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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Subsea 7 SA - Ads Representing One Common Share (MM) | NASDAQ:SUBC | NASDAQ | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 25.94 | 0 | 01:00:00 |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
(Mark One)
| ¨ | REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended November 30, 2010
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
OR
| ¨ | SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Date of event requiring this shell company report
Commission File Number 00-21742
SUBSEA 7 S.A.
(Exact name of Registrant as specified in its charter)
LUXEMBOURG
(Jurisdiction of incorporation or organization)
c/o Subsea 7 M.S. Limited
200 Hammersmith Road, London W6 7DL England
(Address of principal executive offices)
Contact Details of Company Contact Person:
Name: Karen Menzel
E-mail: karen.menzel@subsea7.com
Telephone: +44(0) 20 8210 5568
Address: 200 Hammersmith Road, London W6 7DL, England
Securities registered or to be registered pursuant to Section 12(b) of the Act:
|
Title of each class |
Name of each exchange on which registered |
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| Common shares, $2.00 par value | Nasdaq Global Select Market | |||
| Securities registered or to be registered pursuant to Section 12(g) of the Act: | ||||
| None | ||||
| Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: | ||||
| None | ||||
|
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: |
||||
| Common shares, $2.00 par value | 194,953,972 (including 11,014,762 treasury shares) | |||
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Exchange Act. x Yes ¨ No
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Act of 1934. ¨ Yes x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ¨ Yes ¨ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
|
U.S. GAAP |
¨ | |||
| International Financial Reporting Standards as issued by the International Accounting Standards Board | x | |||
| Other | ¨ | |||
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the Registrant has elected to follow: ¨ Item 17 ¨ Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) ¨ Yes x No
Overview
What we do
Providing a full spectrum
of seabed-to-surface services
We concentrate on services and solutions that add value to our clients throughout the lifecycle of their offshore energy fields. We aim to deliver projects on time, within budget and to the highest quality standards, whilst making safety and security an absolute priority.
The offshore upstream cycle covers: seismic, exploration and appraisal, development, production and decommissioning and abandonment and is typically a 10 to 50 year cycle. Subsea 7 is typically involved in the late-cycle activities, in particular in development and production related activities.
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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Overview
Chairman’s Statement
Taking advantage of
future growth opportunities
We entered 2010 against the backdrop of challenging economic and financial markets. Clients were cautious about the economic outlook and continued to defer decisions on the award of major projects, as they sought greater market visibility and remained focused in the short-term, on optimising cash.
Both companies were focused on the need to respond to these conditions, aligning their size and cost bases to the anticipated market demand. It was also a period where we were able to capitalise on opportunities when they presented themselves, such as the acquisition of Borealis .
As confidence returned, supported by an improving global economic climate and strengthening oil price, the industry began to see some of the major projects that had been delayed come to award.
Combined strength
The awards of increasingly large and complex projects was also helpful in supporting the long-recognised industrial rationale for combinations in our industry.
The Combination presents an exciting opportunity for our shareholders, our clients and our people. We are pleased to note the positive reaction to the Combination we have received from many of our clients, particularly the larger operators. The benefits of the Combination are as valid today as they were in June of last year when we announced the decision to combine. We believe this Combination will benefit all stakeholders, not least our clients to whom we bring larger resources, access to a greater depth of expertise, a more diversified fleet and enable us to meet their needs of safe and efficient operations in increasingly harsh and challenging environments.
We have a stronger combined balance sheet and better access to new capital if required. We are focused on cost and ensuring that we maintain a competitive cost level and are efficient in all areas of our business. Our enhanced operational capability will provide further personal development and growth opportunities for our people. The excellent strategic fit of the two companies should enable us to deliver enhanced long-term value for all stakeholders.
Growth opportunities
With the Combination complete, the new Subsea 7 is well positioned to move forward. We are the main contractor in our field; with a truly global organisation of 12,000 employees and able to offer our clients a step-change in service offering. We can better meet the growing size and technical complexity of subsea projects, driven by the demand to access ever more remote reserves in increasingly harsh environments.
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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We are confident in the future and are excited about the opportunities in our industry. We will not become complacent and are committed to ensuring that the integration activities that are proceeding well do not distract us from our focus on delivering excellence in our operations, whilst we minimise risk and concentrate on safety.
The new Subsea 7 is built on strong values: Safety, Integrity, Innovation, Performance and Collaboration. These values recognise the key principles of honesty, predictability and longevity, principles which we believe are required for any organisation to be successful. Our objective is to be the contractor of choice based on quality and a predictable operation.
Safety remains the core value of the Group. 2010 has sadly reminded us of this fact only too clearly. The tragic events in the Gulf of Mexico last spring reminded us of the need to drive for the highest safety standards. Our track record for 2010 was good and we continue to strive for improvements.
Preparing for the future Both companies bring with them a strong heritage. The new Subsea 7 is the product of experience gained over many years. The challenge is now to ensure that our inherited strengths are nurtured to capitalise on the opportunities that lie ahead while maintaining a disciplined approach to risk.
We have recently announced our intention to delist from NASDAQ and to deregister and terminate our reporting obligations under the US Securities and Exchange Act, as soon as we are eligible to do so. Following the completion of the Combination, an increasing proportion of our worldwide trading volume is conducted through the Company’s common shares listed on the Oslo Børs. We believe that the costs and expenses associated with maintaining a dual listing, including Exchange Act reporting obligations, outweigh the benefits of continuing the US listing and registration. We believe the delisting and deregistration will free up management time, reduce costs and complexity without detracting from our standards of governance and controls. |
2011 will present challenges: the reduced number of projects awarded during 2009 and 2010 and the challenging pricing environment and market conditions during this time are expected to impact margins in 2011, despite higher activity levels. The medium to long-term outlook, however, remains positive and we are optimistic about the outlook.
I speak on behalf of the whole Board when I say that we are fortunate to have a highly experienced Executive Management team in place. Led by Chief Executive Officer, Jean Cahuzac, he and his colleagues can count on the support and guidance of the Board. On behalf of the Board, I would like to record my thanks for the significant contributions made by the outgoing Board members of both Acergy S.A. and Subsea 7 Inc. during their tenures.
During this period of change, I would also like to thank our people and acknowledge their considerable efforts. The strong performance in 2010 could not have been delivered without the continued efforts of our global workforces, both onshore and offshore. We thank you for your daily contribution to our safe and efficient operation.
Having the best people in our business will help us achieve our vision of taking leadership as the seabed-to-surface engineering, construction and services contractor based on delivery of quality and predictability. Never before have we been stronger. Together we shall build on this position and lead the industry forward.
Kristian Siem Chairman |
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15
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Business Review
Chief Executive Officer’s Review
Delivering the next generation
of subsea projects
2010 was an excellent year for the Group. Our safety results continued to improve, we delivered strong operational and financial results, secured key contracts around the world and increased our backlog. We remain on track with our fleet enhancement and renewal plans and announced the combination between Acergy SA. and Subsea 7 Inc.
Reflecting on our operational and financial performance
Our focused and disciplined approach has allowed us to deliver excellent execution for our clients in a safe and consistent manner. During 2010, Subsea 7 S.A. (formerly Acergy S.A.) successfully completed a number of important projects, including the Block 15 SURF Project in Angola, the EPC4A Conventional Project in Nigeria, the Pluto and Pyrenees Projects in Australia, the second Roncador Manifolds Project in Brazil, to name but a few and over a dozen projects in the North and Norwegian Seas. This performance is reflected in our strong financial results.
A long-term growing market
Commodity prices stabilised somewhat during 2010 but ongoing uncertainty over the prevailing economic backdrop meant clients continued to behave cautiously for a sizeable part of the year delaying the award of major projects. As confidence returned, supported by an improving global economic climate and more visibility on the oil price trend, the industry began to see some of the major projects, that had been delayed, come to market award in the latter part of the year.
We are looking forward to 2011 with confidence. A robust oil price and rising tendering activity around the world underpins order book momentum. Execution and activity levels are expected to rise, although contracts awarded in more challenging market conditions during 2009 and 2010 will impact the Group’s Adjusted EBITDA margin in 2011.
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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A number of the major SURF contracts, in Australia, Brazil, West Africa and other countries are expected to come to market award in the coming months. The offshore installation phase of most of these new projects will commence beyond 2011 and in some cases beyond 2012. Conventional activity in West Africa is expected to remain strong in the short and medium-term.
We remain optimistic about the outlook for our business as the medium and long-term fundamentals remain robust. Our clients are committed to strategic projects in deepwater and harsh environments. As they seek to grow production, they face multiple challenges including low reserve replacement ratios, high underlying decline rates on producing fields and oil becoming more difficult to produce as reservoirs are deeper and in more remote and less accessible areas. We believe the trend will be for subsea projects to continue to increase in size and complexity. This will contribute to strong industry growth for those companies that have the capabilities to execute such projects in a consistent, reliable and cost effective manner.
Positioning the Group for the future
Building backlog with a disciplined long-term approach In 2010, we have maintained a disciplined approach to managing our risk profile for all projects, with the right contract terms, ensuring that we achieve an appropriate return on large multi-year contracts. We were very pleased to announce in July the award of the CLOV Project, offshore Angola. At $1.3 billion it is our largest project award to date. We continue to see good growth potential in SURF activities and anticipate a number of major contracts coming to market award in 2011.
Driving long term efficiencies We have continued to optimise our costs and improve our processes without impeding our ability to grow when the market returns to growth. Training and developing our people has remained a priority as we maintained our recruitment efforts in Engineering and Project Management.
Enhancing our fleet Our strong balance sheet and actions have enabled us to capitalise on investment opportunities and our fleet enhancement programme is on track.
For Subsea 7 S.A. (formerly Acergy S.A.) this is most evident in our acquisition of Borealis, Antares, Polar Queen and Pertinacia. |
Borealis is a versatile high-specification vessel for operations in deepwater and harsh environments worldwide. Building costs are expected to be approximately $500 million, funded entirely from the Group’s existing cash resources. Work is progressing well and she is on track and on budget to join our fleet in the first half of 2012.
Antares, a new build shallow-water barge pipelay and hook-up projects in West Africa, commenced operations in Nigeria during the fourth quarter. Polar Queen and Pertinacia are two pipelay and subsea construction vessels, which originally joined the fleet in 2006 and 2007 on long-term charter and which are currently on long-term agreement with Petrobras in Brazil. Total costs for these three vessels were approximately $190 million, funded from the Group’s existing cash resources.
In addition, during the second half, we also completed major dry-docks on Acergy Condor and Acergy Harrier, prior to their commencement of new contracts in Brazil.
In 2010 Subsea 7 Inc. also achieved significant progress, completing their five year $1 billion fleet enhancement programme with the delivery of two new builds, Seven Atlantic and Seven Pacific. Both vessels are state-of-the-art pipelay and construction ice-class vessels suitable for unrestricted operation worldwide. They commenced operations in the first and fourth quarter of the year, respectively.
In the first half of 2011 we expect to take delivery of two new vessels with our Joint Venture partners. Seven Havila, a newbuild diving support vessel, and Oleg Strashnov a second heavy lifting vessel for SHL.
Developing local content A strong local presence is essential and is a competitive advantage in many parts of the world. Onshore, the global operations of the new Group already include an extensive infrastructure of pipeline spool bases, fabrication and operations support yards. These strategically-positioned assets, in conjunction with a network of local partners, are central to our objective of developing strong and sustainable local businesses. We are also focused on recruiting talent that reflects our geographical development and ambitions, and in establishing a real integrated presence in key growth countries such as Angola, Australia, Brazil, Malaysia and Nigeria. |
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Business Review
Chief Executive Officer’s Review continued
The announced Combination between Acergy S.A. and Subsea 7 Inc.
The Combination is an excellent strategic fit which is supported by industry fundamentals. The combined Group will benefit from the value created by the combination of our people and expertise. With a combined backlog of $6.4 billion and an industry leading fleet of 42 vessels supported by extensive fabrication and onshore facilities, we will be very well positioned to deliver enhanced long-term value for our clients, our people and all stakeholders.
Integration is on track following completion of the transaction on January 7, 2011. Our integration teams, comprising employees from both legacy businesses, are working together collaboratively. Since the Combination, I have spent a lot of time visiting the different parts of our combined business and I have been very impressed by the positive attitude of the people that I have met and by their determination to make the Combination work.
At the time of the announcement of the Combination, we indicated that we expected to deliver a run rate of at least $100 million of synergies by 2013. I am confident that we will achieve this objective.
Conclusion
We see signs of improvement in our markets and rising levels of confidence among our clients.
We have world-class engineering and project management and the right fleet of assets to support our clients’ needs in all region and all water depths. Reflecting on our successes of the past year including the significant milestone of the Combination we are proud of what we have achieved and we will continue to leverage our global capabilities to capture more business opportunities.
We believe the next generation of projects will be more remote and technically ever more demanding. Oil companies will require offshore services contractors on a global scale, able to field an outstanding team of talented and experienced engineers, supported by extensive project management expertise and the right fleet of world-class assets. The new Subsea 7, drawing fully on the heritage of both legacy businesses, will meet that need.
We are very well positioned and have an exciting future ahead.
In conclusion, I would like to thank our clients for their confidence and support as well as our employees for the dedication and commitment that they have shown in a demanding year.
Jean Cahuzac
Chief Executive Officer
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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Business Review
Market Review
Strong fundamentals driving
medium and long-term growth
The medium and long-term fundamentals for the oil and gas industry remain strong driven by increasing global demand, higher decline rates on producing fields and the need to access challenging new reserves to replenish current production.
The International Energy Agency (IEA) forecasts global energy demand to increase 36% between 2008 and 2035. Strong growth in demand is forecasted by non- OECD countries, which are expected to account for over 90% of this total increase, led by China. In fact, the IEA’s preliminary data suggests that China overtook the US in 2009 to become the world’s largest energy user despite its low per capita energy use. Oil demand continues to grow steadily, reaching about 99 million barrels per day (mb/d) by 2035, 15 mb/d higher than in 2009, driven by growing demand from non-OECD countries, especially China.
During the period to 2035, other sources of energy are also expected to increase, including unconventional gas and coal, especially in the US, nuclear and renewable energy. The rapidly emerging market for renewable energy is expected to play a central role in reducing carbondioxide emissions and diversifying energy supplies. The share of modern renewable energy sources, including sustainable hydro, wind, solar, geothermal and marine energy, in global primary energy use is expected to triple between 2008 and 2035 and their combined share in total primary energy demand is expected to increase to 14%, according to the IEA. However, even allowing for the most optimistic assumptions about the development of renewable technology, greater consumption of renewable energy and the abatement arising from actions taken to reduce CO 2 emissions, oil and gas are expected to remain the world’s main source of energy for many years to come.
Since 2008, the worldwide economic recession has slowed the rate of growth of energy consumption. While concerns over the economic outlook and the desire for greater market visibility led most major oil companies to delay capital expenditure until confidence returned. This resulted in many new major offshore project awards being delayed for a period of nearly two years. As a consequence the major oil companies lowered their medium-term growth outlook. However, this lower near-term capital expenditure, has resulted in most struggling to achieve production growth beyond 1% in the medium-term.
Consequently, oil companies continue to face the combined challenges of:
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low reserve replacement ratios. The current three-year moving average is slightly above 100%, representing a slight improvement from the low level experienced from 2004 to 2006. However, these figures have also been supported by the absence of production growth in the same period. |
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high underlying decline rates on producing fields. More and more of the world’s oil fields have entered into peak production and are in rapid decline. Russia and Mexico are now declining areas, in addition to the North Sea and the US, which have seen dwindling production for a while. According to the IEA analysis of the world’s 500 largest fields, the underlying average production-weighted observed rate of decline, worldwide, was 7% for those fields past the peak of production. |
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oil production becoming more challenging, as reservoirs become deeper, in more remote and less accessible areas, coupled with fewer large discoveries. |
To address these challenges, oil companies need to access increasingly challenging new reserves to replenish production. One such new frontier is expected to be deepwater, where there have been important discoveries lately, including Brazil, the US Gulf of Mexico and West Africa. These discoveries present greater technical challenges and higher exploration and production costs. According to Barclays Capital, this is expected to result in an 11% increase in global exploration and production capital expenditure, which is expected to increase to $490 billion in 2011. Of this amount, offshore and in particular deepwater, production capital expenditure, is expected to grow significantly faster than that of onshore or shallower water.
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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These factors suggest a continued strong demand for the types of services and specialist activities provided by Subsea 7 in the medium and long-term. The demand for services in the offshore engineering, construction, and maintenance (OECM) market is global in nature, and is driven by the global nature of the oil and gas markets. Consequently most market participants operate on a worldwide basis. The industry has remained competitive, with competition arising from established offshore contractors, as well as from smaller regional competitors and less integrated providers of offshore services. In recent years a number of contractors, as well as pure ship owners, have placed orders for additional ships capable of working in the offshore OECM market which might cause an excess of supply adversely affecting the demand for services in the near-term.
Despite recent macroeconomic events, delays in contract awards, delays arising from the Macondo incident in the US Gulf of Mexico and increased capacity, Subsea 7 expects to see a continued expansion of demand for its services in the medium to long-term. While increased exploration and technological improvements have resulted in higher annual levels of oil discoveries, including some recent significant finds such as the deepwater pre-salt fields offshore Brazil, the demand for oil, and production capacity of the oil business, suggests a tight market with a low reserve replacement ratio, exacerbated by accelerating decline rates for mature fields.
Subsea 7’s largest activity relates to the installation of infrastructure related to subsea trees or floating production platforms, including pipelines, risers, umbilicals, moorings and other subsea structures such as manifolds. Subsea 7 expects the demand for these activities in the medium and long-term to remain strong. Leading indicators of demand for subsea projects support this view. A significant number of multi-year deepwater drilling contracts were awarded during 2007 and 2008, typically lasting 3 to 5 years. These drilling contracts represent a significant investment on behalf of the major oil companies and it is expected that most of these contracts will, in time, lead to subsea projects. However, there have been significant delays in the award of the associated subsea contracts in the offshore market over the past two years, representing future growth potential for the offshore engineering, construction and maintenance market as a whole. |
The number of subsea trees scheduled for installation is a further lead indicator of growth in demand for subsea projects in any given year. 2009 and 2010 saw a significant decrease in the number of trees installed due to the delay in contract awards resulting from the challenging macro environment. The combination of manufacturer investment and medium-term growth in the demand by major operators in the offshore oil and gas market suggests positive growth. Infield Systems Ltd forecasts that the total volume of EPIC project activity is expected to increase by 60% over the next five years compared to the previous five years, with developments in water depths greater than 500 metres expected to grow at the fastest rate. Quest Offshore, a market research firm, is forecasting awards of close to 600 trees in 2012 on a global basis. This level is around 40-50% above 2006-2008 average levels. The installation of more subsea trees, as well as the shift to deeper water depths, is expected to continue to drive growth in the market for the subsea contractors.
The demand for Life-of-Field projects has traditionally focused on mature subsea infrastructure in the North Sea and the US Gulf of Mexico, of which the latter has often been driven by hurricane repair work. The continued increase in the installation of subsea equipment, suggests that the level of operating expenditure required to undertake inspections by specialist survey assets and to maintain and repair previously installed and new infrastructure will also increase. This has important implications for Life-of-Field projects, where growth is expected in the medium and long-term. Furthermore, this sector is expected to become more global in nature, following the trend of increasing globalisation of the OECM market.
Activity in subsea projects has been cyclical. The increasing size and complexity of projects, together with external factors including national oil company approval, financial arrangements for the field operators, and the timing of the various development and exploration phases for these fields, suggest that the fundamentals going forward are strong but the exact timing of awards will remain difficult to predict. |
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Business Review
Operating Review
Africa & Gulf of Mexico (AFGoM 1 )
West Africa and the Gulf of Mexico form two of the three pillars of the ‘Atlantic triangle’. In West Africa, Angola’s offshore deepwater production is expected to double to over three million barrels of oil equivalents per day by 2015, subject to OPEC quotas. Contract awards for Nigeria’s significant deepwater offshore reservoirs have continued to experience delays, however awards are expected to be announced during 2011 and beyond. In addition, the requirement to eliminate gas flaring will lead to a number of initiatives in this region, as demonstrated by the development of the Angola LNG plant in Soyo and the associated gas gathering system for blocks 0, 14, 15, 17 and 18.
| 1 |
AFGoM primarily comprises the following previously disclosed business segments: Acergy AFMED, Acergy NAMEX, Subsea 7 Africa and Subsea 7 North America. |
| 2 |
2010 Highlights present highlights for Acergy S.A. and Subsea 7 Inc. in fiscal year 2010, prior to the Combination in January 2011. |
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Revenue from continuing operations for fiscal year 2010 for Acergy AFMED, Acergy NAMEX, Subsea 7 Africa & Subsea 7 North America. |
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Backlog as at end fiscal year 2010 for Acergy AFMED, Acergy NAMEX, Subsea 7 Africa & Subsea 7 North America. |
The demand for shallow water activity in West Africa has traditionally focused on mature infrastructure in Nigeria. To maintain and increase current production levels requires material expenditure which presents opportunities for refurbishment work on the extensive array of shallow water platforms and associated pipelines in West Africa. With over 100 shallow water platforms in Nigeria alone requiring refurbishment works in the coming years, it is expected that this sector will remain strong in the near and medium term, with Nigeria and Angola expected to remain key geographies for these activities.
The Gulf of Mexico is one of the most prolific hydrocarbon basins in the world. Events arising from the Macondo incident in 2010, led to delays in contract awards, and permitting issues. However, development of the region’s ultra deepwater fields, in close to 10,000 feet (some 3,000 metres) of water is expected to lead to significant future opportunities. These lower tertiary developments present technological challenges and require substantive innovation to provide the engineering and construction solutions that our clients require.
Opportunities for the future
Subsea 7, has successfully executed a broad range of complex deepwater and ultra-deepwater projects in West Africa and the Gulf of Mexico. In West Africa, we have developed advanced technological solutions for our clients which have been supported by successful execution, including installation of the world’s largest Hyperflow ® Riser Tower bundle at 1,200m long x 2.3m diameter, weighing 4,200T. Our shallow water business, focused on West Africa, has also been awarded a number of conventional contracts including in Angola, EPC4A and in Nigeria, EGP3B and Oso Re.
Completion of the Perdido and Independence Hub Projects, including the installation of the deepest umbilicals in the world in 2,941m water depth in the Perdido Field and in almost 2,750m water depth at Independence Hub, demonstrates Subsea 7’s ability to execute successfully in the ultra deepwater of the Gulf of Mexico.
We have considerable local capabilities in Angola and Nigeria and a strong track record. We have invested significantly in developing local expertise and innovative capability in our people and fabrication yards. During 2010, Subsea 7 was awarded the company’s largest ever EPIC SURF project at $1.3 billion on the CLOV Development, offshore Angola. We see our long-term local presence as a priority and key strength which, together with our track record positions us well to capture future opportunities.
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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Asia Pacific & Middle East (APME 1 )
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Asia Pacific represents a significant area for future growth of offshore field developments. Strong and rapidly growing demand for energy is driving offshore oil and gas exploration and development in the Asia Pacific region notably in Malaysia, Indonesia, India, China and Australia’s Northwest Shelf. Development activity in the region is expected to grow sharply to exploit untapped deepwater resources, providing growth opportunity to highly specialised contractors able to operate in deepwater and challenging environments.
This region is also set to become a major area of liquefaction facility construction for the provision of LNG. The Northwest shelf offshore Australia currently comprises predominantly gas driven developments. Australia has the potential to become one of the largest global suppliers of LNG. With fourteen proposed new LNG developments, in addition to Gorgon and PNG LNG Australasia, more than $110 billion is expected to be spent over the next decade on liquefaction facilities.
1 APME primarily comprises the following previously disclosed business segments: Acergy AME and Subsea 7 Asia Pacific.
2 2010 Highlights present highlights for Acergy S.A. and Subsea 7 Inc. in fiscal year 2010, prior to the Combination in January 2011.
3 Revenue from continuing operations for fiscal year 2010 for Acergy AME & Subsea 7 Asia Pacific, excluding revenue from associates and non-consolidated JVs.
4 Backlog as at end fiscal year 2010 for Acergy AME & Subsea 7 Asia Pacific, includes share of backlog from SapuraAcergy. |
The shallow continental shelf has presented many opportunities to date. However, the size and scale of future developments is expected to require greater expertise and resources to address the challenges of increasingly larger and deeper projects, coupled with the complexities presented by the large-scale gas developments offshore, Australia.
Opportunities for the future Subsea 7 has successfully completed a broad spectrum of projects throughout the Asia Pacific region, including Malaysia, Vietnam, Japan, Australia and New Zealand. The increased scale and resource base of the Group is expected to present opportunities to optimise resource allocation across the Group to this region and to provide clients with advanced solutions and versatile assets to support their future developments.
Our joint venture, SapuraAcergy has successfully commenced offshore operations on the Gumusut Project, the first of the major deepwater projects in Malaysia. With high local content, a growing track record following successful project completions in India, Japan and Australia, SapuraAcergy has demonstrated its ability to deliver excellence from design to delivery, with strong execution using one to the world’s most advanced pipelay and construction vessels, Sapura 3000 .
The Group is dedicated to leveraging its expertise and experience to create innovative solutions for our clients, the world’s national, international and independent oil and gas companies. Our client base, experience and industry knowledge means we are well positioned to anticipate market developments and prepare for future tendering of major contracts as existing and new basins reach development milestones.
Over the coming years, we believe access to new oil and gas reserves are expected to become increasingly challenging and complex, presenting many new opportunities in the significant and diverse Asia Pacific region, where we have an established presence, high local content and increasingly strong track record. |
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Business Review
Operating Review continued
Brazil (BRAZIL 1 )
The pre-salt discoveries in deepwater, offshore Brazil represent a substantial opportunity for the industry. Brazil’s national oil company, Petrobras’ total planned investment for the period 2010 – 2014, show significant increases over the previous five years with the largest increase focused on investment in offshore E&C activities. With some $50 billion earmarked for new upstream projects focused on new production systems at Campos Basin, the start of the Santos Basin pre-salt development and accelerating the development of the Espirito Santo pre-salt (Parque das Baleias). Pre-salt production is expected to account for nearly 50% of Petrobras’ production by 2020, from nil in 2008.
| 1 |
BRAZIL primarily comprises the following previously disclosed business segments: Acergy SAM and Subsea 7 Brazil. |
| 2 |
2010 Highlights present highlights for Acergy S.A. and Subsea 7 Inc. in fiscal year 2010, prior to the Combination in January 2011. |
| 3 |
Revenue from continuing operations for fiscal year 2010 for Acergy SAM & Subsea 7 Brazil. |
| 4 |
Backlog as at end fiscal year 2010, for Acergy SAM & Subsea 7 Brazil. |
Opportunities for the future
Subsea 7 has a strong presence in the traditional offshore field developments in the Santos basis. Through the provision of highly specialised pipelay vessels, Subsea 7 has supported Petrobras for some 20 years in offshore construction. In May 2009, Pertinacia completed work on the deepwater flexible lines to enable Petrobras to achieve ‘first oil’ on the Tupi Field, representing a key milestone for the pre-salt fields. Following production on this extended well test, Petrobras has subsequently announced favourable results from other reservoir tests; including the Guara reservoir that responded extremely well to flow testing. It is expected that the Guara and Tupi NE SURF contracts will be awarded to the industry in 2011.
Subsea 7 has a proven track record of execution in Brazil. Highly specialised world-class pipelay and construction vessels are supported by extensive fabrication and onshore facilities. Subsea 7 is well positioned to deliver the full spectrum of subsea engineering, construction and services to its clients in Brazil.
Whether through the provision of the advanced technology of the rigid risers, fixed by a floating buoy, with flexible risers or the hybrid riser tower technology, proven in West Africa, Subsea 7 is expected to be well positioned to support it clients’ needs in addressing the complex challenges presented by the sour and waxy hydrocarbon content, together with the challenges of water depth presented by the pre-salt field developments.
Traditionally, Petrobras has favoured the use of flexible flowlines, resulting in Brazil representing a significant part of the total market for flexible flowlines. Through its joint venture, NKT Flexibles, Subsea 7 is able to play an important part in meeting its clients needs in this area of the market. This strategic partnership, enabling a symbiotic relationship between manufacturing and installation expertise, further supports Subsea 7’s strong local position.
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North Sea, Mediterranean & Canada (NSMC 1 )
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The North and Norwegian Seas have long been an important market for offshore construction contractors. After decades of exploration and production, the developed infrastructure allows fast-track development from discovery to production. Recent prominent discoveries, in one of the most explored areas, shows that with new technology, new concepts and advanced geology, new resources can be found.
1 NSMC primarily comprises the following previously disclosed business segments: Acergy NEC and Subsea 7 North Sea.
2 2010 Highlights present highlights for Acergy S.A. and Subsea 7 Inc. in fiscal year 2010, prior to the Combination in January 2011.
3 Revenue from continuing operations for fiscal year 2010 for Acergy NEC & Subsea 7 North Sea.
4 Backlog as at end fiscal year 2010 for Acergy NEC & Subsea 7 North Sea. |
It is expected that with time, the harsh and extremely challenging environments of the Barents Sea, and eventually the Arctic will be within the technological capabilities of the industry and the realisable ambitions of our clients.
As older infrastructure comes to the end of its original design life, and new increasingly complex subsea infrastructure is installed, the Life-of-Field market is forecast to grow significantly.
The challenges facing the major oil companies today include increasing decline rates of existing fields and the growing proportion of smaller fields under development. These factors, prevalent in the North Sea and on the Norwegian Continental Shelf, are leading clients to increase levels of standardisation of field development and to seek to reduce the time lapse between final investment decision contract awards and production.
Opportunities for the future Subsea 7 delivers a full suite of services across all categories of Life-of-Field work, including inspection, maintenance and repair, integrity management and remote intervention. Supported by proven project management capability, technical expertise and new technologies, these services can be provided using either Subsea 7 owned or client-supplied vessels.
Subsea 7 has a world-class track record in Life-of-Field activities worldwide. As demonstrated by many long-running contracts, including in the North Sea frame agreements for Shell, ConocoPhilips, Total, the BP Inspection contract, which has run for over 15 years, and the recently awarded multi-year diving support vessel services contract to the DSVi Collective of companies in the North Sea.
Subsea 7’s services are enhanced by working with industry partners and our clients in developing and delivering cutting-edge products and technologies to support their ongoing needs. As the focus for development moves to the Barents Sea and more frontier territories, such as the Arctic, the challenges faced by the subsea contractors increase. Our versatile fleet is capable of operating in the world’s most challenging environments.
Despite challenging market conditions and lower activity levels during 2009 and 2010 the North Sea and Norwegian Seas are expected to present prospects for future growth. With an increasing need to deliver technically challenging contracts efficiently, the market represents a growth opportunity for Subsea 7 in the medium and long-term. |
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Risk
Managing risks
and uncertainties
Effective management of risk and opportunity is essential to the delivery of the Group’s vision, achievement of sustainable shareholder value and protection of its reputation. The Board acknowledges its responsibility for the oversight of the Group’s system of internal control and for reviewing its effectiveness.
The Board has ultimate responsibility for the effectiveness of the Group’s risk management activities and internal control processes. Any system of internal control can provide only 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 Board’s objective is to ensure Subsea 7 has appropriate systems in place for the identification and management of risks, while ensuring that within a given risk appetite, the business is able to optimise enterprise value.
Management-Based Assurance
The Executive Management Team is responsible for monitoring and managing operating and enterprise risk, in accordance with the level of risk the Group chooses to take in pursuit of its business objectives, and where possible, mitigating the various risks facing the business. These activities fall into the following categories:
Market Risks
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Market intelligence gathering |
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Dedicated Relationship Manager for each major client |
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Comprehensive fleet rejuvenation programme |
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Cost reduction initiatives |
Strategic Risks
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Analysis of ownership vs. lease of new assets |
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Organisational restructuring |
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Use of joint ventures or consortium for higher-risk projects |
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Long-term scenario planning |
Operational Risks
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Regular reviews of insurance cover |
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Critical asset management programme |
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Regular supplier and sub-contractor audits |
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ISO 9001 quality compliance audits |
Financial Risks
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Annual financial reporting risk self-assessments |
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Annual reviews of uncertain tax positions |
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Financial training and development programmes |
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Regular testing of key internal controls |
Compliance Risks
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Whistleblower hotline for all employees |
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Annual fraud risk self-assessments |
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Published Code of Conduct |
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Anti-corruption compliance committee |
For a further discussion, refer to ‘Risk Factors’ on page 28.
Commercial Assurance
Marketing of our services is performed through our Territories and regional offices, and most of our work is obtained through a competitive tendering process. When a target project is identified by our marketing teams, the decision to prepare and submit a competitive bid is taken by management in accordance with delegated authority limits. 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.
