up the role of EVP – Commercial in 2010. Steve is a graduate of Robert Gordon University in Aberdeen with a degree in Quantity Surveying. Steve Wisely is a British citizen.

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.

CORPORATE GOVERNANCE

2015 Corporate Governance Report

The Board of Directors is committed to meeting high corporate governance standards in pursuing our corporate vision. We are committed to cultivating a values-based performance culture that rewards ethical business conduct, respect for the environment and personal and corporate integrity. We believe that there is a link between high-quality governance and the creation of shareholder value.

The Board of Directors has determined the Values by which the Group conducts its business as set out on the inside front cover. Corporate responsibility is embedded in these Values and the Group's Code of Conduct, which is available on Subsea 7's website: www.subsea7.com, enforces these Values.

Corporate governance at Subsea 7

Subsea 7 S.A.'s Board of Directors is responsible for and committed to the maintenance of high standards of corporate governance at all times throughout the Group. The Board of Directors strongly believes that the observance of these standards is in the best interests of all our stakeholders.

The Board of Directors is charged with ensuring that the Group conducts its business in accordance with exacting standards of business practice worldwide and observes high ethical standards. The Group conducts its operations in challenging environments, which heightens the need for a robust culture of governance. The role of the Board of Directors is to proactively encourage, monitor and safeguard this governance culture. The Board of Directors and its committees oversee the management of the Group's operations and the effectiveness of its internal controls.

The work of the Board of Directors is based on a clearly defined division of roles and responsibilities between the shareholders, the Board of Directors and the Executive Management Team. Our governing structures and controls help to ensure that we run our business in an appropriate manner where the Group operates for the benefit of shareholders, employees, clients and other stakeholders.

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-the-counter 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, 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.

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 a Code of Conduct which reflects its commitment to shareholders, employees, clients and other stakeholders to conduct business legally and with integrity and honesty. The Code of Conduct was approved by the Board of Directors and was issued to all directors, officers and employees and is subject to periodic review and updating.

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

Subsea 7 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.

The Group also offers the full spectrum of products and capabilities to deliver Life of Field services to its clients.

Through the i-Tech Division, the Group provides ROVs and intervention tooling services to support exploration, production and drilling activities.

Further details of the Group's business are outlined in the 'What we do' section on pages 4 and 5, 'Our Market Segments' on pages 6 and 7 and 'Where we operate' on pages 8 and 9.

Equity and dividends

Shareholders' equity

Total shareholders' equity at 31 December 2015 was \$5.38 billion (2014: \$5.59 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 Annual General Meeting (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 inter alia reduce the administrative burden of convening an extraordinary general meeting annually.

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 above. 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 personally interested.

The Group's Code of Conduct requires any director or employee to declare if they hold any direct or indirect 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 USA. All shares are freely negotiable. The Articles of Incorporation contain no form of restriction on the negotiability of shares in the Company.

General meetings

The Articles of Incorporation provide that the AGM is held each year on the fourth Friday in June in Luxembourg. Subject to approval by the shareholders, the AGM can be held at an earlier date and this year will be held on 14 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 is no minimum quorum requirement for annual general meetings. 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, Group 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.

Nominations Committee

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.

The 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.

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.

Governance

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 whom are independent.

Board Members

Kristian Siem	Chairman
Sir Peter Mason KBE	Senior Independent Director
Jean Cahuzac	Chief Executive Officer
Eystein Eriksrud	Director
Dod Fraser	Independent Director
Robert Long	Independent Director
Allen Stevens	Independent Director

Biographies of the individual Directors are detailed on page 16.

The majority of the Directors were, during the financial year 2015, 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.

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 ratify 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.

Attendance by Directors at the meetings of the Board of Directors and its committees during 2015 is summarised below:

2015 Meetings

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

(a) Additionally, a joint session of the Audit Committee and Corporate Governance and Nominations Committee was held on 20 May 2015 at which all members of both committees were present.

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' share holdings are on page 85.

The 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. Setting and approving policies.

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

CORPORATE GOVERNANCE CONTINUED

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 2016, 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 whom are on page 17. 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. In addition to the previously mentioned Corporate Governance and Nominations Committee, the Board of Directors has established 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.

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 25 to 29. 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 internal audit and the external auditor where appropriate.

Remuneration of the Board of Directors

The Company's Directors receive remuneration in accordance with their individual roles and committee membership. The remuneration of the CEO 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.

The 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 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-in-kind 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. Performance-related 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 six 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.

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 open 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 http://www.oslobors. no/ob_eng/Oslo-Boers/Listing/Shares-equity-certificates-and-rightsto-shares/Oslo-Boers-and-Oslo-Axess/Code-of-Practice-for-IR.

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 beneficial owners who own more than 5% of the Company's issued share capital:

	%(a)
Siem Industries Inc.	21.3%
Folketrygdfondet	8.3%
Orbis Investment Management Limited	5.5%
BlackRock, Inc.	5.0%

(a) Information is correct as at 31 December 2015.

Audit Committee

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 16. The Board of Directors has determined that Mr Fraser is the Audit Committee 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.

The Audit Committee

Committee members

Dod Fraser – Committee Chairman Eystein Eriksrud Robert Long

The Audit Committee's main responsibilities are:

• 1. Monitoring the financial reporting process.
• 1. Monitoring the effectiveness of the Company's and the Group's internal control, internal audit, 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.
• 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 provision of additional services to the Company and the Group 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.

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.

Directors' Responsibility Statement

We confirm that, to the best of our knowledge, the Consolidated Financial Statements for the year ended 31 December 2015 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 2015 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 Chairman

1 March 2016

Jean Cahuzac

CEO and Director 1 March 2016

RISK MANAGEMENT

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, therefore, 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 business, which represents the majority of the Group's revenue, is generally contracted on a fixed-price basis and involves the engineering, procurement, installation and commissioning of highly complex systems offshore on behalf of its clients. The costs and margins realised on such projects could vary from the 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 of these risks. The Conventional, Hook-up and Life of Field businesses have similar although less challenging risk profiles. Revenue from the i-Tech Division is contracted on a day-rate basis and consequently has the lowest risk profile.

The Group operates in a cyclical industry whose activity is strongly influenced by the current and forecast price of oil and gas. The Group's risk management processes assist the Group to respond to changes in levels of activity and take steps to adjust its cost base as far as practical whilst at the same time ensuring that additional risk is not assumed by the business as a consequence.

Roles and responsibilities

The Board of Directors has oversight of the Group's risk management activities and internal control processes. The CEO determines the level of risk which can then be taken by Corporate, Business Units, region and country management. This is managed through Group policies and delegated authority levels which, inter alia, 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.

The Executive Management Team is responsible for monitoring and managing operational and enterprise risk in pursuit of the Group's business objectives. It 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.

Principal risks

The principal risks and the means the Group employs to mitigate or eliminate those risks are set out below. Risks of particular importance are: health, safety, security and environmental risks, bidding risk, project execution, supply chain management, regulatory, and compliance and ethics risks. Each of these has the potential to have a material adverse effect on the Group's reputation, operations, financial performance and position.

In common with many international businesses, the Group faces a number of financial and treasury risks and uncertainties and, in particular, those arising from managing exposures to the currencies of the countries in which the Group operates. The Group has controls in place to manage such risks.

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 and/or 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

Economic

Our business depends on the level of activity in the oil and gas industry and, consequently, any significant change in the level or timing of our clients' expenditure plans could adversely impact the Group's order intake. Such plans could be impacted by demand for, and supply of, oil and gas. In the current economic climate, failure by a client or a client experiencing financial difficulties could lead to late or non-collection of amounts owed. In the medium-term, demand for these hydrocarbons could also be affected by the introduction of alternative energy sources.

Competition

The Group faces competition for both contracts and resources. Competition could result in pricing pressures, lower sales and reduced margins that would have an adverse effect on the operating results, financial performance and position of the Group.

Risk Mitigation

The Group works closely with its clients to understand their future plans. It also seeks to diversify selectively into new markets within the oil and gas sector and into other geographies for its services. The financial strength and solvency of our clients is always considered before entering into a contract and is a specific area of focus in the current economic climate. In addition the Group has reviewed, adjusted and continues to adjust its cost base to reflect the current uncertainties in the market.

The Group's experience and resources, in particular its fleet and technological abilities, help it respond effectively to challenges from competitors. A further differentiator is the Group's ability to partner with clients and form alliances with other oilfield service companies to contribute to the early development stages of projects, as well as offer cost effective and efficient solutions to its clients.

Governance

Business environment risks

Risk	Mitigation
Geographic
The Group operates in various countries around the world which gives rise to a number of risks and uncertainties, including:	These risks are carefully considered prior to the Group working in such regions and appropriate procedures are developed
• Legal and regulatory • Sanctions and export controls • Political • Compliance and Ethics • Financial • Operational.	and implemented to mitigate their impact. Such risks can, on occasion, adversely impact the costs of project execution. The Group adopts a proactive and rigorous approach to assessing and mitigating these risks.
Technology risks
The Group's clients seek to develop oil and gas fields in increasingly deeper waters and more 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.	The Group continues to focus on developing new technologies to maintain the Group's competitiveness. In implementing new technologies, the risks associated with their first implementation are carefully considered and addressed. Risk is also mitigated by negotiating the risk profile for technology-rich projects with our clients.
Organisation and management risks
Risk	Mitigation
People
Failure to recruit and retain suitably skilled and capable personnel could adversely impact the Group's ability to execute projects and its future growth. Increased competition for skilled personnel could result in a lack of resources or increased salary costs to the Group.	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.
Compliance and Ethics
The Group's reputation and its ability to do business may be impaired by inappropriate behaviour by any of its employees, representatives or other persons associated with it. While the Group is committed to conducting business in a legal and ethical manner, there is a risk that its employees, representatives or such other persons may take actions that breach the Group's Code of Conduct	The Group's Code of Conduct clearly sets out the behaviours expected of its employees and those who work with it. Mandatory e-learning courses are used to raise awareness of the Code within the Group and encourage compliance. The Group has policies, procedures and controls in place to support and implement the Code of Conduct and the Group's joint venture

or applicable laws, including but not limited to anti-bribery and anti-corruption laws. Any such breach could result in monetary penalties, convictions, debarment and damage to its reputation and could therefore impact the Group's ability to do business.

Information technology and security

The Group's operations depend on the availability and security of a number of key information technology (IT) systems. Disruption to these systems or a breach of information security could adversely impact the Group's ability to operate and its reputation.

partners and suppliers are also expected to have equivalent policies and procedures in place. Appropriate due diligence is undertaken of all key suppliers, joint venture partners and representatives to ensure that they are aware of and understand the Group's Code of Conduct and its expectations.

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. These policies are regularly reviewed to ensure they continue to address existing and emerging information security and cybercrime risks. Courses are used to raise awareness among employees of these risks and of the Group's procedures to manage them. The Group recognises the increased incidence of cyber security threats and has recently reviewed its policies, procedures and defences to mitigate associated risks.

Delivery and operational risks

Risk	Mitigation
Bidding risk
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 estimate and understand the risks, costs and contractual terms involved in such contracts could have an adverse impact on the Group's profitability.	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 our commercial standards and market conditions. Before the tender is submitted, a formal review process is performed. Tenders are first reviewed at the 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 risk criteria being approved by a Committee of the Board of Directors.
Realisation and renewal of backlog
Delays, suspensions, cancellations, and scope changes to awarded projects in backlog could all materially impact the revenue and profitability of the Group in 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, in certain instances, engage in a joint venture with selected partners to obtain the necessary expertise or local knowledge. A failure by a joint venture partner to perform to the standards required could result in financial and reputational loss 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 condition and cash flow.	The Group seeks to ensure that any joint venture partner selected not only has the necessary skills and experience and financial condition but is also able to meet the Group's health, safety and environmental standards and its Code of Conduct. The Group endeavours to establish appropriate governance and oversight mechanisms to monitor the performance of its joint venture partners to ensure their continued suitability.
Project execution
The projects in which the Group is involved are complex and a failure to meet our clients' contractual requirements could have several adverse consequences (including contract disputes, non-agreed claims and cost overruns) which could adversely impact the Group's profitability and reputation.	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 financial performance, cost management, project progress, risk management and sensitivity analysis. Detailed assessments of costs and revenues are estimated and reported upon, taking
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 which can result in unforeseen delays	into account project performance, planning schedules, contract variations, claims, allowances and contingency analysis. Risk registers are maintained and periodically reviewed.
to the project or damage to vessels and equipment or injury to those working offshore.	The Group factors the risk of adverse weather conditions into the design of its vessels, equipment and procedures, as well as the training of its offshore workforce. It also works to mitigate the potential adverse financial consequences when negotiating contractual terms with the client.
Supply chain
Failure of a key supplier could result in disruption to the Group's ability to complete a project in a timely manner. The resultant time delays could lead to increased and irrecoverable costs to the Group and the imposition of financial penalties from clients.	The financial stability and strength of the Group's supply chain is reviewed during the pre-qualification process and is considered prior to signing 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 who have worked successfully with it in the past.

Delivery and operational risks continued

Risk	Mitigation
Health, safety, security and environmental
The Group's projects are complex and require the monitoring and management of health, safety, security and environmental risks associated with them. A failure to manage these risks could expose our people and those who work with us to injury or harm and could result in significant commercial, legal and reputational damage.	The Group has detailed health, safety, security and environmental policies which are designed to reduce such risks and ensure compliance with relevant laws and regulations. These policies are subject to monitoring and review and are externally certified by accreditation bodies such as DNV.
Fleet management
The Group has a fleet of vessels which are essential to the successful delivery of its projects. These vessels operate in a number of regions which are subject to political, fiscal, legal and regulatory risks. Failure to manage such risks could lead	The Group considers carefully the political, fiscal, legal and regulatory risks associated with the deployment of its vessels in the regions in which it operates, and monitors changes and developments to ensure it is able to respond appropriately.
to financial penalties.	Maintenance and dry-dockings are subject to detailed
Availability of vessels could also be impacted by delays to the completion of major repairs or upgrading of vessels (including dry-dockings).	planning, and controls are in place to mitigate the risk of completion delays.
In extreme and exceptional circumstances, the non-availability of a vessel through loss or irreparable damage could compromise the Group's ability to meet its contractual obligations.	The design and operational capability of a vessel is assessed carefully on its deployment to a particular project, and is then monitored closely during that project's execution. The impact of potential non-availability of a vessel is mitigated by both the
To maintain the competitiveness of the fleet, the Group from time to time makes significant investments in the construction or purchase	size and diversity of the Group's fleet and its ability to access the vessel charter market.
of new vessels. If the anticipated demand for those vessels does not materialise, such investments may not generate the intended return.	Before initiating construction or purchase 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 returns.

Financial risks

Revenue 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 of completion 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.

Risk Mitigation

Project performance is monitored by means of Project Monthly Status Reports (PMSRs) which record costs to date (ACWP) and estimates of costs to completion and 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" provides more detail on the Group's approach to revenue recognition on long-term contracts.

Financial risks continued

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 performancerelated 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- 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.

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 recognises that any system of internal controls can only provide reasonable and not absolute assurance that material financial irregularities 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 and Environmental processes
• Group Treasury policies
• The Group's whistleblowing policy, which allows individuals to raise concerns in confidence about potential breaches of the Code of Conduct.

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.

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Risk Mitigation

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.

FINANCIAL REVIEW

Financial highlights

Revenue for 2015 was \$4.8 billion compared to \$6.9 billion for the prior year, reflecting lower levels of activity resulting from the challenging industry conditions, and the impact of the strengthening US Dollar. Vessel utilisation was 72% compared with 82% in 2014. Net operating income was \$144 million after recognising a goodwill impairment charge of \$521 million and impairment charges related to property, plant and equipment of \$136 million. Excluding the goodwill impairment charge, the Group generated net operating income of \$665 million, which mainly resulted from the successful completion of the offshore phases of several large projects and the implementation of cost reduction measures across the Group.

The goodwill impairment charge of \$521 million, in aggregate, arose as a result of the Group's annual review of the carrying value of goodwill. This non-recurring, non-cash charge, which had no tax impact, affected both Business Units following a downward revision of forecast activity levels, driven by challenging market conditions.

The Group incurred a net loss of \$37 million, equivalent to a diluted loss per share of \$0.05, after deducting the goodwill impairment charge of \$521 million. Excluding this charge, the Group's net income for 2015 was \$484 million, equivalent to Adjusted diluted earnings per share of \$1.45.

As at 31 December 2015, the Group's backlog totalled \$6.1 billion, a decrease of \$2.1 billion compared to 31 December 2014. The decrease in backlog reflected delays in awards to the market in both Business Units and adverse foreign exchange movements.

The PLSV, Seven Rio, joined the fleet during the year. The Group continued with its new-build vessel programme focused on fleet renewal and enhancement. Construction progressed on Seven Kestrel, a new diving support vessel for operation in the North Sea, with delivery expected in second quarter of 2016, Seven Arctic, a heavy construction vessel, also due for delivery in the second quarter of 2016, and on two PLSVs, Seven Sun and Seven Cruzeiro, linked to long-term contracts awarded by Petrobras, with expected delivery dates in the second and fourth quarters of 2016 respectively.

As part of the Group's cost reduction and resizing programme Seven Polaris was scrapped and a further five owned vessels were stacked.

The Group held cash and cash equivalents of \$947 million at 31 December 2015 compared with \$573 million at 31 December 2014, and had total borrowings of \$524 million at 31 December 2015 compared with \$578 million at 31 December 2014.

For the year ended (in \$ millions, except Adjusted EBITDA margin, share and per share data)	2015 31 Dec	2014 31 Dec
Revenue	4,758	6,870
Adjusted EBITDA(a) (unaudited)	1,217	1,439
Adjusted EBITDA margin(a) (unaudited)	26%	21%
Net operating income excluding goodwill impairment charge	665	930
Goodwill impairment charge	(521)	(1,183)
Net operating income/(loss)	144	(254)
Net income excluding goodwill impairment charge	484	802
Net loss	(37)	(381)
Earnings per share – in \$ per share
Basic	(0.05)	(1.02)
Diluted	(0.05)	(1.02)
Adjusted diluted(b)	1.45	2.32
As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Backlog (unaudited)	6,110	8,239
Cash and cash equivalents	947	573

Borrowings 524 578

(a) For explanations and reconciliations of Adjusted EBITDA and Adjusted EBITDA margin please refer to page 95 of the Consolidated Financial Statements.

(b) For explanation and a reconciliation of diluted and Adjusted diluted earnings per share please refer to Note 12 'Earnings per share' in the Consolidated Financial Statements.

Revenue

Revenue for 2015 was \$4.8 billion compared with \$6.9 billion in 2014. The decrease reflected lower activity levels in both Business Units and the strengthening of the US Dollar against the currencies in which the Group primarily transacted in the year.

Adjusted EBITDA

Adjusted EBITDA and Adjusted EBITDA margin were \$1.2 billion and 26% respectively compared to \$1.4 billion and 21% in 2014. The reduction in Adjusted EBITDA reflected the decrease in activity and included a restructuring charge of \$136 million related to the Group's programme of cost reduction measures, primarily focused on a resizing of the fleet and workforce. Excluding this charge, Adjusted EBITDA margin was 28% driven by the successful completion of the offshore phases of several projects and the implementation of cost reductions across the Group.

Net operating income/(loss)

Net operating income was \$144 million, compared to a net operating loss of \$254 million in 2014. Net operating income/(loss) included a goodwill impairment charge of \$521 million in 2015 and \$1,183 million in 2014. Excluding the impact of the goodwill impairment charge, net operating income was \$665 million in 2015, a decrease of \$265 million or 28% compared to 2014 and was mainly due to:

• lower activity levels in both Business Units, partially offset by the impact of the successful completion of certain large projects in Africa;
• a restructuring charge of \$136 million associated with the Group's cost reduction and resizing programme, of which \$93 million related to operating expenses and \$43 million related to administrative expenses; and

impairment charges of \$136 million related to property, plant and equipment compared to \$89 million recognised in 2014 partially offset by:

reduced administrative expenses, excluding the restructuring charge related to the resizing programme, resulting mainly from lower personnel costs combined with the strengthening of the US Dollar.

Net loss

Net loss was \$37 million in 2015, compared to a net loss of \$381 million in 2014. The decrease in net loss was primarily due to:

• a net operating income of \$144 million in 2015 compared to a net operating loss of \$254 million in 2014 which reflected the reduction of \$662 million in the goodwill impairment charge in 2015 compared to 2014;
• net foreign currency gains of \$31 million in 2015, recognised within other gains and losses, compared with \$24 million in 2014; and
• lower finance costs of \$8 million compared to \$19 million in 2014 mainly due to the absence of interest charges related to the \$275 million 3.5% convertible bonds which matured in October 2014, and the favourable impact of capitalised interest costs in relation to the new-build vessel programme

partially offset by:

an increase of \$70 million in the tax charge compared to 2014. Excluding the impact of the goodwill impairment charge the effective tax rate for 2015 was 31% compared to 16% in 2014, reflecting the benefit of certain discrete items.

Earnings per share

Diluted loss per share was \$0.05 for 2015 compared to a diluted loss per share of \$1.02 for 2014, calculated using a weighted average number of shares of 326 million and 331 million respectively. Adjusted diluted earnings per share, which excludes the impact of the goodwill impairment charge, was \$1.45 (2014: \$2.32).

Cash and cash equivalents

Cash and cash equivalents increased from \$573 million to \$947 million during 2015. The movement in cash and cash equivalents was mainly attributable to:

cash generated from operating activities of \$1,049 million

partially offset by:

• expenditure on property, plant and equipment of \$639 million, mainly related to the Group's new-build vessel programme; and
• the repurchase of \$70 million (par value) of the \$700 million 1.00% convertible bonds due 2017, for \$65 million in cash.

Borrowings

Borrowings decreased by \$54 million to \$524 million during 2015. The reduction was largely due to the repurchase of \$70 million (par value) of the \$700 million 1.00% convertible bonds due to mature in October 2017 for \$65 million in cash.

Allocation of net loss

The net loss for the year of \$37 million (2014: \$381 million) was transferred to equity, of which \$17 million (2014: \$338 million) was recognised in retained earnings attributable to shareholders of the parent company and \$20 million in non-controlling interests (2014: \$43 million).

Business Unit highlights

For the year ended 31 December 2015

(in \$ millions)	Northern Hemisphere and Life of Field	Corporate	Total
Selected financial information:		and Global Projects
Revenue	2,019.0	2,709.9	29.2	4,758.1
Net operating income/(loss) excluding goodwill impairment charge	183.4	678.7	(197.4)	664.7
Impairment of goodwill	(351.3)	(169.6)	–	(520.9)
Net operating (loss)/income including goodwill impairment	(167.9)	509.1	(197.4)	143.8

For the year ended 31 December 2014

(in \$ millions)	Northern Hemisphere and Life of Field Re-presented(a)	Southern Hemisphere and Global Projects Re-presented(a)	Corporate Re-presented(a)	Total Re-presented(a)
Selected financial information:
Revenue(a)	3,087.3	3,774.6	8.0	6,869.9
Net operating income/(loss) excluding goodwill impairment charge	340.9	674.7	(86.1)	929.5
Impairment of goodwill	(594.1)	(589.2)	–	(1,183.3)
Net operating (loss)/income including goodwill impairment	(253.2)	85.5	(86.1)	(253.8)

(a) Re-presented due to the reorganisation of the reportable segments from 1 January 2015.

Northern Hemisphere and Life of Field

Revenue was \$2.0 billion, a decrease of \$1.1 billion or 35% compared to 2014. This reduction was largely due to decreased activity on the Martin Linge, Knarr and Delta S2 projects, offshore Norway; the Laggan Tormore and Dana Western Isles projects, offshore UK and the Line 60 and 67 projects, offshore Mexico, which all had significant offshore phases in 2014. In addition there was a significant decrease in Life of Field activity in the North Sea as clients curtailed investment related to existing infrastructure.

Net operating loss was \$168 million compared to a net operating loss of \$253 million in 2014. The net operating losses included a goodwill impairment charge of \$351 million in 2015 and \$594 million in 2014 as a result of a downward revision of forecast activity levels, driven by challenging market conditions. Excluding the impact of the goodwill impairment charge, net operating income was \$183 million, a decrease of \$158 million or 46% compared to 2014, this was mainly due to decreased activity levels.

Southern Hemisphere and Global Projects

Revenue was \$2.7 billion, a decrease of \$1.1 billion or 28% compared to 2014. Revenue decreased due to the relative stage of completion of the Block 31 GES and CLOV, both offshore Angola, OFON 2, offshore Nigeria, Gorgon Heavy Lift and Tie-ins, offshore Australia and Guará Lula NE, offshore Brazil, projects which were all in their offshore phases in 2014.

Net operating income was \$509 million, compared to \$86 million in 2014. Net operating income included a goodwill impairment charge of \$170 million in 2015 and \$589 million in 2014 as a result of a downward revision of forecast activity levels, driven by challenging market conditions. Excluding the impact of the goodwill impairment charge, net operating income was \$679 million, an increase of \$4 million compared to 2014. The net operating income in 2015 reflected an increase in margin following the successful completion of the offshore phases of several large projects. This was partially offset by decreased activity levels and lower contribution from the SapuraAcergy joint venture due to a significant drop in activity after completion of the Gorgon Heavy Lift and Tie-ins project.

Corporate

Net operating loss was \$197 million (2014: \$86 million). The increased net operating loss was primarily due to a \$136 million charge associated with the Group's cost reduction and resizing programme recognised in the year and an impairment charge of \$136 million related to property, plant and equipment recognised in 2015 compared to a charge of \$79 million in 2014. This was partially offset by lower personnel costs and associated cost savings, excluding the restructuring charge related to the resizing programme, and an increased contribution from the Seaway Heavy Lifting joint venture due to higher activity levels during 2015 compared to 2014, which was adversely impacted by the dry-docking of Stanislav Yudin.

Backlog

At 31 December 2015 backlog was \$6.1 billion, a decrease of \$2.1 billion compared with 31 December 2014. New awards and project escalations totalling \$3.4 billion were recorded in the year. Major awards included the West Nile Delta projects, offshore Egypt, with scopes for both BP and Burullus Gas Company and the East Nile Delta project, offshore Egypt, for Pharaonic Petroleum Company; the Maria project, offshore Norway, for Wintershall; the Culzean project, offshore UK, for Maersk and Life of Field work for Chevron in Australia. In addition there were renewals of existing frame agreements including the USC contract for Shell and DSVi operations, both offshore UK. During the year backlog was adversely impacted by foreign exchange movements, which affected contracts wholly or partly denominated in Brazilian Reais, Norwegian Krone and British Pounds. These currencies weakened relative to the US Dollar during the year.

\$4.8 billion of the backlog at 31 December 2015 related to SURF activity, which included \$2.2 billion related to long-term day-rate contracts for PLSV's in Brazil, \$1.0 billion related to Life of Field and i-Tech and \$0.3 billion related to Conventional and Hook-up. \$3.2 billion of this backlog is expected to be executed in 2016; \$1.6 billion in 2017 and \$1.3 billion in 2018 and thereafter. Backlog related to associates and joint ventures is excluded from these figures.

Balance sheet

Goodwill

As at 31 December 2015 goodwill was \$767 million, a reduction of \$556 million in the year following the recognition of an impairment charge of \$521 million and movements related to foreign exchange. This non-recurring, non-cash charge, which had no tax impact, affected both the Northern and Southern Business Units following a downward revision of forecast activity levels, driven by challenging market conditions. The recoverable amounts of goodwill were determined on a value-in-use basis using cash flow projections covering a five-year period. Cash flows beyond this five-year period were extrapolated in perpetuity using a 2.0% growth rate to determine the terminal value.

Property, plant and equipment

Additions to property, plant and equipment totalled \$671 million (2014: \$878 million). Additions included \$281 million related to the construction of three PLSVs for Brazil, Seven Sun, Seven Rio and Seven Cruzeiro linked to long-term contracts awarded by Petrobras. Construction continued on Seven Arctic and Seven Kestrel, with associated expenditure of \$217 million in aggregate. The remaining capital expenditure mainly related to dry-dockings, equipment renewals of the existing fleet and the construction of new office facilities in London.

During the year, impairment charges totalling \$136 million (2014: \$89 million) were recognised. \$40 million was recognised in respect of Seven Polaris before it was scrapped. \$86 million was recognised in respect of six other vessels. Impairments arose as a result of continued declines in expectations of future oil and gas prices, which in the near-term are expected to negatively impact on the projected levels of investment and growth in the oil and gas sector. The downturn in the market has impacted on both current market valuations and the expected future utilisation of vessels. In addition an impairment charge of \$11 million was recognised in respect of property and equipment where future recoverable amounts were reassessed and reduced.

Interest in associates and joint ventures

There were no significant changes in the Group's interests in associates and joint ventures during 2015.

Borrowings

During the year the Group repurchased \$70 million (par value) of the 2017 1.00% convertible bonds for \$65 million (an average 92.4% of the par value). The cost of each repurchase was allocated to both the liability and equity component of the bonds. This resulted in a gain on repurchase of the liability component of \$3 million recognised within finance income in the Consolidated Income Statement. These bonds have not been cancelled but continue to be held by the Group and are available for re-issue at a future date.

Facilities

In July 2015 the Group entered into a \$357 million senior term loan facility secured on two vessels under construction. 90% of the facility is provided by an Export Credit Agency (ECA) and 10% by two banks and the facility is available for general corporate purposes. As at 31 December 2015 the facility remained unutilised. The facility may be drawn prior to the delivery of the vessels. If unutilised, upon delivery of the vessel, the facility will terminate.

As at 31 December 2015 the Group had total facilities of \$857 million, all of which were unutilised. This included the \$500 million multi-currency credit and guarantee facility which matures on 3 September 2019.

Issued share capital and treasury shares

During 2015, the Group repurchased 815,578 (2014: 4,457,078) shares under the July 2014 share repurchase programme for a total consideration of \$8 million (2014: \$49 million). Cumulatively 5,272,656 shares have been repurchased under the July 2014 share repurchase programme for a total consideration of \$57 million.

On 17 April 2015 an Extraordinary General Meeting of shareholders approved the renewal and extension of the authorised share capital of the Company to \$900 million, represented by 450 million common shares with a par value of \$2.00 per share.

On 30 September 2015 the directors of the Company, in accordance with the delegation of authority given to the Board of Directors, approved the cancellation of 4,799,956 common shares held in treasury resulting in a reduction in the issued share capital of the Company of \$9,599,912.

Shareholders

The 20 largest shareholders as at 31 December 2015, 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	8.3
Orbis Investment Management Ltd.	5.5
BlackRock, Inc.	5.0
Templeton Investment Counsel, LLC	4.8
DNB Asset Management AS	3.7
Danske Capital (Norway)	2.3
SAFE Investment Company Limited	2.0
Nordea Funds Oy	1.9
Robotti & Company Advisors, LLC	1.8
KLP Forsikring	1.8
The Vanguard Group, Inc.	1.5
Storebrand Kapitalforvaltning AS	1.4
Pareto Forvaltning AS	1.1
Marshall Wace LLP	1.1
GE Asset Management Inc.	1.0
Oslo Asset Management ASA	0.9
ODIN Forvaltning AS	0.8
Bestinver Gestión S.G.I.I.C. S.A.	0.8
BNP Paribas Investment Partners (France)	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:

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Cash and cash equivalents at the beginning of the year	573	692
Net cash generated from operating activities	1,049	1,450
Net cash used in investing activities	(554)	(828)
Net cash used in financing activities	(96)	(720)
Effect of exchange rate changes on cash and cash equivalents	(25)	(21)
Cash and cash equivalents at the end of the year	947	573

Net cash generated from operating activities was \$1.0 billion (2014: \$1.4 billion) and included an increase in net operating liabilities of \$64 million during 2015.

Investing activities consumed \$554 million in 2015 compared with \$828 million in 2014. This was mainly attributable to expenditure on property, plant and equipment of \$639 million, a decrease of \$222 million from the \$861 million incurred in 2014, partly offset by dividends received from joint ventures of \$64 million, an increase of \$45 million compared to 2014.

Financing activities consumed \$96 million in 2015 mainly driven by the repurchase of \$70 million (par value) of the 2017 1.00% convertible bonds for \$65 million in cash.

New-build vessel programme

Actual and forecast expenditure on the Group's new–build vessel programme as at 31 December 2015 was:

	Actual expenditure			Forecast expenditure
(in \$ millions)	2013	2014	2015	2016
Total	372	544	499	340

Actual and forecast expenditures include an estimate of capitalised interest during construction as part of the initial cost of the vessels. The new-build vessel programme is expected to be completed during 2016.

Liquidity

As at 31 December 2015, the Group had sufficient liquidity to meet its expected funding requirements for the next twelve months. The Group had cash and cash equivalents of \$947 million and unutilised committed credit and guarantee facilities of \$857 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 2016.

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 as at 31 December 2015.

Outlook

The low oil and gas price continues to depress industry activity as clients delay and cancel new projects; the timing of market recovery remains highly uncertain. As guided previously, revenue and Adjusted EBITDA percentage margin are expected to be significantly lower in 2016 compared to 2015.

Backlog as at 31 December of \$6.1 billion, included \$2.2 billion related to 10 long-term contracts for PLSVs, offshore Brazil. There are two third party Brazilian flagged single-lay PLSVs with a top tension capacity of less than 350 tonnes that may be prioritised under Brazilian law over international vessels of a similar specification. As a result, a proportion of the Group's backlog relating to these contracts could be affected and discussions are in progress with the client regarding this risk.

Despite the difficult near to medium-term outlook, the fundamental long-term outlook for deepwater subsea field developments remains intact and industry activity is expected to recover when the oil and gas market rebalances. Subsea 7 has already implemented a number of initiatives to strengthen its position and will continue to actively adapt to industry conditions without losing its focus on long-term strategic priorities.

CONSOLIDATED FINANCIAL STATEMENTS CONTENTS

	Page
Report of the Réviseur d'Entreprises Agréé	37
Consolidated Income Statement	38
Consolidated Statement of Comprehensive Income	39
Consolidated Balance Sheet	40
Consolidated Statement of Changes in Equity	41
Consolidated Cash Flow Statement	43

Notes to the Consolidated Financial Statements	Page
1. General information	44
2. Adoption of new accounting standards	44
3. Significant accounting policies	46
4. Critical accounting judgements and key sources of estimation uncertainty	53
5. Revenue	54
6. Segment information	54
7. Net operating income/(loss)	57
8. Other gains and losses	57
9. Finance income and costs	58
10. Taxation	58
11. Dividends	61
12. Earnings per share	61
13. Goodwill	62
14. Intangible assets	64
15. Property, plant and equipment	65
16. Interest in associates and joint ventures	66
17. Advances and receivables	68
18. Inventories	68
19. Trade and other receivables	69
20. Other accrued income and prepaid expenses	69
21. Construction contracts	69
22. Cash and cash equivalents	69
23. Issued share capital	70
24. Treasury shares	70
25. Non-controlling interests	71
26. Borrowings	73
27. Convertible bonds	74
28. Other non-current liabilities	75
29. Trade and other liabilities	75
30. Provisions	75
31. Commitments and contingent liabilities	76
32. Operating lease arrangements	77
33. Financial instruments	77
34. Related party transactions	85
35. Share-based payments	87
36. Retirement benefit obligations	89
37. Deferred revenue	92
38. Cash flow from operating activities	92
39. Post balance sheet events	93
40. Wholly-owned subsidiaries	93

REPORT OF THE RÉVISEUR D'ENTREPRISES AGRÉÉ

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

Report on the Consolidated Financial Statements

Following our appointment by the General Meeting of the Shareholders dated 17 April 2015, we have audited the accompanying Consolidated Financial Statements of Subsea 7 S.A., which comprise the Consolidated Balance Sheet as at 31 December 2015, the Consolidated Income Statement, Consolidated Statement of Comprehensive Income, Consolidated Statement of Changes in Equity and Consolidated Cash Flow Statement for the year then ended, and a summary of significant accounting policies and other explanatory information.

Board of Directors' responsibility for the Consolidated Financial Statements

The Board of Directors is responsible for the preparation and fair presentation of these Consolidated Financial Statements in accordance with International Financial Reporting Standards as adopted by the European Union, and for such internal control 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.

Responsibility of the réviseur d'entreprises agréé

Our responsibility is to express an opinion on these Consolidated Financial Statements based on our audit. We conducted our audit in accordance with International Standards on Auditing as adopted for Luxembourg by the Commission de Surveillance du Secteur Financier. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance whether the Consolidated Financial Statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Consolidated Financial Statements. The procedures selected depend on the judgement of the réviseur d'entreprises agréé including the assessment of the risks of material misstatement of the Consolidated Financial Statements, whether due to fraud or error. In making those risk assessments, the réviseur d'entreprises agréé considers internal control relevant to the entity's preparation and fair presentation of the Consolidated Financial Statements 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 entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by the Board of Directors, as well as evaluating the overall presentation of the Consolidated Financial Statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the Consolidated Financial Statements give a true and fair view of the consolidated financial position of Subsea 7 S.A. as of 31 December 2015, and of its financial performance and its consolidated cash flows for the year then ended in accordance with International Financial Reporting Standards as adopted by the European Union.

Report on other legal and regulatory requirements

The consolidated Directors' report, including the corporate governance statement, which is the responsibility of the Board of Directors, is consistent with the Consolidated Financial Statements and includes the information required by the law with respect to the corporate governance statement.