Formal review process: Before the tender package is submitted to the client, it is subject to a disciplined review process. Tenders are first reviewed at the Territory level where the technical, operational, legal and financial aspects of the proposal are considered in detail. Completion of the territory review process requires the formal approval of the Senior Vice-President of the Territory, followed by a detailed review by the appropriate Tender Review Board, depending on tender value.
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Risk Framework
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— Tenders with values below $50 million require approval from the Territory Senior Vice President.
— Tenders with values between $50 million and $100 million require approval from the Executive Vice President – Commercial.
— Tenders with values between $100 million and $250 million require the further approval of the Chief Executive Officer.
— Tenders in excess of $250 million require a further review and approval of the Board.
Risk management: A formal risk assessment is performed for each project for which we intend to submit a tender. The assessment consists of a legal risk assessment that compares the contractual terms and conditions of the proposed tender to our standard terms and conditions. The financial impact of any deviation from our standard terms and conditions is quantified and a risk mitigation plan is proposed. In addition, an operational risk assessment is conducted that analyses factors such as the impact of weather, supplier delays, industrial action and other factors to quantify the potential financial impact of such events. In addition, Internal Audit reviews tenders for compliance to standard terms. |
Standardisation of approach: The implementation of standard tendering policies has resulted in the information contained in tender review packages being uniform across the organisation, allowing the relative risks and benefits of tendering for various projects to be assessed. As projects continue to increase in size and complexity, a larger proportion of tenders are reviewed centrally by Executive Management and great emphasis is placed on adherence to the standard contractual terms and conditions. With these policies in place, a significant amount of management time is devoted to the tendering process and, given the costs associated with the tendering process, management is selective of the initiation of new tenders, focusing on those tenders it believes it is well placed to win and which will deliver a positive financial return.
Variation orders: The Group’s policy is not to undertake variations to work scope without prior agreement of scope, schedule and price. A tender board appointed to supervise each tender can decide whether or not to deviate from this policy. It is customary that, where a variation to the project scope or specifications is required, execution of the project usually continues through to completion. These often give rise to claims and variation orders, which will be negotiated with the client during the ordinary course of the project, although settlement may follow the completion of the offshore activities. |
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Internal Controls
The Board acknowledges its responsibility for the oversight of the Group’s system of internal controls and for reviewing its effectiveness. The Group’s system of internal controls is designed to manage rather than eliminate the risk of failure to achieve business objectives. It provides reasonable but not absolute assurance against material misstatement or loss.
Internal Audit is responsible for the independent review of risk management and the Group’s control environment. Its objective is to provide reliable, valued and timely assurance to the Board, the Audit Committee, the Chief Executive Officer and the Executive Management Team over the effectiveness of controls, mitigating current and evolving high risks and in so doing enhancing the controls culture within the Group. In particular Internal Audit assists Executive Management by carrying out independent appraisals of the effectiveness of the internal control environment and makes recommendations for the improvement, and supports the Group’s business management policies. The Audit Committee reviews and approves Internal Audit’s programme and resources, reviews and discusses major findings of audit reviews together with management responses and evaluates the effectiveness of Internal Audit.
External advisors, from time to time, provide advice to the Board on issues related to corporate governance such as reviewing board effectiveness and insurance cover.
The Group’s Executive Management, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, believes that as of November 30, 2010 the Group’s internal control over financial reporting was effective.
Management’s Report on Internal Control over Financial Reporting, as well as an attestation Report from our Independent Auditor’s is part of our Annual Report on Form 20-F for fiscal year 2010, which will be filed with the SEC (see ‘Cross reference table’ on page 171). The Group intends to maintain its focus on improving the control environment within the business and considers it to be a key pillar contributing to an appropriate financial strategy.
As of November 30, 2010 no material weaknesses had been identified. For ongoing monitoring of the progress of Sarbanes-Oxley compliance project, regular Sarbanes- Oxley Steering Committee meetings are held. Members of the Steering Committee include the Chief Financial Officer, the Group Financial Controller and the Head of Internal Audit. In addition, representatives from our Independent Auditor’s are invited to attend certain meetings.
There has been no change in our internal control over financial reporting that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
The Board derives further assurance from the reports from the Audit Committee, which has been delegated
responsibility to review the effectiveness of the internal financial control systems implemented by management and is assisted by Internal Audit.
The Group carried out an evaluation under the supervision, and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of disclosure controls and procedures as at November 30, 2010. Management are satisfied that disclosure controls and procedures were effective.
Risk Factors
The following factors and the other information contained in this Report should be carefully considered. The following is a description of the risks that may affect some or all of our activities and which may affect the value of an investment in our securities. If any of the events described below occurs, the business, financial condition or results of operations of the Group could be adversely affected in a material way. 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 business, results of operations and financial condition.
Market Risks
The Group’s business is affected by expenditure by participants in the oil and gas industry.
Demand for the Group’s services depends on expenditure by participants in the oil and gas industry and particularly on capital expenditure budgets of the companies engaged in the exploration, development and production of offshore oil and gas. Should a major (and/or several small or medium) international or national oil and gas company(ies) significantly scale back their project expenditure programme, or delay, change the scope of, or cancel projects already included in the Backlog of the Group, this may have adverse effects on the Group’s revenue and profits.
Offshore oil and gas field capital expenditures are also influenced by many other factors beyond the Group’s control, including:
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prices of oil and gas and anticipated changes in world oil and gas demand; |
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the discovery rate of new offshore oil and gas reserves; |
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the economic feasibility of developing particular offshore oil and gas fields; |
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the production from existing producing oil and gas fields; |
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political and economic conditions in areas where offshore oil and gas exploration and development may occur; |
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governmental regulations regarding environmental protection and the oil and gas industry generally, including policies regarding the exploration for, pricing and production and development of their oil and gas reserves; and |
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the ability of oil and gas companies to access or generate capital and the cost of such capital. |
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The Group faces competition both for contracts and for resources.
Contracts for the Group’s services are generally awarded on a competitive bid basis, and although clients may consider, among other things, the availability and capability of equipment and the reputation and experience of the contractor, price is a primary factor in determining which contractor is awarded a contract.
Competition could result in pricing pressures, lower sales and reduced margins that would have an adverse effect on the operating results, cash flows and financial condition of the Group. The Group may experience constraints in its supply chain due to future increases in expenditure by their clients in the industry which could lead to increased competition for resources, such as raw materials, equipment and skilled workers. Such supply chain bottlenecks or limited availability of resources could negatively affect the results of operations of the Group. For more information, please refer to ‘Additional Information – Competition’.
The Group depends on certain significant clients and long-term contracts.
The loss of any one or more significant clients, or a failure to replace significant long-term projects on similar terms, or a substantial decrease in demand by the Group’s significant clients, could result in a substantial loss of revenue which could have a material adverse effect on the business of the Group. For more information, please refer to ‘Additional Information – Clients’.
The offshore oil and gas operations of the Group could be adversely impacted by certain consequences of the Macondo incident and resulting oil spill.
To date, the Group has not experienced a material impact on its operations as a result of the Macondo incident. However, at this time, the Group cannot predict what future impact, if any, the incident may have on the regulation of offshore oil and gas exploration and development activity in the US Gulf of Mexico or elsewhere (including the imposition of a moratorium on exploration or development in certain regions), the cost or availability of insurance coverage to cover the risks of such operations, or what actions may be taken by clients of the Group or other industry participants in response to the incident or its potential consequences. Increased costs for the operations of the Group’s clients in the US Gulf of Mexico or in other areas, along with possible delays to obtain necessary permits, could negatively affect the economics of currently planned activity in these areas and demand for the Group’s services, and may result over the long-term in a shift in activity away from these areas. A prolonged suspension of drilling activity in the US Gulf of Mexico or in other areas and resulting new regulations in or similar regulatory action in the US or other regions could adversely affect the award of future deepwater projects, which may in turn negatively affect the Group’s financial condition, results of operations or cash flows. |
Strategic Risks
The Group’s international operations are exposed to political, social and economic instability in the developing countries in which the Group operates, and other risks inherent in international business.
Many of the Group’s operations are performed in emerging markets. Operations in these emerging markets present risks including:
— economic and political instability;
— increased risk of fraud and political corruption;
— boycotts and embargoes that may be imposed by the international community;
— requirements of local ownership of operations and requirements to use local suppliers or subcontractors;
— disruptions due to civil war, terrorist activities, piracy, labour unrest, election outcomes, shortage of commodities, power interruptions or inflation;
— the imposition of adverse tax policies; and
— exchange controls and other restrictions by foreign governments.
Such events could cause cost overruns on projects for which the Group is not reimbursed and sharing of revenues where local ownership is required. Additionally, these factors could delay the completion of projects resulting in contractual penalties and the unavailability of assets that are needed elsewhere. Political or social instability could also reduce growth opportunities for the Group’s business. It may also lead to the loss of or damage to assets, including due to acts of piracy.
Further, operations in developing countries are subject to decrees, laws, regulations and court decisions that may change frequently or be retroactively applied and could cause the Group to incur unanticipated or unrecoverable costs or delays. The legal systems in developing countries may not always be fully developed and courts or other governmental agencies in these countries may interpret laws, regulations or court decisions in a manner which might be considered inconsistent or inequitable in the United States or Western Europe, and may be influenced by factors other than legal merits, which could have a material adverse effect on the Group’s business and financial results.
The Group must continuously improve technology and equipment to compete for business and avoid asset write-downs.
The Group’s clients seek to develop oil and gas fields in increasingly deeper waters and more challenging offshore environments. To meet clients’ needs, the Group must continuously develop new and update existing technology for the installation, repair and maintenance of offshore structures. If it does not, the Group may not be able to meet its clients’ requirements and compete effectively for projects. In addition, rapid and frequent technology and market demand changes can render existing technologies obsolete, requiring substantial new capital expenditures and |
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Risk continued
write-downs of the Group’s assets. Any failure by the Group to anticipate or to respond adequately and timely to changing technology, market demands and client requirements could adversely affect the Group’s business and financial results.
Operational Risks
The Group may experience equipment or mechanical failures.
The Group operates a scheduled maintenance programme in order to keep all assets in good working order, but despite this breakdowns can and do occur. Such problems could increase costs, impair revenue and result in penalties for failure to meet project completion requirements.
The Group’s results may fluctuate due to adverse weather conditions.
A substantial portion of the Group’s revenue from continuing operations is generated from work performed offshore West Africa, Brazil, the US Gulf of Mexico and the North Sea and may in the future be performed in other areas, where during certain periods of the year adverse weather conditions usually result in low levels of offshore activity. During such periods of curtailed activity, the Group continues to incur operating expenses, but revenue from operations may be delayed or reduced.
The Group is exposed to substantial hazards, risks and delays, the resulting liabilities of which may potentially exceed insurance coverage and contractual indemnity provisions.
The Group’s operations could result in injury or death to personnel or third parties, reputational damage or damage to or loss of property. A successful liability claim for which the Group is underinsured or uninsured could have a material adverse effect on the Group. Additionally, such events could cause the suspension of the Group’s operations on particular projects, delays and cost overruns.
The Group generally seeks to obtain indemnity agreements from its clients requiring them to hold the Group harmless in the event of damage to existing facilities, loss of production or liability for pollution. Such contractual indemnification, however, may not necessarily cover liability resulting from the gross negligence or wilful misconduct of, or violation of law by, the Group’s employees or subcontractors. Additionally, if the client does not satisfy its obligations, the Group could suffer losses.
Unexpected costs or estimating errors may adversely affect the amount realised from lump-sum contracts.
A significant proportion of the Group’s business is performed on a lump-sum basis where the contract price is based on the Group’s estimates at the time the contract is entered into. Consequently, unexpected costs can reduce the profitability of, or cause a loss to, a lump-sum project if the Group is not contractually
entitled to compensation for the cost overrun. Unexpected costs can arise from equipment failures, subcontractor problems, unanticipated offshore conditions or price increases on necessary materials. Estimating errors may arise due to failure to correctly assess during the tender process elements such as the quality of materials or level of labour required to complete a lump-sum project.
The Group employs the percentage-of-completion method of accounting, which relies on its ability to develop reliable estimates of progress toward completion. Unexpected costs could require the Group to take charges against income to reflect properly the level of completion of a project and to recognise loss-making projects immediately. This could result in a reduction or elimination of previously reported contract revenues.
Delays or cancellation of projects included in the Group’s Backlog may adversely affect future revenue.
The US Dollar amount of the Group’s backlog does not necessarily indicate actual future revenue or earnings related to the performance of that work. Backlog refers to expected future revenue under signed contracts, which are determined as likely to be performed. During the course of a project, the backlog is adjusted to take account of alterations to the scope of work under approved variation orders and contract extensions. Although the backlog represents only business that is considered to be firm, cancellations, delays or scope adjustments have occurred in the past and may occur in the future as a result of economic downturn or as a result of regulatory or other action, including actions connected to the Macondo incident. Due to factors outside the Group’s control, such as changes in project scope and schedule, it is not possible to predict with certainty when or the extent to which projects included in the Backlog will be performed, if at all. Delays, changes in scope or cancellations of projects in the Backlog may adversely affect future revenue.
The Group may experience unexpected costs and/or delays in completing Borealis.
The completion of Borealis is covered by several contracts. There can be no certainty that the construction of this vessel will be completed on time and on budget. Delay in the delivery and completion of this vessel may result in it being unavailable to undertake contracted work, which may result in increased costs or penalties for late arrival or non availability.
The Group may be unable to attract and retain skilled workers in a competitive environment.
The ability to execute the growing number of large projects to the high-quality standard required is heavily dependent on the number of qualified engineers and project managers available. If the Group is not able to attract the number and quality of such personnel required, there is a risk that the future growth of the Group may not be achieved as planned.
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Additionally, if the Group is not able to retain such key employees and other experienced and skilled workers with knowledge of the Group’s operations and procedures, the Group’s future operating results could be adversely affected.
Financial and Compliance Risks
The Group’s reputation and its ability to do business may be impaired by corrupt behaviour by any of its employees or agents or those of its affiliates.
The Group and its affiliates, including joint ventures, operate in countries historically known to experience governmental and institutional corruption. While the Group is committed to conducting business in a legal and ethical manner, there is a risk that its employees or agents or those of its affiliates may take actions that violate the law and could result in monetary penalties against the Group or its respective affiliates and could damage the reputation and, therefore, the ability to do business of the Group.
The Group is exposed to financial risk involving third parties.
If one or more of the Group’s major banks or depositing counterparties becomes insolvent the Group could lose access to agreed credit lines or lose its cash deposits. If the banks which provide the Group’s guarantee facilities are unable to continue to provide the current level of guarantee facilities, this would negatively impact the Group’s ability to bid for new contracts and could undermine the Group’s ability to fulfil existing contracts since a large portion of available contracts require provision of bank guarantees.
The Group may be liable to third parties for the failure of the Group’s joint venture partners to fulfil their obligations.
The Group’s ability to service indebtedness and fund its operations depends on cash flows from its subsidiaries.
As a holding company, the Group’s principal assets consist of its direct and indirect shareholdings in its respective subsidiaries. Accordingly, the Group’s ability to make required payments of interest and principal on its indebtedness and the funding of its operations is affected by the ability of the respective operating subsidiaries, the principal source of cash flow, to transfer available cash within the Group. The intercompany transfer of funds and repatriation of profit or capital (by way of dividends, inter-company loans or otherwise) may be restricted or prohibited by legal requirements applicable to its subsidiaries and their directors, especially in the event that the liquidity or financial position of the relevant subsidiary is uncertain. In addition, such repatriation of profits, capital or funds could be subject to tax at various levels within the corporate structure of the Group and, depending on where tax is payable, the effective tax rate for either company may be adversely affected. |
The Group’s international operations expose it to the risk of fluctuations in currency exchange rates.
The revenue and costs of operations and financial position of many of the Group’s non-US subsidiaries are measured initially in the local currencies of countries in which those subsidiaries reside. That financial information is then translated into US dollars (the reporting currency of the Group) at the applicable exchange rate. The exchange rate between these currencies and the US Dollar may fluctuate substantially, which could have a significant effect both from a translational and operational perspective on the reported consolidated results of operations and financial position of the Group. For more information, please refer to Note 34 ‘Financial instruments’ to the Consolidated Financial Statements.
The Group manages its foreign currency exchange exposure by, among other things, using derivative instruments to hedge revenue or expenditure that is not in the functional currency of a given subsidiary. However, the Group may not be able to eliminate such exposure and, therefore, currency exchange rate movements and volatility can have a material adverse impact on its financial position.
The Group’s tax liabilities could increase as a result of recently becoming subject to Luxembourg’s ordinary tax regime.
The Luxembourg law of July 31, 1929 on the tax regime of financial participation companies (holding companies) provides exemption from Luxembourg corporate taxes on earnings (including dividends, interest, and royalties) in certain circumstances. The Group ceased to benefit from this special tax status on December 31, 2010 and on January 1, 2011 the Group became subject to Luxembourg’s ordinary tax regime. The Group is in the process of restructuring its affairs to mitigate any potential adverse effects as a result of being subject to Luxembourg’s ordinary tax regime. However, when finalised, the measures actually implemented by the Group may not be sufficient to eliminate all potential adverse effects of the new tax regime, in which case the Group’s tax liabilities may increase by amounts that currently cannot be estimated.
The future tax liabilities of the Group could increase as a result of a change to the existing UK tax position of certain of the Group’s UK subsidiaries.
Following completion of the Combination of Acergy S.A. and Subsea 7 Inc., the existing UK tax position of some of the Group’s UK subsidiaries is expected to change as a result of the operation of UK tax law. Currently, some of the Group’s UK subsidiaries have elected into the UK tonnage tax regime (‘tonnage tax’) such that they are taxed based on the tonnage of the vessels they operate whereas certain other of the Group’s UK subsidiaries are taxed under the standard UK Corporation Tax regime. |
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If the Group’s UK ship operating subsidiaries leave the tonnage tax regime as a consequence of the Combination, the Group’s deferred tax liability would increase by approximately $48.6 million, with a corresponding change to the income statement and an equity reduction.
If agreement can be reached with the UK tax authorities as to the eligibility of the Group to be within the tonnage tax regime, it is management’s current intention to elect for the qualifying operating subsidiaries to be taxed under this regime. For more information, please refer to Note 40 ‘Post balance sheet events’ to the Consolidated Financial Statements.
The Group’s tax liabilities could increase as a result of adverse tax audits, enquiries or settlements.
Due to its global operations, the Group routinely deals with complex transfer pricing, permanent establishment and other similar international tax issues, as well as competing tax systems where tax treaties may not exist. In the ordinary course of events, the operations of the Group are currently or will be subject to audit, enquiry and possible re-assessment by different tax authorities. The Group makes tax provisions for the amounts it considers may become payable in the ordinary course of business or as a result of tax audits, and for which a reasonable estimate may be made. The risk exists that current provisions may not be adequate and areas not currently provided for may require future provisions. Therefore, adjustments may subsequently be required to tax provisions in later years as and when these and other matters are finalised with the appropriate tax authorities. The Group’s operations in various countries are currently subject to enquiries, audits and disputes including with respect to its operations in Angola, Australia, Brazil, Canada, Congo, Denmark, France, Gabon, Indonesia, Nigeria, the UK and US. For more information, please refer to Note 11 ‘Taxation’ to the Consolidated Financial Statements.
If, as expected, Subsea 7 S.A. is no longer traded on NASDAQ and deregisters under the US Securities Exchange Act of 1934, the Group will no longer be subject to certain US corporate governance and disclosure rules, nor will it be traded on any US national securities exchange.
Subsea 7 S.A. has commenced procedures to delist its ADSs from NASDAQ and intends to deregister its ADSs and common shares under the US Securities Exchange Act of 1934 as soon as it becomes eligible to do so.
If, as expected, Subsea 7 S.A. accomplishes the delisting and deregistration, the Group will no longer be subject to certain US rules related to corporate governance
and disclosure requirements, although it will be subject to corporate governance and disclosure requirements applicable to Luxembourg companies primarily listed on the Oslo Børs. For example, following delisting from NASDAQ, the Group will not be required to maintain an audit committee that is independent as required under the NASDAQ rules. In addition, following deregistration of its ADSs and common shares under the US Securities Exchange Act of 1934, the Group will not be required, among other things, to (i) file Annual Reports on Form 20-F or furnish Current Reports on Form 6-K with the US Securities and Exchange Commission or (ii) comply with the US Sarbanes-Oxley Act of 2002 (including annual assessments of internal controls required by Section 404 thereof). As a result of such delisting and deregistration, a holder of the Group’s ADSs or common shares will no longer be afforded the protection of these rules. For more information, please refer to Note 40 ‘Post balance sheet events’ to the Consolidated Financial Statements.
In addition, following delisting from NASDAQ, the Group’s ADSs will no longer be traded on any national securities exchange in the US. The Group’s common shares will continue to be listed on the Oslo Børs and the Group anticipates that its ADSs will continue to be traded in the US on the US over-the-counter market. Securities quoted on the US over-the-counter market generally have less liquidity in the US than securities traded on a US national securities exchange, including lower US trading volumes, delays in the timing of transactions and reduced securities analyst and news coverage in the US. The Group does not intend to facilitate the trading of its ADSs in the over-the-counter market and there is no guarantee that any such trading will occur.
Risks Relating to the Combination
The Group expects to incur substantial costs related to the integration of Acergy and Subsea 7 businesses.
The Group expects that it will incur substantial costs in connection with integrating the respective businesses, policies, procedures, operations, technologies and systems of Acergy S.A. and Subsea 7 Inc. There are a large number of systems that must be integrated, including information management, purchasing, accounting and finance, sales, billing, payroll and benefits, fixed asset and lease administration systems and regulatory compliance. There are a number of factors beyond the control of the Group that could affect the total amount or the timing of all of the expected integration expenses. Moreover, many of the expenses that will be incurred are, by their nature, difficult to estimate accurately at the present time. These expenses could, particularly in the near term, exceed the savings
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that the Group expects to achieve from the elimination of duplicative expenses, the realisation of economies of scale and cost savings and revenue enhancements related to the integration of the businesses. These integration expenses may result in the Group taking significant charges against earnings.
The Group may be unable to successfully integrate the businesses which could result in the Group’s failure to realise anticipated cost savings, revenue enhancements and other benefits expected from the Combination.
The Combination involves the integration of two companies which previously operated as independent public companies. The Group is required to devote substantial management attention and resources to integrating its business practices and operations. Potential difficulties the Group may encounter in the integration process include the following:
— the inability to successfully integrate the respective businesses of Acergy S.A. and Subsea 7 Inc. in a manner that permits the Group to achieve the cost savings and operating synergies anticipated to result from the Combination, which would result in the anticipated benefits of the Combination (including the expected synergies) not being realised partly or wholly in the time frame currently anticipated or at all;
— loss of revenue and/or clients as a result of certain clients of either or both of the two companies deciding not to do business with the combined Group, or deciding to decrease their amount of business with the combined Group in order to reduce their reliance on a single provider;
— the integration of personnel from the two companies while maintaining focus on providing consistent, high quality products and client service in a safe manner;
— potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the Combination; and
— performance shortfalls at one or both of the two companies as a result of the diversion of management’s attention caused by completing the Combination and integrating the two companies’ operations.
In connection with the Combination, the Group announced that it expects to achieve synergies of at least $100 million per annum within three years of completion of the Combination, primarily from operating cost and vessel fleet efficiencies. These synergies may not be achieved to the fullest extent or within the timeframe expected, which could have an adverse effect on the Group’s results of operations. Achieving the benefits of the Combination will depend in part upon the Group’s ability to meet the challenges inherent in the successful integration of global business enterprises of the size and scope of the new Group. |
The Group is subject to regulatory requirements and approvals regarding the Combination which may impose conditions that could have a material adverse effect on the operating or financial performance of the Group.
The Group is subject to the regulatory requirements and approval of antitrust authorities in the UK and Brazil. On December 21, 2010 the UK Office of Fair Trading (OFT) announced that it had suspended its duty to refer the proposed Combination to the UK Competition Commission (CC) and was considering undertakings from Acergy S.A. and Subsea 7 Inc. This followed the submission of a notification to the OFT regarding the proposed Combination on September 23, 2010. The undertakings under consideration are: the divestiture of one pipelay vessel, most likely Acergy Falcon , and potentially one diving support vessel. Should the OFT reject the undertakings, the OFT would reactivate its duty to refer the Combination to the CC, which would trigger an in-depth investigation lasting at least five months. The Group cannot predict the outcome of any such investigation which could result in undertakings that are more or less burdensome than those imposed by the OFT (or no undertakings at all).
The OFT’s announcement followed prior unconditional clearances received from the relevant authorities in the US, Norway and Australia. Competition clearance is still being sought in Brazil. No assurance can be given that the necessary approvals will be obtained within a reasonable timeframe or at all. Anti-trust authorities may make their decisions or approvals conditional upon the Group accepting certain restrictions or undertakings, that could have a material adverse effect on the operating or financial performance of the Group. |
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33
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Governance
Board of Directors
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Kristian Siem 1949 Chairman 2, 3
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Appointment: Mr. Siem is Chairman of Subsea 7 S.A. He became Chairman following completion of the Combination of Acergy S.A, and Subsea 7 Inc. in January 2011, prior to which he was Chairman of the Board of Directors of Subsea 7 Inc. since January 2002.
Skills and experience: Prior to his current appointment Mr. Siem was Chairman of the Board of Directors of Subsea 7 Inc. since January 2002. He has a degree in business economics and has been active in the oil and gas industry since 1972.
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External appointments: Mr. Siem is the Chairman of Siem Industries Inc., Siem Offshore Inc., and Siem Industrikapital AB. Mr. Siem is a Director of Star Reefers Inc., North Atlantic Smaller Companies Investment Trust plc and Frupor S.A. He was also a Director of Transocean Inc. until December 2008.
Mr. Siem is a Norwegian citizen. |
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Sir Peter Mason KBE 1946 Senior Independent Director* 2
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Appointment: Sir Peter Mason KBE FREng became Senior Independent Director of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. He served as an Independent Director of Acergy S.A. since October 2006 and was appointed Chairman of Acergy S.A. in May 2009.
Skills and experience: 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 Institute of Civil Engineers and holds a Bachelor of Science degree in Engineering.
External appointments: Sir Peter has been Chairman of the Board of Directors of Thames Water Utilities Ltd since December 2006 and a Non-executive Director of BAE Systems plc since January 2003. He was also, until October 2008, a Board Member of the 2012 Olympic Delivery Authority.
Sir Peter is a British citizen.
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Jean Cahuzac 1954 Chief Executive Officer
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Appointment: Mr. Cahuzac became Chief Executive Officer of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this he was appointed Chief Executive Officer of Acergy S.A. in April 2008 and became an Executive member of the Board of Acergy S.A. in May 2008.
Skills and experience: Mr. Cahuzac has over 30 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, US where he held the positions of Chief Operating
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Officer and then President, prior to the merger with Global SantaFe. 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, Executive VP and President. He holds a Master’s degree in Mechanical Engineering from École des Mines de St Etienne and is a graduate of the French Petroleum Institute in Paris.
Mr. Cahuzac is a French citizen. |
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Mel Fitzgerald 1950 Director 1
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Appointment: Mr. Fitzgerald joined the Board of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this Mr. Fitzgerald joined Subsea 7 Inc. as CEO in July 2004 and was a member of the Board of Directors of Subsea 7 Inc. from May 2007 until joining the Board of Subsea 7 S.A.
Skills and experience: Mr. Fitzgerald has been involved in the oil industry since he joined Brown & Root in 1974. In 1988 he joined European Marine Contractors (EMC) where he held a number of management positions before joining Halliburton Subsea as a Vice President in 2000. He held this position until
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January 2001, when he then took up the role of UK Vice President for Halliburton’s Energy Services Group. Mr. Fitzgerald has a Bachelor of Science degree in Engineering and a Masters in Business Administration.
External appointments: Mr. Fitzgerald has no other external appointments to public companies.
Mr. Fitzgerald is an Irish citizen. |
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Dod Fraser 1950 Independent Director* 1
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Appointment: Mr. Fraser joined the Board of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this he was a member of the Board of Acergy S.A. from December 2009.
Skills and experience: Mr. Fraser is President of Sackett Partners Incorporated, a consulting company, and 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
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of Lazard Freres & Co. Mr. Fraser has been a trustee of Resources for the Future, a Washington-based, environmental policy think-tank. He is a graduate of Princeton University.
External appointments: Mr. Fraser is a Board member of Forest Oil Corporation and is a former director of Terra Industries, Inc. and Smith International Inc.
Mr. Fraser is a US citizen. |
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34 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
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Robert Long 1946 Independent Director* 3
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Appointment: Mr. Long joined the Board of Subsea 7 S.A. upon completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011.
Skills and experience: Mr. Long served as Chief Executive Officer and a member of the Board of Directors of Transocean Ltd., the world’s largest offshore drilling contractor, 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 time of the Sedco Forex merger, 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 served five years in the Naval Nuclear Power Programme before joining SONAT Inc, the parent company of The Offshore Company, in 1975. As a result of multiple mergers The Offshore Company ultimately became Transocean Ltd. Mr. Long was until recently a member of the National Ocean Industries Association and the International Association of Drilling Contractors.
External appointments: Mr. Long has no other external appointments to public companies.
Mr. Long is a US citizen.
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Arild Schultz 1944 Director 3
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Appointment: Mr. Schultz joined the Board of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this he was a member of the Board of Directors of Subsea 7 Inc. from August 2002.
Skills and experience: Mr Schultz has been in several leading positions within shipping chartering and broking, and since 1980 has been conducting his own business within project financing and consulting. He has a Master of Business Administration Degree from the University of Utah.
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External appointments: Mr. Schultz has no other external appointments to public companies.
Mr. Schultz is a Norwegian citizen. |
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Allen Stevens 1943 Independent Director* 2
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Appointment: Mr. Stevens joined the Board of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this he was a member of the Board of Directors of Subsea 7 Inc. from December 2005.
Skills and experience: 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 with him many years of experience in shipping, finance and management to the role.
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External appointments: Mr. Stevens is Chairman of the Board of Directors of Trailer Bridge Inc. and a Vice President of Masterworks Development Corporation, a hotel developer and operator.
Mr. Stevens is a US citizen. |
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Trond Westlie 1961 Independent Director* 1
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Appointment: Mr. Westlie joined the Board of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc in January 2011. Prior to this he was a member of the Board of Acergy S.A. from June 2004.
Skills and experience: Mr. Westlie was appointed Group Chief Financial Officer of A.P. Moller-Maersk A/S on January 1, 2010, and is a member of their Executive Board. He was previously Executive Vice President and Chief Financial Officer of the Telenor Group. He gained extensive experience in the oil and gas service sector as Executive Vice President and Chief Financial Officer of Aker Kvaerner ASA from 2002 to 2004. His management positions included the position of Executive
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Vice President and Chief Financial Officer of Aker Maritime ASA from 2000 to 2002, and Executive Vice President, Business Development for Aker RGI ASA from 1998 to 2000. He has served on numerous corporate boards. Mr. Westlie qualified as a State Authorised Public Auditor from Norges Handelshøyskole (the Norwegian School of Economics and Business Administration).
External appointments: Mr. Westlie is Group Chief Financial Officer of A.P. Moller-Maersk A/S and is a member of their Executive Board. He is also a Board member of Mesta Konsern ASA.
Mr. Westlie is a Norwegian citizen. |
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Committee membership
1. Audit Committee 2. Governance and Nomination Committee 3. Compensation Committee |
Independent Directors’
* As used above, ‘independence’ is as defined in the Combination Agreement, dated June 20, 2010. Additionally, at all times, including from the end of the standstill period, the Board must satisfy the rules and codes of corporate governance of the stock exchange on which Subsea 7 S.A. is primarily listed. At the date of this report, the NASDAQ Global Select Market is Subsea 7 S.A.’s primary listing, however Subsea 7 S.A. has commenced procedures to delist from NASDAQ. |
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All Directors of the Board were appointed to the Board of Subsea 7 S.A. upon completion of the Combination of Acergy S.A and Subsea 7 Inc in January 2011. The Board of Subsea 7 S.A. comprises the persons listed above.
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. Mr. Kristian Siem, Sir Peter Mason KBE, Mr. Jean Cahuzac, Mr. Mel Fitzgerald and Mr. Robert Long will serve for an initial term expiring at the Annual General Meeting to be held in June 2012. The initial term of the remaining Directors: Mr. Dod Fraser, Mr. Arild Schultz, Mr. Allen Stevens and Mr. Trond Westlie will expire at the Annual General Meeting in June 2013. Under the Company’s Articles of Incorporation, the Board must consist of not fewer than three Directors.