Ernst & Young S.A. Société Anonyme Cabinet de révision agréé

Thierry Bertrand 1 March 2016

CONSOLIDATED INCOME STATEMENT

For the year ended (in \$ millions, except per share data)	Notes	2015 31 Dec	2014 31 Dec
Revenue	5	4,758.1	6,869.9
Operating expenses	7	(3,851.7)	(5,694.9)
Gross profit		906.4	1,175.0
Administrative expenses	7	(305.1)	(314.7)
Impairment of goodwill	13	(520.9)	(1,183.3)
Share of net income of associates and joint ventures	16	63.4	69.2
Net operating income/(loss)		143.8	(253.8)
Finance income	9	16.7	19.3
Other gains and losses	8	32.6	23.7
Finance costs	9	(8.2)	(18.7)
Income/(loss) before taxes		184.9	(229.5)
Taxation	10	(221.9)	(151.7)
Net loss		(37.0)	(381.2)
Net loss attributable to:
Shareholders of the parent company		(17.0)	(337.8)
Non-controlling interests	25	(20.0)	(43.4)
		(37.0)	(381.2)
		\$	\$
Earnings per share	Notes	per share	per share
Basic	12	(0.05)	(1.02)
Diluted(a)	12	(0.05)	(1.02)
Adjusted diluted(a)	12	1.45	2.32

(a) For explanation and a reconciliation of diluted and Adjusted diluted earnings per share please refer to Note 12 'Earnings per share' to the Consolidated Financial Statements included.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the year ended (in \$ millions)	Notes	2015 31 Dec	2014 31 Dec
Net loss		(37.0)	(381.2)
Items that may be reclassified to the income statement in subsequent periods:
Foreign currency translation losses		(215.7)	(303.3)
Cash flow hedges:
Net fair value losses arising	33	(4.1)	(16.2)
Reclassification adjustments for amounts recognised in the Consolidated Income Statement	33	15.5	(9.6)
Adjustments for amounts transferred to the initial carrying amounts of hedged items	33	(0.1)	0.1
Share of other comprehensive income of associates and joint ventures	16	7.3	3.9
Tax relating to components of other comprehensive income which may be reclassified	10	21.3	42.3
Items that will not be reclassified to the income statement in subsequent periods:
Remeasurement gains/(losses) on defined benefit pension schemes	36	1.2	(3.5)
Tax relating to remeasurement (gains)/losses on defined benefit pension schemes	10	(0.3)	1.1
Other comprehensive loss		(174.9)	(285.2)
Total comprehensive loss		(211.9)	(666.4)
Total comprehensive loss attributable to:
Shareholders of the parent company		(209.2)	(626.6)
Non-controlling interests		(2.7)	(39.8)
		(211.9)	(666.4)

CONSOLIDATED BALANCE SHEET

As at (in \$ millions)	Notes	2015 31 Dec	2014 31 Dec
Assets
Non-current assets
Goodwill	13	766.8	1,322.3
Intangible assets	14	18.6	21.2
Property, plant and equipment	15	4,559.0	4,565.0
Interest in associates and joint ventures	16	368.5	373.8
Advances and receivables	17	100.7	128.3
Derivative financial instruments	33	4.4	3.8
Retirement benefits assets	36	0.8	–
Deferred tax assets	10	9.1	48.2
		5,827.9	6,462.6
Current assets
Inventories	18	46.1	59.1
Trade and other receivables	19	584.1	840.4
Derivative financial instruments	33	18.2	28.0
Assets classified as held for sale		0.6	–
Construction contracts – assets	21	278.1	378.4
Other accrued income and prepaid expenses	20	152.4	283.3
Cash and cash equivalents	22	946.8	572.6
		2,026.3	2,161.8
Total assets		7,854.2	8,624.4
Equity
Issued share capital	23	654.7	664.3
Treasury shares	24	(31.7)	(75.2)
Paid in surplus		3,223.0	3,255.5
Equity reserve	27	63.2	71.2
Translation reserve		(452.8)	(242.6)
Other reserves		(55.8)	(73.8)
Retained earnings		1,976.5	1,987.5
Equity attributable to shareholders of the parent company		5,377.1	5,586.9
Non-controlling interests	25	(30.9)	(25.2)
Total equity		5,346.2	5,561.7
Liabilities
Non-current liabilities
Non-current portion of borrowings	26	523.9	576.2
Retirement benefit obligations	36	13.3	21.3
Deferred tax liabilities	10	63.4	117.1
Provisions	30	47.0	30.3
Contingent liability recognised	31	4.0	6.0
Derivative financial instruments	33	9.4	15.3
Other non-current liabilities	28	73.1	93.3
		734.1	859.5
Current liabilities
Trade and other liabilities	29	1,123.5	1,674.1
Derivative financial instruments	33	12.2	25.1
Current tax liabilities		76.7	45.8
Current portion of borrowings	26	–	1.9
Provisions	30	92.6	28.9
Construction contracts – liabilities	21	458.9	425.7
Deferred revenue	37	10.0	1.7
		1,773.9	2,203.2
Total liabilities		2,508.0	3,062.7
Total equity and liabilities		7,854.2	8,624.4

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2015

(in \$ millions)	Issued share capital	Treasury shares	Paid in surplus	Equity reserves	Translation reserve	Other reserves	Retained earnings	Total	Non controlling interests	Total equity
Balance at 1 January 2015	664.3	(75.2)	3,255.5	71.2	(242.6)			(73.8) 1,987.5 5,586.9	(25.2)	5,561.7
Comprehensive loss
Net loss	–	–	–	–	–	–	(17.0)	(17.0)	(20.0)	(37.0)
Foreign currency translation (loss)/gain	–	–	–	–	(233.0)	–	–	(233.0)	17.3	(215.7)
Cash flow hedges	–	–	–	–	–	11.3	–	11.3	–	11.3
Share of other comprehensive income of associates and joint ventures	–	–	–	–	–	7.3	–	7.3	–	7.3
Remeasurement gains on defined benefit pension schemes	–	–	–	–	–	1.2	–	1.2	–	1.2
Tax relating to components of other comprehensive income	–	–	–	–	22.8	(1.8)	–	21.0	–	21.0
Total comprehensive loss	–	–	–	–	(210.2)	18.0	(17.0)	(209.2)	(2.7)	(211.9)
Transactions with owners
Shares repurchased	–	(7.6)	–	–	–	–	–	(7.6)	–	(7.6)
Dividends declared	–	–	–	–	–	–	–	–	(3.0)	(3.0)
Equity component of convertible bonds	–	–	–	(8.0)	–	–	7.5	(0.5)	–	(0.5)
Share-based payments	–	–	6.8	–	–	–	–	6.8	–	6.8
Vesting of share-based payments	–	–	1.6	–	–	–	(1.6)	–	–	–
Shares reissued relating to share-based
payments	–	0.6	–	–	–	–	–	0.6	–	0.6
Gain on reissuance of treasury shares	–	–	–	–	–	–	0.1	0.1	–	0.1
Shares cancelled	(9.6)	50.5	(40.9)	–	–	–	–	–	–	–
Total transactions with owners	(9.6)	43.5	(32.5)	(8.0)	–	–	6.0	(0.6)	(3.0)	(3.6)
Balance at 31 December 2015	654.7	(31.7)	3,223.0	63.2	(452.8)			(55.8) 1,976.5 5,377.1	(30.9)	5,346.2

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2014

	Issued								Non
(in \$ millions)	share capital	Treasury shares	Paid in surplus	Equity reserves	Translation reserve	Other reserves	Retained earnings	Total	controlling interests	Total equity
Balance at 1 January 2014	703.6	(356.9)	3,841.6	248.5	31.9	(59.5)	2,142.4	6,551.6	19.5	6,571.1
Comprehensive loss
Net loss	–	–	–	–	–	–	(337.8)	(337.8)	(43.4)	(381.2)
Foreign currency translation (loss)/gain	–	–	–	–	(306.9)	–	–	(306.9)	3.6	(303.3)
Cash flow hedges	–	–	–	–	–	(25.7)	–	(25.7)	–	(25.7)
Share of other comprehensive income of associates and joint ventures	–	–	–	–	–	3.9	–	3.9	–	3.9
Remeasurement losses on defined benefit pension schemes	–	–	–	–	–	(3.5)	–	(3.5)	–	(3.5)
Tax relating to components of other comprehensive income	–	–	–	–	32.4	11.0	–	43.4	–	43.4
Total comprehensive loss	–	–	–	–	(274.5)	(14.3)	(337.8)	(626.6)	(39.8)	(666.4)
Transactions with owners
Shares repurchased	–	(157.0)	–	–	–	–	–	(157.0)	–	(157.0)
Shares reissued to convertible noteholders	–	21.8	–	–	–	–	–	21.8	–	21.8
Dividends declared	–	–	(200.0)	–	–	–	–	(200.0)	(4.9)	(204.9)
Equity component of convertible bonds	–	–	–	(177.3)	–	–	177.3	–	–	–
Share-based payments	–	–	7.7	–	–	–	–	7.7	–	7.7
Vesting of share-based payments	–	–	(26.5)	–	–	–	26.5	–	–	–
Shares reissued relating to share based payments	–	14.1	–	–	–	–	–	14.1	–	14.1
Loss on reissuance of treasury shares	–	–	–	–	–	–	(20.9)	(20.9)	–	(20.9)
Tax effects	–	–	(3.8)	–	–	–	–	(3.8)	–	(3.8)
Shares cancelled	(39.3)	402.8	(363.5)	–	–	–	–	–	–	–
Total transactions with owners	(39.3)	281.7	(586.1)	(177.3)	–	–	182.9	(338.1)	(4.9)	(343.0)
Balance at 31 December 2014	664.3	(75.2)	3,255.5	71.2	(242.6)	(73.8)	1,987.5	5,586.9		(25.2) 5,561.7

CONSOLIDATED CASH FLOW STATEMENT

For the year ended (in \$ millions) Notes 31 Dec 31 Dec Net cash generated from operating activities 38 1,048.6 1,449.7 Cash flows from investing activities Proceeds from disposal of property, plant and equipment 4.0 1.3 Purchases of property, plant and equipment (639.2) (861.2) Purchases of intangible assets (5.5) (6.4) Loan repayments from joint venture 6.6 Interest received 16.7 19.3 Dividends received from associates and joint ventures 63.6 19.3 Investment in associates and joint ventures (0.2) (0.1) Net cash used in investing activities (554.0) (827.8) Cash flows from financing activities Interest paid (15.1) (24.3) Proceeds from borrowings 80.0 Repayments of borrowings (80.5) Cost of share repurchases 24 (165.7) (7.6)
Dividends paid to equity shareholders of the parent company 11 – (194.6)
Redemption of convertible bonds – (182.0)
Repurchase of convertible bonds (64.7) (154.9)
Proceeds from reissuance of treasury shares 0.7 1.3
Dividends paid to non-controlling interests (8.4)
Net cash used in financing activities (95.6) (720.2)
Net increase/(decrease) in cash and cash equivalents 399.0 (98.3)
Cash and cash equivalents at beginning of year 22 572.6 691.5
Effect of foreign exchange rate movements on cash and cash equivalents (24.8) (20.6)
Cash and cash equivalents at end of year 22 946.8 572.6

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 2015.

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. The Group also offers a full spectrum of products and capabilities to deliver full Life of Field services to its clients. Through its i-Tech Division, the Group provides remotely operated vehicles and tooling services to support exploration and production activities.

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 1 March 2016.

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. Foreign operations are included 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 2015.

The Consolidated Financial Statements have been prepared on the historical cost basis except for the revaluation of certain financial instruments. The principal accounting policies adopted are consistent with the Consolidated Financial Statements for the year ended 31 December 2014, 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 amended International Financial Reporting Standards (IFRS) and interpretations which were effective for the financial year beginning on 1 January 2015. These amended standards and interpretations did not have a significant impact on the Group's financial position or performance:

• Amendments to IAS 19 'Defined Benefit Plans: Employee Contributions'
• Annual Improvements 2010 2012 Cycle
• Annual Improvements 2011 2013 Cycle

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

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

IFRS 9 'Financial Instruments'

IFRS 9 is the International Accounting Standard Board's (IASB) replacement of IAS 39 'Financial Instruments: Recognition and Measurement' and applies to classification and measurement of financial assets and financial liabilities as defined in IAS 39.

The standard replaces the multiple classification and measurement models in IAS 39 'Financial Instruments: Recognition and Measurement' with a single model that has initially only two classification categories: amortised cost and fair value. IFRS 9 also contains new hedge accounting rules, which better align hedge accounting more closely with common risk management practices, and a new impairment model. In addition to changes to recognition and measurement criteria, IFRS 9 introduces expanded disclosure requirements and changes in presentation.

IFRS 9 is effective for annual periods beginning on or after 1 January 2018, subject to endorsement for EU entities, with early adoption permitted. The Group is in the process of fully evaluating the impact of the requirements of IFRS 9.

IFRS 15 'Revenue from Contracts with Customers'

IFRS 15 establishes a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. Upon its effective date, IFRS 15 will supersede all existing revenue standards and interpretations. In particular, the standard replaces IAS 18 'Revenue' and IAS 11 'Construction Contracts', upon which the Group's current revenue recognition policies are based.

IFRS 15 will only cover revenue arising from contracts with customers. Under IFRS 15, a customer of an entity is a party that has contracted with the entity to obtain goods or services that are an output of the entity's ordinary activities in exchange for consideration. The core principle of IFRS 15 is that an entity should recognise revenue to depict the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity is expected to be entitled in exchange for those goods and services. IFRS 15 is effective for reporting periods beginning on or after 1 January 2018, subject to endorsement for EU entities, with early adoption permitted. The disclosure requirements are more extensive and adoption is therefore expected to result in additional revenue related disclosures. The Group is in the process of fully evaluating the impact of the requirements of IFRS 15.

IFRS 16 'Leases'

IFRS 16 establishes new recognition, measurement and disclosure requirements for both parties to a lease contract. The standard eliminates the classification of a lease as either operating or finance 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 of use of the leased asset. These changes will result in significant changes to the accounting 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 increases in leased assets and corresponding financial liabilities. The income statement will also be impacted with operating lease expenses being replaced with interest and depreciation charges.

IFRS 16 is effective for reporting periods beginning on or after 1 January 2019, subject to endorsement for EU entities, with early adoption permitted provided that IFRS 15 has also been adopted. The adoption of this standard will result in a number of leases currently classified as operating leases being recognised on the balance sheet. Application of the revised model will have an impact on both the income statement and balance sheet. The Group is in the process of fully evaluating the impact of the requirements of IFRS 16.

Amendments to recognition of deferred tax assets for unrealised losses – Amendments to IAS 12

The amendments to IAS 12 'Income Taxes' clarify how to account for deferred tax assets related to debt instruments measured at fair value and provide guidance around which profits should be considered when determining available profits against which unrealised losses can be recovered. The amendments are effective for reporting periods beginning on or after 1 January 2017, subject to endorsement for EU entities. The Group is in the process of fully evaluating the impact of the amendments.

Clarification of acceptable methods of depreciation and amortisation – Amendments to IAS 16 and IAS 38

The amendments to IAS 16 'Property, Plant and Equipment' prohibit entities from using a revenue based depreciation method for items of property, plant and equipment. The amendments apply prospectively for annual periods beginning on or after 1 January 2016. The Group is evaluating the requirements to determine the effect these may have on its depreciation and amortisation policies.

Acquisition of Interests in Joint Operations – Amendments to IFRS 11

The amendments relate to where an entity acquires an interest in a joint operation which constitutes a business. Where an acquisition occurs the acquirer, to the extent of its share, must apply all of the principles of IFRS 3 'Business Combinations' and other IFRSs, provided they do not conflict with the requirements of IFRS 11 'Joint Arrangements'. Additionally, acquirers will be required to disclose business combination information required under relevant IFRSs. The amendments apply prospectively for annual periods beginning on or after 1 January 2016. The Group is evaluating the requirements to determine the effect these may have on its future acquisitions.

Equity Method in Separate Financial Statements – Amendments to IAS 27

The amendments to IAS 27 'Equity Method in Separate Financial Statements' will allow the Group's subsidiaries to use the equity method described in IAS 28 'Investments in Associates and Joint Ventures' to account for investments. The amendments apply prospectively for annual periods beginning on or after 1 January 2016. These amendments are not expected to have a material impact on the financial statement of subsidiaries of the Group.

Disclosure initiative – Amendments to IAS 1

The amendments to IAS 1 'Presentation of Financial Statements' are made in the context of the IASB's Disclosure Initiative, which explores how financial statement disclosures can be improved. The amendments are intended to assist entities in applying judgement when meeting the presentation and disclosure requirements in IFRS and provide clarification on a number of issues including materiality, disaggregation and subtotals, notes and the presentation of other comprehensive income arising from investments accounted for under the equity method. The amendments have been endorsed for EU entities and apply prospectively for annual periods beginning on or after 1 January 2016.

Annual improvements to IFRS 2012-2014 Cycle

The annual improvements project provides a mechanism for making necessary, but not urgent, amendments to IFRS. None of these amendments are expected to have a significant impact on the Group's financial position or performance.

There are no other IFRSs or interpretations which are not yet effective which would be expected to have a material impact on the Group's financial position, performance or disclosure obligations.

seabed-to-surface 45

3. Significant accounting policies

Basis of consolidation

The Consolidated Financial Statements incorporate the financial statements of 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 re-assesses 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 profit 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 about 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 of subsidiaries are identified separately from the Group's equity. Non-controlling interests consist of the amount of those interests at the date the Group obtains control over the subsidiary together with the non-controlling shareholders' share of net income or loss and share of other comprehensive income or loss since that date.

Investments in associates and joint ventures

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 venture is a commercial business governed by an agreement between two or more participants, giving them joint control over a business and rights to the net assets of the business.

Investments 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 the results of operations after tax 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. Net incomes and losses resulting from transactions between the Group and the associate or joint venture are eliminated to the extent of the Group's interest.

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/cost-plus contracts and similar contracts are recognised on an accrual basis as services are provided.

Long-term construction contracts

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.

The percentage-of-completion is calculated based on the ratio of costs incurred to date to total estimated costs. 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 those costs will be recoverable.

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. 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 the 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 loss provision recognised exceed progress billings, or as 'Construction contracts – liabilities' when progress billings exceed project revenues plus any full-life project loss provision recognised.

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 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 expensed 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 will be 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 net income or loss. 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 Dollars, 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 equity is reclassified to the Consolidated Income Statement.

3. Significant accounting policies continued

Foreign currency translation continued

At 31 December 2015, the exchange rates of the main currencies used throughout the Group, compared to the US Dollar, were as follows:

GBP 0.674 EUR 0.913 NOK 8.718 BRL 3.990

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 net income or loss 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 in the Consolidated Balance Sheet with a corresponding adjustment to equity through Other Comprehensive Income in the period in which they occur. 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 following changes in the net defined benefit obligation under both operating expenses and administration expenses in the Consolidated Income Statement:

• service costs comprising current service costs, past-service costs, gains and losses on curtailments and non-routine settlements
• net interest expense or income.

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

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 rates and tax laws 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 in net income or loss.

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 associates, and interests in 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 balance sheet 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 or the equity component of the Consolidated Balance Sheet, in which case the deferred tax is also dealt with in the Consolidated Statement of Comprehensive Income or the

equity component of the Consolidated Balance Sheet. 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 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 assets given, liabilities incurred or assumed, and equity instruments issued by the Group in exchange for control of the acquiree. 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 and liabilities or assets related to employee benefit arrangements are recognised and measured in accordance with IAS 12 'Income Taxes' and IAS 19 'Employee Benefits' respectively
• 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.

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 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 excess of the sum of the consideration transferred, the amount of any non-controlling interests in the acquiree and the fair value of the acquirer's previously held equity interest (if any) in the entity over the net of the acquisition date amounts of the identifiable assets acquired and the liabilities assumed. If, after reassessment, the Group's interest in the fair value of the acquiree's identifiable net assets exceeds the sum of the consideration transferred, the amount of any non-controlling interests in the acquiree and the fair value of the acquirer's previously held equity interest in the acquiree (if any), the excess is recognised immediately in the Consolidated Income Statement. Goodwill is not amortised but is reviewed for impairment at least annually.

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. 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 or the expected pattern of consumption of future economic benefits embodied in the assets 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 on an individual project as an internally generated intangible asset when it can demonstrate that it can meet the criteria for recognition specified in IAS 38 'Intangible Assets'.

Amortisation of the asset over the period of 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.

3. Significant accounting policies continued

Property, plant and equipment

Property, plant and equipment, including major 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 to be in 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 lives and methods of depreciation are reviewed at least annually and adjusted if appropriate.

The gains or losses arising on disposal of assets are determined as the difference between any disposal proceeds and the carrying amount of the asset. These are recognised in the Consolidated Income Statement in the period that the asset is disposed of.

Tendering costs

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

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 or cash-generating unit'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 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 those expense categories 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 value 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 cashgenerating units, or groups of cash-generating units, 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 cash-generating units, and a reallocation is justified, goodwill is reallocated based on relative value at the time of the change in composition. Following any reorganisation the cash-generating units 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 cash-generating unit (or group of cash-generating units), to which the goodwill relates. Recoverable amounts are determined based on value-in-use calculations using discounted pre-tax cash flow projections based on financial forecasts approved by the Executive Management Team.

The discount rate applied to the cash flow 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 cash-generating unit (or group of cash-generating units) is less than the carrying amount, an impairment charge is recognised in the Consolidated Income Statement.

Where goodwill forms part of a cash-generating unit (or group of cash-generating units) and part of the operation within that unit is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation. Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the cash-generating unit 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 value. The resultant impairment amount is recognised in the Consolidated Income Statement.

Inventories

Inventories comprise consumables, materials and 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.

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

All financial instruments are initially measured at cost plus 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 and interest rate swaps.

All derivative transactions are undertaken and maintained in order to manage the foreign currency and interest 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 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.

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 value 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 net income.

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 transferred to the Consolidated Income Statement.

Cash and cash equivalents

Cash and cash equivalents in the Consolidated Balance Sheet comprise cash at bank, cash on hand and short-term 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 fully 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.

3. Significant accounting policies continued

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 equity reserves within shareholders' equity. The carrying value 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 equity reserves to retained earnings.

Treasury shares

Treasury shares are the Group's own equity instruments which are reacquired 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 directly in the equity component of the Consolidated Balance Sheet. No gains or losses are recognised in the Consolidated Income Statement.

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.

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 a current pre-tax amount that reflects 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 of significant classes of provision:

Restructuring charges

The Group accounts for restructuring charges, including statutory 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.

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.

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 of the loss can be reliably estimated.

Other contingent liabilities are disclosed in the Notes to the Consolidated Financial Statements, but not recognised until they meet the criteria for recognition as a provision.

Share-based payments

Certain employees of the Group receive part of their remuneration in the form of share options and 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 Black-Scholes or Monte Carlo 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 fully entitled to the award (the vesting date). The cumulative expense recognised for equitysettled 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 share option using the share price on 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 computed using the weighted average number of common shares and common share equivalents outstanding during each period excluding treasury shares. The dilutive effect of outstanding options and performance shares is reflected as additional 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.

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

The Group accounts for long-term construction contracts, including engineering, procurement, installation and commissioning (EPIC) contracts, using the percentage-of-completion method, which is standard practice in the industry. Contract revenues and total cost estimates are reviewed by regional 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 method.

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 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 cost and revenue estimates. A key element of the PMSRs is the estimate of contingency. Contingency is an estimate of the cost required to cover identified future project risks. The Group uses a systematic approach in estimating contingency based on a risk register which identifies and assesses 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 these risks will be released from the full project cost estimates, throughout the remaining life of the project, as these risks are eliminated.

Revenue recognition on variation orders and claims

A major 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 commonly billed to clients.

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 approval is received from the client.

Allocation of goodwill to cash-generating units (CGUs)

Following the implementation of a new organisation structure management concluded that a change in the composition of CGUs was justified. Previously, with the exception of i-Tech, goodwill was monitored at a Territory level. Subsequent to the reorganisation, goodwill is reviewed at a management region level, with the exception of Africa and Global projects, Life of Field and i-Tech which are reviewed separately. Management regions are aggregated to form the Group's Business Units.

Goodwill was allocated to the lowest level at which individual financial position and performance is monitored for impairment purposes. The reallocation was effective from 1 January 2015 and was based on the relative values of the new CGUs. Relative value was determined by comparing the headroom of each CGU's forecast value-in-use in excess of its net assets. The estimates used in calculating value-in-use for each CGU are described in Note 13 'Goodwill'. The assumptions used were consistent with those applied as at 31 December 2014.

Goodwill carrying value

Goodwill is reviewed at least annually to assess whether there is objective evidence to indicate that the carrying value 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 are 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 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 value 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 belong, 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. In many cases 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. However, 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 the Group anticipates.

Furthermore, the Group is involved in legal proceedings from time to time 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 established.

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 benefit is required to settle the obligation. Management may also use its judgement to determine the amount of the obligation. Management uses external advisers to assist with some of these judgements. Further details relating to provisions and contingent liabilities can be found 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 10 'Taxation'.

5. Revenue

An analysis of the Group's revenue is as follows:

	2015 31 Dec	2014 31 Dec
For the year ended (in \$ millions)		Re-presented(a)
SURF	3,701.1	5,303.0
Conventional and Hook-up	406.1	705.0
Life of Field and i-Tech	650.9	861.9
Total revenue	4,758.1	6,869.9

(a) Re-presented due to the reorganisation of the reportable segments from 1 January 2015.

6. Segment information

Prior to 1 January 2015, the Group was organised into four Territories which were representative of its principal activities. With effect from 1 January 2015, the Group implemented a new organisational structure. The new organisation and segmental structure comprises two Business Units, which replaced four geographical Territories, and a Corporate segment.

The Corporate segment includes all activities that serve both Business Units. All onshore and offshore assets are allocated between the two Business Units. Reporting segments are defined below:

Northern Hemisphere and Life of Field

The Northern Hemisphere and Life of Field Business Unit includes activities in UK, Canada, Norway and the Gulf of Mexico together with the i-Tech division and Life of Field business line. It also includes spoolbases in Vigra, Norway and Leith, Scotland and a fabrication yard in Wick, Scotland. This segment also includes the Normand Oceanic and Eidesvik Seven joint ventures.

Southern Hemisphere and Global Projects

The Southern Hemisphere and Global Projects Business Unit includes activities in Africa, Asia Pacific and Middle East, Brazil and activities related to the performance of global projects managed within the Global Projects Centre in London and Paris. It also includes fabrication yards in Takoradi, Ghana; Warri, Nigeria; Port Gentil, Gabon and Lobito, Angola. This segment also includes the SapuraAcergy and Subsea 7 Malaysia joint ventures.

Corporate

This segment includes all activities that serve both Business Units and includes: management of offshore resources; captive insurance activities, operational support and corporate services. It also includes the results of the Seaway Heavy Lifting joint venture.

The accounting policies of the reportable segments were the same as the Group's accounting policies, which are described in Note 3 'Significant accounting policies'. There is a percentage of central costs applied 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) was 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 included.

Summarised financial information concerning each reportable business segment is as follows:

For the year ended 31 December 2015

(in \$ millions)	Northern Hemisphere and Life of Field	Southern Hemisphere and Global Projects	Corporate	Total
Selected financial information:
Revenue(a,b)	2,019.0	2,709.9	29.2	4,758.1
Operating expenses	(1,783.1)	(1,911.8)	(156.8)	(3,851.7)
Impairment of goodwill	(351.3)	(169.6)	–	(520.9)
Share of net income of associates and joint ventures	6.8	(3.5)	60.1	63.4
Depreciation, mobilisation and amortisation expenses	(113.6)	(216.8)	(85.3)	(415.7)
Impairment of property, plant and equipment	–	(8.0)	(128.5)	(136.5)
Reconciliation of net operating income to income before taxes:
Net operating income/(loss) excluding goodwill impairment	183.4	678.7	(197.4)	664.7
Net operating (loss)/income including goodwill impairment	(167.9)	509.1	(197.4)	143.8
Finance income				16.7
Other gains and losses				32.6
Finance costs				(8.2)
Income before taxes				184.9

(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 both Northern Hemisphere and Life of Field and Southern Hemisphere and Global Projects market segments, were as follows; Client A \$741.5 million (2014: \$1,176.3 million), Client B \$633.1 million (2014: \$949.4 million) and Client C \$456.0 million (2014: \$442.4 million).

For the year ended 31 December 2014

	Northern Hemisphere	Southern Hemisphere
(in \$ millions)	and Life of Field Re-presented(a)	and Global Projects Re-presented(a)	Corporate Re-presented(a)	Total Re-presented(a)
Selected financial information:
Revenue(b,c)	3,087.3	3,774.6	8.0	6,869.9
Operating expenses	(2,658.1)	(3,023.7)	(13.1)	5,694.9
Impairment of goodwill	(594.1)	(589.2)	–	(1,183.3)
Share of net income of associates and joint ventures	5.9	47.2	16.1	69.2
Depreciation, mobilisation and amortisation expenses	(102.0)	(229.2)	(89.3)	(420.5)
Impairment of property, plant and equipment	–	(9.4)	(79.4)	(88.8)
Reconciliation of net operating income to loss before taxes:
Net operating income/(loss) excluding goodwill impairment	340.9	674.7	(86.1)	929.5
Net operating (loss)/income including goodwill impairment	(253.2)	85.5	(86.1)	(253.8)
Finance income				19.3
Other gains and losses				23.7
Finance costs				(18.7)
Loss before taxes				(229.5)

(a) Re-presented due to the reorganisation of the reportable segments from 1 January 2015.

(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.

(c) Three clients in the year individually accounted for more than 10% of the Group's revenue. The revenue from these clients, attributable to both Northern Hemisphere and Life of Field and Southern Hemisphere and Global Projects market segments, were as follows; Client A \$1,176.3 million, Client D \$1,155.3 million and Client B \$949.4 million.

6. Segment information continued

Geographic information Revenues from external clients

The segmental information above shows revenues split by geographic location. This split is based on the location of the work performed which is determined from the country of registered office of the Group subsidiary or branch.

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
United Kingdom	1,736.0	2,377.2
Norway	557.9	1,090.9
Nigeria	512.7	651.8
France	364.9	429.6
United States of America	350.1	307.2
Australia	309.8	848.3
Brazil	262.6	360.2
Republic of Congo	188.5	68.1
Ghana	185.0	59.8
Angola	153.9	415.7
Other countries	136.7	261.1
	4,758.1	6,869.9

Non-current assets

Goodwill is allocated to cash-generating units (CGUs) rather than individual legal entities, therefore it is not possible to allocate it to individual countries. The allocation of goodwill to regions is shown in Note 13 'Goodwill'.

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:

As at (in \$ millions)	2015 31 Dec	2014 31 Dec
United Kingdom	3,800.8	3,270.2
Norway	430.5	420.2
Gibraltar	322.8	314.8
Angola	169.9	200.0
Cyprus	147.4	140.3
Isle of Man	35.5	103.5
Other countries	139.9	639.3
	5,046.8	5,088.3

7. Net operating income/(loss)

Net operating income/(loss) includes:

2015 For the year ended (in \$ millions) 31 Dec	2014 31 Dec
Research and development costs 22.5	19.5
Employee benefits (excluding termination expenses) 1,247.1	1,984.0
Restructuring – termination(a) 98.4	–
Restructuring – other(b) 37.7	–
Depreciation of property, plant and equipment (Note 15) 386.4	392.5
Amortisation of intangible assets (Note 14) 7.2	11.2
Mobilisation costs 22.1	16.8
Impairment of goodwill (Note 13) 520.9	1,183.3
Net impairment of property, plant and equipment (Note 15) 136.5	88.8
Auditor's remuneration 2.2	3.7

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

(b) Includes onerous lease charges and professional fees.

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

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Audit fees	1.4	1.3
Audit-related fees	–	0.1
Tax fees	0.7	0.8
Other fees	0.1	1.5
	2.2	3.7

Reconciliation of operating expenses and administrative expenses by nature

		31 Dec 2015			31 Dec 2014
For the year ended (in \$ millions)	Operating expenses	Administration expenses	Total expenses	Operating expenses	Administration expenses	Total expenses
Employee benefits (excluding termination
expenses)	1,078.0	169.1	1,247.1	1,789.8	194.2	1,984.0
Restructuring – termination(a)	83.8	14.6	98.4	–	–	–
Restructuring – other(b)	8.9	28.8	37.7	–	–	–
Depreciation, amortisation and mobilisation	393.1	22.6	415.7	399.2	21.3	420.5
Net impairment of property, plant and equipment	136.5	–	136.5	88.8	–	88.8
Other expenses	2,151.4	70.0	2,221.4	3,417.1	99.2	3,516.3
Total	3,851.7	305.1	4,156.8	5,694.9	314.7	6,009.6

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

(b) Includes onerous lease charges and professional fees.

8. Other gains and losses

	2015	2014
For the year ended (in \$ millions)	31 Dec	31 Dec Re-presented(a)
Losses on disposal of property, plant and equipment	(33.0)	(1.4)
Insurance income	30.6	–
Net gain on derivative financial instruments	1.3	1.1
Net gain on repurchase of convertible bonds	2.6	0.2
Net foreign currency exchange gains	31.1	23.8
Total	32.6	23.7

(a) 2014 comparatives have been re-presented to separately disclose net gain on convertible bonds.

Financials

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

9. Finance income and costs

	2015	2014
For the year ended (in \$ millions)	31 Dec	31 Dec
Interest income	16.7	19.3
Total finance income	16.7	19.3
	2015	2014
For the year ended (in \$ millions)	31 Dec	31 Dec
Interest and fees on borrowings	5.7	11.1
Interest on convertible bonds (Note 27)	20.4	29.8
Total borrowing costs	26.1	40.9
Less: amounts capitalised and included in the cost of qualifying assets	(20.4)	(18.9)
	5.7	22.0
Interest on tax liabilities	2.5	(3.3)
Total finance costs	8.2	18.7

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 (2014: between 3.5% and 3.6%).

10. Taxation

Tax recognised in the Consolidated Income Statement

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Tax charged/(credited) in the Consolidated Income Statement
Current tax:
Corporation tax on income for the year	242.9	184.8
Adjustments in respect of prior years	(8.4)	(9.8)
Total current tax	234.5	175.0
Deferred tax credit	(12.6)	(23.3)
Total	221.9	151.7
Tax recognised in the Consolidated Statement of Comprehensive Income
For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Tax credit relating to items recognised directly in comprehensive income
Current tax on:
Exchange differences	(22.8)	(32.4)
Income tax recognised directly in comprehensive income	(22.8)	(32.4)
Deferred tax on:
Net gains/(losses) on revaluation of cash flow hedges	1.5	(9.9)
Actuarial gains/(losses) on defined benefit pension plans	0.3	(1.1)
Deferred tax recognised directly in comprehensive income	1.8	(11.0)
Total	(21.0)	(43.4)
Deferred tax recognised in the Consolidated Statement of Changes in Equity
For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Share-based payments	–	3.6
Total	–	3.6

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 2015 for the purpose of the reconciliation of the total tax charge is 29.22% which corresponds to the blended tax rate applicable to Luxembourg entities (2014: 29.22%).

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Income/(loss) before taxes	184.9	(229.5)
Tax at the blended tax rate of 29.22% (2014: 29.22%)	54.0	(67.0)
Effects of:
Benefit of tonnage tax regimes	(11.2)	(29.1)
Different tax rates of subsidiaries operating in other jurisdictions	(48.5)	(125.6)
Movement in unprovided deferred tax(a)	437.8	76.0
Tax effect of share of net income of associates and joint ventures	(18.5)	(20.2)
Withholding taxes and unrelieved overseas taxes	46.6	40.9
Changes in tax rates	(2.4)	0.8
Other permanent differences	7.8	(6.6)
Goodwill impairment not deductible	152.2	311.6
Impairment of subsidiaries of the parent company(a)	(372.1)	–
Adjustments related to prior years	(23.8)	(29.1)
Tax charge in the Consolidated Income Statement	221.9	151.7

(a) The movement in unprovided deferred tax mainly related to net operating losses arising as a result of the impairments of direct subsidiaries of the parent company. Impairments arose primarily as a result of the reorganisation of a corporate structure.

Deferred tax

Movements in the net deferred tax balance were:

(in \$ millions)	2015	2014
At year beginning	(68.9)	(121.3)
Credited/(charged) to:
Consolidated Income Statement	12.6	23.3
Consolidated Statement of Comprehensive Income	(1.8)	11.0
Consolidated Statement of Changes in Equity	–	(3.6)
Transfer to current tax	0.6	18.0
Exchange differences	3.2	3.7
At year end	(54.3)	(68.9)

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:

As at 31 December 2015

Total	34.3	(88.6)	(54.3)
Other	24.0	(13.5)	10.5
Tax losses	5.3	–	5.3
Share-based payments	0.2	–	0.2
Accrued expenses	4.6	–	4.6
Property, plant and equipment	0.2	(75.1)	(74.9)
(in \$ millions)	Deferred tax asset	Deferred tax liability	Net recognised deferred tax asset/(liability)

10. Taxation continued

As at 31 December 2014

– 26.9	(16.3) –	0.2 (16.3) 26.9
3.9	–	3.9
45.7	(114.6)	(68.9)
	Deferred tax asset 4.1 10.6 0.2	Deferred tax liability (86.7) (11.6) –

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

As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Deferred tax assets	9.1	48.2
Deferred tax liabilities	(63.4)	(117.1)
Total	(54.3)	(68.9)

At the balance sheet date, the Group had tax losses of \$1,811.2 million (2014: \$535.3 million) available for offset against future taxable profits. A deferred tax asset has been recognised in respect of \$22.6 million (2014: \$88.6 million) of such losses. No deferred tax asset has been recognised in respect of the remaining \$1,788.6 million (2014: \$446.7 million) as it is not considered probable that there will be sufficient future taxable profits available for offset. In addition, the Group has other unrecognised deferred tax assets of approximately \$55.6 million (2014: \$162.6 million) in respect of deferred project expenditure and 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 associates and interests in joint ventures 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 2015 was \$1,031.8 million (2014: \$1,146.2 million).

Tonnage tax regime

The tax charge reflected a net benefit in the year of \$11.2 million (2014: \$29.1 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)	2015 31 Dec	2014 31 Dec
Within five years	35.7	33.7
5 to 10 years	144.8	190.0
11 to 20 years	125.0	73.1
Without time limit	1,505.7	238.5
Total	1,811.2	535.3

There were \$136.3 million NOLs included in the above relating to Brazil on which no deferred tax asset was recognised by the Group at 31 December 2015 (2014: \$112.2 million).

Included in the above were \$1,351.6 million (2014: \$84.8 million) of losses relating to Luxembourg, which could be subject to future claw-back if certain transactions were entered into. The loss significantly increased during the year as a result of the impairment of investments in direct subsidiaries held by Subsea 7 S.A. following a corporate reorganisation.

Tax contingencies and provisions

Business operations are carried out in several countries, through subsidiaries and branches of subsidiaries, and the Group is subject to the jurisdiction of a significant number of tax authorities. Furthermore, the mobile 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 similar 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 often leads to uncertainty on tax positions.

In 2015, operations in various countries were subject to enquiries, audits and disputes, including, but not limited to, those in Brazil, Angola, Gabon, Canada, Nigeria, the US and Norway. These audits are at various stages of completion. The Group's policy is to co-operate fully with the relevant tax authorities while seeking to defend its tax positions.

In the year, the Group recorded a net tax increase in respect of its tax provisions of \$3.6 million (2014: \$34.1 million release) as a result of revised future potential exposures and 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.

11. Dividends

No dividends were paid in 2015 related to the year ended 31 December 2014. In 2014 a dividend related to the year ended 31 December 2013 of \$194.6 million, representing NOK 3.60 per common share, was paid.

12. 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 is adjusted to eliminate the interest expense (net of 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 loss and share data used in the basic and diluted earnings per share calculations were as follows:

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Net loss attributable to shareholders of the parent company	(17.0)	(337.8)
Earnings used in the calculation of diluted earnings per share	(17.0)	(337.8)
For the year ended	2015 31 Dec Number of shares	2014 31 Dec Number of shares
Weighted average number of common shares used in the calculation of basic earnings per share	325,768,171	330,784,021
Convertible bonds	–	–
Share options and performance shares	–	–
Weighted average number of common shares used in the calculation of diluted earnings per share	325,768,171	330,784,021
For the year ended (in \$ per share)	2015 31 Dec	2014 31 Dec
Basic earnings per share	(0.05)	(1.02)
Diluted earnings per share	(0.05)	(1.02)

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:

	2015	2014
	31 Dec	31 Dec
	Number of	Number of
For the year ended	shares	shares
Convertible bonds	21,216,925	37,333,844
Share options and performance shares	2,417,260	2,844,471

12. Earnings per share continued

Adjusted diluted earnings per share

Adjusted diluted earnings per share represents diluted earnings per share excluding the goodwill impairment charge of \$520.9 million (2014: \$1,183.3 million). The loss and share data used in the calculation of Adjusted diluted earnings per share were as follows:

Net loss attributable to shareholders of the parent company (17.0) (337.8) Impairment of goodwill 520.9 1,183.3 Interest on convertible bonds (net of amounts capitalised) – 10.9 Earnings used in the calculation of Adjusted diluted earnings per share 503.9 856.4 2015 2014 31 Dec 31 Dec Number of Number of For the year ended shares shares Weighted average number of common shares used in the calculation of basic earnings per share 325,768,171 330,784,021 Convertible bonds 21,216,925 37,333,844 Share options and performance shares 80,820 892,643 Weighted average number of common shares used in the calculation of Adjusted diluted earnings per share 347,065,916 369,010,508 2015 2014 For the year ended (in \$ per share) 31 Dec 31 Dec Adjusted diluted earnings per share 1.45 2.32 13. Goodwill The movement in goodwill during the year was as follows: (in \$ millions) Total Cost At 1 January 2014 2,584.6 Exchange differences (89.8) At 31 December 2014 2,494.8 Exchange differences (89.1) At 31 December 2015 2,405.7 Accumulated impairment At 1 January 2014 – Impairment charge 1,183.3 Exchange differences (10.8) At 31 December 2014 1,172.5 Impairment charge 520.9 Exchange differences (54.5) At 31 December 2015 1,638.9	For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec

Carrying amount

At 31 December 2014	1,322.3
At 31 December 2015	766.8

With effect from 1 January 2015, following the implementation of a new organisation structure, management concluded that a change in the composition of cash-generating units (CGUs) had occurred and a reallocation of goodwill was required. For financial management and reporting purposes the Group is organised into management regions. Management regions are aligned with the two Business Units and the Corporate segment used by the CODM to allocate resources and appraise performance. Following the reorganisation there are eight CGUs.