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seabed-to-surface
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35
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Governance
Executive Management Team
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Jean Cahuzac 1954 Chief Executive Officer |
Simon Crowe 1967 Chief Financial Officer |
John Evans 1963 Chief Operating Officer |
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Appointment: Jean Cahuzac became Chief Executive Officer of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this he was appointed Chief Executive Officer of Acergy S.A. in April 2008 and became an Executive member of the Board of Acergy S.A. in May 2008.
Mr. Cahuzac’s full biography is included under “Board of Directors” on page 34. |
Appointment: Simon Crowe became Chief Financial Officer of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this he was Chief Financial Officer of Acergy S.A. from October 2009.
Skills and experience: Prior to joining Acergy, Mr. Crowe held senior financial, strategic and corporate finance positions across a range of industries, including several international energy companies, having worked in a number of locations around the world including London, Geneva, Houston, Paris and Singapore. His most recent roles prior to joining Acergy were at Transocean as Vice President, Strategy and Planning, & Finance Director of Transocean’s Europe & Africa Business.
Mr. Crowe holds a degree in Physics from Liverpool University and is a member of the Chartered Institute of Management Accountants in the UK. Mr. Crowe is a British citizen. |
Appointment: John Evans became Chief Operating Officer of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this he was Chief Operating Officer of Subsea 7 Inc. from July 2005 to January 2011.
Skills and experience: Mr. Evans has over 20 years experience in the engineering and contracting sector as a senior manager and Chartered Engineer. During 18 years with Kellogg Brown & Root (‘KBR’) he gained a successful record in general management, commercial and operational roles in the offshore oil and gas industry. Between 2002 and mid-2005 he was Chief Operating Officer for KBR’s Infrastructure business in Europe and Africa.
Mr. Evans has a Bachelor of Engineering degree in Mechanical Engineering, is a Chartered Mechanical and Marine Engineer, and Chartered Director. Mr. Evans is a British citizen. |
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Keith Tipson 1958 Executive Vice President – Human Resources |
Steve Wisely 1962 Executive Vice President – Commercial |
Graeme Murray 1968 General Counsel |
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Appointment: Keith Tipson became Executive Vice President – Human Resources for Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to that he was Corporate Vice President Human Resources for Acergy S.A. since November 2003.
Skills and experience: Mr Tipson’s role within the Executive Management Team of Subsea 7 S.A. is to develop and implement the Subsea 7 Human Resources strategy and develop the global Human Resources team. He has responsibility for resourcing, performance and reward, people development and communications. His previous experience in the engineering project sector was with the Dowty Group and latterly with Alstom, where he held the position of Senior VP Human Resources, Power Sector, based in Paris.
Mr. Tipson has a business degree from Thames Valley University, London and has worked in Belgium, France, Switzerland and the UK. Mr. Tipson is a British citizen. |
Appointment: Steve Wisely became Executive Vice President – Commercial of Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this he was Commercial VP at Subsea 7 Inc.
Skills and experience: Mr. Wisely has held a number of commercial and operational positions with Subsea 7 Inc. and its predecessor companies since 1987, in the UK and overseas. In the early 1990s Mr. Wisely held the position of Commercial Manager in Norway before returning to the UK where he held a number of roles in the commercial function. Moving to Singapore in 1997 he progressed to the position of Regional VP Asia Pacific before returning to the UK to perform the role of Regional VP UK and then the position of Commercial VP.
Mr. Wisely is a graduate of The Robert Gordon Institute of Technology in Aberdeen with a degree in Quantity Surveying. Mr. Wisely is a British citizen. |
Appointment: Graeme Murray became General Counsel for Subsea 7 S.A. following completion of the Combination of Acergy S.A. and Subsea 7 Inc. in January 2011. Prior to this he was General Counsel and Vice President Commercial & Procurement at Subsea 7 Inc.
Skills and experience: In the early part of his career Mr. Murray spent six years as a solicitor in private practice before joining KLM where he worked on aircraft finance and lease transactions. He then joined Coflexip Stena where he worked on general subsea contracts. Following his time at Coflexip Stena he joined Halliburton where amongst other activities he led the legal process for establishing the Halliburton DSND Joint venture (subsequently renamed Subsea 7 Inc.).
Mr. Murray has a Law Degree from the University of Aberdeen, is a solicitor admitted to practice by the Law Society of Scotland and is a Notary Public. Mr. Murray is a British citizen.
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36 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
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Governance
Corporate Governance
Creating long-term value
through strong corporate governance
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The Board is committed to meeting high corporate governance standards in pursuing our corporate mission – to be acknowledged by our clients, our people and shareholders as the leading strategic partner in seabed-to-surface engineering, construction and services. We are committed to cultivating a value-based performance culture that rewards exemplary ethical behaviours, 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.
Corporate Governance at Subsea 7 Subsea 7’s Board is responsible for, and committed to, the maintenance of high standards of corporate governance at all times throughout the Group. The Board believes strongly that the observance of these standards is in the best interests of all of our stakeholders.
The Board 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, and the role of the Board is to proactively encourage, monitor and safeguard this governance culture. The Board and its Committees oversee the management of the Group’s operations, and report to shareholders on the effectiveness of Subsea 7’s internal controls.
The work of the Board is based on the existence of a clearly defined division of roles and responsibilities between the shareholders, the Board and the Group’s Executive Management. The Group further ensures good governance is adopted by holding regular Board meetings at which the Executive Management Team attend to report on strategic, operational and financial matters.
Our governing structures and controls help to ensure that we run our business in an appropriate manner for the benefit of our shareholders, employees and other stakeholders in the societies in which we operate. |
Legal and regulatory framework Subsea 7 S.A. (formerly Acergy S.A.) is a ‘société anonyme’ organised in the Grand Duchy of Luxembourg under the Company Law of 1915, as amended and was incorporated in Luxembourg in 1993 as the holding company for all of our activities. The Company became an ordinary taxable company in Luxembourg on January 1, 2011. Upon completion of the Combination between Acergy S.A. and Subsea 7 Inc. on January 7, 2011, the Company was renamed Subsea 7 S.A.
Our 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 quoted on both the NASDAQ Global Select Market and the Oslo Børs, Subsea 7 is subject to a number of different laws and corporate governance regulations. So long as Subsea 7 S.A. remains listed on NASDAQ, it is subject to the NASDAQ Marketplace Rule 5600 Series establishing certain corporate governance requirements. Pursuant to Rule 5615(a)(3), as a foreign private issuer we may follow our home country corporate governance practices in lieu of the requirements of the Rule 5600 Series provided that we comply with certain mandatory sections of the Rule 5600 Series, make disclosure of those areas where our home country practice departs from NASDAQ requirements, and provide certification to NASDAQ that our corporate governance practices are not prohibited by Luxembourg law. Further details can be found on page 157. On February 15, 2011 Subsea 7 S.A. commenced procedures to delist from NASDAQ. For more information, please refer to Note 40 ‘Post balance sheet events’ to the Consolidated Financial Statements. As a company listed on the Oslo Børs, the Company follows the Norwegian Code of Corporate Governance for non- Norwegian incorporated companies on a ‘comply or explain’ basis, where these do not contradict Luxembourg laws and regulations and those of the NASDAQ Global Select Market and the US Securities and Exchange Commission (SEC).
A key corporate governance activity undertaken by the Group in 2010 concerned compliance with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002, which is applicable to most companies listed on a US national securities exchange and enforced by the SEC.
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seabed-to-surface
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37
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Governance
The Board
The Board – Subsea 7 S.A.
The appointment of the Board of Directors (‘the Board’) became effective upon completion of the Combination between Acergy S.A. and Subsea 7 Inc. on January 7, 2011, at which time the Company was renamed Subsea 7 S.A.
| Board Members | ||
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· Kristian Siem |
Chairman |
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· Sir Peter Mason KBE FREng |
Senior Independent Director |
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· Jean Cahuzac |
Chief Executive Officer |
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· Mel Fitzgerald |
Director |
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· Dod Fraser |
Independent Director |
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· Robert Long |
Independent Director |
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· Arild Schultz |
Director |
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· Allen Stevens |
Independent Director |
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· Trond Westlie |
Independent Director |
As used above, ‘independence’ is as defined in the Relationship Agreement, dated June 20, 2010, among Subsea 7 Inc., Acergy S.A. and Siem Industries Inc., which is relevant during the standstill period of 30 months from the date of the Relationship Agreement. Additionally, at all times, including from the end of the standstill period, the Board must satisfy the rules and codes of corporate governance of the stock exchange on which Subsea 7 S.A. is primarily listed. At the date of this report, NASDAQ Global Select Market is Subsea 7 S.A.’s primary listing; however Subsea 7 S.A. has commenced procedures to delist from NASDAQ. For more information, please refer to Note 40 ‘Post Balance Sheet Events’ to the Consolidated Financial Statements.
Board responsibilities
The Board’s purpose and key responsibilities include:
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setting the Group’s overall strategy and five-year plan, and monitoring performance against the agreed strategy and plan; |
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responsibility for, and regular review of, the Group’s operational and financial performance; |
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approval of major capital projects, related capital expenditure, significant investments and disposals, and contracts in excess of $250 million; |
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ensuring effective structuring of the Group, including changes to the Company’s share capital structure, corporate structure and listings; |
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ensuring effective Corporate Governance of the Group; |
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responsibility for the Company’s financial reporting and for compliance with financial reporting and disclosure obligations; |
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oversight of and responsibility for the risk management of the Group. The Board shall identify any risks which threaten the fulfilment of the Group’s business objectives, including failure to perform in accordance with agreed business plans, non-compliance with law and regulation, fraud and material losses and failure to maintain appropriate accounting records; and ensure that an effective system of internal controls is in place at all times to manage and mitigate those risks; and |
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electing the Chairman and Senior Independent Director; appointing, compensating and removing the Chief Executive Officer; ensuring adequate succession plans are in place at Chief Executive Officer and senior management levels and setting the Group’s remuneration policy. |
The Board, according to the Company’s Articles of Incorporation may set up different committees including, without limitation, a management committee, an audit committee, a corporate governance and nomination committee and a compensation committee. Under Luxembourg law and the listing rules of NASDAQ and the Oslo Børs an Audit Committee is mandatory.
Board relations with management
The Board is responsible for the oversight of overall control of the Group’s affairs. The Executive Management Team is responsible for control and management of day-to-day business matters. The Board delegates day-to-day and business control matters to the Chief Executive Officer who, with the Executive Management Team, is responsible for implementing Group policy and monitoring the performance of the business.
The Executive Management Team comprises the Chief Executive Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Executive Vice President – HR and Executive Vice President – Commercial. Effective liaison between the Board and the Executive Management Team is achieved through regular attendance by members of the Executive Management Team at Board meetings, and the provision of financial and operational updates by the Executive Management Team to the Board.
Board balance
The Board shall be composed of not less than three Directors. The Board comprises nine Directors: including a Chairman, Senior Independent Director, Chief Executive Officer and a majority of Independent Directors. The Directors provide experience and knowledge gained in a variety of sectors, and constructively challenge management’s proposals for the strategy and direction of the business. Biographies of Board members are shown on pages 34 and 35.
The Board shall appoint a Chairman. The Chairman is responsible for the leadership of the Board, ensuring its effectiveness and independence from the Group’s management. The Chief Executive Officer is responsible for implementing the strategy of the business, within the authorities delegated to him by the Board.
The Board shall also appoint a Senior Independent Director from among the Independent Directors who shall provide a sounding board to the Chairman and serve as an intermediary for the other Directors if necessary.
Under the Company’s Articles of Incorporation, the Directors are elected by the General Meeting of shareholders for a term not exceeding two years. Directors need not be shareholders and may be re-elected. The Company’s General Meeting of shareholders may dismiss any Director at any time, notwithstanding any agreement between the Company and such Director, with or without cause. Such dismissal may not prejudice the claims that such 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, the remaining Directors appointed by the General Meeting have the right to appoint a replacement Director until the next meeting of shareholders.
The Company’s Articles of Incorporation provide that, with the exception of a candidate recommended by the Board, or a Director whose term of office expires at a general meeting of shareholders 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 shareholder duly authorised, shall have been deposited at the Group’s registered office, together with a written declaration, signed by the proposed candidate confirming his or her wish to be appointed.
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38 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
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Audit Committee
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Corporate Governance and Nomination Committee
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Committee Members
· Trond Westlie (Chairman and Audit Committee financial and accounting and audit expert)
· Mel Fitzgerald (a)
· Dod Fraser |
Committee Members
· Sir Peter Mason KBE FREng (Chairman)
· Kristian Siem
· Allen Stevens |
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Key duties The Corporate Governance and Nomination Committee assists the Board with respect to matters relating to corporate governance and succession. The main duties of the Corporate Governance and Nomination Committee are summarised as follows:
· to establish, review and make recommendations to the Board regarding Board composition and structure, and review and evaluate the performance and effectiveness of the Board annually;
· to review and make recommendations to the Board regarding the nature and duties of Board Committees;
· to evaluate potential candidates for election or re-election as Directors and for service on each Board Committee;
· to interview those candidates whom the Board decides are qualified candidates and make the final recommendation to the Board as to whom the Board should propose for appointment as Directors;
· to review, from time to time, the appropriate skills and characteristics required of Board members in the context of the current make-up of the Board, including such factors as business experience, diversity, personal skills in technology, finance, marketing, international business, financial reporting and other areas that are expected to contribute to an effective Board;
· to consider questions of possible conflicts of interest of Board members and senior executives;
· to consider matters of corporate governance, and review annually Corporate Governance Guidelines; and
· to review the duties and performance of the Chairman.
The Corporate Governance and Nomination Committee’s Terms of Reference require that the Committee shall consist of no fewer than three members. The members shall meet the definition of independence as contained in the Combination Agreement, dated June 20, 2010.
A copy of the Corporate Governance and Nomination Committee’s Terms of Reference is available for download from the Group’s website www.subsea7.com |
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(a) Mr Fitzgerald will become a member of the Audit Committee in May 2011, following the cessation of his employment with the Group.
Each of the Audit Committee members meet the independence requirements under Luxembourg law and are independent as defined in Rule 10A-3 under the Securities Exchange Act of 1934, as amended, and therefore qualify for an exemption from the NASDAQ independence requirements.
Key duties The terms of reference of the Audit Committee satisfy the requirements of applicable law and NASDAQ, and are in accordance with the Articles of Incorporation. The Audit Committee’s responsibilities include:
· to monitor the effectiveness of the Group’s internal control, internal audit and, where applicable, risk management systems;
· to monitor the statutory audit of the annual and consolidated accounts of the Group;
· to review the quarterly, half-yearly and annual financial statements before their approval by the Board;
· to review and monitor the independence of the auditor of the Group, and in particular with respect to the provision of additional non-audit services to the Group; and make recommendations with respect to the selection and the appointment of the Group’s auditor;
· to review the report from the auditor on key matters arising from the statutory audit, and in particular on material weaknesses in internal control in relation to the financial reporting process;
· to deal 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; and
· to conduct a review and oversight for potential conflict of related party interests.
The Committee is chaired by Trond Westlie who is currently Chief Financial Officer (CFO) of AP Moeller Maersk, and was previously CFO of Telenor Group. The Board has determined that Trond Westlie is the Audit Committee financial expert and competent in accounting and audit practice with recent and relevant financial experience.
The Audit Committee’s Terms of Reference require that the Committee shall consist of not less than three Directors and that all members of the Audit Committee are independent as set forth in Rule 10A-3 of the Securities Exchange Act of 1934, as amended, (unless otherwise exempt), and eligible pursuant to home country (Luxembourg) rules. It is expected that Mr. Fitzgerald will become a member of the Audit Committee in May 2011, prior to its next scheduled meeting, thus fulfilling the Committee’s membership requirements. The Audit Committee meets at least four times a year, and its meetings are attended by representatives of the external independent auditor and by the head of the Internal Audit function.
A copy of the Audit Committee Terms of Reference is available for download from the Group’s website www.subsea7.com |
|
|
seabed-to-surface
|
|
39
|
Governance
The Board continued
Compensation Committee
Committee Members
| · |
Kristian Siem (Chairman) |
| · |
Robert Long |
| · |
Arild Schultz |
Key duties
The Compensation Committee assists the Board in developing a fair compensation programme for executives and complying with the Board’s legal and regulatory requirements in respect of executive compensation. In matters relating to the Chief Executive Officer, the Committee’s remit is confined to making recommendations to the Board. The Compensation Committee’s main duties are summarised as follows:
| · |
to recommend performance targets for the Chief Executive Officer for approval by the Board; |
| · |
to recommend to the Board any change to the Chief Executive Officer’s remuneration, including salary and performance related incentives; |
| · |
to review annually with the Chief Executive Officer the career development plans and succession plans of the Chief Executive Officer and his/her direct reports and consider the adequacy of available managerial talent in the Group and report to the Board; |
| · |
to review each year with the Chief Executive Officer the performance and compensation of the executive management of the Group; |
| · |
to approve the appointment of the Chief Executive Officer, appointments to the Executive Management Team and other senior executives; |
| · |
to review the Group’s remuneration policy and management’s proposals for compensation strategy in order to determine whether they are appropriate for the industry in which Subsea 7 operates, are competitive, and are structured to attract and retain key staff of the required calibre; |
| · |
to review the effectiveness of existing long-term compensation plans and consider whether any changes to existing plans or other types of plan are appropriate; and |
| · |
to review all benefit plans proposed by Management or changes to existing plans. |
A copy of the Compensation Committee’s Terms of Reference is available for download from the Group’s website www.subsea7.com
Other Committees
Disclosure Committee
Key duties
The Disclosure Committee assists the Chief Executive Officer and Chief Financial Officer in fulfilling their responsibility for oversight of the accuracy and timeliness of the disclosures made by the Group.
The Disclosure Committee’s main duties are summarised below:
| · |
to monitor the integrity and effectiveness of disclosure controls and procedures and consult with the Chief Executive Officer; |
| · |
to assist the Chief Executive Officer in complying with his obligations under applicable securities laws; |
| · |
to ensure that information required to be disclosed is accumulated and communicated by the Disclosure Committee; |
| · |
to apply disclosure requirements to accumulated information so that reports can be made in compliance with applicable securities laws; |
| · |
to oversee and review the preparation of financial reports (including the Annual Report to Shareholders on the Group and Company, Annual Report on Form 20-F, the quarterly, semi-annual and annual results announcements) and present them for review to the Chief Executive Officer and the Audit Committee; and |
| · |
to oversee and review preparation of disclosure documents other than those described above, such as registration statements and other securities offering documents, press releases containing financial or other material information, earnings guidance, presentations to analysts and the investment community, presentations to ratings agencies, communications with shareholders such as proxy statements and other publicly disseminated information. |
Members of the Disclosure Committee are: Chief Financial Officer, Chief Operating Officer, Group Financial Controller, General Counsel, Head of Internal Audit and Investor Relations Director.
Directors’ interests
The interests of the Directors in the share capital of the Company as at February 23, 2011 are set out below:
| Director |
Total performance
shares |
Total owned
shares |
Total restricted
shares |
|||||||||
|
Kristian Siem (a) |
Nil | Nil | Nil | |||||||||
|
Sir Peter Mason |
||||||||||||
|
KBE FREng (b) |
Nil | 10,000 | Nil | |||||||||
|
Jean Cahuzac (b) (c) |
70,000 | 57,258 | 20,000 | |||||||||
|
Mel Fitzgerald |
Nil | 74,109 | 158,975 | |||||||||
|
Dod Fraser |
Nil | 2,000 | Nil | |||||||||
|
Robert Long |
Nil | Nil | Nil | |||||||||
|
Arild Schultz |
Nil | 745,500 | Nil | |||||||||
|
Allen Stevens |
Nil | 10,650 | Nil | |||||||||
|
Trond Westlie (b) |
Nil | Nil | Nil | |||||||||
|
Total |
70,000 | 899,517 | 178,975 | |||||||||
| (a) | As at February 23, 2011 Siem Industries Inc. which is a company controlled through trusts where certain members of Mr. Siem’s family are potential beneficiaries, owned 69,681,932 shares, representing 19.8% of issued shares. |
| (b) | Details of share options held by Sir Peter Mason, Trond Westlie and Jean Cahuzac are shown in the Remuneration Report on page 50. No other Directors held share options on February 23, 2011. |
| (c) | Total performance shares and restricted shares held represents the maximum award expected assuming all conditions are met. |
As at February 23, 2011, the Directors of Subsea 7 S.A. directly and indirectly owned a total of 1,148,492 shares including the maximum award of performance and restricted shares, representing 0.3% of issued shares.
|
40 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Directors’ fees and share options Directors, excluding Executive Directors, are paid a base fee for their services, with additional fees to reflect Chairmanship or membership of the Audit Committee. Directors, excluding Executive Directors will not receive pension contributions, benefits-in-kind, bonuses or share options. The fee structure which will apply during fiscal year 2011 is as follows:
|
|
Constructive use of General Meetings All holders of American Depositary Receipts through Deutsche Bank Trust Company, our depository in the United States, and all shareholders that are registered in the branch shareholder register, kept by VPS, the central depository of Oslo Børs, receive written notice of meetings, and may attend and vote at our general meetings. They have the right to submit proposals and may vote either directly or by proxy.
The Board is obliged to call a general meeting of shareholders within 30 days of receipt of a written demand from shareholders representing at least one-tenth of the issued and outstanding shares entitled to vote.
Annual General Meeting business The Company’s 2011 Annual General Meeting will be held on May 27, 2011 and, thereafter on the fourth Friday in June of each year.
At the Annual General Meeting shareholders are invited to, but are not limited to, elect the Board Directors, approve the Annual Report and Financial Statements of the Group and the Company, approve the payment of the proposed dividend, if applicable (see ‘Dividend Policy’) and approve the appointment of the external auditors.
Dividend policy In light of the development of the combined business and the Group’s investment opportunities, the Board has proposed not to pay a dividend for the 2010 fiscal year. The Board is reviewing methods of balancing the optimal use of cash in light of the opportunities available.
Ethics, Integrity and Corporate Social Responsibility Code of Conduct Subsea 7 has adopted a Code of Conduct applicable to all Directors, officers and employees, which also constitutes the Code of Ethics applicable to our Chief Executive Officer, Chief Financial Officer, Financial Controller and persons performing similar functions, in accordance with the Sarbanes-Oxley Act of 2002 and the applicable laws, rules and regulations of the SEC and NASDAQ.
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. Transactions between the pre-Combination Group and members of the Board, Management Team or close associates during fiscal year 2010 are detailed as related party transactions in Note 35 ‘Related party transactions’ to the Consolidated Financial Statements.
The Code of Conduct details the Company’s expectations and requirements in regards to its corporate responsibility, including but not limited to human rights, prevention of corruption, employee rights, health and safety and the working environment, discrimination, whistle blowing as well as environmental issues. A copy of the Code of Conduct is available for download from the Group’s website www.subsea7.com
|
||||||||
| Fee | $ per annum | |||||||||
|
Chairman fee |
200,000 | |||||||||
|
Senior Independent Director fee |
125,000 | |||||||||
|
Base fee for Non-executive Directors |
105,000 | |||||||||
|
Additional fee for chairing the Audit Committee |
8,000 | |||||||||
|
Additional fee for Audit Committee members |
6,000 | |||||||||
|
Directors’ term of office Directors’ contracts and the Company’s Articles of Incorporation provide that each Director is appointed by a general meeting of shareholders for a term that will not exceed two years. If Directors are not re-elected their term of office ends immediately after the Annual General Meeting in the year of the expiry.
The Chief Executive Officer is an Executive Director, whose appointment to the Board is also for a term that will not exceed two years. As an Executive Director, he also has a contract of employment with the Group.
The Company may, by a resolution of a general meeting of shareholders, dismiss any Director before the expiration of his or her term of office, notwithstanding any agreement between the Company and such Director.
Kristian Siem, Sir Peter Mason KBE FREng, Jean Cahuzac, Mel Fitzgerald and Robert Long will serve for an initial term expiring at the 2012 Annual General Meeting to be held in June 2012. Dod Fraser, Arild Schultz, Allen Stevens and Trond Westlie will serve for an initial term expiring at the 2013 Annual General Meeting to be held in June 2013.
Directors’ indemnification Directors are indemnified under the Company’s Articles of Incorporation against liability and expenses reasonably incurred or paid by them in connection with claims, actions, suits or proceedings in which they become involved by virtue of being a Director of the Company. No indemnification is provided, however, to Directors against any liability to the Company or its shareholders by reason of wilful misfeasance, gross negligence or reckless disregard of their duties or where the Director is adjudicated to have acted in bad faith and not in the interests of the Company.
Shareholder Relations and General Meetings Contacts with major shareholders The Board seeks to encourage a positive dialogue with shareholders. The Chairman is available to discuss issues with shareholders and to address any shareholder concerns which may arise. The Senior Independent Director is available to resolve any matters which cannot be dealt with through the normal channel of contact with the Chairman.
Information on Subsea 7’s Investor Relations programme is given in the ‘Key Investor Information’ section on page 169. A list of major shareholders is given in the Additional Information section on page 168. |
|
|
||||||||
|
seabed-to-surface
|
|
41
|
Governance
Remuneration Report
Remuneration Report
The Group’s remuneration policy is set by the Compensation Committee. The policy is designed to provide remuneration packages which would 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 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.
Executive 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 fiscal period, and in specific instances, the total award available to certain individuals.
Chief Executive Officer remuneration
The remuneration package of the Chief Executive Officer was determined by the Board, on the recommendation of the Compensation Committee. The compensation of the Chief Executive Officer, for fiscal year 2010 is reported on page 49.
Executive Management Team remuneration
The aggregate compensation for the five members of the Executive Management Team (excluding the Chief Executive Officer) is expected to include base salary, bonus, benefits-in-kind, pension contributions and an element of performance bonus which is related to the future development of the Group’s share price.
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 below:
Share options held by the Executive Management Team (excluding the Chief Executive Officer) as at February 23, 2011 were:
| Name | Date of Grant | Number of Options | Exercise Price | Date of Expiry | ||||||||||||
|
Simon Crowe |
Nil | |||||||||||||||
|
John Evans |
June 16, 2005 | 12,780 | NOK44.85 | February 2014 | ||||||||||||
|
Graeme Murray |
Nil | |||||||||||||||
|
Keith Tipson |
November 22, 2005 | 22,000 | $10.32 | November 21, 2015 | ||||||||||||
| November 21, 2006 | 24,500 | $19.45 | November 20, 2016 | |||||||||||||
| March 12, 2008 | 15,000 | $22.52 | March 11, 2018 | |||||||||||||
|
Steve Wisely |
Nil | |||||||||||||||
|
Total |
74,280 | |||||||||||||||
|
The interests of the Executive Management Team (excluding the Chief Executive Officer) in the share capital of the Company as at February 23, 2011 were:
|
|
|||||||||||||||
| Name |
Total Performance Shares (a) |
Total Owned Shares |
Total Restricted Shares (a) |
|||||||||||||
|
Simon Crowe |
44,000 | 17,703 | Nil | |||||||||||||
|
John Evans |
Nil | 1,141 | 136,674 | |||||||||||||
|
Graeme Murray |
Nil | 1,112 | 28,399 | |||||||||||||
|
Keith Tipson |
32,000 | 8,836 | 5,000 | |||||||||||||
|
Steve Wisely |
Nil | Nil | 96,559 | |||||||||||||
|
Total |
76,000 | 28,792 | 266,632 | |||||||||||||
| (a) | Total performance shares and restricted shares held represents the maximum award assuming all conditions are met. |
Long-term incentive arrangements
The Group operates a number of long-term incentive arrangements to reward and incentivise key management. These are summarised below:
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 December 17, 2009. The 2009 LTIP is an essential component of the Company’s compensation policy, and was designed to place the Company on a par with competitors in terms of recruitment and retention abilities. The 2009 LTIP provides for whole share awards, which vest after three years, based on the performance conditions set out below:
Performance conditions are based on relative Total Shareholder Return (‘TSR’) against a specified comparator group of 13 companies determined over a three year period. This comparator group included Subsea 7 Inc., which ceased to form part of the comparator group upon Completion. The Company would have to deliver TSR above the median for any awards to vest. At the median level, only 30% of the maximum award would vest. The maximum award would only be achieved if the Company achieved top decile TSR (i.e. if, when added to
|
42 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
the comparator group, the Company was first or second, in terms of TSR performance). In addition, individual award caps have been introduced. No senior executive or other employee may be granted shares under the 2009 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 his or her annual base salary as of the first day of said year. Additionally, a holding requirement for senior executives has been introduced. Senior executives must hold 50% of all awards that vest until they have built up a shareholding of 1.5 x salary, which must be maintained.
The first tranche of awards under the 2009 LTIP was made on April 8, 2010. Awards were made over 970,000 performance shares, subject to the 2009 LTIP’s performance conditions, in conjunction with which 583,000 were transferred to an Employee Benefit Trust at the closing share price on the Oslo Stock Exchange on April 9, 2010 from Treasury Shares previously held indirectly by Acergy Investing Limited. The fair market value per share on the date of the award was $19.83. The 2009 LTIP currently covers approximately 100 senior managers and key employees. Grants are determined by the Company’s Compensation Committee, which is responsible for operating and administering the plan. The 2009 LTIP has a five-year term with awards being made annually. The aggregate number of shares subject to all awards which may be granted in any calendar year is limited to 0.5% of issued and outstanding share capital on January 1 of each such calendar year. |
||
|
Special Incentive Plan 2009 Subsequent to November 30, 2009, but prior to the adoption of the 2009 Long-Term Incentive Plan, described above, and as an interim measure, the Company put in place the Special Incentive Plan 2009 (‘SIP 2009’), a cash-settled incentive plan designed to provide awards to selected executives and key employees, thus further aligning their interests with those of shareholders. Awards under the SIP 2009 are in the form of a cash bonus, payable in April 2012, of between zero and twelve months’ base salary, dependent on the Company’s average share price as quoted on NASDAQ between January 1, 2012 and March 31, 2012. If the average share price over that period is $8.75 or less, no cash bonus will be payable. If the average share price over that period is $35.00 or more, a cash bonus equal to twelve months’ base salary will be payable. If the average share price over that period is between $8.75 and $35.00, a cash bonus equal to between zero and twelve months’ base salary will be payable, calculated on a straight-line basis pro rata to the share price. Awards under the SIP 2009 are capped at the equivalent of twelve months’ base salary. No other performance criteria apply. |
|
|
|
2010 Executive Deferred Incentive Scheme During fiscal year 2010 the Board approved and adopted a new deferred incentive scheme for selected senior employees. The scheme enabled executives to defer, on a voluntary basis, up to 50% of their annual bonus into the shares of the Company which will be matched in cash at the end of the three year period, subject to performance conditions. The value of the bonus deferred was used to purchase 44,015 shares based on a prevailing share price on April 16, 2010 of $19.69. Participants who continue to be employed by the Group and hold the shares until March 31, 2013 will receive a cash payment consisting of two elements. There will be a guaranteed payment of 50% of the gross amount deferred and a variable element of up to 100% of the gross amount deferred, but conditional upon reaching target Total Shareholder Return over the three year period to March 2013. |
||
|
2009 Executive Deferred Incentive Scheme During fiscal year 2009 the Board approved and adopted a deferred incentive scheme for selected senior executives. The scheme enabled the executives to defer, on a voluntary basis, up to 50% of their annual bonus into shares of the Company, which will be matched in cash at the end of the three year period, subject to performance conditions. The value of the bonus deferred was used to purchase 58,374 shares based upon the prevailing share price on April 17, 2009 which was $7.64. The matched element is conditional upon achieving target Total Shareholder Return over the three years to March 2012 and is conditional on the shares being held for three years.
2008 Executive Deferred Incentive Scheme During fiscal year 2008 the Board approved and adopted a deferred incentive scheme for selected senior executives including stipulating the number of shares that may be awarded. The scheme enabled the executives to defer, on a voluntary basis, up to 50% of their annual bonus into shares of the Company which will be matched in shares at the end of three years subject to performance conditions. The value of the bonus deferred was used to purchase 17,797 shares based upon the prevailing share price on March 31, 2008 which was $21.35. The matched element was conditional upon the growth of earnings per share over the three years to November 30, 2010. The 2008 Executive Deferred Incentive Scheme did not meet the required performance conditions; therefore no matched shares were issued under this scheme.
Restricted Share Plan In March 2008 the Board approved and adopted a restricted share plan to provide a retention incentive to selected senior executives. The plan stipulated that the number of free shares (without any cash compensation) that may be awarded under the plan may not exceed an average of 350,000 common shares over a three year period. During the three year restricted plan period, participants are not permitted to sell or transfer shares but would be entitled to dividends which will be held by the Company until the restricted period lapses during fiscal year 2011. In April 2008, 65,000 restricted shares were issued to selected senior executives as part of the retention incentive of the plan. These shares had a fair value of $22.23 representing the market price on the date of issue. No further restricted shares have been issued under the Restricted Share Plan. |
|
seabed-to-surface
|
|
43
|
Governance
Remuneration Report continued
Upon completion of the Combination, the Group also assumed certain long-term incentive arrangements in place at Subsea 7 Inc. with awards still outstanding. These assumed schemes are summarised below:
Share Option Plan – Subsea 7 Inc.