• CGUs for APME, Brazil, GOM, Norway and UK and Canada include activities connected with the performance of projects in those management regions.
• Africa and Global Projects CGU includes activities in Africa and activities related to the performance of global projects managed within the Global Project Centres located in London and Paris.
• i-Tech CGU includes activities connected with the provision of remotely operated vehicles and tooling services.
• Life of Field CGU includes activities connected with the provision of non-UK Life of Field services.

Goodwill was reallocated as at 1 January 2015 based on the relative values of each CGU. Relative value was calculated as value-in-use less net assets of each CGU. The assumptions used in estimating value-in-use were consistent with those applied as at 31 December 2014. Comparative financial information for 2014 has been re-presented to reflect the revised CGUs.

The carrying amounts of goodwill allocated to the CGUs subsequent to the impairment charges were as follows:

	2015	2014
	31 Dec	31 Dec
As at (in \$ millions)		Re-presented(a)
Africa and Global Projects	427.7	441.6
APME	91.0	260.7
GOM	–	57.8
i-Tech	68.0	69.8
Norway	105.2	156.0
UK and Canada	74.9	336.4
Total	766.8	1,322.3

(a) Re-presented due to the reallocation of goodwill to new CGUs following the business reorganisation on 1 January 2015.

The Group performed its annual impairment test as at 31 December 2015.

The recoverable amounts of the CGUs were determined based on a value-in-use calculation using pre-tax cash flow projections approved by the Executive Management Team covering a five-year period. Cash flows beyond this five-year period were extrapolated in perpetuity, using a 2.0% (2014: 2.0%) growth rate to determine the terminal value. The pre-tax discount rate applied to cash flow projections was 11.1% (2014: 11.8%).

Following the annual impairment review, the impairment charge in respect of goodwill recognised in the Consolidated Income Statement for the year ended 31 December 2015 was as follows:

	2015 31 Dec	2014 31 Dec
For the year ended (in \$ millions)		Re-presented(a)
Africa and Global Projects	–	306.1
APME	169.6	–
Brazil	–	283.1
GOM	55.2	58.3
Norway	46.9	171.4
UK and Canada	249.2	364.4
Total	520.9	1,183.3

Impairments relating to UK and Canada, GOM and Norway CGUs are reported within the Northern Hemisphere and Life of Field operating segment. The impairment relating to APME CGU is reported within Southern Hemisphere and Global Projects operating segment.

As at 31 December and, following the recognition of impairments, the recoverable amounts relating to UK and Canada, GOM, Norway and APME CGUs were \$687.2 million, \$228.9 million, \$325.8 million and \$177.2 million respectively.

Decreases in the recoverable amounts related to the CGUs arose as a result of the challenging business environment and updated estimates of the anticipated impact of low oil prices in the short to medium term. Low oil prices combined with declining levels of project awards and project profitability are expected to impact negatively on the projected levels of investment and activity in the oil and gas sector in the short to medium term.

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 rates; 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 and asset utilisation. Assumptions are based on a combination of internal and external studies, management judgement and historical information, adjusted for any foreseen changes in market conditions.

Discount rates – 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. Country risk premiums were not applied to the discount rates as the cash flows were risk adjusted.

Growth rate estimates – The 2.0% (2014: 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.

13. Goodwill continued

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 have been 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 carrying amount of the CGUs for Africa and Global Projects or i-Tech to materially exceed its recoverable amount and hence no goodwill impairment charge was recognised.

CGUs where goodwill has been impaired

Following the recognition of the impairment charges, the carrying values of the Group's operations in APME, Norway and UK and Canada are equal to their estimated recoverable amounts, consequently any future adverse changes in the key assumptions in isolation may result in further impairment charges being recognised against goodwill.

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

Changes to key assumptions used in the impairment review would, in isolation, lead to an (increase)/decrease in the aggregate goodwill impairment charge recognised in the year ended 31 December 2015 as follows:

(in \$ millions)	APME	Norway	UK and Canada
Pre-tax discount rate
Increase by 1 percentage point	(35.0)	(40.9)	(72.5)
Decrease by 1 percentage point	44.3	46.9	94.1
Long-term growth rate
Increase by 1 percentage point	32.4	35.7	65.9
Decrease by 1 percentage point	(26.1)	(28.7)	(52.9)
EBITDA upon which terminal values have been calculated
Decrease by 5 percent	(16.9)	(17.6)	(31.1)
Increase by 5 percent	16.9	17.6	31.1

14. Intangible assets

(in \$ millions)	Software	Customer contracts (Backlog)	Developed technology	Other intangibles	Total
Cost
At 1 January 2014	30.6	32.5	13.2	6.4	82.7
Additions	6.4	–	–	–	6.4
Disposals	–	(32.5)	–	–	(32.5)
Exchange differences	(1.7)	–	(0.6)	(0.1)	(2.4)
At 31 December 2014	35.3	–	12.6	6.3	54.2
Additions	5.5	–	–	–	5.5
Disposals	(2.2)	–	(12.3)	–	(14.5)
Exchange differences	(1.2)	–	(0.3)	(0.6)	(2.1)
At 31 December 2015	37.4	–	–	5.7	43.1
Amortisation
At 1 January 2014	15.4	29.4	8.0	3.1	55.9
Charge for the year	5.2	3.1	2.7	0.2	11.2
Disposals	–	(32.5)	–	–	(32.5)
Exchange differences	(1.1)	–	(0.5)	–	(1.6)
At 31 December 2014	19.5	–	10.2	3.3	33.0
Charge for the year	4.4	–	2.5	0.3	7.2
Disposals	(2.2)	–	(12.3)	–	(14.5)
Exchange differences	(1.1)	–	(0.4)	0.3	(1.2)
At 31 December 2015	20.6	–	–	3.9	24.5
Carrying amount:
At 31 December 2014	15.8	–	2.4	3.0	21.2
At 31 December 2015	16.8	–	–	1.8	18.6

Included in the table above is software under development of \$2.9 million (2014: \$3.1 million).

15. Property, plant and equipment

(in \$ millions)	Vessels	Operating equipment	Land and buildings	Other assets	Total
Cost
At 1 January 2014 – re-stated(a)	4,811.2	441.4	459.0	102.2	5,813.8
Additions	696.2	94.3	79.1	8.1	877.7
Exchange differences	(101.3)	(9.1)	(33.2)	(6.5)	(150.1)
Disposals	(72.2)	–	0.2	(13.0)	(85.0)
At 31 December 2014 – re-stated(a)	5,333.9	526.6	505.1	90.8	6,456.4
Additions	539.9	72.9	47.9	9.8	670.5
Exchange differences	(83.0)	(24.3)	(43.0)	(6.0)	(156.3)
Reclassified as held for sale	–	–	(1.1)	–	(1.1)
Disposals	(320.4)	(11.3)	(2.8)	(4.3)	(338.8)
Transfer(b)	(276.9)	285.6	–	(8.7)	–
At 31 December 2015	5,193.5	849.5	506.1	81.6	6,630.7
Accumulated depreciation and impairment At 1 January 2014 Charge for the year Impairment – re-stated(a) Exchange differences	1,222.4 296.9 65.9 (22.0)	130.9 54.5 13.6 0.4	87.6 26.2 9.3 (4.4)	65.8 14.9 –	1,506.7 392.5 88.8
				(4.6)	(30.6)
Eliminated on disposals	(53.0)	–	–	(13.0)	(66.0)
At 31 December 2014 – re-stated(a)	1,510.2	199.4	118.7	63.1	1,891.4
Charge for the year	279.4	63.0	26.7	17.3	386.4
Impairment	125.2	3.3	8.0	–	136.5
Exchange differences Reclassified as held for sale	(24.1) –	(5.7) –	(6.4) (0.5)	(4.0) –	(40.2) (0.5)
Eliminated on disposals	(284.8)	(10.7)	(2.1)	(4.3)	(301.9)
Transfer(b)	(187.0)	194.6	–	(7.6)	–

Carrying amount:

(a) 2014 comparatives have been re-stated to amend an incorrect classification of an asset under construction and an associated impairment. The re-statements result in a \$32.7million decrease in the net book value of operating equipment and a \$32.7million increase in the net book value of land and buildings as at 31 December 2014.

(b) During 2015, equipment and ancillary assets previously allocated to vessels were reallocated from vessel to operating equipment and other assets. The transfer was undertaken at net book value.

The table above includes assets under construction of \$1,033.0 million (2014: \$955.9 million) including Seven Kestrel, Seven Arctic and the new-build PLSVs, Seven Sun and Seven Cruzeiro, linked to long-term contracts with Petrobras.

An impairment review was performed at 31 December 2015. A decline in expectations for future oil and gas prices, which in the near term are expected to negatively impact the projected levels of investment and growth in the oil and gas sector, have adversely impacted both current market valuations and expected future utilisation of specific vessels.

Following a detailed assessment, impairment charges have been recognised to reduce the net book values of certain vessels to their estimated recoverable amount defined as fair value less costs of disposal.

Fair value was estimated in line with Level 2 of the 'fair value hierarchy' contained within IFRS 13 'Fair Value Measurement'. Fair value was determined by management and 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.

\$39.5 million (2014: \$43.5 million) impairment was recognised in respect of Seven Polaris before its disposal.

\$85.7 million (2014: \$22.4 million) impairment was recognised in respect of six vessels. Impairment charges were recognised in the Consolidated Income Statement in operating expenses within the Corporate segment.

\$11.3 million (2014: \$22.9 million) was recognised in respect of operating equipment and land and buildings where the future recoverable amounts were reassessed and reduced.

During the year, \$32.5 million of damaged vessel components were disposed with associated insurance income of \$30.5 million recognised.

16. Interest in associates and joint ventures

The Group has interests in two associates and eight joint ventures which are all accounted for using the equity method.

		Year End Country of Registration	Operating segment	Classification	Subsea 7 ownership %
Deep Seas Insurance(a)	31 December	Cayman Islands	Corporate	Associate	49
Global Oceon	31 December	Nigeria	Southern Hemisphere and Global Projects	Associate	40
Eidesvik Seven	31 December	Norway	Northern Hemisphere and Life of Field	Joint Venture	50
ENMAR	31 December	Mozambique	Southern Hemisphere and Global Projects	Joint Venture	51
Normand Oceanic	31 December	Norway	Northern Hemisphere and Life of Field	Joint Venture	50
SapuraAcergy(b)	31 January	Malaysia	Southern Hemisphere and Global Projects	Joint Venture	50
Seaway Heavy Lifting	31 December	Cyprus	Corporate	Joint Venture	50
SIMAR	31 December	Angola	Southern Hemisphere and Global Projects	Joint Venture	49
Subsea 7 Malaysia	31 December	Malaysia	Southern Hemisphere and Global Projects	Joint Venture	30
Belmet 7	31 December	Ghana	Southern Hemisphere and Global Projects	Joint Venture	49

(a) The remaining 51% ownership of Deep Seas Insurance is held by Siem Industries Inc., a related party as described in Note 34 'Related party transactions'.

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

For all entities, with the exception of Seaway Heavy Lifting, which has a principal place of business in the Netherlands, 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 investments in associates and joint ventures are accounted for using the equity method. Financial information for the year ended 31 December 2015 is used for all entities. The movement in the balance of equity investments, including long-term advances, was as follows:

For the year (in \$ millions)	2015	2014
At year beginning	373.8	310.7
Share of net income and losses of associates and joint ventures	63.4	69.2
Dividends received by the Group	(65.2)	(0.5)
Increase in investment	0.2	0.1
Net reversal of reclassification of negative investment balance as liabilities	(0.5)	(0.3)
Share of other comprehensive income of associates and joint ventures	7.3	3.9
Exchange differences	(10.5)	(9.3)
At year end	368.5	373.8

Summarised financial information

The tables below provide summarised financial information for those associates and joint ventures which are determined to be material to the Group. The amounts reflect the Group's contractual entitlement and include amounts reported in the respective entity's financial statements, IFRS adjustments where the financial statements are not prepared in accordance with IFRS and adjustments made when using the equity method. All amounts are presented before the elimination of transactions with other Group undertakings.

SapuraAcergy

The Group holds a 50% interest in SapuraAcergy which is an engineering and construction contractor providing planning, design and delivery of integrated offshore oil and gas development projects in the Asia Pacific region. The entity complements the core products and service offerings of the Group.

During 2015, the Group recognised dividends of \$33.5 million (2014: \$12.5 million) from SapuraAcergy.

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Selected financial information:
Revenue	165.8	161.8
Other expenses	(125.5)	(32.4)
Depreciation and amortisation	(17.2)	(16.6)
Finance expense	(1.8)	(7.1)
Income before tax	21.3	105.7
Taxation	(10.7)	(22.7)
Income after tax	10.6	83.0
Other comprehensive income	0.5	4.2
Total comprehensive income	11.1	87.2
Group's share of income for the year	5.6	43.6
As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Selected financial information:
Non-current assets	182.2	195.5
Non-current liabilities	–	(0.5)
Non-current financial liabilities (excluding trade and other payables and provisions)	–	(0.5)
Current assets	180.0	343.1
Cash and cash equivalents (as included in current assets above)	94.6	201.0
Current liabilities	(120.2)	(240.4)
Equity	242.0	297.8
Group's share of equity	121.0	148.9
Reconciliation to carrying amount
Investment	1.8	1.8
Group's carrying amount of the investment	122.8	150.7

Significant restrictions

SapuraAcergy is regulated by the Central Bank of Malaysia in respect of the repatriation of funds. Dividends are restricted to 70% of net income in the year to which the dividend relates.

Guarantee arrangements

Details of facilities and guarantees are contained in Note 26 'Borrowings'.

Seaway Heavy Lifting

The Group holds a 50% interest in Seaway Heavy Lifting which is a leading offshore contractor to the global oil and gas and renewables industries offering transportation, installation and EPIC solutions. The entity complements the core products and services offerings of the Group.

During 2015, the Group recognised dividends of \$20.0 million (2014: \$18.7 million of dividends previously recognised were cancelled).

2015	2014
	31 Dec
490.7	292.2
(317.0)	(205.2)
(37.2)	(43.8)
(10.3)	(13.5)
126.2	29.7
(5.2)	1.4
121.0	31.1
8.7	(0.8)
129.7	30.3
64.9	15.2
	31 Dec

16. Interest in associates and joint ventures continued

	2015	2014
As at (in \$ millions)	31 Dec	31 Dec
Selected financial information:
Non-current assets	546.7	558.9
Non-current liabilities	(189.5)	(242.7)
Non-current financial liabilities (excluding trade and other payables and provisions)	(189.5)	(242.7)
Current assets	217.0	131.8
Cash and cash equivalents (as included in current assets above)	158.0	76.9
Current liabilities	(160.7)	(124.7)
Equity	413.5	321.6
Group's share of equity	206.8	160.8
Group's carrying amount of the investment	206.8	160.8

Significant restrictions

Dividend payments from Seaway Heavy Lifting are restricted to 75% of net income of the previous year.

Individually immaterial associates and joint ventures

The carrying amount of the Group's interests in individually immaterial associates and joint ventures at 31 December 2015 was \$38.9 million (2014: \$62.3 million).

Summarised aggregated financial information for the Group's interests in associates and joint ventures which are individually immaterial is shown below. Amounts disclosed represent the aggregate of the Group's share in individual associates and joint ventures. Amounts are presented before the elimination of transactions with other Group undertakings.

	Interest in associates		Interest in joint ventures
For the year (in \$ millions)	2015	2014	2015	2014
Summarised financial information
Aggregated (loss)/income	(0.6)	1.9	(1.8)	10.2
Aggregated other comprehensive income	0.2	–	2.4	2.2
Total comprehensive (loss)/income	(0.4)	1.9	0.6	12.4
17. Advances and receivables
As at (in \$ millions)			2015 31 Dec	2014 31 Dec
Non-current amounts due from associates and joint ventures			71.4	90.5
Capitalised fees for long-term loan facilities			3.7	1.7
Deposits held by third parties			1.1	1.2
Other receivables			24.5	34.9
Total			100.7	128.3
18. Inventories
As at (in \$ millions)			2015 31 Dec	2014 31 Dec
Materials and spares			21.6	29.4
Consumables			24.5	29.7
Total			46.1	59.1
For the year ended (in \$ millions)			2015 31 Dec	2014 31 Dec
Total cost of inventory charged to the Consolidated Income Statement			67.0	151.8
Write-down of inventories charged to the Consolidated Income Statement			6.9	1.0
Reversal of provision for obsolescence credited to the Consolidated Income Statement			(0.6)	–

Inventories include a provision for obsolescence as at 31 December 2015 of \$7.2 million (2014: \$2.9 million). There were no inventories pledged as security.

19. Trade and other receivables

2014 31 Dec
552.6
(10.2)
542.4
5.9
46.7
182.6
7.4
55.4
840.4

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.

20. Other accrued income and prepaid expenses

As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Unbilled revenue	107.1	181.5
Prepaid expenses	45.3	101.8
Total	152.4	283.3

Unbilled revenue related to work completed on day-rate contracts, which had not been billed to clients as 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 the next twelve months.

21. Construction contracts

	2015	2014
As at (in \$ millions)	31 Dec	31 Dec
Contracts in progress
Construction contracts – assets	278.1	378.4
Construction contracts – liabilities	(458.9)	(425.7)
Total	(180.8)	(47.3)
Contract costs incurred plus recognised net profits less recognised losses to date	8,794.2	9,986.3
Less: progress billings	(8,975.0)	(10,033.6)
Total	(180.8)	(47.3)

Revenue from construction contracts in the year was \$3.5 billion (2014: \$5.3 billion).

22. Cash and cash equivalents

Cash and cash equivalents 946.8	572.6
2015 As at (in \$ millions) 31 Dec	2014 31 Dec

Cash and cash equivalents included funds totalling \$82.0 million (2014: \$194.4 million) held by Group undertakings in certain countries whose exchange controls significantly restrict or delay the remittance of these funds to foreign jurisdictions.

23. Issued share capital

	2015 31 Dec	2015	2014 31 Dec	2014
As at	Number of shares	31 Dec in \$ millions	Number of shares	31 Dec in \$ millions
Authorised common shares, \$2.00 par value	450,000,000	900.0	430,373,336	860.7
Issued shares	2015		2014
As at	31 Dec Number of shares	2015 31 Dec in \$ millions	31 Dec Number of shares	2014 31 Dec in \$ millions
Fully paid and issued common shares	327,367,111	654.7	332,167,067	664.3
The issued common shares consist of:
Common shares excluding treasury shares	325,643,852	651.3	326,368,007	652.7
Treasury shares at par value (Note 24)	1,723,259	3.4	5,799,060	11.6
Total	327,367,111	654.7	332,167,067	664.3

Authorised share capital

An Extraordinary General Meeting of shareholders took place on 17 April 2015. The sole resolution passed was in relation to the renewal and extension of the authorised share capital of the Company to \$900 million, represented by 450 million common shares with a par value of \$2.00 per share. The resolution also inter alia delegated authority to the Board of Directors to issue shares.

Cancellation of shares

On 30 September 2015, in accordance with the delegation of authority given to the Board of Directors at the Extraordinary General Meeting of shareholders on 27 November 2014, 4,799,956 common shares held in treasury were cancelled. As a result, the issued share capital of the Company was reduced by \$9,599,912.

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, which allows for the purchase of up to a maximum of 10% of the Group's issued share capital, net of purchases already made. During 2015, the Group repurchased 815,578 (2014: 4,457,078) shares for a total consideration of \$7.6 million (2014: \$49.5 million). Cumulatively 5,272,656 shares have been repurchased under the July 2014 repurchase programme for a total consideration of \$57.1 million.

On 28 July 2015, the Board of Directors authorised a 24 month extension to the Group's 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 Extraordinary General Meeting held on 27 November 2014, which allows for the purchase of up to a maximum of 10% of the Group's issued common shares, net of common shares previously repurchased and held as treasury shares.

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. The repurchased shares were held as treasury shares.

At the Extraordinary General Meeting of shareholders on 27 November 2014 the Board of Directors was authorised to cancel any shares repurchased, up to a maximum of 33,216,706 common shares, until 26 May 2020 and to reduce the issued share capital through such cancellations.

On 30 September 2015, in accordance with the delegation of authority given to the Board of Directors at the Extraordinary General Meeting of shareholders on 27 November 2014, 4,799,956 shares held in treasury were cancelled, thereby reducing the number of shares held as treasury shares to 1,723,259. Subsequent to the cancellation the Board of Directors is authorised to cancel a further 28,416,750 repurchased common shares.

Summary

Movements in treasury shares are shown in the table below:

Balance at year end	1,723,259	31.7	5,799,060	75.2
Shares reissued relating to share-based payments	(91,423)	(0.6)	(588,272)	(14.1)
Shares cancelled	(4,799,956)	(50.5)	(19,626,664)	(402.8)
Shares repurchased	815,578	7.6	10,517,017	157.0
Shares reissued to convertible bondholders/noteholders (Note 27)	–	–	(907,104)	(21.8)
At year beginning	5,799,060	75.2	16,404,083	356.9
	Number of shares	2015 in \$ millions	Number of shares	2014 in \$ millions
	2015		2014

Consisting of:

As at	2015 31 Dec Number of shares	2014 31 Dec Number of shares
Common shares held as treasury shares by Subsea 7 S.A.	31,683	4,019,378
Common shares held as treasury shares by employee benefit trusts	1,691,576	1,779,682
Total	1,723,259	5,799,060

At 31 December 2015, the Group directly held 31,683 (2014: 4,019,378) treasury shares amounting to 0.01% (2014: 1.2%) of the total number of issued shares. A further 1,441,200 (2014: 1,526,200) common shares were held by an employee benefit trust to satisfy performance shares under the Group's 2009 Long-term Incentive Plan and 250,376 (2014: 253,482) shares were held in a separate employee benefit trust to support specified share option awards.

25. Non-controlling interests

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

	Year End	Country of Registration	Subsea 7 ownership %
Sonamet	31 December	Angola	55.0
Sonacergy	31 December	Angola	55.0
Setemares	31 December	Angola	49.0
Globestar Engineering Company	31 December	Nigeria	98.8
Subsea 7 Mexico	31 December	Mexico	52.0
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
Nigerstar7 Limited	31 December	Nigeria	49.0
Nigerstar7 FZE	31 December	Nigeria	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 consolidated into the Group financial statements is based on financial information of the entity for the year ended 31 December 2015.

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

(in \$ millions)	2015	2014
At year beginning	(25.2)	19.5
Share of net loss for the year	(20.0)	(43.4)
Dividends	(3.0)	(4.9)
Exchange differences	17.3	3.6
At year end	(30.9)	(25.2)

Summarised financial information for non-wholly owned subsidiaries which have non-controlling interests that are material to the reporting entity is shown below. All amounts are presented before the elimination of transactions with other Group undertakings.

25. Non-controlling interests continued

Subsea 7 Mexico

The Group controls interests in three Mexican subsidiaries: Subsea 7 Mexico (52% ownership), Servicios Subsea 7 (52% ownership) and Naviera Subsea 7 (49% ownership). These entities are closely related and therefore combined financial data, excluding any transactions and balances between the three Mexican entities, has been disclosed below. No dividends were paid to non-controlling interests during 2015 or 2014.

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Revenue	(11.2)	91.9
Net loss	(72.4)	(136.0)
Total comprehensive loss	(72.4)	(136.0)
Attributable to non-controlling interests	(34.9)	(65.4)
For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Net cash flows used in operating activities	(15.7)	(93.1)
Net cash flows used in financing activities	(4.7)	58.8
Net decrease in cash and cash equivalents	(20.4)	(34.3)
As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Non-current assets	–	0.1
Current assets	175.3	284.9
Non-current liabilities	(69.9)	(1.3)
Current liabilities	(319.5)	(457.0)
Net liabilities	(214.1)	(173.3)
Total equity	(214.1)	(173.3)
Attributable to non-controlling interests	(103.2)	(83.3)

At 31 December 2015, Subsea 7 Mexico had net liabilities of \$214.1 million (2014: \$173.3 million). Subsea 7 Mexico had three interest bearing loans outstanding to the Group totalling \$163.3 million (2014: \$163.3 million) including a term loan of \$160 million. Interest charged varies by loan and ranges from 2.2% to 7.8% per annum. \$76.8 million (representing 48% of the \$160 million term loan) is guaranteed by the shareholder of the non-controlling interest. In addition, Subsea 7 Mexico owed \$76.1 million (2014: \$86.8 million) to certain wholly-owned subsidiaries of the Group for vessels provided and services rendered. In total, Subsea 7 Mexico owed \$239.4 million (2014: \$250.1 million) to certain wholly-owned subsidiaries of the Group.

The market outlook for Subsea 7 Mexico is uncertain due, in part, to the current and forecast lower oil and gas price environment. This together with Subsea 7 Mexico's current financial position substantially increases the risk that Subsea 7 Mexico will be unable to repay in full the outstanding loans and trade payables due to certain wholly-owned subsidiaries of the Group. The \$76.8 million term loan guarantee provided by the shareholder of the non-controlling interest may not be fully collectible depending on the financial position of the guarantor.

If Subsea 7 Mexico were unable to repay the amounts due and the Group were unable to collect the amount guaranteed by the shareholder of the non-controlling interest, equity attributable to shareholders of the parent company would be adversely affected. In light of these risks the financial exposure to the shareholders of the parent company is estimated to be approximately \$90.0 million. If this financial exposure were to crystallise in full, the impact would be to decrease equity attributable to shareholders of the parent company by approximately \$90.0 million and increase equity attributable to non-controlling interests by approximately \$90.0 million. There would be no impact on the Consolidated Income Statement, the Consolidated Cash Flow Statement or total equity of the Group. The calculation of earnings per share is not expected to be significantly impacted.

26. Borrowings

2015 As at (in \$ millions) 31 Dec	2014 31 Dec
\$700 million 1.00% convertible bonds due 2017 (Note 27) 523.9	576.2
\$15 million loan facility due 2015 –	1.9
Total 523.9	578.1
Consisting of:
Non-current portion of borrowings 523.9	576.2
Current portion of borrowings –	1.9
Total 523.9	578.1

Commitment fees expensed during the year in respect of unused lines of credit totalled \$1.7 million (2014: \$2.9 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. This 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 was unutilised at 31 December 2015 and matures on 3 September 2019. The facility is guaranteed by Subsea 7 S.A. and Subsea 7 Finance (UK) PLC (formerly Subsea 7 Finance (UK) Limited).

During the year the Group drew down, and subsequently repaid, \$80.0 million under the \$500 million multi-currency revolving credit and guarantee facility. The proceeds were utilised to meet short-term operational funding requirements.

The \$357 million 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 delivery of the vessels. If the bank tranche is not refinanced satisfactorily after five years then the ECA tranche also becomes due. As at 31 December 2015 the facility remained unutilised. The facility may be drawn prior to the delivery of the vessels; upon delivery, if unutilised, the facility will terminate. The facility is guaranteed by Subsea 7 S.A. and Subsea 7 Finance (UK) PLC (formerly Subsea 7 Finance (UK) Limited).

\$15 million loan facility

On 26 May 2008, Sonamet Industrial S.A. entered into a \$15 million loan facility with Banco Angolano de Investimentos S.A. for the construction of Sonamet's headquarters in Lobito, Angola. After an initial 20-month repayment grace period the loan was repaid in full in equal instalments over 66 months and matured on the 26 July 2015.

Utilisation of facilities

As at (in \$ millions)	2015	2015	2015	2014	2014	2014
	31 Dec	31 Dec	31 Dec	31 Dec	31 Dec	31 Dec
	Utilised	Unutilised	Total	Utilised	Unutilised	Total
Cash loans	–	857.0	857.0	1.9	513.1	515.0

Bank overdraft and short-term lines of credit

Overdraft facilities consisted of \$16.7 million (2014: \$18.9 million), of which \$nil (2014: \$nil) was drawn as at 31 December 2015.

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 as at 31 December 2015 was \$476.1 million (2014: \$619.0 million).

Guarantee arrangements with joint ventures

Normand Oceanic AS (NOAS) is a joint venture between Solstad Offshore ASA and the Group. NOAS is the vessel owning entity for Normand Oceanic and has a \$152.3 million loan facility which it used to part finance the purchase of the vessel. The loan has a termination date of 20 July 2017 with an outstanding balance at 31 December 2015 of \$119.3 million (2014: \$129.4 million). NOAS also entered into an interest rate swap, maturing on 19 July 2017, swapping a floating rate based on LIBOR to a fixed rate of 0.85% per annum. Both Solstad Offshore ASA and Subsea 7 S.A. have provided guarantees to the banking syndicate each guaranteeing 50% of the payment obligations and liabilities under the loan and hedging agreements.

SapuraAcergy is the collective term for the Group's investments in its joint ventures SapuraAcergy Assets Pte Limited (SAPL) and SapuraAcergy Sdn. Bhd. (SASB). The joint venture partner for both joint ventures is Nautical Essence Sdn. Bhd. which is wholly-owned by SapuraKencana Petroleum Berhad. At 31 December 2015, SASB had an \$82.8 million facility in place (2014: \$157.0 million multicurrency facility). Both the Group and SapuraKencana Petroleum Berhad had issued guarantees for 50% of the financing respectively. The facility consisted of \$40.0 million available for the issuance of the principal bank guarantees and \$30.0 million available for letters of credit, a revolving credit facility totalling \$5.5 million and a \$7.3 million Foreign Exchange Facility. At 31 December 2015, the amount drawn under the principal bank guarantee was \$35.4 million (2014: \$96.0 million); all other facilities noted were undrawn (2014: \$nil).

27. Convertible bonds

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

On 5 October 2012, the Group issued \$700.0 million in aggregate principal amount of 1.00% convertible bonds due 2017. The issuance was completed on 5 October 2012 with the receipt of net proceeds after deduction of issuance related costs of \$697.9 million.

The net proceeds received from the issue of the 2017 Bonds were allocated between the liability and equity components as follows. The equity component represented the fair value of the embedded option to convert the liability into equity of the Group.

(in \$ millions)	2017 Bonds
Principal value of convertible bonds issued	700.0
Proceeds of issue (net of transaction costs)	697.9
Liability component at date of issue	(617.3)
Transfer to equity reserve at date of issue	80.6

The 2017 Bonds have 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 redeemed, converted or cancelled will mature on 5 October 2017 at 100% of their principal amount.

The bondholders were granted an option which allowed them to convert the convertible bonds into common shares with an initial conversion price of \$30.10 per share at the date of issue, equivalent to 23,255,814 common shares or approximately 7.1% of Subsea 7 S.A.'s issued share capital (excluding treasury shares held).

At 31 December 2015, \$548.2 million (2014: \$618.2 million) at par value of the 2017 Bonds, excluding those bonds repurchased and held by the Group, were outstanding with a conversion price at that date of \$28.39 (2014: \$28.39) per share, adjusted for the payment of dividends since issuance. This was equivalent to 19,309,616 (2014: 21,775,273) common shares, or 5.9% (2014: 6.7%) of the Group's issued share capital (excluding treasury shares held). The conversion price will continue to be adjusted in line with the 2017 Bonds' terms and conditions.

There was also an option for the Company to call the 2017 Bonds on or after 26 October 2015 if the price of the common shares exceeds 130% of the conversion price for a specified period or at any time provided that 90% or more of the 2017 Bonds had been redeemed or converted into common shares. The option lapsed as the share price of the common shares did not exceed 130% of the conversion price during the relevant period.

The following is a summary of certain other terms and conditions that apply to the 2017 Bonds:

• the 2017 Bonds are unsecured but contain a negative pledge provision which restricts encumbrances or security interests on current and future property or assets to ensure that the convertible bonds will rank equally with other publicly quoted or listed debt instruments
• a cross default provision subject to a minimum threshold of \$25.0 million and other events of default in connection with non-payment of the 2017 Bonds
• various undertakings in connection with the term of any further issuance of common shares and continuance of the listing of the shares
• provisions for the adjustment of the conversion price in certain circumstances.

Bond repurchases

During 2015 the Group repurchased \$70.0 million (par value) of the 2017 1.00% convertible bonds for \$64.7 million (equivalent to an average 92.4% of the par value). Each repurchase price was treated as payment for the liability and equity component of the bonds. This treatment resulted in a gain on repurchase of the liability of \$2.6 million recognised within finance income in the Consolidated Income Statement. The repurchase of the convertible element of the bond resulted in a \$0.5 million credit being recognised within retained earnings. These bonds have not been cancelled but continue to be held by the Group and are available for reissue at a future date.

Following the repurchases of the \$70.0 million of bonds, \$8.0 million of the related equity component was transferred from equity reserves to retained earnings.

Movements in convertible bonds

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

(in \$ millions)	2015	2014
At year beginning	576.2	911.7
Interest accrued	–	2.3
Bonds converted	–	(13.9)
Bonds redeemed	–	(182.0)
Bonds repurchased	(66.7)	(155.2)
Interest charged (Note 9)	20.4	29.8
Interest paid	(6.0)	(16.5)
At year end (Note 26)	523.9	576.2
The interest charged in the year was calculated by applying an effective interest rate of 3.5%.
The movement in the equity components of the convertible bonds was as follows:
For the year (in \$ millions)	2015	2014
At year beginning	71.2	248.5
Reclassification of equity component of bonds redeemed, repurchased or converted in year	(8.0)	(177.3)
At year end	63.2	71.2
28. Other non-current liabilities
As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Accrued salaries and benefits	16.2	27.7
Non-current amounts due to associates and joint ventures	1.8	1.8
Other	55.1	63.8
Total	73.1	93.3
29. Trade and other liabilities
	2015	2014
As at (in \$ millions)	31 Dec	31 Dec
Accruals	684.3	970.4

29. Trade and other liabilities
As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Accruals	684.3	970.4
Trade payables	131.8	284.4
Current amounts due to associates and joint ventures	5.1	17.6
Accrued salaries and benefits	155.5	211.5
Withholding taxes	13.4	11.6
Other taxes payable	79.3	145.5
Other current liabilities	54.1	33.1
Total	1,123.5	1,674.1

30. Provisions

(in \$ millions)		Claims Decommissioning	Restructuring	Other	Total
At 1 January 2014	21.6	18.5	7.1	7.3	54.5
Additional provision in the year	7.7	1.4	5.2	18.5	32.8
Utilisation of provision	(5.2)	(2.8)	(2.2)	(0.4)	(10.6)
Unused amounts released during the year	(6.0)	–	–	(4.2)	(10.2)
Exchange differences	(2.0)	(0.8)	(1.4)	(3.1)	(7.3)
At 31 December 2014	16.1	16.3	8.7	18.1	59.2
Additional provision in the year	6.8	9.4	136.1	24.0	176.3
Utilisation of provision	(1.4)	(3.7)	(65.9)	(4.9)	(75.9)
Unused amounts released during the year	(2.5)	(0.2)	–	(5.0)	(7.7)
Reclassifications(a)	–	–	9.0	(9.0)	–
Exchange differences	(3.5)	(1.4)	(5.2)	(2.2)	(12.3)
At 31 December 2015	15.5	20.4	82.7	21.0	139.6

(a) During 2015 an onerous lease provision related to a pre-2015 restructuring exercise was reallocated from Other to Restructuring.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

30. Provisions continued

As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Consisting of:
Non-current provisions	47.0	30.3
Current provisions	92.6	28.9
Total	139.6	59.2

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 year the leases cease, which ranges from 2016 to 2019.

The restructuring provision relates to expenses associated with cost reduction and headcount resizing activities announced by the Group. The provision includes employee termination costs, onerous lease charges and professional fees. The provision is based on statutory requirements and discretionary arrangements for employee headcount reduction and the best estimate of costs associated with onerous lease contracts. Outflows associated with termination costs and professional fees are expected to occur within 2016. Outflows associated with onerous leases are expected to occur between 2016 and 2020.

31. Commitments and contingent liabilities Commitments

The Group's commitments at 31 December 2015 consist of:

• commitments to purchase property, plant and equipment from external vendors of \$279.5 million (2014: \$770.3 million) mainly related to the construction of Seven Kestrel, Seven Arctic, and two new-build PLSVs, Seven Sun and Seven Cruzeiro, linked to long-term contracts with Petrobras;
• operating lease commitments as indicated in Note 32 'Operating lease arrangements'.

Contingent liabilities

A summary of the contingent liabilities is as follows:

	2015	2014	2015	2014
(in \$ millions)	Contingent liability recognised		Contingent liability not recognised
At year beginning	6.0	6.8	267.8	280.3
New assessments (including effect of interest rate changes)	–	–	73.7	6.8
Contingent liability derecognised	–	–	(64.9)	–
Exchange differences	(2.0)	(0.8)	(99.5)	(19.3)
At year end	4.0	6.0	177.1	267.8

Contingent liabilities recognised in the Consolidated Balance Sheet

As a result of the Combination, and in accordance with IFRS 3 'Business Combinations', a contingent liability of \$9.3 million was recognised in the Consolidated Balance Sheet as at 7 January 2011 in respect of claims made against Subsea 7 do Brasil Serviços Ltda, equivalent to \$3.9 million as at 31 December 2015 (2014: \$5.9 million). A further \$3.3 million of contingent liabilities were recognised in the Consolidated Balance Sheet as at 7 January 2011 in relation to several other smaller claims, equivalent to \$0.1m as at 31 December 2015 (2014: \$0.1 million).

Contingent liabilities not recognised in the Consolidated Balance Sheet

Between 2009 and 2015, 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 as at 31 December 2015 amounted to BRL 706.7 million, equivalent to \$177.1 million (2014: BRL 667.9 million, equivalent to \$267.8 million). Of this amount BRL 339.1 million, equivalent to \$84.9 million (2014: BRL 654.7 million, equivalent to \$163.7m) related to ICMS. The remainder of the balance related to assessments for federal taxes and associated interest. The Group has challenged these assessments with some cases being dismissed by the tax authorities during 2015. No provision has been made in relation to these cases.

A contingent liability has been disclosed for those cases where the recognition criteria has been met; however, the Group does not believe that likelihood of payment is probable.

In the ordinary course of business, various claims, litigation 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 position.

32. Operating lease arrangements The Group as lessee

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Payments made under operating leases	276.3	339.0

The total operating lease commitments as at 31 December 2015 were \$507.0 million (2014: \$738.8 million). These included vessel charter hire obligations of \$297.5 million (2014: \$509.5 million). The remaining obligations as at 31 December 2015 related to office facilities and other equipment of \$209.5 million (2014: \$229.3 million).

The Group's outstanding lease commitments fall due as follows:

As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Within one year	185.8	273.9
Years two to five inclusive	255.2	376.1
After five years	66.0	88.8
Total	507.0	738.8

The leases have various terms and future renewal options, none of which are individually significant to the Group. Renewal options which have not yet been exercised are excluded from the outstanding commitments.

33. Financial instruments

Derivative financial instruments recognised in the Consolidated Balance Sheet were as follows:

As at (in \$ millions)	31 Dec 2015 Assets	31 Dec 2015 Liabilities	31 Dec 2015 Total	31 Dec 2014 Assets	31 Dec 2014 Liabilities	31 Dec 2014 Total
Non-current
Forward foreign exchange contracts	4.4	(8.4)	(4.0)	3.8	(13.1)	(9.3)
Interest rate swap	–	(1.0)	(1.0)	–	(2.2)	(2.2)
Total	4.4	(9.4)	(5.0)	3.8	(15.3)	(11.5)
Current
Forward foreign exchange contracts	18.2	(12.2)	6.0	28.0	(25.1)	2.9
Total	18.2	(12.2)	6.0	28.0	(25.1)	2.9

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'.