During 2005, the shareholders of Subsea 7 Inc. approved the implementation of a share option plan. The exercise price of the options granted is equal to the market price of the shares on the grant date. Options vest in equal proportions on a quarterly or annual basis over a period of time, generally five years. Options vested cannot be exercised until at least one year after grant. The options are only exercisable within seven days after the announcement of quarterly results.
The Annual General Meeting of shareholders of Subsea 7 Inc. held in May 2009 approved a modification to the existing share stock option plan. Employees of Subsea 7 who held existing share options under the share option plan with a strike price greater than NOK 44.85 were given the opportunity to surrender those options in exchange for an award under the restricted share plan (the ‘replacement awards’). The replacement awards were offered on the basis of one restricted share for three share options under the share option plans. Of the 1,797,120 share options eligible, 1,732,620 were exchanged for 577,476 shares. The replacement awards have the same vesting terms, dividend and voting rights as the restricted stock award plan discussed below. Of the original exchange (totalling 577,476 restricted shares), 538,913 remain as allocated to employees in the plan. A small number of personnel elected to remain in the option plan and 40,987 options remain as allocated to employees in the plan.
Restricted Stock Award Plan – Subsea 7 Inc.
On May 8, 2009 the Annual General Meeting of shareholders of Subsea 7 Inc. approved a restricted share award plan (the ‘share plan’) and during 2009 a total of 1,100,000 shares were awarded under the Share Plan. The shares had a fair value of $9.93 (NOK 63.6) per share, equivalent to the market price on the grant date. An award will normally vest and shares will be issued or transferred to the employee subject to the employee remaining in employment with Subsea 7 until the vesting dates that are specified in the award certificate. 60% of the awards will normally vest on the third anniversary of the initial award date, and the remaining 40% of the awards will normally vest on the fifth anniversary of the initial award date. Awards will not attract any dividends or dividend equivalents prior to the delivery of shares. A total of 974,616 restricted shares remain as allocated to employees in the plan. The number of restricted shares awarded is subject to a limit in that, in any ten-year period, not more than 5% of the issued ordinary share capital of Subsea 7 Inc. may be issued under the restricted stock award plan and in addition, in any one-year period, not more than 1% of the issued ordinary share capital of Subsea 7 Inc. may be issued under the plan.
Employee Share Purchase Plan – Subsea 7 Inc.
The employee share purchase plan allowed participating employees, depending on their governing tax jurisdiction, to acquire shares in Subsea 7 Inc. at a discount to the market price and to receive additional matching shares paid for by Subsea 7 Inc. Employees must remain in continuous service with Subsea 7 for a period of three years in order to receive the additional matching shares. This plan has now been terminated but previously purchased and relevant matching shares continue to be held subject to the normal rules of the plan.
|
44 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
Governance
Board – Acergy S.A. fiscal year 2010
The members of the Board of the Company, prior to the Combination with Subsea 7 Inc., for fiscal year 2010 which ended on November 30, 2010 were:
Board Members
| · |
Sir Peter Mason KBE FREng Chairman |
| · |
Tom Ehret Deputy Chairman |
| · |
Jean Cahuzac Chief Executive Officer |
| · |
Thorleif Enger Independent Non-executive Director |
| · |
Dod Fraser Independent Non-executive Director |
| · |
Ron Henderson Independent Non-executive Director |
| · |
J. Frithjof Skouverøe Independent Non-executive Director |
| · |
Trond Westlie Independent Non-executive Director |
Board responsibilities
For fiscal year 2010, the Board’s key responsibilities were:
| · |
to set values and standards and agree policies and processes which were used to guide the affairs of the Group. This includes the setting of clear principles of ethical conduct to apply to all activities undertaken by the Group; |
| · |
to agree a business strategy for the Group which was reviewed and refreshed as necessary to ensure its relevance to the Group’s market; |
| · |
to ensure that an effective system of internal controls was in place at all times. Such a system was used to identify and manage risks that threatened the fulfilment of the Group’s business strategies. This included material failure to perform in accordance with agreed business plans, non-compliance with law and regulation, fraud and material losses and failure to maintain appropriate accounting records; and |
| · |
to ensure that it received accurate and timely information on the performance of the Group, and to agree with the Chief Executive Officer the nature and scope of the information to be provided. |
Board purpose
During fiscal year 2010, the Board was the principal oversight and decision-making forum of the Group and ensured overall control of the Group’s affairs. The Board was responsible for setting the Group’s strategy, for oversight of and approving all of the financial statements, acquisitions and disposals, treasury and risk management policies, approval of major capital projects and for the maintenance of high standards of corporate governance.
The composition of the Board and its Committees for the fiscal year 2010 is shown below:
| Director |
Year of
appointment to the Board |
Independent | Audit Committee |
Governance and
Nomination Committee |
Compensation
Committee |
|||||||||||||||
|
Sir Peter Mason KBE FREng |
2006 | Yes | Yes | Chairman | No | |||||||||||||||
|
Tom Ehret (a) |
2003 | Yes | (a) | No | Yes | Chairman | ||||||||||||||
|
Jean Cahuzac |
2008 | No | No | No | No | |||||||||||||||
|
Thorleif Enger |
2009 | Yes | No | Yes | Yes | |||||||||||||||
|
Dod Fraser |
2009 | Yes | No | No | Yes | |||||||||||||||
|
Ron Henderson |
2010 | Yes | Yes | No | No | |||||||||||||||
|
J. Frithjof Skouverøe |
1993 | Yes | Yes | No | No | |||||||||||||||
|
Trond Westlie |
2004 | Yes | Chairman | No | No | |||||||||||||||
| (a) | Mr Ehret was not considered an ‘Independent Director’ for the purpose of the NASDAQ Marketplace Rules. |
The Board was accountable for the proper stewardship of the Group’s affairs, with the Non-executive Directors having a particular responsibility for ensuring that strategies proposed for the development of the business were critically reviewed. This ensured that the Board acted in the best long-term interest of shareholders and took account of the wider community of interests represented by clients, employees and suppliers, as well as broader social, environmental and ethical interests.
Board relations with management
The Board was responsible for overall control of the Group’s affairs. The Corporate Management Team was responsible for control and management of day-to-day business matters. The Board delegated day-to-day and business control matters to the Chief Executive Officer who, with the Corporate Management Team, was responsible for implementing Group policy and monitoring the performance of the business.
During fiscal year 2010, the Corporate Management Team comprised the Chief Executive Officer, Chief Operating Officer, Chief Financial Officer, Senior Vice Presidents of Territories 1 and 2 and the heads of all key Group functions. Effective liaison between the Board and the Corporate Management Team was achieved through regular attendance by members of the Corporate Management Team at Board meetings, and the provision of financial and operational updates by the Corporate Management Team to the Board.
|
46 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Board balance The Board comprised a Non-executive Chairman, the Non-executive Deputy Chairman, the Chief Executive Officer, and four further Non-executive Directors.
The Chairman was responsible for the leadership of the Board, ensuring its effectiveness and independence from the Group’s management. The Chief Executive Officer was responsible for implementing the strategy of the business, within the authorities delegated to him by the Board.
The Chairman was supported by the Deputy Chairman. The Non-executive Directors provided experience and knowledge gained in a variety of sectors, and constructively challenged management’s proposals for the strategy and direction of the business.
Ron Henderson was appointed to the Board at the 2010 Annual General Meeting.
Directors’ interests The interests of the Directors in the share capital of the Company as at January 7, 2011, being the last effective date of the Board, prior to completion of the Combination is set out below:
|
|
|||||
| Director |
Number of
shares held |
|
||||
|
Sir Peter Mason KBE FREng |
10,000 | |||||
|
Tom Ehret |
90,094 | |||||
|
Jean Cahuzac (a) (b) |
77,258 | |||||
|
Thorleif Enger |
nil | |||||
|
Dod A. Fraser |
2,000 | |||||
|
Ron Henderson |
nil | |||||
|
J. Frithjof Skouverøe |
26,500 | |||||
|
Trond Ø. Westlie |
nil | |||||
|
Total |
205,852 | |||||
|
(a) Restricted shares held represents the maximum award assuming all conditions are met.
(b) In addition to Shares held, as detailed above, Mr. Cahuzac also held 70,000 Performance Shares.
Details of share options held by Directors are shown in the Remuneration Report.
Immediately prior to completion of the Combination on January 7, 2010, the Directors of Acergy S.A. (detailed above) directly and indirectly owned a total of 205,852 shares (excluding Performance Shares), representing less than 0.1% of all issued shares in Acergy S.A. prior to completion of the Combination.
Directors’ term of office The appointment of Tom Ehret, Thorleif Enger, Ron Henderson and J. Frithjof Skouverøe to the Board ceased upon completion of the Combination with Subsea 7 Inc. Upon completion of the Combination, the Company was renamed Subsea 7 S.A. and the appointment of the Board of Subsea 7 S.A. (detailed on pages 34 to 35) became effective.
How the Board operated Schedule of meetings The Board met thirteen times during the fiscal year, with meetings scheduled around key reporting dates in the Group’s financial calendar, and all Directors were encouraged to attend all meetings wherever possible. The increased number of Board meetings during fiscal year 2010 (2009: five) was primarily due to the consideration and subsequent approval and recommendation to shareholders of the proposed Combination with Subsea 7 Inc. Details of the Directors’ attendance at meetings of the Board and its Committees, in person or via telephone conference, during fiscal year 2010 are shown below: |
|
|||||
| Board |
Audit
Committee |
Governance and Nomination Committee |
Compensation Committee |
|||||||||||||||
|
2010 Meetings |
13 | 4 | 2 | 3 | ||||||||||||||
|
Sir Peter Mason KBE FREng |
13/13 | 2/2 | 2/2 | – | ||||||||||||||
|
Tom Ehret |
13/13 | – | 2/2 | 3/3 | ||||||||||||||
|
Jean Cahuzac |
13/13 | – | – | – | ||||||||||||||
|
Thorleif Enger |
9/13 | – | 1/2 | 1/3 | ||||||||||||||
|
Dod Fraser |
13/13 | – | – | 3/3 | ||||||||||||||
|
Ron Henderson |
6/8 | 1/2 | – | – | ||||||||||||||
|
J. Frithjof Skouverøe |
12/13 | 4/4 | – | – | ||||||||||||||
|
Trond Westlie |
11/13 | 3/4 | – | – | ||||||||||||||
|
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|
|
47
|
Governance
The Board – Acergy S.A. fiscal year 2010 continued
Purpose of meetings
The agendas of the Board meetings were drawn up by the Chairman, on the recommendation of Management. The Board regularly met without members of Management present. The Non-executive Directors also regularly met without the presence of Executive Directors.
Annual General Meeting business
The Company’s 2010 Annual General Meeting was held in Luxembourg on May 28, 2010. At the Annual General Meeting Shareholders approved the (re)election of the Directors to the Board, the Annual Report and Financial Statements of the Group and Company, the appointment of the external auditors. Shareholders also gave authorisation to permit the purchase of common shares and approved the proposed dividend.
Extraordinary General Meetings
The Company held three Extraordinary General Meetings during 2010. At an Extraordinary General Meeting on February 16, 2010, the resolution to appoint Dod Fraser as a Non-executive Director was approved by Shareholders.
At a subsequent Extraordinary General Meeting on November 9, 2010, Shareholders approved:
| · |
the first resolution, to approve the Combination of the Company with Subsea 7 Inc., the increase of the authorised share capital of the Company and the amendment of the Articles of Incorporation with effect from completion of the Combination, including changing the name of the Company to ‘Subsea 7 S.A.’; and |
| · |
the second resolution, to appoint the eight named Directors to the Board of Directors of the combined Group, effective upon completion of the Combination. |
A further Extraordinary General Meeting was held on December 20, 2010, at which Shareholders approved the resolution to appoint Bob Long as the ninth Director of the Board of Directors of the Combined Group, effective upon completion of the Combination.
Dividends
Following shareholder approval at the 2010 Annual General Meeting, the Company paid a dividend of $0.23 per common share to shareholders on June 12, 2010 and to holders of American Depository Receipts on June 14, 2010.
Audit Committee Report
The Acergy S.A. Audit Committee had overall responsibility for overseeing the accounting and financial processes of the Group and was directly responsible for the appointment, compensation, retention and oversight of the work of the Group’s external auditor. For a list of key duties, see ‘Audit Committee’ on page 39.
The Acergy S.A. Audit Committee was chaired by Trond Westlie who, was Chief Financial Officer of AP Moeller Maersk, and previously of Telenor Group. The Board determined that Trond Westlie was the Audit Committee’s financial expert and competent in accounting and audit practice and had recent and relevant financial experience. The other Committee members were Sir Peter Mason KBE and J. Frithjof Skouverøe.
The Acergy S.A. Audit Committee’s Terms of Reference required that the Committee consisted of not less than three Non-executive Directors, and that all three members of the Committee were independent, Non-executive Directors. This Committee met four times during fiscal year 2010, and its meetings were attended by representatives of the external independent auditor and the Head of Internal Audit.
Governance and Nomination Committee
The Acergy S.A. Governance and Nomination Committee assisted the Board with respect to matters related to governance and succession. For a list of key duties, see ‘Governance and Nomination Committee’ on page 39.
The Acergy S.A. Governance and Nomination Committee was chaired by Sir Peter Mason KBE. The other Committee members were Tom Ehret and Thorleif Enger. All three members of this Committee were Independent Non-executive Directors.
Compensation Committee Report
The Acergy S.A. Compensation Committee reviewed and decided upon issues of compensation strategy, management appointments and compensation awards. In matters relating to the Chief Executive Officer, the Committee’s remit was confined to making recommendations to the Board. For a list of key duties, see ‘Compensation Committee’ on page 40.
The Acergy S.A. Compensation Committee was chaired by Tom Ehret. The other Committee members were Thorleif Enger and Dod Fraser. All three members of this Committee were Independent Non-executive Directors.
Disclosure Committee
The Acergy S.A. Disclosure Committee assisted the Chief Executive Officer and Chief Financial Officer in fulfilling their responsibility for oversight of the accuracy and timeliness of the disclosures made by the Group. For a list of key duties, see ‘Disclosure Committee’ on page 40.
|
48 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
Governance
Remuneration Report – Acergy S.A. fiscal year 2010
|
Remuneration Report The Group’s remuneration policy was set by the Compensation Committee. The policy was designed to provide remuneration packages which would 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 sought to ensure that the Group offered rewards and incentives which were competitive with those offered by the Group’s peers. The Committee sought to ensure that the remuneration policy was applied consistently across the Group and that remuneration was fair and transparent, whilst encouraging high performance.
Executive remuneration comprised base salary, bonus, share based payments, benefits-in-kind and pension contributions. In benchmarking elements of remuneration against Subsea 7’s peers, the Compensation Committee took advice from time to time from external consultants. External advice was taken for the Acergy S.A. 2009 Long-Term Incentive Plan.
Chief Executive Officer remuneration The remuneration package of the Chief Executive Officer was determined by the Board on the recommendation of the Compensation Committee.
The compensation of the Chief Executive Officer, for fiscal year 2010 was $2.0 million (2009: $2.1 million) and included base salary, bonus, benefits-in-kind and pension contributions. This excluded compensation paid under the incentive plans described below. Effective April 14, 2008, as a component of his compensation package, he was awarded 20,000 restricted shares under the Restricted Share Plan and 70,000 Performance Shares under the 2009 Long-Term Incentive Plan. He also held as at January 7, 2011 share options, which are shown in the table below:
|
|
|||||||||||||||||
| Name | Date of Grant | Number (a) | Exercise Price ($) | Date of Expiry |
|
|||||||||||||
|
Jean P. Cahuzac |
April 14, 2008 | 100,000 | 24.20 | April 13, 2018 | ||||||||||||||
|
(a) Represents the number of common shares to be awarded.
Non-executive Directors’ fees and share options Non-executive Directors were paid a base fee for their services, with additional fees to reflect membership of committees and further fees to reflect chairmanship of committees. The fee structure which applied during fiscal year 2010 was as follows:
|
|
|||||||||||||||||
| Fee | $ per annum | |||||||||||||||||
|
Chairman fee |
200,000 | |||||||||||||||||
|
Deputy Chairman fee |
117,000 | |||||||||||||||||
|
Base fee for Non-executive Directors |
105,000 | |||||||||||||||||
|
Additional fee for Audit Committee members |
|
6,000 | ||||||||||||||||
|
Additional fee for chairing a Committee |
8,000 | |||||||||||||||||
|
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|
|
49
|
Governance
Remuneration Report continued
Details of the fees paid to Non-executive Directors for the fiscal year to November 30, 2010 are set out below:
| Name | Annual Fee ($) |
Chairman of Committee ($) |
Member of Audit Committee ($) |
2010 Total ($) |
2009 Total ($) |
|||||||||||||||
|
Sir Peter Mason KBE FREng |
200,000 | 200,000 | 174,178 | |||||||||||||||||
|
Tom Ehret |
117,000 | 8,000 | 125,000 | 102,000 | ||||||||||||||||
|
Thorleif Enger |
105,000 | 105,000 | 36,918 | |||||||||||||||||
|
Dod Fraser |
105,000 | 105,000 | – | |||||||||||||||||
|
Ron Henderson |
105,000 | 6,000 | 111,000 | – | ||||||||||||||||
|
J. Frithjof Skouverøe |
105,000 | 6,000 | 111,000 | 107,500 | ||||||||||||||||
|
Trond Westlie |
105,000 | 8,000 | 113,000 | 115,000 | ||||||||||||||||
Non-executive Directors did not receive pension contributions, benefits-in-kind or bonuses. Non-executive Directors were previously eligible to participate in share option plans. However, a review was undertaken, based on advice provided by external advisors, as a result of which Non-executive Directors agreed to the cancellation of share options awarded to them in March 2008. Options awarded prior to March 2008 and still held by Non-executive Directors, as at January 7, 2011 were as follows:
| Name of Director | Date of Grant | Number (a) | Exercise Price ($) | Date of Expiry | ||||||||||||
|
Sir Peter Mason KBE FREng |
November 21, 2006 | 5,000 | 19.45 | November 20, 2016 | ||||||||||||
|
Tom Ehret |
November 22, 2005 | 33,750 | 10.32 | November 21, 2015 | ||||||||||||
| November 21, 2006 | 50,000 | 19.45 | November 20, 2016 | |||||||||||||
|
Thorleif Enger |
Nil | |||||||||||||||
|
Dod Fraser |
Nil | |||||||||||||||
|
Ron Henderson |
Nil | |||||||||||||||
|
J. Frithjof Skouverøe |
November 12, 2004 | 5,000 | 5.02 | November 11, 2014 | ||||||||||||
| November 22, 2005 | 5,000 | 10.32 | November 21, 2015 | |||||||||||||
| November 21, 2006 | 5,000 | 19.45 | November 20, 2016 | |||||||||||||
|
Trond Westlie |
November 12, 2004 | 5,000 | 5.02 | November 11, 2014 | ||||||||||||
| November 22, 2005 | 5,000 | 10.32 | November 21, 2015 | |||||||||||||
| November 21, 2006 | 5,000 | 19.45 | November 20, 2016 | |||||||||||||
|
Total |
118,750 | |||||||||||||||
| (a) | Represents the number of common shares awarded. |
|
50 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Corporate Management Team remuneration The aggregate compensation for the eleven members of the Corporate Management Team (excluding the Chief Executive Officer) for fiscal year 2010 was $8.8 million (fiscal year 2009: $7.5 million; ten members). This included base salary, bonus, benefits-in-kind, pension contributions and an element of performance bonus which was related to the future development of the Group’s share price. Share options held by the Corporate Management Team and details of long-term incentive arrangements are shown below.
Share options held by the Corporate Management Team (excluding the Chief Executive Officer) as at January 7, 2011 were as follows:
|
|
|||||||||||||
| Name | Date of Grant | Number (a) | Exercise Price ($) | Date of Expiry | ||||||||||
|
Gaël Cailleaux |
November 22, 2005 | 4,500 | 10.32 | November 21, 2015 | ||||||||||
| November 21, 2006 | 5,000 | 19.45 | November 20, 2016 | |||||||||||
| March 12, 2008 | 8,000 | 22.52 | March 11, 2018 | |||||||||||
|
Olivier Carré |
November 22, 2005 | 10,000 | 10.32 | November 21, 2015 | ||||||||||
| November 21, 2006 | 25,000 | 19.45 | November 20, 2016 | |||||||||||
| March 12, 2008 | 35,000 | 22.52 | March 11, 2018 | |||||||||||
|
Bruno Chabas |
December 5, 2003 | 5,625 | 2.24 | December 4, 2013 | ||||||||||
| November 22, 2005 | 24,374 | 10.32 | November 21, 2015 | |||||||||||
| November 21, 2006 | 35,000 | 19.45 | November 20, 2016 | |||||||||||
| March 12, 2008 | 25,000 | 22.52 | March 11, 2018 | |||||||||||
|
Simon Crowe |
Nil | |||||||||||||
|
Andrew Culwell |
May 9, 2001 | 1,000 | 13.56 | May 8, 2011 | ||||||||||
| December 3, 2001 | 1,000 | 6.25 | December 2, 2011 | |||||||||||
| March 17, 2003 | 1,000 | 1.19 | March 16, 2013 | |||||||||||
| December 5, 2003 | 10,000 | 2.24 | December 4, 2013 | |||||||||||
| November 12, 2004 | 6,000 | 5.02 | November 11, 2014 | |||||||||||
| November 22, 2005 | 4,500 | 10.32 | November 21, 2015 | |||||||||||
| November 21, 2006 | 4,500 | 19.45 | November 20, 2016 | |||||||||||
| March 12, 2008 | 6,000 | 22.52 | March 11, 2018 | |||||||||||
|
Jean-Luc Laloë |
November 21, 2006 | 24,500 | 19.45 | November 20, 2016 | ||||||||||
| March 12, 2008 | 15,000 | 22.52 | March 11, 2018 | |||||||||||
|
Allen Leatt |
November 21, 2006 | 24,500 | 19.45 | November 20, 2016 | ||||||||||
| March 12, 2008 | 15,000 | 22.52 | March 11, 2018 | |||||||||||
|
Øyvind Mikaelsen |
May 14, 2004 | 60,000 | 2.30 | May 13, 2014 | ||||||||||
| November 12, 2004 | 3,300 | 5.02 | November 11, 2014 | |||||||||||
| November 22, 2005 | 18,750 | 10.32 | November 21, 2015 | |||||||||||
| November 21, 2006 | 30,000 | 19.45 | November 20, 2016 | |||||||||||
| March 12, 2008 | 15,000 | 22.52 | March 11, 2018 | |||||||||||
|
Johan Rasmussen |
December 3, 2003 | 13,750 | 2.24 | December 2, 2013 | ||||||||||
| May 14, 2004 | 30,000 | 2.30 | May 13, 2014 | |||||||||||
| November 12, 2004 | 6,050 | 5.02 | November 11, 2014 | |||||||||||
| November 22, 2005 | 16,500 | 10.32 | November 21, 2015 | |||||||||||
| November 21, 2006 | 24,500 | 19.45 | November 20, 2016 | |||||||||||
| March 12, 2008 | 15,000 | 22.52 | March 11, 2018 | |||||||||||
|
Keith Tipson |
November 22, 2005 | 22,000 | 10.32 | November 21, 2015 | ||||||||||
| November 21, 2006 | 24,500 | 19.45 | November 20, 2016 | |||||||||||
| March 12, 2008 | 15,000 | 22.52 | March 11, 2018 | |||||||||||
|
Total |
584,849 | |||||||||||||
| (a) Represents | the number of common shares awarded. |
|
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|
|
51
|
Governance
Remuneration Report continued
Share ownership of Corporate Management Team
The interests of the Corporate Management Team (excluding the Chief Executive Officer) in the share capital of the Company as at January 7, 2011 the date of completion of the Combination, are set out below:
| Name |
Total
Performance Shares (a) |
Total
Owned Shares (b) |
||||||
|
Gaël Cailleaux |
24,000 | 18,752 | ||||||
|
Olivier Carré |
35,000 | 11,084 | ||||||
|
Bruno Chabas (a) |
50,000 | 26,504 | ||||||
|
Simon Crowe |
44,000 | 17,703 | ||||||
|
Andrew Culwell |
10,000 | 590 | ||||||
|
Jean-Luc Laloë (a) |
25,000 | 27,114 | ||||||
|
Allen Leatt (a) |
32,000 | 5,000 | ||||||
|
Øyvind Mikaelsen |
35,000 | 13,313 | ||||||
|
Johan Rasmussen (a) |
25,000 | 17,752 | ||||||
|
Keith Tipson (a) |
32,000 | 13,836 | ||||||
|
Total |
312,000 | 151,648 | ||||||
| (a) | Total performance shares represent the maximum award assuming all conditions are met. |
| (b) | Includes shares purchased or allocated under the Executive Deferred Incentive Schemes and the Restricted Share Plan and represents the maximum award assuming all conditions are met. |
As at January 7, 2011, the Corporate Management Team directly and indirectly owned a total of 151,648 shares, representing 0.1% of issued shares in Acergy S.A. prior to completion of the Combination. The Chief Executive’s interest in Acergy S.A. shares is shown in ‘Directors interests’.
Pension arrangements
Acergy S.A. operated a number of pension schemes, depending on location, covering certain qualifying employees. One of these pension schemes was a defined benefit scheme; the remainder were defined contribution schemes. The Chief Executive Officer, and all members of the Corporate Management Team, were members of defined contribution schemes sponsored by the Group, and contributions were made by the Group to those schemes on their behalf.
Long-term incentive arrangements
The Group operated a number of long-term incentive arrangements to reward and incentivise key management. These are summarised in ‘Share ownership of the Executive Management Team – long-term incentive arrangements’ on page 42.
|
52 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Governance Chief Executive Officer and Chief Financial Officer’s Responsibility Statement
Chief Executive Officer and Chief Financial Officer’s Responsibility Statement We confirm to the best of our knowledge that:
· the consolidated financial statements of the Group presented in this Annual Report and prepared in accordance with International Financial Reporting Standards (‘IFRS’) and as adopted in the European Union (‘EU’) give a true and fair view of the assets, liabilities, financial position and profit of Subsea 7 S.A. and the undertakings included within the consolidation taken as a whole; and
· the management report includes a fair review of the development and performance of the business and the position of Subsea 7 S.A. and the undertakings included within the consolidation taken as a whole, together with a description of the principal risks and uncertainties that they face.
By order of the Board
Chief Executive Officer Jean Cahuzac
February 23, 2011
Chief Financial Officer Simon Crowe
February 23, 2011 |
|
|
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|
|
53
|
Financial Review and Statements
Financial Review
Strong financial performance
2010 was a year characterised by a measure of stabilisation of the energy and financial markets. While the global economic recession continued to impact exchange rates in the US and the Eurozone, commodity markets recovered from their previous lows and some calm seemed to return to the wider market. Our 2010 fiscal year finished with the price of oil at approximately $85 per barrel which was very similar to the price at the start of the fiscal year and the volatility in the price of oil was less than experienced in recent previous years. Clients remained cautious with delays in some contract awards; however we saw some good awards and Backlog growth which indicated a more positive market sentiment.
It was a busy year for the Group which was dominated by the negotiation and preparation for the Combination with Subsea 7 Inc. Borealis was purchased in December 2009, and the construction and conversion continued throughout the year. We also completed the purchase of Antares , Pertinacia and Polar Queen . In addition, we replaced our bank facilities with a new five year, $1 billion multi-currency revolving credit and guarantee facility. On top of this we delivered a very strong financial performance.
Financial strategy
We continued to focus on our financial strategy which can be summarised as maintaining a strong balance sheet to support the growth of our business in targeted regions with specific services and provide sufficient funding through the business cycle. We will achieve these objectives by having the best people and the best assets. We continually analyse business opportunities that match our resources and those that maximise cash flow, whilst being disciplined in maintaining strict debt service and debt volume ratios. The four key elements of our financial strategy remain as follows:
| — |
Cost control |
| — |
Aligned corporate and entity structure |
| — |
Strong balance sheet to support growth and financial flexibility |
| — |
Robust control environment |
Financial highlights
| For the fiscal year ended November 30 (in $ millions, except share and per share data) | 2010 | 2009 | ||||||
|
Continuing operations: |
||||||||
|
Revenue |
2,369.0 | 2,208.8 | ||||||
|
Gross profit |
668.0 | 525.0 | ||||||
|
Net operating income |
436.1 | 342.7 | ||||||
|
Income before taxes |
399.2 | 361.3 | ||||||
|
Taxation |
(130.8) | (102.8) | ||||||
|
Income from continuing operations |
268.4 | 258.5 | ||||||
|
Net income from discontinued operations |
44.6 | 7.2 | ||||||
|
Net income |
313.0 | 265.7 | ||||||
|
Net income attributable to: |
||||||||
|
Equity holders of parent |
265.4 | 245.0 | ||||||
|
Non-controlling interest |
47.6 | 20.7 | ||||||
| 313.0 | 265.7 | |||||||
| Earnings per share – continuing operations |
$ per
share |
$ per
share |
||||||
|
Basic |
1.20 | 1.30 | ||||||
|
Diluted |
1.16 | 1.29 | ||||||
|
Weighted average number of common shares and common share equivalents |
||||||||
|
Outstanding (millions) |
||||||||
|
Basic |
183.5 | 183.0 | ||||||
|
Diluted |
206.7 | 183.8 | ||||||
|
54 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Continuing operations In fiscal year 2010 the Group delivered revenue from continuing operations of $2,369.0 million (2009: $2,208.8 million), which was an increase of 7%, primarily reflecting strong operational performance.
Our business was divided into segments on a geographic basis. See Note 6 ‘Segment information’ to the Consolidated Financial Statements for further information regarding revenues of our business segments.
Revenue from continuing operations generated by these segments was:
|
|
|||||||||||||||||||
| 2010 | 2009 | |||||||||||||||||||
|
Revenue
(in $ millions) |
Percentage
of total |
Revenue
(in $ millions) |
Percentage
of total |
|||||||||||||||||
|
Acergy NEC |
568.1 | 24.0% | 648.8 | 29.4% | ||||||||||||||||
|
Acergy AME |
179.8 | 7.6% | 206.0 | 9.3% | ||||||||||||||||
|
Acergy AFMED |
1,361.4 | 57.4% | 999.7 | 45.3% | ||||||||||||||||
|
Acergy SAM |
214.3 | 9.0% | 288.8 | 13.1% | ||||||||||||||||
|
Acergy NAMEX |
34.6 | 1.5% | 57.8 | 2.6% | ||||||||||||||||
|
Acergy Corporate |
10.8 | 0.5% | 7.7 | 0.3% | ||||||||||||||||
| 2,369.0 | 100.0% | 2,208.8 | 100.0% | |||||||||||||||||
|
Revenue from continuing operations generated by project activities was:
|
|
|||||||||||||||||||
| 2010 | 2009 | |||||||||||||||||||
|
Revenue (in $ millions) |
Percentage
of total |
Revenue (in $ millions) |
Percentage
of total |
|||||||||||||||||
|
SURF |
1,238.6 | 52.3% | 1,615.8 | 73.1% | ||||||||||||||||
|
Conventional |
887.8 | 37.5% | 388.2 | 17.6% | ||||||||||||||||
|
IMR/Survey |
242.6 | 10.2% | 204.8 | 9.3% | ||||||||||||||||
| 2,369.0 | 100.0% | 2,208.8 | 100.0% | |||||||||||||||||
|
Income before taxes from continuing operations increased 10% to $399.2 million (2009: $361.3 million) reflecting strong operational performance. Net income from continuing operations also increased by 4% to $268.4 million (2009: $258.5 million) in spite of an increase in the effective tax rate from 28% in fiscal year 2009 to 33% in fiscal year 2010.
For further detail refer to pages 60 to 63 of the Financial Review.
Earnings per share and dividends Earnings per share Basic earnings per share from continuing operations decreased to $1.20 (2009: $1.30) reflecting increased pressure on administration expenses as a result of the Combination, adverse foreign exchange impacts and increased taxation charges, partially offset by strong subsidiary and joint venture performance. Total diluted earnings per share for continuing operations was $1.16 (2009: $1.29) from a total diluted share count of 206.7 million (2009: 183.8 million). The convertible loan note was considered dilutive in fiscal year 2010 (2009: anti-dilutive) and the number of shares to be issued on conversion has therefore been included in the diluted share count when calculating the diluted earnings per share.