33. Financial instruments continued

The Group's financial instruments are classified as follows:

	2015	2014
As at (in \$ millions)	31 Dec Carrying amount	31 Dec Carrying amount
Financial assets
Cash and cash equivalents	946.8	572.6
Financial assets at fair value through profit or loss – derivative instruments	20.9	28.1
Derivative instruments in designated hedge accounting relationships	1.7	3.7
Loans and receivables:
Net trade receivables (Note 19)	379.9	542.4
Non-current amounts due from associates and joint ventures (Note 17)	71.4	90.5
Current amounts due from associates and joint ventures (Note 19)	33.8	5.9
Finance lease receivables	–	7.4
Other receivables	10.3	30.7
Financial liabilities
Financial liabilities at fair value through profit or loss – derivative instruments	(21.6)	(35.5)
Derivative instruments in designated hedge accounting relationships	–	(4.9)
Other financial liabilities:
Trade payables (Note 29)	(131.8)	(284.4)
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)	(5.1)	(17.6)
Borrowings – Convertible bonds (Note 27)	(523.9)	(576.2)
Other payables	(41.8)	(18.4)

Except as detailed in the following table, the carrying amounts of financial assets and financial liabilities recorded at amortised cost in the Consolidated Financial Statements approximate their fair values:

	2015	2015	2014	2014
	31 Dec	31 Dec	31 Dec	31 Dec
As at (in \$ millions)	Carrying amount	Fair value	Carrying amount	Fair value
Financial liabilities
Borrowings – Convertible bonds (Note 27) – Level 2	(523.9)	(515.7)	(576.2)	(565.5)

Financial risk management objectives

The Group monitors and manages the financial risks relating to its 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 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.

There has been no significant change to the Group's exposure to market risks or the manner in which it manages and measures the risk in the year.

Foreign currency risk management

The Group conducts operations in many countries and, as a result, is exposed to currency fluctuations through the generation of 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 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, Mexican Peso, Nigerian Naira, Norwegian Krone and Singapore Dollar.

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 timeframe. 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 and the hedging reserve, included within other reserves, in respect of designated hedges in addition to net income movements. 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 \$47.8 million (2014: \$45.1 million). The impact would be an increase in reported net assets of \$31.6 million (2014: reduction of \$56.3 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.

The following table details the forward foreign exchange contracts outstanding as at the balance sheet date:

As at 31 December 2015

	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	60.1	20.7	25.4	–	10.1	3.2
Canadian Dollar	–	–	6.1	–	0.2	–
Danish Krone	11.9	–	0.9	–	1.4	–
Euro	137.4	10.8	–	–	4.1	1.3
Norwegian Krone	71.1	24.4	–	–	(9.4)	(8.4)
Australian Dollar	–	–	15.6	–	0.1	–
US Dollar	12.0	–	18.0	–	(0.6)	–
Total	292.5	55.9	66.0	–	5.9	(3.9)

As at 31 December 2014

	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	226.5	18.6	17.9	–	20.0	2.3
Canadian Dollar	6.9	–	–	–	–	–
Danish Krone	35.0	13.0	–	–	0.5	1.3
Euro	119.3	7.5	4.2	–	(1.2)	(0.1)
Norwegian Krone	124.0	59.8	23.0	–	(10.5)	(12.1)
US Dollar	108.8	–	289.6	10.4	(6.2)	(0.4)
Total	620.5	98.9	334.7	10.4	2.6	(9.0)

33. Financial instruments continued

Hedge accounting

Included within the figures in the tables on page 79 are the following outstanding forward foreign exchange contracts which are designated as hedging instruments as at the reporting date:

As at 31 December 2015

		Contracted amount by contract maturity				Fair value by contract maturity
(in \$ millions)		Buy		Sell		Maturity
	< 1 Year	1-5 Years	< 1 Year	1-5 Years	< 1 Year	1-5 Years
Danish Krone	10.4	–	–	–	1.7	–
Total	10.4	–	–	–	1.7	–

As at 31 December 2014

		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
Danish Krone	26.3	11.7	–	–	1.0	1.5
Norwegian Krone	3.8	–	–	–	–	–
US Dollar	14.2	–	168.1	–	(3.7)	–
Total	44.3	11.7	168.1	–	(2.7)	1.5

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)	2015	2014
As at year beginning	(7.6)	8.2
(Losses)/gains on the effective portion of derivative financial instruments deferred to equity:
capital expenditure hedging	–	0.1
revenue hedging	(5.1)	(10.0)
operating expenses hedging	1.0	(6.3)
income tax (losses)/gains recognised in equity	(1.5)	9.9
Cumulative deferred gains/(losses) transferred to Consolidated Income Statement (see below):
revenue hedging	18.3	(12.3)
operating expenses hedging	(2.8)	2.7
Cumulative deferred (losses)/gains transferred to initial carrying amount:
capital expenditure hedging	(0.1)	0.1
Balance at year end	2.2	(7.6)

Cumulative gains and losses transferred from the hedging reserve to the Consolidated Income Statement

	2015	2014
For the year ended (in \$ millions)	31 Dec	31 Dec
Cumulative deferred (gains)/losses recognised in revenue	(18.1)	7.2
Cumulative deferred losses/(gains) recognised in operating expenses	3.2	(0.9)
Cumulative deferred (gains)/losses recognised in other gains and losses	(0.6)	3.3
Total	(15.5)	9.6

During 2015 the Group reclassified \$nil of net gains on foreign currency forward contracts relating to forecast transactions that were no longer expected to occur from the hedging reserve to the Consolidated Income Statement (2014: \$5.4 million).

Revenue hedging

The Group uses forward foreign exchange contracts to manage a proportion of its revenue transaction exposures. The hedging reserve at 31 December 2015 included \$nil million (2014: loss of \$12.0 million) arising from revenue hedges maturing on or before 31 July 2015.

Operating expenses hedging

The Group uses forward foreign exchange contracts to manage a proportion of its operating expense transaction exposures. At 31 December 2015, the hedging reserve balance included a gain of \$2.2 million (2014: gain of \$4.3 million) arising on operating expense hedges maturing on or before 3 August 2016.

Capital expenditure hedging

The Group uses forward foreign exchange contracts to manage certain capital expenditure transaction exposures which are forecast to be incurred in currencies other than US Dollars. The hedging reserve balance at 31 December 2015 related to capital expenditure hedges was \$nil (2014: gain of \$0.1 million).

The effectiveness of foreign exchange hedges

The Group documents its assessment of 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. The Group assesses the effectiveness of foreign exchange hedges based on changes in fair value attributable to changes in spot prices. Changes in fair value due to changes in the difference between the spot price and the forward price are excluded from the assessment of ineffectiveness and are recognised directly in the Consolidated Income Statement.

The cumulative effective portion of changes in the fair value of derivative financial instruments is deferred in equity within 'Other reserves' as hedging reserves in the Consolidated Balance Sheet. The resulting cumulative gains or losses will be reclassified to the Consolidated Income Statement upon the recognition of the underlying transaction or the discontinuance of a hedging relationship. Movements in respect of effective hedges are detailed in the Consolidated Statement of Changes in Equity.

The gains or losses relating to the ineffective portion of cash flow hedges are recognised in the Consolidated Income Statement and the net amount recognised for the year was \$nil (2014: \$0.1 million).

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 return generated.

The Group uses interest rate swaps to manage its exposure to interest rate risk. At 31 December 2015, the Group had one contract entered effective 28 September 2009 and maturing 28 September 2016 for a notional amount of \$50 million. The Group has swapped a floating rate based on LIBOR to a fixed rate of 3.3%. During the year, a mark-to-market gain of \$1.2 million (2014: \$1.4 million) was recognised in the Consolidated Income Statement.

Interest rate sensitivity analysis

Interest on the \$500 million facility discussed in Note 26 'Borrowings' is payable at LIBOR plus a margin which is linked to the ratio of total net debt to Adjusted EBITDA (see Additional Information on page 95) and ranges up to 0.9% per year.

Interest on the \$357 million facility discussed in Note 26 'Borrowings' is payable at LIBOR plus a margin of 1.4%.

As at 31 December 2015, the Group had not drawn down on either facility.

As at 31 December 2015, the Group had significant cash deposits and only fixed rate borrowings. A 1% increase in interest rates would not have a significant impact on the Group's finance costs for the current or prior year.

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 counterparties 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 to and the credit ratings of its banking counterparties are continuously monitored and the aggregate value of transactions concluded is spread among approved counterparties. Credit exposure is controlled by limits on banking counterparties that are reviewed and approved annually and monitored daily. In respect of its clients and suppliers 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 value of amounts on deposit (excluding cash and cash equivalents available on demand of \$454.8 million) at the balance sheet date. These are graded and monitored internally by the Group based on current external credit ratings issued; with 'prime' being the highest possible rating.

As at (in \$ millions)	2015 31 Dec	2014 31 Dec
Counterparties rated high grade	198.9	30.9
Counterparties rated upper medium grade	215.2	–
Counterparties rated lower medium grade	41.0	12.6
Counterparties rated non-investment grade	29.0	18.2
Not rated	7.9	29.2

33. Financial instruments continued

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 debtor categories:

	2015 31 Dec	2014 31 Dec
As at	Debtor category percentage	Debtor category percentage
National oil and gas companies	9%	16%
International oil and gas companies	35%	49%
Independent oil and gas companies	56%	35%
Total	100%	100%

National oil and gas companies are either partially or fully owned by or directly controlled by the government of any one country. 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 table details the ageing analysis for trade receivables:

As at 31 December 2015

(in \$ millions)	Less than 1 month	1-3 months	3 months to 1 year	1-5 years	Total
Trade receivables	263.5	108.6	7.8	–	379.9
Trade receivables considered impaired	1.0	0.8	10.1	11.1	23.0
Total trade receivables (Note 19)	264.5	109.4	17.9	11.1	402.9

As at 31 December 2014

(in \$ millions)	Less than 1 month	1-3 months	3 months to 1 year	1-5 years	Total
Trade receivables	417.4	97.8	15.9	11.3	542.4
Trade receivables considered impaired	2.8	0.3	0.6	6.5	10.2
Total trade receivables (Note 19)	420.2	98.1	16.5	17.8	552.6

Trade receivables balances beyond the one month ageing category in the table above 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 78.

Concentration of credit risk

During the year, three clients (2014: three clients) contributed individually to more than 10% of the Group's revenue. The revenue from these clients was \$1.8 billion or 38% of total Group revenue (2014: \$3.3 billion or 48%).

The five largest receivable balances by client as at 31 December 2015 are shown in the table below:

As at (in \$ millions)	31 Dec 2015
Client A	67.5
Client B	35.5
Client C	32.9
Client D	32.3
Client E	26.6

As at (in \$ millions)	31 Dec 2014
Client A	95.6
Client B	75.2
Client C	36.6
Client D	34.7
Client E	30.1

The client mix for outstanding accounts receivable balances in 2015 is not the same as 2014. The Group does not have any significant credit exposure to any single counterparty as at 31 December 2015. 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 2015, 31% (2014: 30%) of cash was held at counterparties with a credit rating lower than 'upper medium grade' classification.

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 borrowings facilities. Included in Note 26 'Borrowings' is a listing of undrawn facilities that the Group has at its disposal.

Liquidity tables

The following tables detail 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. The table consists of the principal cash flows:

As at 31 December 2015

	Less than		3 months
(in \$ millions)	1 month	1-3 months	to 1 year	1-5 years	Total
Trade payables	128.2	3.6	–	–	131.8
Convertible bonds	–	–	5.5	553.7	559.2
Current amounts due to associates and joint ventures	5.1	–	–	–	5.1
Loan from non-controlling interest	–	–	–	1.8	1.8
Total	133.3	3.6	5.5	555.5	697.9

As at 31 December 2014

(in \$ millions)	Less than 1 month	1-3 months	3 months to 1 year	1-5 years	Total
Trade payables	170.9	113.5	–	–	284.4
Convertible bonds	–	–	7.0	714.0	721.0
Current amounts due to associates and joint ventures	10.3	7.3	–	–	17.6
Loan from non-controlling interest	–	–	–	1.8	1.8
Total	181.2	120.8	7.0	715.8	1,024.8

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 2015

	Less than		3 months
(in \$ millions)	1 month	1-3 months	to 1 year	1-5 years	Total
Net settled:
Foreign exchange forward contracts	–	0.7	9.5	8.5	18.7
Interest rate swap	–	–	–	1.0	1.0
Gross settled:
Foreign exchange forward contract payments	87.3	11.9	6.5	–	105.7
Foreign exchange forward contract receipts	(86.5)	(11.1)	(6.0)	–	(103.6)
Total	0.8	1.5	10.0	9.5	21.8
As at 31 December 2014
	Less than		3 months
(in \$ millions)	1 month	1-3 months	to 1 year	1-5 years	Total
Net settled:
Foreign exchange forward contracts	2.4	1.5	8.2	12.6	24.7
Interest rate swap	–	–	–	2.2	2.2
Gross settled:
Foreign exchange forward contract payments	220.5	223.1	83.3	16.6	543.5
Foreign exchange forward contract receipts	(219.1)	(216.4)	(77.8)	(16.0)	(529.3)
Total	3.8	8.2	13.7	15.4	41.1

33. Financial instruments continued

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

	2015	2014
As at (in \$ millions)	31 Dec	31 Dec
Principal value of remaining convertible bonds (Note 27)	548.2	618.2
Estimated present value of operating lease obligations(a)	1,657.8	2,034.0
Cash and cash equivalents	(946.8)	(572.6)
Net debt	1,259.2	2,079.6
Adjusted EBITDA (see Additional information on page 95)	1,216.9	1,438.8
Debt service ratio(b)	1.0x	1.4x

(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:

As at (in \$ millions)	2015 31 Dec Level 2	2015 31 Dec Level 3	2014 31 Dec Level 2	2014 31 Dec Level 3
Recurring fair value measurements
Financial assets:
Financial assets at fair value through profit or loss – derivative instruments	20.9	–	28.1	–
Derivative instruments in designated hedge accounting relationships	1.7	–	3.7	–
Financial liabilities:
Financial liabilities at fair value through profit or loss – derivative instruments	(21.6)	–	(35.5)	–
Derivative instruments in designated hedge accounting relationships	–	–	(4.9)	–

During the year ended 31 December 2015 there have been 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 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 value 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 is calculated using quoted foreign exchange rates and yield curves derived from quoted interest rates matching maturities of the contract.

Interest rate swap

The fair value of the Group's interest rate swap is calculated using quoted three-month US Dollar LIBOR rates. At the balance sheet date the three month US Dollar LIBOR rate was 0.6%.

Borrowings – convertible bonds

The fair value of the liability components of convertible bonds is determined by matching the maturity profile of the bond to market interest rates available to the Group. At the balance sheet date the interest rate available was 4.7% (2014: 4.5%).

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 for 2015 included 13 individuals (2014: 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 \$	2015 31 Dec \$	2014 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(b)
Allen Stevens	105,000	–	105,000	105,000(b)

(a) Mr Siem's fee is included within payments to Siem Industries Inc. as detailed in 'Other related party transactions' on page 87.

Share options outstanding and shareholdings as at 31 December 2015 were as follows:

Share options

		Number
Name	Date of grant	of options	Exercise price	Date of expiry
Kristian Siem		–
Sir Peter Mason KBE	21 Nov 2006	5,000		NOK124.50 20 Nov 2016
Eystein Eriksrud		–
Dod Fraser		–
Robert Long		–
Allen Stevens		–
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) As at 31 December 2015, 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, as at 31 December 2015, owned 69,731,931 shares representing 21.3% of total fully paid and issued common shares of the Company.

34. Related party transactions continued

Key management

The remuneration of key management personnel, excluding the Non-Executive Directors, during the year was as follows:

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Salaries and other short-term employee benefits	8.4	4.8
Share-based payments	1.4	1.3
Post-employment benefits	0.2	0.3
Total	10.0	6.4

The compensation of the Chief Executive Officer ('CEO') for the year was \$2.4 million (2014: \$1.2 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.

Share options and performance shares outstanding and shareholdings as at 31 December 2015 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	19 Mar 2006	10,000	\$13.81	18 Mar 2016
	21 Nov 2006	4,500	\$19.45	20 Nov 2016
	12 Mar 2008	8,000	\$22.52	11 Mar 2018
Keith Tipson	21 Nov 2006	24,500	NOK 124.50	20 Nov 2016
	12 Mar 2008	15,000	NOK 114.50	11 Mar 2018
Øyvind Mikaelsen	21 Nov 2006	30,000	NOK 124.50	20 Nov 2016
	12 Mar 2008	15,000	NOK 114.50	11 Mar 2018

Shares and performance shares

	Total
	performance	Total owned
Name	shares(a)	shares
Jean Cahuzac	190,000	92,566
Ricardo Rosa	110,000	–
John Evans	133,000	29,948
Nathalie Louys	65,000	2,607
Keith Tipson	73,500	21,931
Steve Wisely	94,000	25,732
Øyvind Mikaelsen	113,000	17,313

(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 251,500 (2014: 243,000) performance shares under the 2013 Long-term Incentive Plan; refer to Note 35 'Share-based payments' for details of the plan.

Dividends totalling \$nil (2014: \$0.1 million) were paid to key management personnel for directly held shareholdings.

Transactions with associates and joint ventures

The Consolidated Balance Sheet included:

	2015	2014
As at (in \$ millions)	31 Dec	31 Dec
Non-current receivables due from associates and joint ventures (Note 17)	71.4	90.5
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)	33.8	5.9
Trade payables due to associates and joint ventures (Note 29)	(5.1)	(17.6)
Net receivables due from associates and joint ventures	98.3	77.0

During the year, the Group provided services to associates and joint ventures amounting to \$9.1 million (2014: \$15.3 million), purchased goods and services from associates and joint ventures amounting to \$76.1 million (2014: \$200.8 million) and received \$0.3 million (2014: \$3.2 million) from Deep Seas Insurance in settlement of insurance claims.

At 31 December 2015, the Group had provided long-term loans to joint ventures amounting to \$71.4 million (2014: \$90.5 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

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 (2014: \$0.3 million). Dividends totalling \$nil (2014: \$40.9 million) were paid to Siem Industries Inc.

Siem Offshore Inc. is a subsidiary 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. relating to vessel charter costs and provision of crew, totalling \$22.2 million, were made during the year (2014: \$9.7 million). At 31 December 2015, the Group had outstanding balances due to these companies of \$0.1 million (2014: \$nil).

DSND Bygg AS is ultimately controlled by Siem Industries Inc. Purchases from DSND Bygg AS in relation to the rental of office accommodation totalling \$0.2 million (2014: \$0.6 million) were made during the year, partly offset by recharges for office management services of \$0.1 million (2014: \$0.2 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:

2015	2014
For the year ended (in \$ millions) 31 Dec	31 Dec
Expense arising from equity-settled share-based payment transactions:
2009 Long-term Incentive Plan 2.2	3.8
2013 Long-term Incentive Plan 4.6	2.9
Subsea 7 Inc. restricted stock award plan –	1.0
Expense arising from cash-settled share-based payment transactions:
Special Incentive Plan 2012 –	1.8
Total 6.8	9.5

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 LTIP during 2013.

The 2009 LTIP provided conditional share awards based upon performance conditions over a performance period of at least three years.

Performance conditions are based on relative Total Shareholder Return (TSR) against a specified comparator group of companies and are determined over a three-year period. The Group will have to deliver TSR above the median for any awards to vest. At the median level 30% of the maximum award will vest. If the actual ranked TSR position of Subsea 7 during the three-year period, as converted to a percentage, is equal to or greater than 50% and below 90%, the vesting of the share award between 30% and 100% is determined by linear interpolation. The maximum award would only vest if the Group achieved top decile TSR ranking.