Dividends per share In light of the development of the combined business and the Group’s investment opportunities, the Board has proposed not to pay a dividend for the 2010 fiscal year. The Board is reviewing methods of balancing the optimal use of cash in light of the opportunities available. The Group distributed a total of $42.2 million to our shareholders in fiscal year 2010 (2009: $40.2 million) in the form of dividends and did not execute any further share buybacks. We delivered a Total Shareholder Return of 39% for the fiscal year 2010 (2009: 162%). |
|
|
||||||||||||||||||
|
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|
|
55
|
Financial Review and Statements
Financial Review continued
Cash flow
Movements in cash balances are summarised as follows:
| For the fiscal year (in $ millions) | 2010 | 2009 | ||||||
|
Cash and cash equivalents at the beginning of the year |
907.6 | 573.0 | ||||||
|
Net cash generated from operating activities |
140.0 | 546.1 | ||||||
|
Net cash used in investing activities |
(493.3) | (100.4) | ||||||
|
Net cash used in financing activities |
(84.5) | (52.0) | ||||||
|
Effect of exchange rate changes on cash and cash equivalents |
(25.4) | 44.5 | ||||||
|
Movement in cash balances classified as assets held for sale |
39.9 | (103.6) | ||||||
|
Cash and cash equivalents at the end of the year |
484.3 | 907.6 | ||||||
Cash generated from operating activities was significantly lower in fiscal year 2010 ($140.0 million) than in fiscal year 2009 ($546.1 million), a decrease of $406.1 million. Increased working capital accounted for most of this decrease: receivables increased due to the strong revenue performance in the second half; approximately $50 million of receivables related to the insurance claim in respect of the Acergy Falcon fire; and payables, excluding capital accruals relating to the construction of Borealis , decreased. We also had an increase in taxes paid due to settlement of various matters in fiscal year 2010 and a higher tax charge for the year.
Our investing activities consumed $493.3 million in fiscal year 2010 compared with $100.4 million in fiscal year 2009. This increase was attributable to the purchase and construction of Borealis as well as the purchase of Antares , Pertinacia and Polar Queen .
Cash used in financing activities relates mainly to issuance costs of new borrowings and the payment of dividends to shareholders and non-controlling interests. We also paid interest on our convertible loan notes in April and October 2010.
The foreign exchange markets remained volatile and this resulted in a $25.4 million adverse impact on our cash balances.
Our asset held for sale, Sonamet, performed strongly in fiscal year 2010. The reduction of cash of $39.9 million was as a result of Sonamet declaring and paying a dividend in fiscal year 2010.
Liquidity
At the end of fiscal year 2010 the Group had unutilised committed credit and guarantee facilities of $827.3 million, of which $500 million was available for cash drawings. On August 10, 2010 we executed our new $1 billion multi-currency revolving credit and guarantee facility which replaced our existing facilities. Combined with cash balances of $484.3 million, this ensured that as at November 30, 2010, the Group had sufficient liquid resources to meet operating requirements for the next twelve months. We continue to monitor our future business opportunities and actively review our credit and guarantee facilities and our long-term funding requirements.
In June 2010, the conversion price of our convertible loan notes was revised to $22.37 per share (2009: $22.71) following shareholder approval of a dividend of $0.23 per common share or share equivalent at the 2010 Annual General Meeting. The conversion price will continue to be adjusted in line with the terms of the convertible loan notes. The notes mature in October 2013 and are a very cost effective source of funds.
Covenant compliance
Our 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 fiscal year 2010 all covenants were met. The Group must meet the requirements of the financial covenants on a consolidated basis in quarterly intervals on the last day of each fiscal quarter. Based on our latest forecasts, the newly combined company, Subsea 7 S.A., expects that it will be able to comply with all financial covenants during fiscal year 2011.
|
56 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| Balance sheet | ||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||
|
Property, plant and equipment |
1,278.8 | 821.8 | ||||||||
|
Interest in associates and joint ventures |
215.1 | 190.3 | ||||||||
|
Trade and other receivables |
382.0 | 297.9 | ||||||||
|
Assets held for sale |
255.5 | 263.6 | ||||||||
|
Other accrued income and prepaid expenses |
242.3 | 212.8 | ||||||||
|
Cash and cash equivalents |
484.3 | 907.6 | ||||||||
|
Other assets |
131.5 | 139.1 | ||||||||
|
Total assets |
2,989.5 | 2,833.1 | ||||||||
|
Total equity |
1,259.3 | 1,099.2 | ||||||||
|
Non-current portion of borrowings |
435.3 | 415.8 | ||||||||
|
Trade and other liabilities |
673.3 | 624.1 | ||||||||
|
Deferred revenue |
217.8 | 279.8 | ||||||||
|
Current tax liabilities |
109.9 | 97.9 | ||||||||
|
Liabilities associated with assets held for sale |
134.5 | 174.9 | ||||||||
|
Other liabilities |
159.4 | 141.4 | ||||||||
|
Total liabilities |
1,730.2 | 1,733.9 | ||||||||
|
Total equity and liabilities |
2,989.5 | 2,833.1 | ||||||||
|
Backlog |
|
|||||||||
| Backlog for continuing operations as at November 30, 2010 was $3.6 billion (2009: $2.8 billion), of which $2.7 billion relates to our SURF activity, $0.8 billion to Conventional and $0.1 billion to Survey/IMR. | ||||||||||
|
We expect that $1.8 billion of this Backlog will be executed in fiscal year 2011, $0.9 billion in fiscal year 2012 and $0.9 billion in fiscal year 2013 and thereafter. Backlog excludes associates, joint ventures and discontinued operations. On January 7, 2011, the Combination with Subsea 7 Inc. was completed, significantly increasing Backlog for execution in fiscal year 2011 and beyond. |
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|
Outlook |
|
|||||||||
| We are looking forward to 2011 with confidence. A robust oil price and rising tendering activity around the world underpins order book momentum. Execution and activity levels are expected to rise, although contracts awarded in more challenging market conditions during 2009 and 2010 will impact the Group’s Adjusted EBITDA margin in 2011. |
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|
Conventional activity in West Africa is expected to remain strong in the short and medium-term. A number of the major SURF contracts, in Australia, Brazil and West Africa, are expected to come to market award in 2011. The offshore installation phase of any such new SURF projects will commence beyond 2011. In the North Sea we are seeing renewed activity, albeit in a pricing environment that, for shorter-term work, remains competitive. |
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|
We believe that the trend will be for subsea projects to continue to increase in size and complexity which will contribute to strong industry growth in the medium-term for those companies that have the capabilities to meet these challenges. |
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seabed-to-surface
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57
|
Financial Review and Statements
Financial Review continued
Significant factors affecting results of operations and financial position
Business environment
The Group’s services largely depend on the success of exploration and the level of investment in upstream offshore exploration and production by the major oil companies. Management believes the medium-term market fundamentals for its business remain strong, driven by increasing field depletion and clients’ strategic needs to access new reserves and replenish production, including the development of hydrocarbon discoveries in increasingly challenging acreage.
2008 witnessed significant and historic events in capital and commodity markets with global financial markets suffering the most serious crisis since the great crash of 1929. For commodity markets, 2008 was a year of extremes as the oil price reached nearly $150 per barrel, later falling to below $40 per barrel. The effect of the economic downturn remained evident throughout 2009. The combination of macro economic concerns and oil price weakness dented market confidence which, together with the credit crunch, put pressure on clients’ short and medium-term capital expenditure plans, resulting in clients delaying the award of large SURF projects and poor short-term visibility in this market. Consequently there was a lower level of activity with pressure on prices throughout 2009.
In 2010, a stronger oil price and more stable macro environment inspired greater confidence in the industry. During the year, tendering activity increased worldwide. In the second half of 2010, a number of contracts that were delayed during 2009, including the first of the delayed major SURF contracts, came to market award. The Group expects further major SURF contracts to come to market award in 2011. The offshore installation phase of these new SURF projects will commence beyond 2011. In the short and medium-term, the Group expects the demand for Conventional services in West Africa to remain strong.
During 2010, events surrounding the Macondo well incident in the US Gulf of Mexico raised questions regarding future activity and regulation within the industry. The Group currently has no material exposure to the US Gulf of Mexico, therefore it does not anticipate a direct impact on its financial performance in the short or medium-term. However, the Group anticipates that some deepwater projects in the US Gulf of Mexico that were previously due to come to market award over the next twelve months may be delayed until late 2011 or possibly 2012. The incident has placed a greater focus on reliability, engineering, and project management resources. The Group anticipates this focus to translate into the specifications for new projects and it is possible that new regulations may be introduced in the US and elsewhere as a result. Whilst it is impossible to predict the impact of any such new regulations, the Group believes its expertise and continued focus on operating to the highest safety standards in the industry provides a good platform to meet such future challenges.
Seasonality
A significant portion of the Group’s revenue in fiscal year 2010 and fiscal year 2009 was generated from work performed offshore West Africa where optimal weather conditions exist only from October to April, with most offshore operations being scheduled for that period. The Group also generated a significant portion of its revenue in fiscal years 2010 and 2009 in the North Sea and Norwegian Sea. Adverse weather conditions during the winter months in this region usually result in low levels of activity. Due to global economic conditions since 2008, the seasonal patterns of an increased level of activity during the summer usually observed in the North Sea and the Norwegian Sea have been noticeably dampened. The Group is expected to generate a significant portion of its revenue from West Africa, the North Sea and Norwegian Sea.
A full-year result is not likely to be a direct multiple of any particular quarter or combination of quarters. During certain periods of the year, the Group may be affected by delays caused by adverse weather conditions such as hurricanes or tropical storms. The Group continues to incur operating expenses during periods of adverse weather, but revenue from operations may only be recognised later in line with the percentage-of-completion method.
Vessel utilisation
The Group’s ability to earn revenue is driven by its optimisation of the utilisation of its vessels. The utilisation rate is calculated by dividing the total number of days for which the vessels were engaged in project-related work by 350 days annually, expressed as a percentage. The remaining 15 days are attributable to routine maintenance.
Utilisation of major vessels (excludes barges and minor support vessels) was 70% in fiscal year 2010 compared to 80% for fiscal year 2009.
The utilisation of deepwater and heavy construction vessels declined compared to fiscal year 2009, primarily due to the prevailing market conditions in the North Sea and Norwegian Sea in fiscal year 2010. Acergy Falcon had low utilisation in fiscal year 2010 as the vessel was out of service for six months due to a serious fire while in planned dry-dock. Both Acergy Condor and Acergy Harrier were in dry-dock before commencing new service agreements with Petrobras.
Utilisation of light construction and survey vessels has decreased in fiscal year 2010 compared to fiscal year 2009, mainly due to reduced utilisation of Acergy Petrel and Acergy Viking , which operated in the competitive North Sea survey market, where overall activity was lower than in fiscal year 2009.
Vessel scheduling
Performance can be adversely affected by conflicts in the scheduled utilisation of key vessels and barges. These can be caused by delays in releasing vessels from projects due to additional client requirements and overruns. Conflicts can also arise from commercial decisions concerning the utilisation of assets after work has been tendered and contracted for. The need to substitute vessels or barges as a result of unavailability of initially planned vessels or barges can adversely affect the results of the projects concerned.
|
58 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| Maintenance and reliability of assets | ||||||||||||||||
| The successful execution of contracts requires a high degree of reliability of vessels, barges and equipment. Breakdowns not only add to the costs of executing a project, but can also cause delays in the completion of subsequent contracts which are scheduled to utilise the same assets. The Group operates a scheduled maintenance programme in order to keep all assets in good working order but, despite this, breakdowns can and do occur. | ||||||||||||||||
|
Revisions on major projects |
|
|||||||||||||||
| During the course of major projects, adjustments to the original estimates of the total contract revenue, total contract cost, or extent of progress toward completion are often required as the work progresses under the contract and as experience is gained, even though in certain cases the scope of work required under the contract may not change. Where a change of scope is required, variation orders are negotiated with the client. However final agreement and settlement are often not achieved until late in the project. As discussed in Note 3 ‘Significant accounting policies – revenue recognition’ to the Consolidated Financial Statements, these revisions to estimates will not result in restating amounts in previous periods. | ||||||||||||||||
|
Estimates are revised monthly on the basis of project status reports, which include an updated forecast of the cost to complete each project. Additional information that enhances and refines the estimation process is often obtained after the balance sheet date but before the issuance of the financial statements. Unless the events occurring after the balance sheet date are outside the normal exposure and risk aspects of the contract, such information will not be reflected in the financial statements until the following fiscal year. |
|
|||||||||||||||
|
The revision of estimates calculation is based on the difference between the current and prior fiscal year’s estimated gross margin at completion of the project, multiplied by the prior fiscal year percentage-of-completion. If a project had not commenced at the end of the previous fiscal year, the revision of estimates incurred for this project during the current fiscal year would not be included in the calculation for revision of estimates. |
|
|||||||||||||||
|
The impact of revisions of project estimates, variation orders and project escalations, at the gross profit level is as follows: |
|
|||||||||||||||
|
For the fiscal year (in $ millions) |
2010 | 2009 | 2008 | |||||||||||||
|
Continuing operations |
||||||||||||||||
|
Positive revisions |
179.1 | 154.8 | 180.8 | |||||||||||||
|
Negative revisions |
(8.9 | ) | (73.9 | ) | (4.5 | ) | ||||||||||
|
Total continuing revisions |
170.2 | 80.9 | 176.3 | |||||||||||||
|
Discontinued operations |
||||||||||||||||
|
Positive revisions |
56.5 | 17.5 | – | |||||||||||||
|
Negative revisions |
– | – | (23.8 | ) | ||||||||||||
|
Total discontinued revisions |
56.5 | 17.5 | (23.8 | ) | ||||||||||||
|
Total |
226.7 | 98.4 | 152.5 | |||||||||||||
|
Continuing operations |
|
|||||||||||||||
| There were positive revisions to estimates, variation orders and project escalations (improvements in projected project margin during and at completion of the contract) reported in all business segments during fiscal year 2010. Positive revisions primarily related to Conventional and SURF projects in Acergy AFMED and SURF projects in Acergy NEC where commercial negotiations on the Marathon Volund Project were successfully completed. Negative revisions in fiscal year 2010 were due to increased operating costs primarily related to SURF projects in Acergy AFMED and Acergy NEC. Negative revisions in fiscal year 2009 primarily related to Acergy NEC, which reported $56.5 million of negative revisions on SURF projects, primarily due to increased operating expenses on the Marathon Volund Project which completed during the fiscal year. In fiscal year 2010, negotiations related to claims and variation orders on the Marathon Volund Project were completed and disputed revenues that were agreed were recognised. | ||||||||||||||||
|
Discontinued operations |
|
|||||||||||||||
| There were positive revisions to estimates (improvements in projected project margin during and at completion of the contract) reported in discontinued operations following the completion of operations and commercial negotiations on the Mexilhao Project in Brazil. | ||||||||||||||||
|
Exchange rates |
|
|||||||||||||||
| The Group transacts in a number of foreign currencies and as a result has foreign currency denominated revenue, expenses, assets and liabilities. However, the consolidated Group results are reported in US Dollars. As a consequence, movements in exchange rates can affect profitability, the comparability of results between periods and the carrying value of assets and liabilities. Other than the US Dollar, the major foreign currencies of the Group are the Euro, British Pound and Norwegian Krone. | ||||||||||||||||
|
The policy of the Group is to contract in the functional currency of the contracting entity where possible. However, when the Group incurs revenues or expenses that are not denominated in the same currency as the related functional currency, foreign exchange rate fluctuations can adversely affect profitability. Where it is not possible to contract in functional currency, the Group’s policy is to use foreign exchange contracts to hedge significant external foreign exchange exposure. The US Dollar is the functional currency of the most significant subsidiaries in Acergy NAMEX, Acergy SAM and Acergy AME. In Acergy AFMED, the functional currencies are primarily the Euro, Nigerian Naira and US Dollar. In Acergy NEC, the functional currencies are primarily the Norwegian Krone, US Dollar, Canadian Dollar and British Pound. Exposure to currency exchange rate fluctuations results from net investments in foreign subsidiaries, primarily in the United Kingdom, |
|
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|
seabed-to-surface
|
|
59
|
Financial Review and Statements
Financial Review continued
Norway, France and Brazil. There is also exposure to fluctuations in several other currencies resulting from operating expenditures and significant one-off non-project-related transactions such as capital expenditure.
In order to prepare the consolidated financial statements, non-US Dollar denominated results of operations, assets and liabilities are translated to US Dollars. Balance sheet items are translated into US Dollars using the relevant exchange rate at the fiscal year end for assets and liabilities, and income statement and cash flow items are translated using exchange rates which approximate the average exchange rate during the relevant period. Fluctuations in the value of the US Dollar versus other currencies will have an effect on the reported Consolidated Income Statement and the value of assets and liabilities in the Consolidated Balance Sheet even where the results of operations or the value of those assets and liabilities have not changed in their local functional currency. For more information refer to Note 34 ‘Financial instruments’ to the Consolidated Financial Statements.
As the Group conducts operations in many countries there is exposure to currency exchange rate fluctuations through generation of revenue and expenditure in the normal course of business. The foreign currency rate exposure policy prescribes the range of allowable hedging activity to minimise this exposure. Forward foreign exchange contracts are used primarily to hedge capital expenditure and operational nonfunctional currency exposure on a continuing basis for periods consistent with committed exposures.
Impairment charges
Impairment charges in fiscal year 2010 amounted to $3.8 million (2009: $15.6 million), reflecting a charge of $7.0 million related to software costs included in intangible assets, partially offset by an impairment reversal of $3.2 million (2009: impairment charge of $4.8 million) related to the Group’s investments in Sonamet, which were classified as assets held for sale at November 30, 2010.
For more information regarding impairment charges, refer to Note 15 ‘Intangible assets’, Note 16 ‘Property, plant and equipment’ and Note 21 ‘Assets classified as held for sale’ to the Consolidated Financial Statements.
Impairment charges in fiscal year 2009 amounted to $15.6 million (2008: $2.8 million). The charge for 2009 included $9.8 million relating to underutilised operating equipment and $4.8 million relating to the Group’s investments in Sonamet, which were classified as assets held for sale at November 30, 2009. Discontinued operations contributed $1.0 million to the impairment charge, relating to a reduction in the expected sale price of equipment relating to but not included in the sale of Acergy Piper .
In fiscal year 2008, impairment charges in respect of underutilised operating equipment amounted to $2.8 million and a reversal of an impairment charge relating to Acergy Piper of $14.3 million was reflected in the net loss from discontinued operations.
Financial Review
Revenue
Revenue from continuing operations increased by 7.3% to $2,369.0 million in fiscal year 2010 compared to fiscal year 2009 (2009: $2,208.8 million). SURF activity contributed $1,238.6 million or 52.3% of revenue from continuing operations (2009: $1,615.8 million or 73.1%) . Conventional activity comprised $887.8 million or 37.5% of revenue from continuing operations (2009: $388.2 million, 17.6%) . Other revenue streams related to IMR/Survey activity of $242.6 million (2009: $204.8 million), which represented 10.2% (2009: 9.3%) of revenue from continuing operations. As at November 30, 2010, an estimated $1.8 billion of the $3.6 billion Backlog was scheduled for execution in fiscal year 2011.
Revenue from continuing operations decreased by 12.4% to $2,208.8 million in fiscal year 2009 compared to fiscal year 2008 (2008: $2,522.4 million). SURF activity contributed $1,615.8 million or 73.1% of revenue from continuing operations (2008: $1,832.4 million, 72.6%) . Conventional activity comprised $388.2 million or 17.6% of revenue from continuing operations (2008: $442.0 million, 17.5%) . Other revenue streams related to IMR/Survey activity of $204.8 million (2008: $248.0 million), which represented 9.3% (2008: 9.8%) of the revenue from continuing operations. As at November 30, 2009, an estimated $1.7 billion of the $2.8 billion Backlog was scheduled for execution in fiscal year 2010.
Operating expenses
Operating expenses in fiscal year 2010 amounted to $1,701.0 million (2009: $1,683.8 million), an increase of 1.0% compared to fiscal year 2009, but supporting a 7.3% increase in revenue. The result reflects actions taken in prior years to reduce operating costs and increase operating efficiency.
Operating expenses in fiscal year 2009 amounted to $1,683.8 million (2008: $1,874.2 million), a decrease of 10.2% compared to fiscal year 2008, slightly less than the 12.4% decline in revenue during the same period. Despite careful monitoring of project expenses, operating expenses increased, leading to an overall gross profit margin percentage point decrease of 1.9% compared to fiscal year 2008. This was primarily due to increased operating expenses on the Marathon Volund Project which completed during fiscal year 2009, but for which revenues could not be recognised during fiscal year 2009 while subject to ongoing commercial negotiations.
Gross profit
Gross profit for the fiscal year 2010 was $668.0 million (2009: $525.0 million), an increase of 27.2%, with the gross profit margin of 28.2% increasing from 23.8% in fiscal year 2009. The strong increase in gross profit reflects increased activity levels in Conventional and IMR/Survey and the current portfolio mix with more major SURF projects in installation phase compared to fiscal year 2009. A number of SURF and Conventional projects reached completion during the fiscal year contributing to the increased gross profit margin. This was partially offset by weaker utilisation of vessels. Fiscal year 2010 reflected the successful resolution of commercial negotiations on the Marathon Volund Project,
|
60 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| which completed operations in fiscal year 2009. Certain expenses relating to this project were recognised in fiscal year 2009 but the related revenues could not be recognised during fiscal year 2009 while subject to ongoing commercial negotiations. | ||||||||||||||||
|
Gross profit for the fiscal year 2009 was $525.0 million (2008: $648.2 million), a decrease of 19.0%, with the gross profit margin of 23.8% declining from 25.7% in 2008. The decrease in gross profit reflected lower activity levels and a portfolio mix with fewer major SURF projects in installation phase or completed compared to fiscal year 2008. This was partially offset by good project execution and good utilisation of vessels. |
|
|||||||||||||||
|
Administrative expenses |
|
|||||||||||||||
| Administrative expenses increased $75.4 million (32.6%) to $306.7 million in fiscal year 2010 from $231.3 million in fiscal year 2009 and represented 12.9% of revenue (2009: 10.5%). This increase is largely as a result of the transaction costs of $15.1 million and restructuring costs of $12.1 million relating to the Combination with Subsea 7 Inc., business process and improvement costs, increased tendering activity and foreign exchange impacts. | ||||||||||||||||
|
Administrative expenses decreased $22.5 million (8.9%) to $231.3 million in fiscal year 2009 from $253.8 million in fiscal year 2008 and represented 10.5% of revenue (2008: 10.1%). This reduction was the combination of cost reduction initiatives launched in early 2009, continuous monitoring of the cost base and favourable foreign exchange rate movements. |
|
|||||||||||||||
|
Share of net income of associates and joint ventures |
|
|||||||||||||||
| The Group’s share of net income of associates and joint ventures was as follows: | ||||||||||||||||
|
For the fiscal year (in $ millions) |
2010 | 2009 | 2008 | |||||||||||||
|
Dalia |
1.4 | 2.9 | 0.6 | |||||||||||||
|
Oceon |
0.4 | (0.9 | ) | (0.9 | ) | |||||||||||
|
Acergy/Subsea 7 (a) |
– | 0.6 | 3.5 | |||||||||||||
|
SapuraAcergy |
28.5 | 9.7 | (15.4 | ) | ||||||||||||
|
Seaway Heavy Lifting |
30.8 | 15.0 | 29.6 | |||||||||||||
|
NKT Flexibles |
13.7 | 21.7 | 45.6 | |||||||||||||
|
Total |
74.8 | 49.0 | 63.0 | |||||||||||||
|
(a) Represents historical project specific contractual joint activity in the North Sea. |
|
|||||||||||||||
|
The Group’s share of net income of associates and joint ventures in fiscal year 2010 increased 52.7% to $74.8 million compared to $49.0 million in fiscal year 2009. The results were primarily due to a higher contribution from SapuraAcergy of $28.5 million (2009: $9.7 million) due to the Gumusut and Iwaki Projects and a higher contribution from Seaway Heavy Lifting of $30.8 million (2009: $15.0 million) as a result of the Greater Gabbard Project completing during the year. This was partially offset by a lower positive contribution from NKT Flexibles of $13.7 million (2009: $21.7 million) largely due to continuing challenging conditions in the flexible pipelay market.
|
|
|
|
|
||||||||||||
| The Group’s share of net income of associates and joint ventures in fiscal year 2009 decreased 22.2% to $49.0 million compared to $63.0 million in fiscal year 2008. The results were primarily due to a reduced NKT Flexibles contribution of $21.7 million (2008: $45.6 million), that reflected challenging conditions in the flexible pipelay market, and a lower contribution from Seaway Heavy Lifting, which contributed $15.0 million (2008: $29.6 million) due to a particularly strong performance in fiscal year 2008. This was partially offset by a positive contribution from SapuraAcergy of $9.7 million (2008: loss of $15.4 million) largely due to improvements in Kikeh and MHS Project performance and Sapura 3000 being available for the full fiscal year. | ||||||||||||||||
|
Net operating income from continuing operations |
|
|||||||||||||||
| Net operating income increased by $93.4 million to $436.1 million in fiscal year 2010 (2009: $342.7 million), representing an increase of 27.3% from fiscal year 2009. This strong performance is a result of increased revenue combined with the increase in the gross margin percentage. The share of net income of associates and joint ventures also increased 52.7% to $74.8 million (2009: $49.0 million) as a result of the contributions from SapuraAcergy and Seaway Heavy Lifting. | ||||||||||||||||
|
Net operating income decreased by $118.1 million to $342.7 million in fiscal year 2009 (2008: $460.8 million). This represented a reduction of 25.6% from fiscal year 2008 reflecting the overall decline in market activity observed in fiscal year 2009, which was evidenced by a reduction in gross profit margin and a $14.0 million decrease in the share of net income of associates and joint ventures. |
|
|||||||||||||||
|
Investment income |
|
|||||||||||||||
| In fiscal year 2010, investment income increased to $9.8 million compared to $6.4 million in fiscal year 2009, mainly as a result of an increase in global interest rates on overnight balances. This was a reversal in the trend that was experienced in fiscal year 2009, during which investment income decreased to $6.4 million from $17.9 million in fiscal year 2008. | ||||||||||||||||
|
Other gains and losses |
|
|||||||||||||||
| Other gains and losses was a loss of $18.0 million in fiscal year 2010, compared to gains of $43.6 million and $44.1 million in fiscal years 2009 and 2008 respectively. Other gains and losses are composed of the effects of movements in foreign currency exchange and disposals of property, plant and equipment. In fiscal year 2010 gains of $0.2 million were recorded on the disposal of property, plant and equipment (2009: $0.4 million, 2008: $5.4 million). | ||||||||||||||||
|
seabed-to-surface
|
|
61
|
Financial Review and Statements
Financial Review continued
Net foreign currency exchange gains or losses
During fiscal year 2010 the Group recorded a foreign currency exchange loss of $18.2 million. The largest elements of this loss related to losses of $10.0 million on short-term inter-company balances and losses of $8.5 million arising on the fair value of derivatives where hedge accounting was not applied. The overall foreign currency exchange loss of $18.2 million was primarily caused by the strengthening of the US Dollar compared to all other major currencies.
In fiscal year 2009 the Group recorded foreign currency exchange gains of $43.2 million. The largest elements of this gain related to gains of $52.7 million arising on the revaluation of cash balances and unrealised hedging gains of $20.2 million, partially offset by foreign currency exchange losses of $30.4 million arising on the revaluation of short-term inter-company balances between subsidiary entities.
In fiscal year 2008 the Group recorded foreign exchange gains of $39.0 million. The largest element of this gain related to the revaluation of short-term inter-company balances in subsidiary entities and the strengthening of the US Dollar compared to other currencies, primarily the Euro.
Details relating to the effect of exchange rate, related risks and hedging positions are presented in Note 34 ‘Financial instruments’ to the Consolidated Financial Statements.
Finance costs
Finance costs in fiscal year 2010 were comparable to fiscal year 2009, totalling $28.7 million in comparison to $31.4 million for fiscal year 2009, relating mainly to fixed interest on convertible loan notes, and interest on borrowings. The charge for the fiscal year 2010 was partially offset by $13.7 million capitalised interest on property, plant and equipment under construction.
Finance costs in fiscal year 2009 increased to $31.4 million compared to $30.5 million in fiscal year 2008, relating mainly to interest on convertible loan notes.
Income before taxes
In fiscal year 2010 income before taxes increased to $399.2 million (2009: $361.3 million and 2008: $492.3 million). Strong operational performance and a significant increase in the share of net income of associates and joint ventures were partially offset by increased administration expenses (2010: $306.7 million, 2009: $231.3 million, 2008: $253.8 million) and foreign currency exchange losses of $18.2 million (2009: gain of $43.2 million, 2008: gain of $39.0 million).
Taxation
The Group recorded a net tax charge of $130.8 million on continuing operations in fiscal year 2010 as compared to $102.8 million in fiscal year 2009 (2008: $162.6 million). The effective tax rate on continuing operations for fiscal year 2010 was 32.8%, compared to an effective tax rate of 28.5% for fiscal year 2009 (2008: 33.0%).
The movements in the tax provision or benefit year-on-year generally are a product of the differing levels of profitability achieved in each of the many territories in which business is conducted. The significant components of the tax provision are referred to in the following paragraphs.
As discussed more fully in Note 11 ‘Taxation’ to the Consolidated Financial Statements, the Group reassessed its estimates of the probable liabilities resulting from ongoing tax audits and uncertain tax positions. The French tax audit closed in the year resolving all open cases through fiscal year 2006. In fiscal year 2009 the Group released provisions totalling $10.2 million. In 2008, a provision of $4.1 million was made for risks arising out of tax audits and enquiries in the UK. It is possible that the ultimate resolution of ongoing tax inquiries and audits and uncertain tax positions could result in tax charges that are materially higher or lower than the amounts accrued or provided for.
The Group recognised net deferred tax liabilities totalling $21.3 million in fiscal 2010 (2009: a deferred tax liability of $30.6 million, 2008: a deferred tax liability of $16.3 million) for the tax effects of temporary differences related to property, plant and equipment, accrued expenses, share-based payments, convertible loan notes and tax losses. An analysis of these balances is shown in Note 11 ‘Taxation’ to the Consolidated Financial Statements.
The Group’s UK vessel operating subsidiaries continue to be taxed within the UK tonnage tax regime. The profits of these vessels operating as tonnage subsidiaries are adjusted by reference to a formula linked to the tonnage of the vessels before being taxed at the UK statutory tax rate. The tax charge reflected a net benefit of $7.0 million in fiscal year 2010 compared to $6.0 million in fiscal year 2009 (2008: $7.5 million). This is compared to the UK tax that would be payable had the Group not elected to join the UK tonnage tax regime.
The tax rate in fiscal year 2010 benefited from a net release of provisions and prior year adjustments totalling $1.4 million (2009: $6.0 million, 2008: $7.5 million).
The Group has potential future tax deductions, tax credits and Net Operating Losses (‘NOLs’) in several countries, including the US. With the exception of some of the losses in Norway and the UK, no deferred tax asset has been recognised in respect of the future benefit of NOL’s because the Group determined, based on current estimates of future taxable earnings and due to an uncertainty over future profits and a history of losses in the jurisdictions concerned, that it is unlikely that tax deductions will be realised. Across its subsidiaries, the Group has NOLs and similar deductions of $128.4 million (2009: $148.0 million, 2008: $194.6 million), a substantial proportion of which are in the US. It should be noted that following completion of the Combination with Subsea 7 Inc. it is considered likely that this will be a change of control event restricting the Group’s ability to utilise the NOLs in the US.
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62 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
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As at November 30, 2010, the Company was a tax exempt 1929 Luxembourg Holding Company. The Luxembourg tax law which provided for a special tax regime for 1929 Holding Companies expired on December 31, 2010. As of January 1, 2011, the 1929 regime ceased to exist and Subsea 7 S.A. became an ordinary taxable Luxembourg company. The Group is in the process of restructuring its affairs to mitigate any potential adverse effects as a result of being subject to Luxembourg’s ordinary tax regime. However, when finalised, the measures actually implemented by the Group may not be sufficient to eliminate all potential adverse effects of the new tax regime, in which case the Group’s tax liabilities may increase by amounts that currently cannot be estimated.
Income from continuing operations Income from continuing operations increased 3.8% to $268.4 million for fiscal year 2010 compared to $258.5 million for fiscal year 2009. The increase in income was a combination of strong operational performance and a significant increase in the share of net income of associates and joint ventures, offset by increased administration expenses and losses on foreign currency exchange and an increased effective tax rate of 32.8%, up from 28.5% in fiscal year 2009.
Income from continuing operations decreased 21.6% to $258.5 million for fiscal year 2009 compared to $329.7 million for fiscal year 2008. The decrease in income was a combination of lower operating activity levels during the year and reduced investment income, partially offset by a reduction in the effective tax rate from 33.0% to 28.5%, where the Group benefited from a tax audit provision reversal reducing the overall tax charge.
Discontinued operations In November 2008 the decision was taken to dispose of the non-core Trunkline business (which included Acergy Piper , a vessel specifically configured for Trunkline operations) and the results of this business segment were classified as discontinued operations. The sale of Acergy Piper to Saipem (Portugal) Comercio Maritimo S.U. Lda was completed on January 9, 2009 for a sales consideration of $78.0 million. The Group continued to generate revenue through the Trunkline business during fiscal years 2009 and 2010 due to project completion work on the Mexilhao Project.
Discontinued operations for fiscal year 2010 generated $83.4 million of revenue, arising from the Mexilhao Project in Brazil. Operating expenses attributable to discontinued operations during fiscal year 2010 amounted to $23.9 million. A net income of $44.6 million was recorded from discontinued operations for fiscal year 2010 after taking into consideration taxation on discontinued operations amounting to $14.9 million.
Discontinued operations for fiscal year 2009 generated $114.8 million of revenue, arising from the Mexilhao Project in Brazil. Operating expenses attributable to discontinued operations during fiscal year 2009 amounted to $99.9 million. A net income of $7.2 million was recorded from discontinued operations for fiscal year 2009 after taking into consideration the impairment charge on Acergy Piper generators and generating sets of $1.0 million and taxation on discontinued operations amounting to $6.7 million.
Discontinued operations for fiscal year 2008 generated $281.8 million of revenue which included $275.9 million primarily related to the Mexilhao Project in Brazil. Operating expenses attributable to discontinued operations during fiscal year 2008 amounted to $320.7 million. A net loss of $22.5 million was incurred from discontinued operations for fiscal year 2008. These results included a $14.3 million reversal of a previous impairment change related to Acergy Piper and a $2.1 million taxation credit on discontinued operations.
Net income In fiscal year 2010 net income for total operations was $313.0 million (2009: $265.7 million, 2008: $307.2 million). Net income attributable to equity shareholders of the parent was $265.4 million (2009: $245.0 million, 2008: $301.4 million), with the balance attributable to non-controlling interests of $47.6 million (2009: $20.7 million, 2008: $5.8 million).
Investment and capital expenditure In fiscal year 2010 additions to property, plant and equipment for continuing operations were $592.8 million (2009: $131.6 million, 2008: $326.6 million). There was no capital expenditure for discontinued operations in fiscal year 2010 (2009: $nil, 2008: $1.4 million).
In December 2009 the Group acquired Borealis , a state-of-the-art deepwater pipelay vessel, which is expected to drive superior returns from future activity. This differentiating asset, currently being built at the Sembawang Shipyard in Singapore, is a DP3 dynamic positioning vessel equipped with a 5,000 tonne crane. The Group plans to install a 1,000 tonne J-Lay tower, which is currently owned, and state-of-the-art 600 tonne S-Lay equipment for worldwide deepwater and harsh environment operations. Final completion and operational delivery of the vessel is scheduled for the first half of fiscal year 2012.
In the third quarter of fiscal year 2010, Acergy S.A. (now Subsea 7 S.A.) acquired Antares , a new shallow water barge for the conventional market for pipelay and hook-up projects in West Africa, and Polar Queen , a flexible pipelay and subsea construction vessel which joined the fleet in 2006 on long-term charter. In the fourth quarter of fiscal year 2010, Acergy S.A. (now Subsea 7 S.A.) acquired Pertinacia , a flexible pipelay vessel, which joined the fleet in 2007 on long-term charter.
All acquisitions have been funded from existing cash reserves.
In the first half of 2011, the Group is expecting to take delivery of Havila (a dive support vessel) and the joint venture, Seaway Heavy Lifting, is expected to take delivery of Oleg Strashnov (a heavy lift vessel). |
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Financial Review and Statements
Financial Review continued
The table below sets out the principal additions of property, plant and equipment in the last three fiscal years.
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||
|
Construction support vessels |
472.6 | 53.2 | 180.1 | |||||||||
|
Operating equipment |
115.0 | 60.6 | 123.4 | |||||||||
|
Land and buildings |
0.4 | 13.1 | 6.6 | |||||||||
|
Other assets |
4.8 | 4.7 | 16.5 | |||||||||
|
Total |
592.8 | 131.6 | 326.6 | |||||||||
The four largest capital expenditure projects during fiscal year 2010 were:
| Assets | Description of capital expenditure project | (in $ millions) | ||||
|
Borealis |
Purchase of vessel and improvements | 295.9 | ||||
|
Antares, Pertinacia and Polar Queen |
Purchase of vessels and conversions | 172.9 | ||||
|
Acergy Condor and Acergy Harrier |
Dry-dock | 31.6 | ||||
|
Acergy Falcon (a) |
Dry-dock | 11.5 | ||||
(a) Excluding insurance proceeds.
The four largest capital expenditure projects during fiscal year 2009 were:
| Assets | Description of capital expenditure project | (in $ millions) | ||||
|
Sonamet construction (a) |
Upgraded facilities | 37.1 | ||||
|
Acergy Polaris |
Improvements to J-Lay tower | 13.4 | ||||
|
Skandi Acergy |
Vessel conversion | 12.4 | ||||
|
Acergy Legend |
Class dry-dock | 9.5 | ||||
(a) Classified as an asset held for sale at year end.
The four largest capital expenditure projects during fiscal year 2008 were:
| Assets | Description of capital expenditure project | (in $ millions) | ||||
|
Acergy Polaris |
30 year class dry-dock (a) | 74.5 | ||||
|
Skandi Acergy |
Vessel conversion | 34.5 | ||||
|
Acergy Petrel |
Purchase of vessel | 31.7 | ||||
|
Toisa Proteus |
Flexible lay system | 27.9 | ||||
| (a) | This includes capital expenditure on Acergy Polaris for its 30 year class dry-dock carried out between May 2008 and January 2009 and the additional installation of the Deep Water Stinger. |
Capital expenditure planned for fiscal year 2011
Planned capital expenditure on property, plant and equipment for fiscal year 2011 is estimated to be approximately $550 million. The majority of the expenditure will be the continued development of Borealis and Antares , as well as continuing to further upgrade and rejuvenate the fleet which operates across the various segments. The 2011 capital expenditure is expected to be financed from existing cash resources.
Divestitures
As at fiscal year end 2010, net assets held for sale and the related business segments were:
| As at November 30 (in $ millions) | 2010 | 2009 | 2008 | |||||||||
|
Acergy AME (a) |
– | 1.1 | 1.1 | |||||||||
|
Acergy NEC (b) |
1.0 | 1.0 | 74.4 | |||||||||
|
Acergy NAMEX |
– | 0.1 | – | |||||||||
|
Acergy AFMED (c) |
120.0 | 86.5 | – | |||||||||
|
Total |
121.0 | 88.7 | 75.5 | |||||||||
| (a) | This relates to the land, buildings and office equipment in Balikpapan, Indonesia in Acergy AME sold in October 2010. |
| (b) | This relates to the disposal of the Trunkline business in 2008 including Acergy Piper , a semi-submersible pipelay barge which was sold on January 9, 2009. The 2010 value represents equipment purchased for Acergy Piper that is expected to be sold in 2011. |
| (c) | This relates to assets and liabilities of Sonamet that has been classified as an asset held for sale as a result of the expected sale of 19% of the Group’s interest in 2011. See Note 21 ‘Assets classified as held for sale’ to the Consolidated Financial Statements. |
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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Business segments’ results During fiscal year 2010, the Group’s operations were managed through five geographical segments that were combined into ‘Territory 1’ and ‘Territory 2’ in order to improve the Group’s commercial focus and the co-ordination and utilisation of worldwide resources. Following the combination with Subsea 7 Inc. these have changed, see Note 40 ‘Post Balance Sheet Events’ to the Consolidated Financial Statements.
‘Territory 1’ comprised Acergy Northern Europe and Canada, and Acergy Asia and Middle East.
‘Territory 2’ comprised Acergy Africa and Mediterranean, Acergy North America and Mexico and Acergy South America.
‘Corporate’ managed activities that served more than one segment.
The chief operating decision maker during fiscal year 2010 was the Chief Executive Officer of Acergy S.A. (now Subsea 7 S.A.). He was assisted by the Chief Operating Officer, who was supported by the Senior Vice President of each ‘Territory’. Each region within the ‘Territories’ was managed by a Vice President who was responsible for all aspects of the projects within the relevant segment, from initial tender to completion. Each segment was accountable for income and losses for such projects. One segment may provide support to other segments; an example is the Mexilhao Project where Acergy NEC provided project management support to Acergy SAM.
Territory 1 Acergy Northern Europe and Canada (‘NEC’) This segment included activities in Northern Europe and Eastern Canada. Its offices were based in Aberdeen, Scotland, UK; Stavanger, Norway; Moscow, Russia; and St John’s, Canada.
|
|
|
|
|||||||||||||||||||||||
| For the fiscal year |
2010 (in $ millions) |
% |
2009 (in $ millions) |
% |
2008 (in $ millions) |
% | ||||||||||||||||||||
|
Revenue |
568.1 | 24.0 | (a) | 648.8 | 29.4 | (a) | 843.1 | 33.4 (a) | ||||||||||||||||||
|
Operating expenses |
(432.2 | ) | 24.8 | (b) | (519.7 | ) | 30.9 | (b) | (574.5 | ) | 30.7 (b) | |||||||||||||||
|
Net operating income |
83.6 | 67.4 | 192.0 | |||||||||||||||||||||||
|
(a) Segment revenue as a percentage of total revenue from continuing operations.
(b) Segment operating expenses as a percentage of total operating expenses from continuing operations.
Investment In fiscal year 2007 the Group entered into an agreement with Havila Shipping ASA for a new build diving support vessel for Acergy NEC which is expected to join the fleet in the first half of 2011. The vessel, Havila , will be a state-of-the-art diving support vessel and is specifically designed for efficient diving operations in the harshest environments. Havila will be owned by Acergy Havila Limited, a subsidiary in which the Group has a 50% ownership, and will be operated by the Group for a period of ten years.
Revenue Acergy NEC’s revenue from continuing operations for fiscal year 2010 was $568.1 million representing 24.0% of total revenue from continuing operations, a decrease of $80.7 million compared to $648.8 million in fiscal year 2009. The decrease reflected lower activity levels in an ongoing challenging market environment as well as lower vessel utilisation and fewer projects in installation phase, partly offset by good operational progress on a number of projects including BP Skarv, Deep Panuke, DSVi frame agreement, DONG Siri and Trym, and the successful resolution of ongoing commercial negotiations on the Marathon Volund Project. This illustrates the continuation of the trend observed in both fiscal years 2009 and 2008 where new project awards had smaller value in comparison to previous years. This resulted in a decline of SURF activity to $373.8 million in fiscal year 2010 compared to $506.7 million in fiscal year 2009, while IMR and Survey activities increased with revenues of $194.3 million compared to $142.1million in fiscal year 2009 following the award of the TAQA and DSVi frame agreements.
Acergy NEC’s revenue from continuing operations for fiscal year 2009 was $648.8 million representing 29.4% of total revenue from continuing operations, a decrease of $194.3 million compared to $843.1 million in fiscal year 2008. The decrease reflected lower activity levels, and lower vessel utilisation in the highly competitive North Sea market. All business areas were affected by the economic downturn; SURF activity revenues declined to $506.7 million in fiscal year 2009 compared to $647.0 million in fiscal year 2008; IMR and Survey activities also declined with revenues of $142.1 million in fiscal year 2009 compared to $196.1 million in fiscal year 2008. The market conditions and reduced investment in the segment also resulted in new project awards of smaller value in comparison to the main revenue generating projects which reached maturity in 2008.
Operating expenses Acergy NEC’s operating expenses for fiscal year 2010 were $423.2 million representing 24.8% of total operating expenses from continuing operations, a decrease of $96.5 million compared to $519.7 million in fiscal year 2009, mainly a result of the lower activity levels explained in the revenue section. Operating expenses were 74.5% of the segment’s revenue compared to 80.1% in fiscal year 2009. The decrease is mainly due to the high level of operating expenses on the Marathon Volund Project in the previous fiscal year when the project reflected a loss. The project completed during fiscal year 2009 but the settlements on claims and variation orders were not reached until fiscal year 2010, at which point such revenues could be recognised. Excluding the impact of the Marathon Volund Project for both fiscal years 2009 and 2010, total operating expenses increased slightly in fiscal year 2010 due to the newly awarded Taurt & Ha’Py Project following various vessel reschedulings. |
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Financial Review and Statements
Financial Review continued
Acergy NEC’s operating expenses for fiscal year 2009 were $519.7 million representing 30.9% of total operating expenses from continuing operations, a decrease of $54.8 million compared to $574.5 million in fiscal year 2008. Operating expenses were 80.1% of the segment’s revenue compared to 68.1% in fiscal year 2008. Operating expenses for fiscal year 2008 included a credit of $30.0 million related to the settlement of a Norwegian defined benefit pension scheme. Excluding the settlement, operating expenses represented 80.1% of the segment’s revenue in fiscal year 2009 compared to 71.7% in 2008. The increase predominantly reflected the additional operating expenses on the Marathon Volund Project which completed during fiscal year 2009.
Net operating income
Acergy NEC’s net operating income for fiscal year 2010 was $83.6 million, an increase of $16.2 million compared to $67.4 million in fiscal year 2009. The increase in fiscal year 2010 is primarily due to good overall project performance. Fiscal year 2010 reflected the successful resolution of ongoing commercial negotiations on the Marathon Volund Project and the recognition of the related revenues. In fiscal year 2009 the net operating income was adversely impacted by increased operating expenses on the Marathon Volund Project since related revenues could not be recognised while in negotiation.
Acergy NEC’s net operating income for fiscal year 2009 was $67.4 million, a decrease of $124.6 million compared to $192.0 million in fiscal year 2008. The decrease in fiscal year 2009 is primarily due to a reduction in gross profit of $139.5 million due to lower project activity levels and an increase in operating expenses on the Marathon Volund Project which completed during the fiscal year 2009 but for which revenue could not be recognised during fiscal year 2009 while subject to ongoing commercial negotiations. This decrease was partially offset by a reduction in administrative expenses of $17.9 million following cost reduction measures taken during the year.
The following table sets forth the most significant recent or ongoing projects in the Acergy NEC segment:
|
Project name |
Description | |
|
Lump sum SURF projects: |
||
|
Asgard Gas Transfer |
Project offshore Norway, expected to be executed during 2011 for Statoil. | |
|
Deep Panuke |
Project offshore Canada, expected to be executed during 2008 to 2011 for Encana Corporation. | |
|
Gjoa Umbilical Riser |
Project offshore Norway, executed during 2008 to 2010 for Statoil. | |
|
Medway Development |
Project offshore Netherlands, expected to be executed during 2010 and 2011 for Dana | |
| Petroleum Netherlands. | ||
|
Njord Gas Export |
Project offshore Norway, executed during 2005 to 2008 for Statoil. | |
|
Nini East Development |
Project offshore Denmark, executed during 2008 to 2010 for DONG Energy. | |
|
Ormen Lange |
Project offshore Norway, executed during 2008 to 2009 for Statoil. | |
|
Talisman Scapa |
Project offshore United Kingdom, executed during 2009 for Talisman. | |
| Project offshore Egypt, expected to be executed during 2010 to 2011 for Pharaonic | ||
|
Taurt & Ha’Py |
Petroleum Company. | |
|
Trym Field Development |
Project offshore Norway, executed during 2009 to 2010 for DONG Energy. | |
|
Tyrihans Subsea |
Project offshore Norway, executed during 2006 to 2008 for Statoil. | |
|
SAGE Hot Tap |
Project offshore United Kingdom, executed during 2007 to 2008 for ExxonMobil. | |
|
Skarv |
Project offshore Norway, expected to be executed during 2009 to 2011 for BP. | |
|
Marathon Volund |
Project offshore Norway, executed during 2007 to 2009 for Marathon Petroleum. | |
|
Day rate IMR projects: |
||
|
DSVi Frame Agreement |
Project offshore North Sea, expected to be executed during the period 2010 to 2013 for the DSVi Collective of companies. | |
|
Hydro Frame Agreement |
Project offshore Norway, executed during the period 1999 to 2010 for Statoil. | |
|
SURF/IMR/Survey projects: |
||
|
BP IMR UK |
Project offshore United Kingdom, expected to be executed during 2008 to 2012 for BP. | |
|
CNR Frame Agreement |
Project offshore United Kingdom, executed during 2006 to 2010 for CNR. | |
|
DONG Energy Frame Agreement |
Project offshore North Sea, expected to be executed during 2008 to 2012 for DONG Energy. | |
|
TAQA Frame Agreement |
Project offshore United Kingdom, expected to be executed during 2009 to 2012 for TAQA. | |
|
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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|
Acergy Asia and Middle East (‘AME’) This segment included activities in Asia Pacific, India, and Middle East and included the Malaysian joint venture, SapuraAcergy, with SapuraCrest Petroleum Berhad. It had its offices in Singapore, Beijing, China and Perth, Australia.
|
|
|
|
|||||||||||||||||||||||
| For the fiscal year |
2010 (in $ millions) |
% |
2009 (in $ millions) |
% |
2008 (in $ millions) |
% | ||||||||||||||||||||
|
Revenue |
179.8 | 7.6 | (a) | 206.0 | 9.3 | (a) | 180.8 | 7.2 (a) | ||||||||||||||||||
|
Operating expenses |
(99.1 | ) | 5.8 | (b) | (156.9 | ) | 9.3 | (b) | (129.0 | ) | 6.9 (b) | |||||||||||||||
|
Net operating income |
83.5 | 37.8 | 14.4 | |||||||||||||||||||||||
|
(a) Segment revenue as a percentage of total revenue from continuing operations.
(b) Segment operating expenses as a percentage of total operating expenses from continuing operations.
Investment The Toisa Proteus three year charter from the Toisa/Sealion Group of companies finished during the third quarter of fiscal year 2010. The vessel completed its demobilisation and restoration programme, including the removal of the flexible lay spread. Sapura 3000 , a new build vessel within the SapuraAcergy joint venture, was delivered in fiscal year 2008.
Revenue Acergy AME’s revenue from continuing operations for fiscal year 2010 was $179.8 million representing 7.6% of the total revenue from continuing operations, a decrease of $26.2 million compared to $206.0 million in fiscal year 2009. Despite successful completion of offshore operations on the Pluto and Pyrenees Projects, the reduction reflects lower activity levels related to the delay in expected SURF project awards during fiscal year 2010.
Acergy AME’s revenue from continuing operations for fiscal year 2009 was $206.0 million representing 9.3% of the total revenue from continuing operations, an increase of $25.2 million compared to $180.8 million in fiscal year 2008. The increase reflected the segment’s strategy to focus its resources on the SURF market and progress of the segment’s portfolio of SURF projects to more advanced stages of execution. Projects which made good progress during fiscal year 2009 included Van Gogh, Pyrenees and Al Shaheen and the Pluto Project, which remained in early stages.
Operating expenses Acergy AME’s operating expenses for fiscal year 2010 were $99.1 million. This represented 5.8% of total operating expenses from continuing operations, a decrease of $57.8 million compared to $156.9 million in fiscal year 2009 reflecting lower ongoing activity in the current year. Operating expenses were 55.1% of the segment’s revenue compared to 76.2% in fiscal year 2009, a decrease of 21.1% primarily due to the efficient execution of offshore operations of the Pluto Project in fiscal year 2010.
Acergy AME’s operating expenses for fiscal year 2009 were $156.9 million. This represented 9.3% of total operating expenses from continuing operations, an increase of $27.9 million compared to $129.0 million in fiscal year 2008. Operating expenses were 76.2% of the segment’s revenue compared to 71.3% in fiscal year 2008. The increase was primarily due to the increase in SURF project activity.
Net operating income Acergy AME’s net operating income for fiscal year 2010 was $83.5 million, compared to $37.8 million in fiscal year 2009, an increase of $45.7 million. This increase was primarily due to a significant contribution from the Pluto and Pyrenees Projects reflecting the successful completion of offshore operations, and the equity accounted profits from the SapuraAcergy joint venture which contributed $28.5 million in fiscal year 2010 compared to $9.7 million in fiscal year 2009. The increased contribution from SapuraAcergy was due to the Iwaki, Devil Creek Development and Gumusut Projects’ performance as well as good utilisation on Sapura 3000 .
Acergy AME’s net operating income for fiscal year 2009 was $37.8 million, compared to $14.4 million in fiscal year 2008, an increase of $23.4 million. This increase was primarily due to a significant contribution from the Van Gogh and Bluewater Al Sheehan Projects and the SapuraAcergy joint venture which contributed a $9.7 million profit in fiscal year 2009 compared with a loss of $15.4 million in fiscal year 2008. The turnaround of the joint venture’s result was due to improvements in the Kikeh and MHS Projects’ performance and Sapura 3000 being available for the full year allowing greater utilisation. |
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67
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Financial Review and Statements
Financial Review continued
The following table sets forth the most significant recent and ongoing projects in the Acergy AME segment:
| Project name | Description | |
|
Lump sum SURF projects: |
||
|
Al-Shaheen Block 5 SPM2 |
Project offshore Qatar, expected to be executed in 2011 for Bluewater. | |
|
Replacement |
||
|
Bluewater Al-Shaheen |
Project offshore Qatar, executed during 2009 for Bluewater. | |
|
Dai Hung |
Project offshore Vietnam, executed during 2005 to 2008 for Petrovietnam Exploration and Production Company. | |
|
Devil Creek Development Project |
A SapuraAcergy project offshore Australia, expected to be executed during 2009 to 2011 for Apache Energy utilising Sapura 3000. | |
|
Gumusut |
A SapuraAcergy project offshore Malaysia, expected to be executed during 2009 to 2012 for Sabah Shell Petroleum Co utilising Sapura 3000 . | |
|
Iwaki |
A SapuraAcergy project offshore Japan, executed during 2009 to 2010 for Nippon Steel Engineering Co. Ltd. | |
|
Kerisi |
Project offshore Indonesia, executed during 2006 to 2007 for ConocoPhillips. | |
|
Kikeh |
A SapuraAcergy project offshore Malaysia, executed during 2007 to 2009 for Murphy Sabah Oil Co utilising Sapura 3000. | |
|
Maari |
Project offshore New Zealand, executed during 2006 to 2008 for Tablelands Development. | |
|
Liu Hua |
Project offshore China, executed during 2007 to 2008 for CNOOC. | |
|
Pluto |
Project offshore Australia, executed during 2008 to 2010 for Woodside. | |
|
Pyrenees |
Project offshore Australia, executed during 2009 to 2010 for BHP Billiton. | |
|
Van Gogh |
Project offshore Australia, executed during 2007 to 2009 for Apache Energy. | |
|
Vincent Development |
Project offshore Australia, executed during 2006 to 2008 for Woodside. |
Territory 2
Acergy Africa and Mediterranean (‘AFMED’)
This segment comprised activities within the Africa and Mediterranean region and has its office in Suresnes, France. It operated fabrication yards in Nigeria, Angola and Gabon and also manages project specific joint ventures such as the Nigerian joint venture, Oceon.
| For the fiscal year |
2010 (in $ millions) |
% |
2009 (in $ millions) |
% |
2008 (in $ millions) |
% | ||||||||||||||||||
|
Revenue |
1,361.4 | 57.5 | (a) | 999.7 | 45.3 | (a) | 1,175.9 | 46.6 | (a) | |||||||||||||||
|
Operating expenses |
(954.1 | ) | 56.1 | (b) | (746.5 | ) | 44.3 | (b) | (897.1 | ) | 47.9 | (b) | ||||||||||||
|
Net operating income |
307.7 | 171.3 | 183.7 | |||||||||||||||||||||
(a) Segment revenue as a percentage of total revenue from continuing operations.
(b) Segment operating expenses as a percentage of total operating expenses from continuing operations.
Investment
During fiscal year 2010 the Group purchased Antares , a new shallow water barge for the Conventional market for pipelay and hook-up projects in shallow water. The vessel was mobilised for its first hook-up project in the fourth quarter of fiscal year 2010, with the completion of the S-Lay system expected to be during the first half of 2011.
Revenue
Acergy AFMED’s revenue from continuing operations for fiscal year 2010 was $1,361.4 million representing 57.5% of total revenue from continuing operations, an increase of $361.7 million compared to $999.7 million in fiscal year 2009. The increase is primarily due to higher Conventional activity, which offset a decrease in SURF revenue. The Conventional activity was mainly represented by projects such as Angola LNG, EPC4A and Block 17 progressing well during the year and contributing $469.7 million to the revenue, an increase of $317.0 million compared to $152.7 million in fiscal year 2009. The decrease in SURF revenue during fiscal year 2010 reflected lower SURF activity levels caused by the delay in new awards, similar to the previous year. Two major SURF projects, PazFlor, which achieved good progress and commenced offshore operations and Block 15, which was completed during fiscal year 2010, were significant contributors to revenue in fiscal years 2010 and 2009.
Acergy AFMED’s revenue from continuing operations for fiscal year 2009 was $999.7 million representing 45.3% of total revenue from continuing operations, a decrease of $176.2 million compared to $1,175.9 million in fiscal year 2008. The decrease primarily reflected the result of lower activity levels in both SURF and Conventional markets caused by delays in new project awards, as a result of the general economic downturn. As anticipated this was reflected in a lower utilisation of all the segment’s vessels, with the exception of Acergy Polaris . Major SURF projects, including Block 15 and PazFlor, progressed well and contributed revenue of $617.2 million compared to $735.8 million in 2008 and Conventional projects, including EPC4A and Angola LNG, contributed revenue of $382.5 million compared to $440.1 million in fiscal year 2008.
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Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Operating expenses Acergy AFMED’s operating expenses in fiscal year 2010 were $954.1 million compared to $746.5 million in fiscal year 2009, representing 56.1% of total operating expenses from continuing operations, an increase of $207.6 million. The increase was primarily due to higher activity levels in Conventional projects. Operating expenses represented 70.0% of revenue compared to 74.7% in fiscal year 2009. The percentage decrease was due to strong profit margins on Conventional projects and good profitability on SURF projects completing in fiscal year 2010 combined with a strong contribution from the Sonamet subsidiary.
Acergy AFMED’s operating expenses in fiscal year 2009 were $746.5 million compared to $897.1 million in fiscal year 2008, representing 44.3% of the total operating expenses from continuing operations, a decrease of $150.6 million. The decrease was primarily due to lower activity levels. Operating expenses represented 74.7% of revenue compared to 76.3% in fiscal year 2008, reflecting operational efficiencies during fiscal year 2009, partially offset by maintenance and repair costs incurred on Acergy Polaris related to its extensive planned dry-dock, which completed during the first quarter of fiscal year 2009.
Net operating income Acergy AFMED’s net operating income in fiscal year 2010 was $307.7 million, an increase of $136.4 million compared to $171.3 million in fiscal year 2009. The increase in net operating income was primarily due to a higher gross profit performance reflecting the increased activity levels in Conventional projects, as well as the higher profitability of SURF projects completing in fiscal year 2010. The increase in net operating income was also due to a strong positive contribution from Sonamet.
Acergy AFMED’s net operating income in fiscal year 2009 was $171.3 million, a decrease of $12.4 million compared to $183.7 million in fiscal year 2008. The reduction in net operating income was primarily due to a lower gross profit performance reflecting the reduced activity levels in Acergy AFMED partially due to the extensive dry-dock on Acergy Polaris . This decrease was partially offset by a positive contribution from Sonamet and a reduction in administrative expenses.
The following table sets forth the most significant recent or ongoing projects in the Acergy AFMED segment:
|
||||
| Project name | Description | |||
|
Lump sum Conventional projects: |
||||
| Angola LNG | Project offshore Angola, expected to be executed during 2008 to 2011 for Angola LNG. | |||
| Block 17/18 | Project offshore Angola, expected to be executed during 2009 to 2011 for Total and BP. | |||
| EPC2B | Project offshore Nigeria, executed during 2005 to 2008 for ExxonMobil. | |||
| EPC4A | Project offshore Nigeria, executed during 2009 to 2010 for ExxonMobil. | |||
| EGP3B | Project offshore Nigeria, expected to be executed during 2010 to 2013 for Chevron. | |||
| Kizomba Satellites C2 | Project offshore Angola, expected to be executed during 2009 to 2012 for ExxonMobil. | |||
| OSO | Project offshore Nigeria, executed in 2007 for ExxonMobil. |
|
||
| OSO RE and Condensate Pipeline | Project offshore Nigeria, expected to be executed during 2010 to 2011 for ExxonMobil. | |||
| Sonamet Projects | Portfolio of shallow water and deepwater fabrication projects performed at the fabrication facility in Lobito, Angola on behalf of the Group and other external clients. | |||
|
Lump sum SURF projects: |
||||
| Agbami | Project offshore Nigeria, executed during 2005 to 2008 for Star Deepwater Petroleum. | |||
| Block 15 | Project offshore Angola, executed during 2008 to 2010 for ExxonMobil. | |||
| Cameron USAN Manifolds | Project offshore Nigeria, expected to be executed during 2008 to 2011 for Cameron. | |||
| CLOV | Project offshore Angola, expected to be executed during 2011 to 2014 for Total. | |||
| Greater Plutonio | Project offshore Angola, executed during 2004 to 2007 for BP. | |||
| Kizomba C Mondo | Project offshore Angola, executed during 2006 to 2008 for ExxonMobil. | |||
| Kizomba C Saxi Batuque | Project offshore Angola, executed during 2006 to 2008 for ExxonMobil. | |||
| Moho Bilondo | Project offshore Congo, executed during 2005 to 2010 for Total. | |||
| PazFlor | Project offshore Angola, expected to be executed during 2008 to 2011 for Total. | |||
| Tombua Landana | Project offshore Angola, executed during 2006 to 2009 for Chevron. | |||
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Financial Review and Statements
Financial Review continued
Acergy North America and Mexico (‘NAMEX’)
This segment included activities in the United States of America, Mexico, Central America and Western Canada. Its office was in Houston, Texas in the United States of America.
| For the fiscal year |
2010
(in $ millions) |
% |
2009
(in $ millions) |
% |
2008
(in $ millions) |
% | ||||||||||||||||||
|
Revenue |
34.6 | 1.4 | (a) | 57.8 | 2.6 | (a) | 4.4 | 0.2 | (a) | |||||||||||||||
|
Operating (expenses)/income |
(22.6 | ) (c) | 1.3 | (b) | (19.1 | ) (c) | 1.1 | (b) | 17.2 | (c) | (0.9 | ) (b) | ||||||||||||
|
Net operating income/(loss) |
(0.4 | ) | 26.0 | 10.5 | ||||||||||||||||||||
| (a) | Segment revenue as a percentage of total revenue from continuing operations. |
| (b) | Segment operating expenses as a percentage of total operating expenses from continuing operations. |
| (c) | The amount includes income from inter-segmental expenditure sharing arrangements. |
Revenue
Acergy NAMEX’s revenue from continuing operations for fiscal year 2010 was $34.6 million, a decrease of $23.2 million compared to $57.8 million in fiscal year 2009, due primarily to the MEGI Project being the only ongoing project executed in fiscal year 2010.
Acergy NAMEX’s revenue from continuing operations for fiscal year 2009 was $57.8 million, an increase of $53.4 million compared to $4.4 million in fiscal year 2008, due primarily to the successful execution and completion of the Perdido and Hess Conger Projects.
Operating (expenses)/income
Acergy NAMEX’s operating expenses in fiscal year 2010 were $22.6 million compared to $19.1 million in fiscal year 2009, an increase of $3.5 million. The increase in operating expenses is mainly due to the prior year being positively impacted by cost sharing with Acergy SAM for the Frade Project, which was completed in fiscal year 2009.
Acergy NAMEX’s operating expenses in fiscal year 2009 were $19.1 million compared to $17.2 million operating income in fiscal year 2008, an increase of $36.3 million, due primarily to expenses incurred for activity related to the Perdido and Hess Conger Projects and this segment’s ongoing support for the Frade Project in Acergy SAM which shared the related operating expenses.
Net operating income/(loss)
The segment’s net operating loss in fiscal year 2010 was $0.4 million, compared to net operating income of $26.0 million in fiscal year 2009. The net operating loss in fiscal year 2010 was due to less activity in Acergy NAMEX as the MEGI Project was the only project being executed, compared to fiscal year 2009 when the Perdido and Hess Conger Projects were executed and completed. The net operating loss also reflected the completion of the Frade Project in fiscal year 2009 which resulted in the end of the revenue and cost sharing with Acergy SAM.