Approximately 120 senior managers and key employees participated in the 2009 LTIP. Grants were determined by the Compensation Committee, which is responsible for operating and administering the plan.

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 and replaces the 2009 LTIP. 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 each such 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 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 share awards 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 2015, awards of 1,273,500 (2014: 1,631,500) shares were made under the terms of the 2013 LTIP; 827,775 (2014: 1,060,475) shares are subject to relative TSR performance measures and 445,725 (2014: 571,025) are subject to ROAIC performance measures.

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.

35. Share-based payments continued

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 plan participants are not entitled to receive dividend equivalent payments.

Approximately 120 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 as 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.

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	2015 31 Dec	2014 31 Dec
Weighted average share price (in \$)	7.66	14.34
TSR performance – Weighted average fair value at grant date (in \$)	4.22	6.45
ROAIC performance – Weighted average fair value at grant date (in \$), excluding non-market measure	7.66	12.62
Expected volatility	35%	28%
Risk free rate	0.59%	1.53%
Dividend yield	–	3.16%

The expected 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 using the one-year dividend yield of nil.

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.

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.

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 2015. 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 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 had vested prior to 31 December 2015.

Share options

Option activity for the 2003 Plan and Subsea 7 Inc. share option plans was as follows:

	Number of options 2015	Weighted average exercise price in \$ 2015	Number of options 2014	Weighted average exercise price in \$ 2014
Outstanding at year beginning	1,149,929	13.42	1,493,781	17.10
Exercised	(91,317)	7.58	(157,657)	7.13
Forfeited	(16,324)	15.03	(140,120)	19.03
Expired	(95,221)	10.40	(46,075)	6.30
Outstanding at year end	947,067	16.16	1,149,929	13.42
Exercisable at the end of the year	947,067	16.16	1,149,929	13.42

The weighted average market price at exercise date of options exercised during the year was \$9.42 (2014: \$16.54).

The following table summarises information regarding share options outstanding as at 31 December 2015:

		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	272,635	1.81	21.75
\$10.01 – \$17.00	664,432	1.48	13.89
\$3.01 – \$10.00	10,000	0.13	9.40
Total	947,067	1.56	16.10

36. Retirement benefit obligations

The Group operates both defined contribution and defined benefit pension plans, depending on location, covering certain qualifying employees.

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 \$57.8 million (2014: \$73.8 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 several separate contracts covering defined benefit pension liabilities in Norway. These 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 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 the ages of 60 and 67 years. 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. The funds of the pension schemes are made to 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. Whilst the pension company is responsible for handling the plan according to Norwegian law, Subsea 7 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 pension scheme.

United Kingdom

The United Kingdom pension plan (the Comex Defined Benefit pension plan) was closed to future accrual in 2012 and the plan was funded by the Group to allow the trustees to proceed with a buy-out of the plan. The buy-out and termination of the pension plan was completed during 2015.

36. Retirement benefit obligations continued

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		United Kingdom		France		Total
(in \$ millions)	2015	2014	2015	2014	2015	2014	2015	2014
Defined benefit obligation
At year beginning	(23.5)	(25.3)	(35.8)	(31.9)	(16.2)	(15.9)	(75.5)	(73.1)
Pension costs charged to the
Consolidated Income Statement:
Service costs	(0.6)	(0.6)	–	–	(1.2)	(1.3)	(1.8)	(1.9)
Interest cost	(0.6)	(0.8)	(0.7)	(1.4)	(0.3)	(0.4)	(1.6)	(2.6)
Curtailment	–	–	–	–	5.0	–	5.0	–
Liabilities extinguished on settlements	–	–	34.9	–	–	–	34.9	–
Employee taxes	0.1	(0.3)	–	–	–	–	0.1	(0.3)
Sub-total	(1.1)	(1.7)	34.2	(1.4)	3.5	(1.7)	36.6	(4.8)
Remeasurement gains/(losses) recognised
in other comprehensive income:
Actuarial changes arising from changes in demographic assumptions	–	–	–	–	–	–	–	–
Actuarial changes arising from changes	0.4	(2.0)	–	(3.3)	–	(2.2)	0.4	(7.5)
in financial assumptions
Experience adjustments	0.9	0.1	–	(2.6)	(0.6)	1.4	0.3	(1.1)
Sub-total	1.3	(1.9)	–	(5.9)	(0.6)	(0.8)	0.7	(8.6)
Benefits paid	0.8	0.8	1.1	1.6	1.4	0.4	3.3	2.8
Exchange differences	3.5	4.6	0.5	1.8	1.5	1.8	5.5	8.2
At year end	(19.0)	(23.5)	–	(35.8)	(10.4)	(16.2)	(29.4)	(75.5)
Fair value of plan assets At year beginning	18.4	22.1	35.8	31.9	–	–	54.2	54.0
Amounts credited to the
Consolidated Income Statement:
Interest Income	0.5	0.7	0.8	1.4	–	–	1.3	2.1
Settlements	–	–	(34.9)		–	–	(34.9)	–
Sub-total	0.5	0.7	(34.1)	1.4	–	–	(33.6)	2.1
Remeasurement gains/(losses) recognised in other comprehensive income:
Return on plan assets (excluding	0.7	(0.4)	–	3.3	–	–	0.7	2.9
amounts in interest income)
Administrative expenses	(0.2)	(0.3)	–	–	–	–	(0.2)	(0.3)
Experience adjustments	–	–	–	2.6	–	–	–	2.6
Sub-total	0.5	(0.7)	–	5.9	–	–	0.5	5.2
Employer and participant contributions	1.1	0.7	0.1	–	–	–	1.2	0.7
Benefits paid	(0.8)	(0.8)	(1.1)	(1.6)	–	–	(1.9)	(2.4)
Exchange differences	(2.8)	(3.6)	(0.7)	(1.8)	–	–	(3.5)	(5.4)
At year end	16.9	18.4	–	35.8	–	–	16.9	54.2
Net defined benefit obligation	(2.1)	(5.1)	–	–	(10.4)	(16.2)	(12.5)	(21.3)
Presented as:
Retirement benefit assets	0.8	–	–	–	–	–	0.8	–
Retirement benefit obligations	(2.9)	(5.1)	–	–	(10.4)	(16.2)	(13.3)	(21.3)
Total	(2.1)	(5.1)	–	–	(10.4)	(16.2)	(12.5)	(21.3)

Unfunded schemes

Included within the defined benefit obligation are amounts arising from plans which are unfunded. The unfunded plans are the French plan which has a total obligation of \$10.4 million (2014: \$16.2 million) and two Norwegian plans with a total obligation of \$nil (2014: \$nil).

The fair value of the Norwegian plan assets were as follows:

	2015	2014
As at (in \$ millions)	31 Dec	31 Dec
Investments quoted in active markets
Quoted equity investments	1.3	2.1
Unquoted investments
Deposits	4.4	4.3
Bonds	8.9	8.8
Property	2.0	2.6
Other	0.3	0.6
Total	16.9	18.4

Future cash flows

The estimated contributions expected to be paid into the French and Norwegian plans during 2016 total \$1.0 million. Contributions are forecast to decrease thereafter.

The average remaining service period for the Norwegian plans is ten years.

Significant actuarial assumptions

The principal assumptions used to determine the present value of the defined benefit obligation were as follows:

Year ended 31 December 2015 (in %)		Norway United Kingdom	France
Pension increase	0.0 – 2.3	–	–
Discount rate	2.5	–	2.0
Future salary increase	2.0	–	3.8

(in %)	Norway	United Kingdom	France
Pension increase	0.1 – 3.0	2.9	–
Discount rate	3.0	3.4	2.0
Future salary increase	3.3	–	3.8

Assumptions regarding future mortality experience are set based on advice in accordance with published statistics and experience. The average life expectancy in years of a pensioner retiring at the plan retirement age was as follows:

				As at balance sheet date
Retirement benefit plan	Retirement age	Sex	2015 31 Dec	2014 31 Dec
Norway office (onshore) plan	67 years	Male	20.0	17.6
	67 years	Female	23.1	23.6

Mortality assumptions are not relevant for the separate sailor pension scheme as participants are only eligible to receive a pension between the ages of 60 and 67, prior to transferring to a defined contribution pension scheme.

36. Retirement benefit obligations continued

Sensitivity analysis

A quantitative sensitivity analysis for significant assumptions as at 31 December 2015 is shown below. The sensitivity analyses have been determined based on a method that extrapolates the impact on the net defined benefit obligation 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)	–	0.4	(0.5)	(0.7)	0.7
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	(0.8)	0.3	0.7	(0.8)	–	–
France
(in \$ millions)						Discount rate
Sensitivity level					0.25% increase	0.25% decrease
Impact on the net defined benefit obligation					0.5	(0.5)
37. Deferred revenue
As at (in \$ millions)					2015 31 Dec	2014 31 Dec
Advances received from clients					10.0	1.7

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	2015 31 Dec	2014 31 Dec
Cash flow from operating activities:
Net income/(losses) before taxes		184.9	(229.5)
Adjustments for non-cash items:
Depreciation of property, plant and equipment	15	386.4	392.5
Net impairment of property, plant and equipment	7	136.5	88.8
Amortisation of intangible assets	14	7.2	11.2
Impairment of goodwill	13	520.9	1,183.3
Mobilisation costs	7	22.1	16.8
Adjustments for investing and financing items:
Share of net income of associates and joint ventures	16	(63.4)	(69.2)
Finance Income	9	(16.7)	(19.3)
Losses on disposal of property, plant and equipment	8	33.0	1.4
Insurance income	8	(30.6)	–
Gain on repurchase of convertible bonds	8	(2.6)	(0.2)
Finance costs	9	8.2	18.7
Adjustments for equity items:
Share-based payments	35	6.8	7.7
		1,192.7	1,402.2
Changes in operating assets and liabilities:
Decrease in inventories		10.1	5.0
Decrease in operating receivables		303.1	228.7
(Decrease)/ Increase in operating liabilities		(249.2)	34.9
		64.0	268.6
Income taxes paid		(208.1)	(221.1)

Net cash generated from operating activities 1,048.6 1,449.7

39. Post balance sheet events Dividend

Reflecting challenges facing the oil and gas industry in the near to medium-term, and in order to preserve the Group's financial flexibility so that it can benefit from opportunities that may arise during the downturn, the Board of Directors will recommend to the shareholders of Subsea 7 S.A., at the Annual General Meeting scheduled for 14 April 2016, that no dividend be paid in respect of 2015.

Convertible bonds

Between 6 January 2016 and 3 February 2016, the Group repurchased bonds totalling \$78.0 million in nominal value of the 2017 1.00% convertible bonds maturing in 2017 for \$71.5 million.

40. Wholly-owned subsidiaries

Subsea 7 S.A. had the following wholly-owned subsidiaries at 31 December 2015.

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 Nigeria Limited	Nigeria	Special Purpose
Acergy Services Limited	United Kingdom	General Trading
Acergy Services SAS	France	General Trading
Acergy Shipping Inc.	Panama	Vessel Owning
Aquarius Solutions Inc.	Canada	General Trading
Class 3 (UK) Limited	United Kingdom	Vessel Owning
Class 3 Shipping Limited	Bermuda	Vessel Owning
Engineering Subsea Solutions Limited	United Kingdom	General Trading
FIE – Fabricantes E Instaladores de Equipamentos	Portugal	Special Purpose
Globestar FZE (Snake Island)	Nigeria	General Trading
Jarius Investments Limited	Gibraltar	Special Purpose
Pelagic Nigeria Limited	Nigeria	Holding
PT. Subsea 7 Manufaktur Indonesia	Indonesia	General Trading
SCS Shipping Corporation	Liberia	Vessel owning
Seaway Offshore Participações S.A.	Brazil	Holding
Sevenseas Angola Limited	Cayman Islands	General Trading
Sevenseas Contractors S de RL de CV	Mexico	General Trading
SO France S.A.	France	Special Purpose
SO Marine Inc.	USA	General Trading
SO Services Inc.	USA	Special Purpose
Subsea 7 (Cayman Vessel Company) Limited	Cayman Islands	Vessel Owning
Subsea 7 (Cyprus) Limited	Cyprus	Vessel Owning
Subsea 7 (Luxembourg) S.à r.l.	Luxembourg	Special Purpose
Subsea 7 (Singapore) PTE Limited	Singapore	General Trading
Subsea 7 (UK Service Company) Limited	United Kingdom	Corporate Service
Subsea 7 (US) LLC	USA	General Trading
Subsea 7 (Vessel Company) B.V.	Netherlands	Vessel Owning
Subsea 7 (Vessel Company) Limited	United Kingdom	Vessel Owning
Subsea 7 Angola SAS	France	Special Purpose
Subsea 7 Asia Pacific Sdn Bhd	Malaysia	Special Purpose
Subsea 7 Australia Contracting Pty Ltd	Australia	General Trading
Subsea 7 B.V.	Netherlands	General Trading
Subsea 7 Canada Inc.	Canada	General Trading
Subsea 7 Cayman Guarantee Company	Cayman Islands	Corporate Service
Subsea 7 Chartering (UK) Limited	United Kingdom	General Trading
Subsea 7 Construction Limited	United Kingdom	General Trading
Subsea 7 Contracting (UK) Limited	United Kingdom	General Trading
Subsea 7 Crewing Limited	United Kingdom	Special Purpose

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED

40. Wholly-owned subsidiaries continued

Name	Country of registration	Nature of business
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 Eiendom AS	Norway	Special Purpose
Subsea 7 Engineering Limited	United Kingdom	General Trading
Subsea 7 Finance (UK) PLC	United Kingdom	Special Purpose
Subsea 7 Ghana FZE Limited	Ghana	General Trading
Subsea 7 Holding Inc.	Cayman Islands	Holding
Subsea 7 Holding Norway AS	Norway	Holding
Subsea 7 Holdings (US) Inc.	USA	Holding
Subsea 7 Holdings B.V.	Netherlands	Holding
Subsea 7 Inc.	Cayman Islands	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 AS	Norway	General Trading
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 M.S. Limited	United Kingdom	Corporate Service
Subsea 7 Marine LLC	USA	General Trading
Subsea 7 Moçambique Lda	Mozambique	General Trading
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 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 Procurement (UK) Limited	United Kingdom	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 Holding AS	Norway	Holding
Subsea 7 Vessel Owner AS	Norway	Vessel Owning
Subsea 7 Viking Holding AS	Norway	Holding
Subsea 7 West Africa Contracting Limited	United Kingdom	General Trading
Subsea 7 West Africa SAS	France	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 consolidation. The proportion of the voting rights in the subsidiary undertakings held directly by the 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.

ADDITIONAL INFORMATION

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-onperiod or with other businesses. The Group defines Adjusted EBITDA as net income adjusted to exclude depreciation, amortisation and mobilisation costs, impairment charges or impairment reversals, finance income, other gains and losses (including gain on disposal of subsidiary and gain on distribution), 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 and taxation. 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/(loss) to Adjusted EBITDA and Adjusted EBITDA margin:

For the year ended (in \$ millions)	2015 31 Dec	2014 31 Dec
Net operating income/(loss)	143.8	(253.8)
Depreciation, amortisation and mobilisation	415.7	420.5
Impairment of goodwill	520.9	1,183.3
Net impairment of property, plant and equipment	136.5	88.8
Adjusted EBITDA	1,216.9	1,438.8
Revenue	4,758.1	6,869.9
Adjusted EBITDA %	25.6%	20.9%
Reconciliation of net loss to Adjusted EBITDA and Adjusted EBITDA margin:

	2015 31 Dec	2014 31 Dec
Net loss	(37.0)	(381.2)
Depreciation, amortisation and mobilisation	415.7	420.5
Net impairment of property, plant and equipment	136.5	88.8
Impairment of goodwill	520.9	1,183.3
Finance income	(16.7)	(19.3)
Other gains and losses	(32.6)	(23.7)
Finance costs	8.2	18.7
Taxation	221.9	151.7
Adjusted EBITDA	1,216.9	1,438.8
Revenue	4,758.1	6,869.9
Adjusted EBITDA %	25.6%	20.9%

ADDITIONAL INFORMATION CONTINUED

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 profits; (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:

Isabel Green

Investor Relations Director Email: isabel.green@subsea7.com Telephone: +44 (0) 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.

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.

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 Email: irene.johansen@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.

Deutsche Bank Trust Company Americas 27th Floor 60 Wall Street New York, NY 10005 USA

Shareholder Service: +1 866 249 2593 (toll free for US residents only)

Broker Service Desk: +1 212 250 9100

Further information is also available at: www.adr.db.com.

Financial calendar

Subsea 7 S.A. intends to publish its quarterly financial results for 2016 on the following dates:

Q1 2016 Results	28 April 2016
Q2 & H1 2016 Results	28 July 2016
Q3 2016 Results	10 November 2016
Q4 & FY 2016 Results	2 March 2017

Annual General Meeting

14 April 2016 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 derivate 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, amortisation and mobilisation costs, impairment charges or impairment reversals, finance income, other gains and losses (including gain on disposal of subsidiary and gain on distribution), 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.
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/joint ventures is excluded from backlog figures, unless otherwise stated.
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.
CapEx	Capital expenditure.
Cash-generating unit (CGU)	These are the separable business units on which impairment reviews are carried out.
Clean operation	A clean operation is any measure beyond a normal operating practice that will save energy.
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.
Conventional	The projects relating to the fabrication and installation of fixed platforms and their umbilicals, flowlines and associated pipelines (surface/shallow water developments).
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.
EBITDA	See Adjusted EBITDA.
Eidesvik Seven	Eidesvik Seven AS and Eidesvik Seven Chartering AS.
ENMAR	ENMAR S.A.
EPIC	Engineering, Procurement, Installation and Commissioning.
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 – Northern Hemisphere and Life of Field and Executive Vice President – Southern Hemisphere and Global Projects.
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 Design, Early phase engineering design process
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.
Granherne	Granherne, a wholly owned subsidiary of KBR, which is a leading front-end engineering consultancy for onshore, offshore and deepwater oil and gas developments
Great Safety Day	A day when the Group achieves zero recordable injuries, zero high-potential incidents or near-misses and zero serious environmental incidents.
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.
Hybrid Riser Tower (HRT)	The HRT is a riser system which is applicable to deepwater and ultra-deepwater applications, and to spread-moored and turret-moored FPSO installations.
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	A division of Subsea 7 that provides remotely operated vehicles and remote intervention tooling services to the global exploration and production industry.
J-lay	A pipelay method consisting of welding single 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.
KBR	KBR is a global engineering, construction and services company supporting the energy, hydrocarbon, government services, minerals, civil infrastructure, power and industrial markets
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).
	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.
NigerStar7	NigerStar7 Limited and NigerStar7 Free Zone Enterprise.
Normand Oceanic	Normand Oceanic AS and Normand Oceanic Chartering AS.
Northern Hemisphere and Life of Field	Part of a new Subsea 7 organisational structure which came into effect on 1 January 2015 and regroups the UK, Canada and Norway with the Gulf of Mexico into one Business Unit. This also incorporates a separately managed global Life of Field business line, and the i-Tech Division.
OneSubsea ®	OneSubsea is a Cameron and 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.
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.
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,

GLOSSARY CONTINUED

	wave and other related marine systems.
Restricted share	Restricted shares were awarded to certain employees of Subsea 7 Inc. 60% vested in June 2012 and 40% vested in June 2014.
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.
Seaway Heavy Lifting	Seaway Heavy Lifting Holding Limited and its subsidiaries.
Setemares	Setemares Angola, Limitada.
SIMAR	SIMAR – Sociedade Angolana de Inspecção, Manutenção e Reparação Maritima, Lda.
S-lay	A pipelay method consisting of continuously welding single 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.
Southern Hemisphere and Global Projects	Part of a new Subsea 7 organisational structure which came into effect on 1 January 2015 and regroups the Brazil and APME Territories and operations in Africa into one Business Unit. This also incorporates Global Projects Centres in Paris and London.
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 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 Vessel Utilisation Ratio of paid days to days available for utilisation (normally assumed to be 350 days per year) expressed as a percentage.
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.

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