The segment’s net operating income in fiscal year 2009 was $26.0 million, an increase of $15.5 million compared to $10.5 million in fiscal year 2008. The increase was primarily due to a gross profit improvement from the Perdido and Hess Conger Projects and income and expenses shared on an equal basis with Acergy SAM in relation to the Frade Project.
The table below sets out the most significant recent or ongoing projects in the Acergy NAMEX segment:
| Project name | Description | |
| Lump sum SURF projects: | ||
| Hess Conger | Project offshore the United States of America, executed during 2009 for Hess. | |
| MEGI | Project offshore Equatorial Guinea executed during 2010 for ExxonMobil. | |
| Perdido | Project offshore the United States of America, executed during 2008 to 2009 for Shell. |
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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|
Acergy South America (‘SAM’) This segment included activities in South America and the islands of the southern Atlantic Ocean and had its office in Rio de Janeiro, Brazil. Its principal operating location was Macae, Brazil.
|
|
|||||||||||||||||||||||||||
|
For the fiscal year |
2010
(in $ millions) |
% |
2009
(in $ millions) |
% |
2008
(in $ millions) |
% | ||||||||||||||||||||||
|
Revenue |
214.3 | 9.0 | (a) | 288.8 | 13.1 | (a) | 320.1 | 12.7 | (a) | |||||||||||||||||||
|
Operating expenses |
(177.2 | ) | 10.4 | (b) | (224.7 | ) | 13.3 | (b) | (268.9 | ) | 14.3 | (b) | ||||||||||||||||
|
Net operating income |
8.4 | 37.5 | 22.6 | |||||||||||||||||||||||||
|
(a) Segment revenue as a percentage of total revenue from continuing operations. (b) Segment operating expenses as a percentage of total operating expenses from continuing operations.
Investment In the third quarter of fiscal year 2010, the Group acquired Polar Queen , a flexible pipelay and subsea construction vessel which joined the fleet in 2006 on long-term charter; and in the fourth quarter of fiscal year 2010 acquired Pertinacia , a flexible pipelay vessel which joined the fleet in 2007 on long-term charter.
Revenue Acergy SAM’s revenue from continuing operations for fiscal year 2010 was $214.3 million representing 9.0% of total revenue from continuing operations, a decrease of $74.5 million compared to $288.8 million in fiscal year 2009. The decrease reflected an anticipated lower contribution from the segment’s SURF project portfolio, due to the completion in fiscal year 2009 of the Frade Project. Four vessels were on long-term service arrangements. Utilisation of Pertinacia and Polar Queen increased, while Acergy Condor and Acergy Harrier achieved lower utilisation as a result of planned dry-dock periods.
Acergy SAM’s revenue from continuing operations for fiscal year 2009 was $288.8 million representing 13.1% of total revenue from continuing operations, a decrease of $31.3 million compared to $320.1 million in fiscal year 2008. The decrease reflected an anticipated lower contribution from the segment’s lump-sum SURF project portfolio, due to the completion in the prior fiscal year of the PRA-1 Project, partially offset by the good contribution from the Frade and Roncador Manifolds Projects which completed during fiscal year 2009. The three vessels on long-term service arrangement, Acergy Condor , Acergy Harrier and Pertinacia , achieved full utilisation outside of dry-docks and generated similar levels of revenue in fiscal year 2009 compared to fiscal year 2008. During fiscal year 2009 Acergy SAM’s segment was awarded a fourth long-term service arrangement contract by Petrobras for Polar Queen for flexible laying services for a period of four years which commenced in fiscal year 2010. |
|
|||||||||||||||||||||||||||
|
Operating expenses Acergy SAM’s operating expenses for fiscal year 2010 were $177.2 million representing 10.4% of total operating expenses from continuing operations, a decrease of $47.5 million compared to $224.7 million in fiscal year 2009. The decrease was primarily due to the lower activity levels in SURF projects in fiscal year 2010.
Acergy SAM’s operating expenses for fiscal year 2009 were $224.7 million representing 13.3% of total operating expenses from continuing operations, a decrease of $44.2 million compared to $268.9 million in fiscal year 2008. The decrease was primarily due to the lower activity levels in the cross-regional SURF projects in fiscal year 2009.
Net operating income Acergy SAM’s net operating income in fiscal year 2010 was $8.4 million compared to $37.5 million in fiscal year 2009, a decrease of $29.1 million primarily due to lower activity level in SURF projects in fiscal year 2010. The 2010 activity mainly reflects the ongoing four long-term service contracts with Petrobras. In fiscal year 2009, activity relating to the Frade Project contributed additional income to the three long-term charter contracts.
Acergy SAM’s net operating income in fiscal year 2009 was $37.5 million compared to $22.6 million in fiscal year 2008, an increase of $14.9 million primarily due to the successful completion of the Frade and Roncador Manifold Projects. |
|
|
|
|
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Financial Review and Statements
Financial Review continued
The following table sets out the most significant recent or ongoing projects in the Acergy SAM segment:
| Project name | Description | |
|
Lump sum SURF projects: |
||
| Frade | Project offshore Brazil, executed during 2006 to 2009 for Chevron. | |
| PRA-1 | Project offshore Brazil, executed during 2006 to 2008 for Petrobras. | |
| Roncador Manifolds | Project offshore Brazil, executed during 2009 for Petrobras. | |
| Roncador Manifolds II | Project offshore Brazil, executed during 2010 for Petrobras. | |
| Roncador Manifolds III | Project offshore Brazil, expected to be executed during 2011 for Petrobras. | |
|
Vessels on long-term service arrangements: |
||
| Acergy Condor | Projects offshore Brazil, executed during 2006 to 2010 for Petrobras. | |
| Acergy Condor | Projects offshore Brazil, expected to be executed during 2010 to 2014 for Petrobras. | |
| Acergy Harrier | Projects offshore Brazil, executed during 2006 to 2010 for Petrobras. | |
| Acergy Harrier | Projects offshore Brazil, expected to be executed during 2011 for Petrobras. | |
| Pertinacia | Projects offshore Brazil, expected to be executed during 2007 to 2013 for Petrobras. | |
| Polar Queen | Projects offshore Brazil, expected to be executed during 2010 to 2013 for Petrobras. | |
Corporate
Acergy Corporate (‘CORP’)
This segment includes activities that serve more than one segment and includes: marine assets which have global mobility including construction and flowline lay support vessels, ROVs and other mobile assets that are not allocated to any one segment; management of offshore personnel; captive insurance activities; management and corporate services provided for the benefit of all regions; NKT Flexibles, a joint venture that manufactures flexible pipeline and risers; and Seaway Heavy Lifting, a joint venture with Morcell Limited, a Cyprus company, which operates the heavy lift vessel Stanislav Yudin .
Its offices are located in Hammersmith, London, United Kingdom.
| For the fiscal year |
2010
(in $ millions) |
% |
2009
(in $ millions) |
% |
2008
(in $ millions) |
% | ||||||||||||||||||
|
Revenue |
10.8 | 0.5 | (a) | 7.7 | 0.3 | (a) | (1.9 | ) | (0.1 | ) (a) | ||||||||||||||
|
Operating expenses |
|
(24.8 |
) |
|
1.5 |
(b) |
|
(16.9 |
) |
|
1.0 |
(b) |
|
(21.9 |
) |
|
1.2 |
(b) |
||||||
|
Net operating (loss)/income |
|
(46.7 |
) |
|
2.7 |
|
|
37.6 |
|
|||||||||||||||
| (a) | Segment revenue as a percentage of total revenue from continuing operations. |
| (b) | Segment operating expenses as a percentage of total operating expenses from continuing operations. |
Revenue
Acergy CORP’s revenue from continuing operations in fiscal year 2010 was $10.8 million compared to $7.7 million revenue in fiscal year 2009. The overall increase of $3.1 million is due to higher personnel services and related costs charged to the SapuraAcergy joint venture in relation to the Gumusut and Iwaki Projects both progressing well in fiscal year 2010.
Acergy CORP’s revenue from continuing operations in fiscal year 2009 was $7.7 million compared to $1.9 million negative revenue in fiscal year 2008. The revenue in fiscal year 2009 was due to personnel services and related costs charged to the SapuraAcergy joint venture.
Operating expenses
In fiscal year 2010 the segment’s operating expenses were $24.8 million, compared to $16.9 million in fiscal year 2009, primarily due to increased operating expenses relating to the Combination with Subsea 7 Inc. and reduced recoveries and associated increased costs as a result of lower vessel utilisation from fewer global vessels. The main contributor to the costs increase was Acergy Falcon which remained in an extended dry-dock as a result of fire damage incurred in January 2010. This was partially offset by higher recovery on offshore crewing costs.
In fiscal year 2009 the segment’s operating expenses were $16.9 million, compared to $21.9 million in fiscal year 2008, primarily due to higher recovery of offshore crewing costs partially offset by a $9.8 million impairment charge in respect of under-utilised operating equipment and a lower contribution from fewer global vessels included in this segment.
Net operating (loss)/income
Acergy CORP’s net operating loss for fiscal year 2010 was $46.7 million compared to net operating income of $2.7 million in fiscal year 2009. The net operating loss in fiscal year 2010 was primarily due to lower utilisation from fewer global vessels, reduced contribution from the NKT Flexibles joint venture, and increased operating expenses relating to the Combination with Subsea 7 Inc. This was partially offset by increased contribution from the Seaway Heavy Lifting joint venture and a more efficient use of internal offshore personnel and offshore equipment.
|
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Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Acergy CORP’s net operating income for fiscal year 2009 was $2.7 million compared to $37.6 million in fiscal year 2008. The decrease of $34.9 million was primarily due to a lower contribution from the Seaway Heavy Lifting and NKT Flexibles joint ventures. This was partially offset by an increase in gross profit due to an over recovery of offshore personnel costs partially offset by lower utilisation on fewer global vessels within the Acergy CORP segment in fiscal year 2009.
Liquidity and capital resources Cash management constraints The Group’s cash operations are managed and controlled by its treasury department. Its cash surpluses and requirements are identified using consolidated cash flow forecasts. It is not always possible to freely transfer funds across international borders. For example, approval from the Central Bank of Brazil is required to obtain remittances from Brazil. Access to the $63.7 million cash that is held by Sonamet is also limited as it requires agreement between the Group and the other shareholders, as well as approval from the National Bank of Angola.
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 maintaining what it believes are adequate reserves, banking facilities and reserve borrowing facilities, by continuously monitoring forecast and actual cash flows and aiming to match the maturity profiles of financial assets and liabilities. Included in Note 27 ‘Borrowings’ to the Consolidated Financial Statements is a list of undrawn facilities that the Group had at its disposal as at November 30, 2010.
The main uncertainties with respect to primary sources of funds are: project related timing of cash inflows and outflows; timing of the costs relating to investment in and expansion of the fleet; the ability to agree with clients, in a timely fashion, the amounts due as claims and variation orders; and the availability of cash flows from joint ventures.
Future compliance with debt covenants As described in Note 27 ‘Borrowings’ to the Consolidated Financial Statements, 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 fiscal year 2010 all covenants were met. The Group must meet the requirements of the financial covenants on a consolidated basis in quarterly intervals on the last day of each fiscal quarter. Based on its latest forecasts, the Group expects that it will be able to comply with all financial covenants during fiscal year 2011.
Sources of cash The Group’s principal source of funds for fiscal year 2010 was cash from operations. |
||
|
The cash and cash equivalents position of $484.3 million at November 30, 2010 (2009: $907.6 million) is largely attributable to net cash generated from operating activities of $140.0 million compared to $546.1 million generated in fiscal year 2009. The readily available funds for ongoing operations were: (i) unutilised credit facilities of $500 million under the Group’s $1 billion revolving credit and guarantee facility; (ii) cash on hand as at November 30, 2010 of $484.3 million; and (iii) ongoing cash generated from operations. Cash balances held by Sonamet continue to be excluded from the Group’s cash and cash equivalents as these entities are held for sale. A cash balance of $63.7 million (2009: $103.6 million) was held, subject to repatriation restrictions discussed above, by Sonamet at November 30, 2010.
At November 30, 2009, cash and cash equivalents were $907.6 million, largely attributable to stronger net cash generated from operating activities of $546.1 million compared to $493.1 million achieved in fiscal year 2008. The readily available funds for ongoing operations were: (i) unutilised credit facilities of $6.1 million; (ii) cash on hand as at November 30, 2009 of $907.6 million; (iii) the sale of Acergy Piper which realised a net addition of $73.0 million in cash on January 9, 2009; and (iv) ongoing cash generated from operations. In respect of amounts available under credit facilities, a further $68.9 million became available on December 17, 2009, increasing the cash available under credit facilities to an aggregate of $75.0 million. There was also a cash balance of $103.6 million (subject to repatriation restrictions discussed above) in Sonamet which had been classified as assets held for sale.
The Group believes that its ability to obtain funding from the sources described above will continue to provide the cash flows necessary to satisfy present working capital and capital expenditure requirements, as well as meet debt repayments and other financial commitments for the next twelve months. The Group also has the ability to raise additional debt and to issue further share capital. |
|
|
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|
Financial Review and Statements
Financial Review continued
The summary of generated and used cash flows is as follows:
| For fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||
|
Cash and cash equivalents at the beginning of the year |
907.6 | 573.0 | 582.7 | |||||||||
|
Net cash generated from operating activities |
140.0 | 546.1 | 493.1 | |||||||||
|
Net cash used in investing activities |
(493.3 | ) | (100.4 | ) | (286.7 | ) | ||||||
|
Net cash used in financing activities |
(84.5 | ) | (52.0 | ) | (186.1 | ) | ||||||
|
Effect of exchange rate changes on cash and cash equivalents |
(25.4 | ) | 44.5 | (30.0 | ) | |||||||
|
Decrease/(increase) in cash balances classified as assets held for sale |
39.9 | (103.6 | ) | – | ||||||||
|
Cash and cash equivalents at the end of the year |
484.3 | 907.6 | 573.0 | |||||||||
Net cash generated from operating activities
Net cash generated by operating activities during fiscal year 2010 was $140.0 million (2009: $546.1 million). The timing of invoice preparation for long-term contracts is typically based on progress towards the completion of work, either defined as agreed project ‘milestones’ or an otherwise agreed staged payment schedule. Cash flows do not always coincide with the recognition of revenue, as payment schedules may differ from revenue recognised on a percentage-of-completion basis. It is the policy, when negotiating a contract, to arrange for cash to be received from the client in advance of the requirement to pay suppliers, thus ensuring a positive impact on liquidity. In fiscal year 2010 customers extended the payment cycle, reflected in the increase in the average credit period to 45 days compared with 37 days in fiscal year 2009. Receivables also included approximately $50 million related to the insurance claim in respect of the Acergy Falcon fire, of which $18 million was received in December 2010. The average credit period of trade purchases (excluding capital expenditure) decreased from 84 days in fiscal year 2009 to 71 days in fiscal year 2010. The level of advance payments made by clients has also decreased, reflected by a decrease in advance payments at the end of fiscal year 2010 to $19.5 million, from $38.6 million in fiscal year 2009. Taxes paid increased due to settlement of various matters in fiscal year 2010 as well as a higher tax charge for the year. The major cash flow movements are disclosed further in the Consolidated Cash Flow Statement.
Net cash generated by operating activities during fiscal year 2009 was $546.1 million (2008: $493.1 million) which included an adjustment for non-cash expenses of $243.3 million (2008: $232.5 million), changes in operating assets and liabilities (net of acquisitions) of $97.0 million (2008: $167.0 million) and income taxes paid of $59.9 million (2008: $213.6 million). At the end of fiscal year 2009 the Group had $21.1 million in advance payments and the performance in cash collection from trade debtors had improved as indicated by the average credit period having decreased to 37 days compared to 39 days in fiscal year 2008.
Net cash used in investing activities
Net cash used in investing activities in fiscal year 2010 was $493.3 million compared to $100.4 million in fiscal year 2009.
In fiscal year 2010, this primarily comprised net cash outflows related to the purchase of property, plant and equipment of $503.9 million (2009: $171.8 million). The capital expenditure includes the acquisition of Borealis in December 2009, Polar Queen and Antares in June 2010 and Pertinacia in September 2010. An additional investment of $14.0 million (2009: $20.6 million) was made to the Seaway Heavy Lifting joint venture which represented a reinvestment of a dividend of $14.0 million (2009: $20.6 million) received from this joint venture. Additional dividends of $14.3 million (2009: $7.4 million) were received from the NKT Flexibles, Acergy/Subsea 7 and Dalia joint ventures.
Net cash used in investing activities in fiscal year 2009 was $100.4 million compared to $286.7 million in fiscal year 2008. This primarily comprised net cash outflows related to the purchase of property, plant and equipment of $171.8 million (2008: $294.3 million) to further develop the asset base, $20.6 million (2008: $nil) additional investment in the Seaway Heavy Lifting joint venture and $5.0 million (2008: $15.1 million) of advances to joint ventures. These outflows were partially offset by cash dividends received from joint ventures amounting to $28.0 million (2008: $10.9 million) and inflows from the sale of property, plant and equipment of $73.6 million (2008: $12.2 million) largely relating to the sale of Acergy Piper which raised net $73.0 million.
Net cash used in financing activities
In fiscal year 2010, net cash used in financing activities was $84.5 million, compared with $52.0 million in fiscal year 2009. This increase was attributable to the dividends paid to non-controlling interests of $20.0 million (2009: $4.9 million); issuance costs of $10.0 million incurred in obtaining the $1 billion revolving credit and guarantee facility; and borrowings repaid of $7.2 million (2009: $nil), partially offset by proceeds from borrowings of $6.1 million (2009: $2.8 million). Dividends paid to shareholders increased by $2.0 million to $42.2 million. Interest of $15.8 million was paid (2009: $11.3 million), including $11.3 million on the convertible loan notes.
In fiscal year 2009, net cash used in financing activities was $52.0 million, compared to net cash used in financing activities of $186.1 million in fiscal year 2008. The decrease was attributable to the absence of share buybacks in fiscal year 2009 compared to $138.3 million spent in fiscal year 2008. Net borrowings decreased by $3.5 million to $2.8 million in fiscal year 2009, and proceeds from option exercises reduced by $2.6 million to $1.6 million. Dividends paid to shareholders increased by $1.9 million. Convertible loan notes interest of $11.3 million remained the same for fiscal year 2009 and fiscal year 2008. Dividends paid to minority interests reduced by $3.8 million to $4.9 million.
|
74 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Effect of exchange rate changes on cash and cash equivalents In fiscal year 2010, foreign exchange variances on cash balances included in the Group’s foreign operations had an unfavourable variance of $25.4 million (2009: favourable variance of $44.5 million), primarily as a result of the strengthening of the US Dollar compared to other currencies.
Details relating to the effect of exchange rate changes, related risks and hedging positions are presented in Note 34 ‘Financial instruments’ to the Consolidated Financial Statements.
Description of indebtedness On October 11, 2006 Acergy S.A (now Subsea 7 S.A.) issued $500 million in aggregate principal amount of 2.25% convertible notes due 2013. The convertible notes have an annual interest of 2.25% payable semi-annually in arrears on April 11 and October 11 of each year up to and including fiscal year 2013.
On August 10, 2010 Acergy S.A (now Subsea 7 S.A.) executed a $1 billion multi-currency revolving credit and guarantee facility with a number of banks. The facility can be used in full for the issuance of guarantees, or for a combination of guarantees and cash drawings subject to a $500 million sub-limit for cash drawings. The $1 billion facility is guaranteed by Subsea 7 S.A., Class 3 Shipping Limited, Acergy Shipping Limited and Subsea 7 Treasury (UK) Limited. Final maturity will be August 10, 2015. However, in accordance with the terms of the agreement, performance guarantees can be issued with up to 78 months duration up to one month prior to the final maturity date of the facility, subject to Subsea 7 providing cash cover for any guarantees outstanding following the final maturity date.
The $1 billion facility contains financial covenants in respect of leverage, interest coverage and gearing ratios. The requirements of the financial covenants must be met on a consolidated basis at a quarterly interval. In addition to the financial covenants listed above, the facility contains affirmative covenants, negative pledges and events of default which are customary for facilities of this nature and consistent with past practice. Such covenants specifically limit mergers or transfers, incurrence of other indebtedness, class 1 acquisitions, loans outside the Group and change of business. On September 28, 2010 the banks consented to retain their commitment under the $1 billion facility following the proposed Combination with Subsea 7 Inc.
The $1 billion facility also contains events of default provisions which include payment defaults (subject to a three day grace period), breach of financial covenants, breach of other obligations, breach of representations and warranties, insolvency, illegality, unenforceability, conditions subsequent, curtailment of business, claims against an obligor’s assets, appropriation of an obligor’s assets, cross-defaults to other indebtedness in excess of $10 million, failure to maintain exchange listing, material adverse change, auditor’s qualification, repudiation and material litigation.
Interest on the $1 billion facility is payable at LIBOR plus a margin which is linked to Subsea 7’s leverage, measured as the ratio of net debt to EBITDA, and which may range from 1.75% to 2.75% per year. The fee applicable for guarantees is linked to the same ratio of net debt to EBITDA and may range from 1.75% to 2.75% per year in respect of financial guarantees and 0.88% to 1.38% in respect of performance guarantees. The margin and guarantee fee are reset quarterly in line with changes to Subsea 7’s leverage. As part of the terms of this agreement, Subsea 7 S.A.’s $400 million facility and $200 million facility were cancelled and any amounts utilised on the execution date were transferred to the $1 billion facility.
On October 14, 2008 the Company completed a NOK Loan and Guarantee Facility of Norwegian Krone 977.5 million for the post delivery financing of Havila dive support vessel.
Subsea 7 also has undrawn bank overdraft facilities and short-term lines of credit of $35.5 million (2009: $36.1 million) of which $nil (2009: $nil) were drawn at year end.
Together these loan facilities and cash balances are expected to provide sufficient liquid resources and working capital to meet forecasted future operating requirements for the next twelve months.
Further details are included in Note 27 ‘Borrowings’ and Note 28 ‘Convertible loan notes’ to the Consolidated Financial Statements.
Off-balance sheet arrangements Leases and bank guarantees The Group does not engage in off-balance sheet financing in the form of special purpose entities or similar arrangements, but engages in operating leases in the normal course of business in respect of vessel charter hire obligations, office facilities and equipment.
The Group also arranges for bank guarantees, which collectively refer to performance bonds, bid bonds, advance payment bonds, guarantees or standby letters of credit in respect of performance obligations to clients in connection with work on specific projects.
The purpose of the bank guarantees, generally, is to enable clients to recover cash advances paid to the Group under the project contracts or to obtain cash compensation should the Group be unable to fulfil performance obligations under contracts. Bank guarantees of $158.9 million were issued in support of projects in fiscal year 2010 (2009: $287.1 million).
In addition to the amount available under the $1 billion facility, the Group has a $30.0 million (2009: $30.0 million) bank guarantee facility with Credit Industriel et Commercial Bank of which $9.0 million (2009: $8.0 million) was utilised as at November 30, 2010.
There are three unsecured local lines of credit in Nigeria for the sole use of the Group’s subsidiary Globestar Engineering Company (Nigeria) Limited, being $13.3 million with Union Bank of Africa plc, $9.9 million with First Bank of Nigeria plc, and $6.6 million with Zenith Bank plc. These facilities were entered into to guarantee the project performance of the subsidiary to third parties in the normal course of business. The total amount drawn under these facilities as at November 30, 2010 was $7.7 million (2009: $0.7 million). |
|
|
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|
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|
Financial Review and Statements
Financial Review continued
The Group had past arrangements with a number of financial institutions to issue bank guarantees on its behalf. As at November 30, 2010, the aggregate amount of guarantees issued under these facilities was $14.4 million (2009: $14.5 million). There was no availability for further issuances under these facilities.
Guarantee arrangements with joint ventures
SapuraAcergy Assets Pte Limited (‘SAPL’), previously known as Nautical Vessels Pte Limited, is a 50/50-owned joint venture between Nautical Essence Sdn. Bhd. (wholly owned by SapuraCrest Petroleum Berhad) and Acergy (Gibraltar) Limited (wholly owned by Subsea 7 S.A.). In 2007 the respective parent companies issued a Charter Guarantee guaranteeing the charter payments from the charterer of Sapura 3000 , SapuraAcergy Sdn. Bhd. to the vessel owner, SAPL. The limit of the guarantee is, at any time, the sum of the outstanding amounts under a $240.0 million Facility Agreement of SAPL less $100.0 million. Any call under the guarantee will not result in a lump sum payment being made, but the guarantors, severally, will have to service the debt by way of charter payments due from the charterer to the vessel owner until the termination date of the loan, which is February 2, 2015.
SapuraAcergy Sdn. Bhd. (‘SASB’) is a 50/50-owned joint venture between Nautical Essence Sdn. Bhd. (wholly owned by SapuraCrest Petroleum Berhad) and Acergy (Gibraltar) Limited (wholly owned by Subsea 7 S.A.). SASB has entered into a $181.3 million multi-currency facility for the financing of the Shell Gumusut Project. Both Subsea 7 S.A. and SapuraCrest Petroleum Berhad have issued several guarantees for 50% of the financing respectively. The facility consists of $44.0 million available for the issuance of bank guarantees, $60.0 million available for letters of credit, and two revolving credit facilities for $57.3 million and $20.0 million respectively. As at November 30, 2010 the amount available for bank guarantees was fully drawn, $16.8 million was drawn under the letter of credit facility and $12.0 million was drawn under the $20.0 million revolving credit facility. There were no drawings under the $57.3 million revolving credit facility.
Investments in associates and joint ventures
| As at November 30 |
Country/place of registration |
Subsea 7 Group business region |
Ownership
% |
2010 (in $ millions) |
2009 (in $ millions) |
|||||||||||||||||||
| Dalia Floater Angola SNC, TSS Dalia SNC (‘Dalia’) (a) | France |
|
Africa and
Mediterranean |
|
Associate | 17.5 | 2.1 | 3.6 | ||||||||||||||||
|
Global Oceon Engineers Nigeria Limited (‘Oceon’) |
|
Nigeria |
|
|
Africa and
|
|
|
Associate |
|
|
40 |
|
|
– |
|
|
– |
|
||||||
|
SapuraAcergy Assets Pte Ltd, SapuraAcergy Sdn Bhd (‘SapuraAcergy’) |
|
Malaysia |
|
|
Asia and
|
|
|
Joint Venture |
|
|
50 |
|
|
15.6 |
|
|
– |
|
||||||
|
Seaway Heavy Lifting (‘SHL’) |
|
Cyprus/Netherlands |
|
|
Corporate |
|
|
Joint Venture |
|
|
50 |
|
|
102.8 |
|
|
77.6 |
|
||||||
|
NKT Flexibles I/S (‘NKT Flexibles’) |
|
Denmark |
|
|
Corporate |
|
|
Joint Venture |
|
|
49 |
|
|
94.6 |
|
|
109.1 |
|
||||||
|
Total |
215.1 | 190.3 | ||||||||||||||||||||||
| (a) | Subsea 7 owns 17.5% and has a significant influence in Dalia Floater Angola and TSS Dalia. Subsea 7 has a veto on decisions which require unanimous agreement. |
Description of joint ventures
Dalia is an associate jointly held with Technip and Saipem to perform work on the Dalia field development Block 17 offshore Angola for Total E&P Angola. The joint venture has responsibility for project management, engineering, procurement, commissioning and hook-up of the FPSO.
During fiscal year 2007, a Nigerian joint venture, Oceon, with Petrolog Engineering Services Limited, an established Nigerian contractor, was founded. The purpose of Oceon is to provide engineering support for future shallow and deepwater projects to be executed in Nigeria, and therefore strengthen Subsea 7’s presence in the country.
In 2006 the Group established the SapuraAcergy joint ventures with SapuraCrest Petroleum Berhad, to take over the build and operation of Sapura 3000 , a new heavy lift and pipelay vessel designed to be one of the most advanced deepwater construction vessels in the Asia Pacific region. During fiscal year 2007, the $150 million loan taken out by the joint venture to partially fund the construction of Sapura 3000 was refinanced into a $200 million term loan with an additional $40 million revolving credit facility.
The Group offers heavy lift floating crane services through SHL. In March 2010 SHL acquired the heavy lift barge Stanislav Yudin , previously chartered from a subsidiary of Morcell Limited, the Group’s joint venture partner in SHL. The barge operates worldwide providing heavy lift services to a range of offshore companies, including occasional projects for the Group. The joint venture also acquired Neftegaz-66 , an anchor handling tug and offshore supply vessel which accompanies Stanislav Yudin . A new build, heavy lift vessel Oleg Strashnov is under construction and the vessel is expected to be in operation in the first half of 2011. The Group increased its investment in SHL during fiscal year 2007 to contribute to the construction costs of this vessel. In addition to this increase in shareholder contribution, SHL took out a term loan, revolving credit and guarantee facility on May 25, 2007. The term loans are for up to € 140 million ($178.0 million) and $180 million, and the revolving credit and guarantee facility for up to $33 million. During fiscal year 2009 an additional investment of $14.0 million was made (2009: $20.6 million) and the existing credit facilities remained in place. There is no recourse to the Group in respect of this facility.
NKT Flexibles manufactures flexible flowlines and dynamic flexible risers. In fiscal year 2010, the Group’s share of net income was $13.7 million (2009 and 2008: $21.7 million and $45.6 million respectively).
More details relating to transactions with the associates and joint ventures are presented in Note 17 ‘Interest in associates and joint ventures’ to the Consolidated Financial Statements.
|
76 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Contractual obligations
Payments due by period (a) |
|
|||||||||||||||||||
|
As at November 30, 2010 (in $ millions) |
Total |
Less than 1 year |
1–3 years |
3–5 years |
After 5 years |
|||||||||||||||
|
Convertible notes (b) |
500.0 | – | 500.0 | – | – | |||||||||||||||
|
Future interest payments (c) |
33.8 | 11.3 | 22.5 | – | – | |||||||||||||||
|
Operating lease payments (d) |
372.8 | 68.2 | 121.6 | 101.7 | 81.3 | |||||||||||||||
|
Purchase obligations (e) |
434.6 | 343.3 | 91.3 | – | – | |||||||||||||||
|
Forward foreign exchange contracts (f) |
34.2 | 27.9 | 6.1 | 0.2 | – | |||||||||||||||
|
Total |
1,375.4 | 450.7 | 741.5 | 101.9 | 81.3 | |||||||||||||||
|
(a) Excludes future retirement benefit obligations of $28.8 million at November 30, 2010, guarantee arrangements with joint ventures and associates of $73.6 million at November 30, 2010, and the main renewal options: Acergy Viking – ten renewal options consisting of two for two years and eight options for one year; purchase options after eight, eleven, fourteen and seventeen years; Skandi Acergy – four renewal options consisting of two options for two years each and two options for one year each.
(b) On October 11, 2006 the Group completed the offering of $500 million in aggregate principal amount of convertible loan notes due in fiscal year 2013 with the receipt of net proceeds after deduction of related costs of $490.8 million. The convertible loan notes have an annual interest rate of 2.25% payable semi-annually in arrears on April 11 and October 11 of each year up to and including fiscal year 2013. They were issued at 100% of their principal amount and unless previously redeemed, converted or cancelled will mature on October 11, 2013. The convertible loan notes are listed on the Euro MTF Market of the Luxembourg Stock Exchange. For further details see Note 28 ‘Convertible loan notes’ to the Consolidated Financial Statements.
(c) The Group’s debt structure currently contains fixed interest rate debt, and therefore it has calculated the amount of the future interest payments based on the 2.25% interest rate on the aggregate principal amount of $500 million of convertible loan notes. For further details see Note 28 ‘Convertible loan notes’ to the Consolidated Financial Statements.
(d) These consisted of charter hire obligations towards certain construction support, diving support, survey and inspection vessels of $189.7 million. The remaining obligations related to office facilities and equipment as at November 30, 2010 of $183.1 million. For further details see Note 33 ‘Operating lease arrangements’ to the Consolidated Financial Statements.
(e) Purchase obligations are an agreement to purchase goods or services that are enforceable and legally binding including fixed or minimum quantities to be purchased. The value disclosed above is inclusive of property, plant and equipment as disclosed in Note 32 ‘Commitments and contingent liabilities’ to the Consolidated Financial Statements.
(f) The Group enters into both derivative financial instruments and non-derivative financial instruments in order to manage its foreign currency exposures. The principal derivatives used are forward foreign currency contracts. The commitments have been drawn up based on the undiscounted net cash inflows or outflows on the derivative. For further details see Note 34 ‘Financial Instruments’ to the Consolidated Financial Statements. |
||||||||||||||||||||
|
Legal matters During fiscal year 2009 the Group’s Brazilian business was audited and formally assessed for ICMS tax (import duty) by the Brazilian tax authorities (Secretaria Fazenda Estado Rio de Janeiro). The amount assessed including penalties and interest as at November 30, 2010 amounted to BRL136.0 million ($79.2 million). At November 30, 2009 the amount assessed including penalties and interest was BRL107.6 million ($61.7 million). The Group has challenged this assessment and will revert to the courts if necessary. No provision has been made for any payment as the Group does not believe that the likelihood of payment is probable.
In the course of business, the Group becomes involved in contract disputes from time-to-time due to the nature of the Group’s activities as a contracting business involved in several long-term projects at any given time. The Group makes 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 and therefore the resulting liabilities may exceed the liability which was anticipated.
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 possible that the final resolution of any litigation could require the Group to make additional expenditures in excess of provisions that the Group may have established. In the ordinary course of business, various claims, suits and complaints have been filed against the Group in addition to the one specifically referred to above. Although the final resolution of any such other matters could have a material effect on operating results for a particular reporting period, the Group believes that they should not materially affect its consolidated financial position. For further details, refer to Note 11 ‘Taxation’ and Note 32 ‘Commitments and contingent liabilities’ to the Consolidated Financial Statements.
Inflation
Transactions in high-inflation countries are denominated substantially in relatively stable currencies, such as the US Dollar, and inflation therefore does not materially affect the Group’s consolidated financial results. Where these transactions are denominated in US Dollars they are hedged in line with the Group’s foreign exchange policies. |
||||||||||||||||||||
|
seabed-to-surface
|
|
77
|
Financial Review and Statements
Financial Review continued
Changes in share capital
In fiscal year 2010 a total of 732,168 share options were exercised (2009: 390,949), raising proceeds of $4.6 million (2009: $1.6 million). The share options exercised during fiscal year 2010 were satisfied by delivering treasury shares. No new common shares were issued.
At the Extraordinary General Meeting of shareholders on November 9, 2010, the Articles of Incorporation were amended to increase the Group’s authorised share capital from 230 million to 450 million common shares effective immediately.
Additional information on the authorised shares and issued common shares is set out in Note 24 ‘Issued share capital’ to the Consolidated Financial Statements.
Subsequent events
On January 7, 2011 the Group acquired 100% of the share capital, and full control of, Subsea 7 Inc. Subsea 7 Inc. is a global subsea contractor within the oil and gas industry with assets around the world, including onshore assets (such as offices, pipeline welding spool base and fabrication facilities) and vessels. Subsea 7 Inc. performs total subsea field projects and provides design, engineering, construction, installation and maintenance of facilities for the subsea production of oil and gas. As a result of the Combination, the Group has enhanced its presence in these markets. The Group also expects that the Combination will give rise to substantial operating and vessel fleet synergies.
On January 7, 2011 Subsea 7 S.A. issued 156,839,759 new shares to the Subsea 7 Inc. shareholders in consideration for the repurchase and cancellation of all Subsea 7 Inc. shares. The fair value of these shares were $25.19 each based on the quoted price of the shares of Subsea 7 S.A. resulting in an aggregate consideration of $3.95 billion.
Upon completion the Company’s name changed to Subsea 7 S.A. and the restated Articles of Incorporation approved by Acergy S.A.’s shareholders on November 9, 2010 and the appointment of the Board of Directors became effective. The first day of trading in the shares of the newly Combined Group, Subsea 7 S.A., was January 10, 2011.
On February 15, 2011 the Group announced its intention to apply for voluntary delisting from the NASDAQ Global Select Market and to deregister and terminate its reporting obligations under the Securities Exchange Act of 1934. The delisting is expected to be effective on March 7, 2011. The Company also intends to deregister and terminate its reporting obligations under the Securities Exchange Act of 1934 as soon as it becomes eligible to do so.
For further details of post balance sheet events refer to Note 40 ‘Post balance sheet events’ to the Consolidated Financial Statements.
Critical accounting policies
For the Group’s critical accounting policies please refer to Note 3 ‘Significant accounting policies’ and Note 4 ‘Critical accounting judgements and key sources of estimation uncertainty’ to the Consolidated Financial Statements.
|
78 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Financial Review and Statements Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Subsea 7 S.A. We have audited the accompanying consolidated balance sheets of Subsea 7 S.A. (a Luxembourg company) and subsidiaries (the “Group”) as at November 30, 2010, 2009 and 2008, and the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of changes in equity, and consolidated cash flow statements for each of the three years in the period ended November 30, 2010. These financial statements are the responsibility of the Group’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Group as at November 30, 2010, 2009 and 2008, and the results of its operations and cash flows for each of the three years in the period ended November 30, 2010, in conformity with International Financial Reporting Standards (“IFRS”) as adopted for use in the European Union and IFRS as issued by the International Accounting Standards Board.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Group’s internal control over financial reporting as of November 30, 2010, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2011 expressed an unqualified opinion on the Group’s internal control over financial reporting. |
||
|
Deloitte LLP London, United Kingdom February 23, 2011 |
||
|
|
|
seabed-to-surface
|
|
79
|
Financial Review and Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Subsea 7 S.A.
We have audited the internal control over financial reporting of Subsea 7 S.A. (a Luxembourg company) and subsidiaries (the “Group”) as at November 30, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Group’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Group’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A group’s internal control over financial reporting is a process designed by, or under the supervision of, the group’s principal executive and principal financial officers, or persons performing similar functions, and effected by the group’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A group’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the group; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the group are being made only in accordance with authorizations of management and directors of the group; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the group’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Group maintained, in all material respects, effective internal control over financial reporting as of November 30, 2010, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Consolidated Financial Statements as of and for the year ended November 30, 2010 of the Group and our report dated February 23, 2011 expressed an unqualified opinion on those financial statements.
Deloitte LLP
London, United Kingdom
February 23, 2011
|
80 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
Financial Review and Statements
Consolidated Income Statement
For the fiscal year ended November 30
| (in $ millions, except per share data) | Notes | 2010 | 2009 | 2008 | ||||||||||||||
|
Continuing operations: |
||||||||||||||||||
|
Revenue |
5 | 2,369.0 | 2,208.8 | 2,522.4 | ||||||||||||||
|
Operating expenses |
(1,701.0 | ) | (1,683.8 | ) | (1,874.2 | ) | ||||||||||||
|
Gross profit |
668.0 | 525.0 | 648.2 | |||||||||||||||
|
Administrative expenses |
(306.7 | ) | (231.3 | ) | (253.8 | ) | ||||||||||||
|
Net other operating income |
– | – | 3.4 | |||||||||||||||
|
Share of net income of associates and joint ventures |
17 | 74.8 | 49.0 | 63.0 | ||||||||||||||
|
Net operating income from continuing operations |
436.1 | 342.7 | 460.8 | |||||||||||||||
|
Investment income from bank deposits |
9.8 | 6.4 | 17.9 | |||||||||||||||
|
Other gains and losses |
9 | (18.0 | ) | 43.6 | 44.1 | |||||||||||||
|
Finance costs |
10 | (28.7 | ) | (31.4 | ) | (30.5 | ) | |||||||||||
|
Income before taxes |
399.2 | 361.3 | 492.3 | |||||||||||||||
|
Taxation |
11 | (130.8 | ) | (102.8 | ) | (162.6 | ) | |||||||||||
|
Income from continuing operations |
268.4 | 258.5 | 329.7 | |||||||||||||||
|
Net income/(loss) from discontinued operations |
12 | 44.6 | 7.2 | (22.5 | ) | |||||||||||||
|
Net income |
313.0 | 265.7 | 307.2 | |||||||||||||||
|
Net income attributable to: |
||||||||||||||||||
|
Equity holders of parent |
265.4 | 245.0 | 301.4 | |||||||||||||||
|
Non-controlling interests |
26 | 47.6 | 20.7 | 5.8 | ||||||||||||||
| 313.0 | 265.7 | 307.2 | ||||||||||||||||
| Earnings/(loss) per share | Notes |
$ per share |
$ per share |
$ per share |
|
|||||||||||||
|
Basic: |
||||||||||||||||||
|
Continuing operations |
1.20 | 1.30 | 1.76 | |||||||||||||||
|
Discontinued operations |
0.24 | 0.04 | (0.12 | ) | ||||||||||||||
|
Net income |
13 | 1.45 | 1.34 | 1.64 | ||||||||||||||
|
Diluted: |
||||||||||||||||||
|
Continuing operations |
1.16 | 1.29 | 1.70 | |||||||||||||||
|
Discontinued operations |
0.22 | 0.04 | (0.11 | ) | ||||||||||||||
|
Net income |
13 | 1.38 | 1.33 | 1.59 | ||||||||||||||
|
seabed-to-surface
|
|
81
|
Financial Review and Statements
Consolidated Statement of Comprehensive Income
For the fiscal year ended November 30
| (in $ millions) | Notes | 2010 | 2009 | 2008 | ||||||||||||
|
Net income |
313.0 | 265.7 | 307.2 | |||||||||||||
|
Foreign currency translation |
(69.4 | ) | 40.5 | (84.6 | ) | |||||||||||
|
Cash flow hedges: |
||||||||||||||||
|
(Losses)/gains on cash flow hedges |
34 | (40.8 | ) | 16.4 | (26.5 | ) | ||||||||||
|
Transferred to income statement on cash flow hedges |
34 | 16.7 | 9.7 | 3.7 | ||||||||||||
|
Transferred to the initial carrying amount of hedged items on cash flow hedges |
34 | (0.2 | ) | 0.2 | (0.5 | ) | ||||||||||
|
Share of other comprehensive income/(loss) of associates and joint ventures |
17 | (5.1 | ) | (1.7 | ) | (23.7 | ) | |||||||||
|
Actuarial losses on defined benefit pension schemes |
37 | (7.2 | ) | (2.8 | ) | (11.1 | ) | |||||||||
|
Tax relating to components of other comprehensive income |
11 | 5.6 | 8.1 | (6.8 | ) | |||||||||||
|
Other comprehensive (expense)/income – net of tax |
(100.4 | ) | 70.4 | (149.5 | ) | |||||||||||
|
Total comprehensive income |
212.6 | 336.1 | 157.7 | |||||||||||||
|
Total comprehensive income attributable to: |
||||||||||||||||
|
Equity holders of parent |
167.0 | 313.7 | 153.4 | |||||||||||||
|
Non-controlling interests |
45.6 | 22.4 | 4.3 | |||||||||||||
| 212.6 | 336.1 | 157.7 | ||||||||||||||
|
82 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
Financial Review and Statements
Consolidated Balance Sheet
As at November 30
| (in $ millions) | Notes | 2010 | 2009 | 2008 |
|
|||||||||||||
|
Assets |
||||||||||||||||||
|
Non-current assets |
||||||||||||||||||
|
Intangible assets |
15 | 6.1 | 9.4 | 3.8 | ||||||||||||||
|
Property, plant and equipment |
16 | 1,278.8 | 821.8 | 907.6 | ||||||||||||||
|
Interest in associates and joint ventures |
17 | 215.1 | 190.3 | 140.2 | ||||||||||||||
|
Advances and receivables |
18 | 62.7 | 43.3 | 29.4 | ||||||||||||||
|
Derivative financial instruments |
34 | 0.7 | 6.0 | 18.4 | ||||||||||||||
|
Retirement benefit assets |
37 | – | – | 0.1 | ||||||||||||||
|
Deferred tax assets |
11 | 22.8 | 19.3 | 39.8 | ||||||||||||||
| 1,586.2 | 1,090.1 | 1,139.3 | ||||||||||||||||
|
Current assets |
||||||||||||||||||
|
Inventories |
19 | 24.1 | 22.4 | 38.5 | ||||||||||||||
|
Trade and other receivables |
20 | 382.0 | 297.9 | 354.5 | ||||||||||||||
|
Derivative financial instruments |
34 | 12.1 | 19.1 | 45.8 | ||||||||||||||
|
Assets classified as held for sale |
21 | 255.5 | 263.6 | 75.5 | ||||||||||||||
|
Other accrued income and prepaid expenses |
22 | 242.3 | 212.8 | 233.5 | ||||||||||||||
|
Restricted cash balances |
3.0 | 19.6 | 11.0 | |||||||||||||||
|
Cash and cash equivalents |
484.3 | 907.6 | 573.0 | |||||||||||||||
| 1,403.3 | 1,743.0 | 1,331.8 | ||||||||||||||||
|
Total assets |
2,989.5 | 2,833.1 | 2,471.1 | |||||||||||||||
|
Equity |
||||||||||||||||||
|
Issued share capital |
24 | 389.9 | 389.9 | 389.9 | ||||||||||||||
|
Own shares |
25 | (209.2 | ) | (222.6 | ) | (229.4 | ) | |||||||||||
|
Paid in surplus |
508.8 | 503.9 | 498.7 | |||||||||||||||
|
Equity reserves |
28 | 110.7 | 110.7 | 110.7 | ||||||||||||||
|
Translation reserves |
(80.2 | ) | (12.0 | ) | (70.4 | ) | ||||||||||||
|
Other reserves |
(90.3 | ) | (60.1 | ) | (70.4 | ) | ||||||||||||
|
Retained earnings |
572.8 | 358.2 | 158.6 | |||||||||||||||
|
Equity attributable to equity holders of the parent |
1,202.5 | 1,068.0 | 787.7 | |||||||||||||||
|
Non-controlling interests |
26 | 56.8 | 31.2 | 13.7 | ||||||||||||||
|
Total equity |
1,259.3 | 1,099.2 | 801.4 | |||||||||||||||
|
Liabilities |
||||||||||||||||||
|
Non-current liabilities |
||||||||||||||||||
|
Non-current portion of borrowings |
27 | 435.3 | 415.8 | 409.2 | ||||||||||||||
|
Retirement benefit obligation |
37 | 28.8 | 27.2 | 21.2 | ||||||||||||||
|
Deferred tax liabilities |
11 | 44.1 | 49.9 | 56.1 | ||||||||||||||
|
Provisions |
31 | 12.4 | 10.6 | 8.0 | ||||||||||||||
|
Derivative financial instruments |
34 | 8.7 | 2.2 | 57.1 | ||||||||||||||
|
Other non-current liabilities |
29 | 10.4 | 7.0 | 3.9 | ||||||||||||||
| 539.7 | 512.7 | 555.5 | ||||||||||||||||
|
Current liabilities |
||||||||||||||||||
|
Trade and other liabilities |
30 | 673.3 | 624.1 | 651.6 | ||||||||||||||
|
Derivative financial instruments |
34 | 28.9 | 21.9 | 62.6 | ||||||||||||||
|
Current tax liabilities |
109.9 | 97.9 | 69.1 | |||||||||||||||
|
Current portion of borrowings |
27 | – | – | 10.1 | ||||||||||||||
|
Liabilities directly associated with assets classified as held for sale |
21 | 134.5 | 174.9 | – | ||||||||||||||
|
Provisions |
31 | 26.1 | 22.6 | 15.2 | ||||||||||||||
|
Deferred revenue |
38 | 217.8 | 279.8 | 305.6 | ||||||||||||||
| 1,190.5 | 1,221.2 | 1,114.2 | ||||||||||||||||
|
Total liabilities |
1,730.2 | 1,733.9 | 1,669.7 | |||||||||||||||
|
Total equity and liabilities |
2,989.5 | 2,833.1 | 2,471.1 | |||||||||||||||
|
seabed-to-surface
|
|
83
|
Financial Review and Statements
Consolidated Statement of Changes in Equity
For the fiscal year
| (in $ millions) |
Issued
share capital |
Own
shares |
Paid in
surplus |
Equity
reserves |
Translation
reserves |
Other
reserves |
Retained
(accumulated
|
Total |
Non-
controlling interests |
Total
equity |
||||||||||||||||||||||||||||||
| Balance at December 1, 2007 | 389.9 | (111.2 | ) | 492.9 | 110.7 | 29.1 | (21.9 | ) | (88.6 | ) | 800.9 | 18.1 | 819.0 | |||||||||||||||||||||||||||
| Comprehensive income | ||||||||||||||||||||||||||||||||||||||||
| Net income | – | – | – | – | – | – | 301.4 | 301.4 | 5.8 | 307.2 | ||||||||||||||||||||||||||||||
| Exchange differences | – | – | – | – | (83.1 | ) | – | – | (83.1 | ) | (1.5 | ) | (84.6 | ) | ||||||||||||||||||||||||||
| Cash flow hedges | – | – | – | – | – | (23.3 | ) | – | (23.3 | ) | – | (23.3 | ) | |||||||||||||||||||||||||||
| Share of other comprehensive income/(loss) of associates and joint ventures | – | – | – | – | – | (23.7 | ) | – | (23.7 | ) | – | (23.7 | ) | |||||||||||||||||||||||||||
| Actuarial losses on defined benefit pension schemes | – | – | – | – | – | (11.1 | ) | – | (11.1 | ) | – | (11.1 | ) | |||||||||||||||||||||||||||
| Tax relating to components of other comprehensive income | – | – | – | – | (16.4 | ) | 9.6 | – | (6.8 | ) | – | (6.8 | ) | |||||||||||||||||||||||||||
| Total comprehensive (loss)/income | – | – | – | – | (99.5 | ) | (48.5 | ) | 301.4 | 153.4 | 4.3 | 157.7 | ||||||||||||||||||||||||||||
| Transactions with owners | ||||||||||||||||||||||||||||||||||||||||
| Share based compensation | – | – | 7.5 | – | – | – | – | 7.5 | – | 7.5 | ||||||||||||||||||||||||||||||
| Tax effects | – | – | (1.7 | ) | – | – | – | – | (1.7 | ) | – | (1.7 | ) | |||||||||||||||||||||||||||
| Shares acquired | – | (138.3 | ) | – | – | – | – | – | (138.3 | ) | – | (138.3 | ) | |||||||||||||||||||||||||||
| Shares reissued | – | 20.1 | – | – | – | – | – | 20.1 | – | 20.1 | ||||||||||||||||||||||||||||||
| Dividends declared and paid | – | – | – | – | – | – | (38.3 | ) | (38.3 | ) | (8.7 | ) | (47.0 | ) | ||||||||||||||||||||||||||
| Loss on reissuance of own shares | – | – | – | – | – | – | (15.9 | ) | (15.9 | ) | – | (15.9 | ) | |||||||||||||||||||||||||||
| Total transactions with owners | – | (118.2 | ) | 5.8 | – | – | – | (54.2 | ) | (166.6 | ) | (8.7 | ) | (175.3 | ) | |||||||||||||||||||||||||
| Balance at November 30, 2008 | 389.9 | (229.4 | ) | 498.7 | 110.7 | (70.4 | ) | (70.4 | ) | 158.6 | 787.7 | 13.7 | 801.4 | |||||||||||||||||||||||||||
| Comprehensive income | ||||||||||||||||||||||||||||||||||||||||
| Net income | – | – | – | – | – | – | 245.0 | 245.0 | 20.7 | 265.7 | ||||||||||||||||||||||||||||||
| Exchange differences | – | – | – | – | 38.8 | – | – | 38.8 | 1.7 | 40.5 | ||||||||||||||||||||||||||||||
| Cash flow hedges | – | – | – | – | – | 26.3 | – | 26.3 | – | 26.3 | ||||||||||||||||||||||||||||||
| Share of other comprehensive income/(loss) of associates and joint ventures | – | – | – | – | – | (1.7 | ) | – | (1.7 | ) | – | (1.7 | ) | |||||||||||||||||||||||||||
| Actuarial losses on defined benefit pension schemes | – | – | – | – | – | (2.8 | ) | – | (2.8 | ) | – | (2.8 | ) | |||||||||||||||||||||||||||
| Tax relating to components of other comprehensive income | – | – | – | – | 19.6 | (11.5 | ) | – | 8.1 | – | 8.1 | |||||||||||||||||||||||||||||
| Total comprehensive (loss)/income | – | – | – | – | 58.4 | 10.3 | 245.0 | 313.7 | 22.4 | 336.1 | ||||||||||||||||||||||||||||||
| Transactions with owners | ||||||||||||||||||||||||||||||||||||||||
| Share based compensation | – | – | 3.9 | – | – | – | – | 3.9 | – | 3.9 | ||||||||||||||||||||||||||||||
| Tax effects | – | – | 1.3 | – | – | – | – | 1.3 | – | 1.3 | ||||||||||||||||||||||||||||||
| Shares reissued | – | 6.8 | – | – | – | – | – | 6.8 | – | 6.8 | ||||||||||||||||||||||||||||||
| Dividends declared and paid | – | – | – | – | – | – | (40.2 | ) | (40.2 | ) | (4.9 | ) | (45.1 | ) | ||||||||||||||||||||||||||
| Loss on reissuance of own shares | – | – | – | – | – | – | (5.2 | ) | (5.2 | ) | – | (5.2 | ) | |||||||||||||||||||||||||||
| Total transactions with owners | – | 6.8 | 5.2 | – | – | – | (45.4 | ) | (33.4 | ) | (4.9 | ) | (38.3 | ) | ||||||||||||||||||||||||||
| Balance at November 30, 2009 | 389.9 | (222.6 | ) | 503.9 | 110.7 | (12.0 | ) | (60.1 | ) | 358.2 | 1,068.0 | 31.2 | 1,099.2 | |||||||||||||||||||||||||||
|
84 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| (in $ millions) |
Issued
share capital |
Own
shares |
Paid in
surplus |
Equity
reserves |
Translation
reserves |
Other
reserves |
Retained
earnings/ (accumulated deficit) |
Total |
Non-
controlling interests |
Total
equity |
|
|||||||||||||||||||||||||||||||
| Comprehensive income | ||||||||||||||||||||||||||||||||||||||||||
| Net income | – | – | – | – | – | – | 265.4 | 265.4 | 47.6 | 313.0 | ||||||||||||||||||||||||||||||||
| Exchange differences | – | – | – | – | (67.4 | ) | – | – | (67.4 | ) | (2.0 | ) | (69.4 | ) | ||||||||||||||||||||||||||||
| Cash flow hedges | – | – | – | – | – | (24.3 | ) | – | (24.3 | ) | – | (24.3 | ) | |||||||||||||||||||||||||||||
| Share of other comprehensive income/(loss) of associates and joint ventures | – | – | – | – | – | (5.1 | ) | – | (5.1 | ) | – | (5.1 | ) | |||||||||||||||||||||||||||||
| Actuarial losses on defined benefit pension schemes | – | – | – | – | – | (7.2 | ) | – | (7.2 | ) | – | (7.2 | ) | |||||||||||||||||||||||||||||
| Tax relating to components of other comprehensive income | – | – | – | – | (0.8 | ) | 6.4 | – | 5.6 | – | 5.6 | |||||||||||||||||||||||||||||||
| Total comprehensive (loss)/income | – | – | – | – | (68.2 | ) | (30.2 | ) | 265.4 | 167.0 | 45.6 | 212.6 | ||||||||||||||||||||||||||||||
| Transactions with owners | ||||||||||||||||||||||||||||||||||||||||||
| Share based compensation | – | – | 4.4 | – | – | – | – | 4.4 | – | 4.4 | ||||||||||||||||||||||||||||||||
| Tax effects | – | – | 0.5 | – | – | – | – | 0.5 | – | 0.5 | ||||||||||||||||||||||||||||||||
| Shares reissued | – | 13.4 | – | – | – | – | – | 13.4 | – | 13.4 | ||||||||||||||||||||||||||||||||
| Dividends declared and paid | – | – | – | – | – | – | (42.2 | ) | (42.2 | ) | (20.0 | ) | (62.2 | ) | ||||||||||||||||||||||||||||
| Loss on reissuance of own shares | – | – | – | – | – | – | (8.6 | ) | (8.6 | ) | – | (8.6 | ) | |||||||||||||||||||||||||||||
| Total transactions with owners | – | 13.4 | 4.9 | – | – | – | (50.8 | ) | (32.5 | ) | (20.0 | ) | (52.5 | ) | ||||||||||||||||||||||||||||
| Balance at November 30, 2010 | 389.9 | (209.2 | ) | 508.8 | 110.7 | (80.2 | ) | (90.3 | ) | 572.8 | 1,202.5 | 56.8 | 1,259.3 | |||||||||||||||||||||||||||||
|
Paid in surplus This reserve represents the amount exceeding the par value on issuance of shares, and is inclusive of the Group’s activities based on its share based payments arising from the share option plans which are available to various staff members within the Group.
Equity reserves This reserve represents the equity component of the convertible loan notes (refer to Note 28 ‘Convertible loan notes’).
Translation reserve This reserve represents the exchange differences, which arise upon the translation of foreign entities’ functional currency into the Group’s reporting currency.
Other reserves Other reserves relate to:
· the net cumulative gains or losses in respect of hedging activity entered into by the Group; · actuarial gains or losses incurred by the Group’s defined benefit pension schemes; and · the Group’s share of other comprehensive losses from its associates and joint ventures. |
|
|||||||||||||||||||||||||||||||||||||||||
|
Retained earnings Luxembourg law requires that 5% of the Group’s unconsolidated net income is allocated to a legal reserve annually, prior to declaration of dividends. This requirement continues until the reserve is 10% of its stated capital, as represented by common shares, after which no further allocations are required until further issuance of shares. The legal reserve may also be satisfied by allocation of the required amount at the issuance of shares or by a transfer from paid in surplus. The legal reserve is not distributable. The legal reserve for all outstanding common shares has been satisfied and appropriate allocations are made to the legal reserve account at the time of each issuance of new shares. |
|
|||||||||||||||||||||||||||||||||||||||||
|
seabed-to-surface
|
|
85
|
Financial Review and Statements
Consolidated Cash Flow Statement
For the fiscal year ended November 30
| (in $ millions) | Notes | 2010 | 2009 | 2008 | ||||||||||||
|
Net cash generated from operating activities |
39 | 140.0 | 546.1 | 493.1 | ||||||||||||
|
Cash flows from investing activities: |
– | – | – | |||||||||||||
|
Proceeds from sale of property, plant and equipment |
0.3 | 73.6 | 12.2 | |||||||||||||
|
Purchases of property, plant and equipment |
(503.9 | ) | (171.8 | ) | (294.3 | ) | ||||||||||
|
Purchases of intangible assets |
15 | (6.2 | ) | (4.6 | ) | (0.4 | ) | |||||||||
|
Proceeds from sale of assets classified as held for sale |
2.2 | – | – | |||||||||||||
|
Dividends received from associates and joint ventures |
28.3 | 28.0 | 10.9 | |||||||||||||
|
Investment in associates and joint ventures |
17 | (14.0 | ) | (20.6 | ) | – | ||||||||||
|
Advances to associates and joint ventures |
17 | – | (5.0 | ) | (15.1 | ) | ||||||||||
|
Net cash used in investing activities |
(493.3 | ) | (100.4 | ) | (286.7 | ) | ||||||||||
|
Cash flows from financing activities: |
||||||||||||||||
|
Interest paid |
(15.8 | ) | (11.3 | ) | (11.3 | ) | ||||||||||
|
Proceeds from borrowings |
6.1 | 2.8 | 6.3 | |||||||||||||
|
Issuance cost of new borrowings |
(10.0 | ) | – | – | ||||||||||||
|
Repayments of borrowings |
(7.2 | ) | – | – | ||||||||||||
|
Own share buy-backs |
– | – | (138.3 | ) | ||||||||||||
|
Dividends paid to equity shareholders of the parent |
14 | (42.2 | ) | (40.2 | ) | (38.3 | ) | |||||||||
|
Proceeds from issuance of ordinary shares |
4.6 | 1.6 | 4.2 | |||||||||||||
|
Dividends paid to non-controlling interests |
26 | (20.0 | ) | (4.9 | ) | (8.7 | ) | |||||||||
|
Net cash used in financing activities |
(84.5 | ) | (52.0 | ) | (186.1 | ) | ||||||||||
|
Net (decrease)/increase in cash and cash equivalents |
(437.8 | ) | 393.7 | 20.3 | ||||||||||||
|
Cash and cash equivalents at beginning of year |
907.6 | 573.0 | 582.7 | |||||||||||||
|
Effect of exchange rate changes on cash and cash equivalents |
(25.4 | ) | 44.5 | (30.0 | ) | |||||||||||
|
Decrease/(increase) in cash balances classified as assets held for sale |
21 | 39.9 | (103.6 | ) | – | |||||||||||
|
Cash and cash equivalents at end of year |
484.3 | 907.6 | 573.0 | |||||||||||||
|
86 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
Financial Review and Statements
Notes to the Consolidated Financial Statements
|
1. General information Subsea 7 is a seabed-to-surface engineering, construction and services contractor for the offshore energy industry worldwide. It provides integrated services and plans, designs, and delivers complex projects in harsh and challenging environments. The address of the registered office is 412F, route d’Esch, L-2086 Luxembourg. The nature of the Group’s operations and its principal activities are set out in Note 6 ‘Segment information’.
Authorisation of financial statements Subsea 7 S.A. is a company registered in Luxembourg whose stock trades on the NASDAQ in the form of American Depository Shares and on the Oslo Stock Exchange. On February 15, 2011, Subsea 7 S.A. commenced procedures to delist from NASDAQ. For more information please refer to Note 40 ‘Post balance sheet events’. The Group financial statements were authorised for issue by the Board on February 23, 2011.
Presentation of financial statements These consolidated financial statements are presented in US Dollars ($) because that is 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’.
2. Adoption of new accounting standards (i) Effective new accounting standards The Group has adopted the following new and amended International Financial Reporting Standards and interpretations as of December 1, 2009:
a)IAS 1 Presentation of Financial Statements (revised 2007).
b)IFRS 3 Business Combinations (revised 2008) and IAS 27 Consolidated and Separate Financial Statements (revised 2008).
c) IFRS 7 Improvement Disclosures about Financial Instruments (revised 2008).
IAS 1 Presentation of Financial Statements (revised 2007) The revised standard separates owner and non-owner changes in equity. The statement of changes in equity includes non-owner changes in equity, details of transactions with owners, with non-owner changes in equity also presented in the new statement of comprehensive income. The Group has elected to present a separate income statement and statement of comprehensive income. |
||
|
IFRS 3 Business Combinations (revised 2008) and IAS 27 Consolidated and Separate Financial Statements (revised 2008) IFRS 3 (revised 2008) introduces significant changes in the accounting for business combinations. Changes affect the valuation of non-controlling interests (previously ‘minority interests’), the accounting for transaction costs, the initial recognition and subsequent measurement of contingent consideration and business combinations achieved in stages. These changes will impact the amount of goodwill recognised, the reported results in the period when an acquisition occurs and future reported results. IAS 27 (revised 2008) requires that a change in the ownership interest of a subsidiary (without a change in control) is to be accounted for as a transaction with owners in their capacity as owners. Therefore such transactions will no longer give rise to goodwill, nor will they give rise to a gain or loss in the statement of comprehensive income. Furthermore the revised standard changes the accounting for losses incurred by a partially owned subsidiary as well as the loss of control of a subsidiary. The changes in IFRS 3 (revised 2008) and IAS 27 (revised 2008) will affect future acquisitions, changes in, and loss of control of, subsidiaries and transactions with non-controlling interests.
The change in accounting policy was applied prospectively but has not materially impacted the Group in fiscal year 2010.
IFRS 7 Improvement Disclosures about Financial Instruments (revised 2008) The revised standard enhances disclosures about fair value measurement and liquidity risk. The significant change to IFRS 7 now requires instruments measured at fair value to be disclosed by the source of the inputs in determining fair value, using the following three-level hierarchy:
a)Quoted prices (unadjusted) in active markets for identical assets and liabilities (Level 1).
b)Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly (as prices) or indirectly (derived from prices) (Level 2).
c) Inputs for the asset or liability that are not based on observable market data (unobservable inputs) (Level 3).
The adoption of the following standards, amendments to standards and interpretation had no material impact on the reported income or net assets of the Group in fiscal year 2010. |
|
|
seabed-to-surface
|
|
87
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
2. Adoption of new accounting standards continued
Date applicable to the Group
| Improvements to IFRS – 2009 | Various | |||
| IAS 23 – Borrowing Costs (Revised) | December 1, 2009 | |||
| IAS 27 – Consolidated and Separate Financial Statements — Cost of an Investment in a Subsidiary, Jointly Controlled Entity or Associate (Amendments) | December 1, 2009 | |||
| IFRIC 9 – Reassessment of Embedded Derivatives and IAS 39 Financial Instruments: Recognition and Measurement — Embedded Derivatives (Amendments) | December 1, 2009 | |||
| IFRS 2 – Share-based Payment – Vesting Conditions and Cancellations (Amendments) | December 1, 2009 |
(ii) Accounting Standards and Interpretations issued but not yet effective
Relevant new standards, amendments and interpretations issued by the IASB and endorsed by the EU but not yet effective and not applied in these financial statements are as follows:
Date applicable to the Group
| IFRS 2 – Share-based Payment – Group Cash-settled Share-based Payment Transactions (Amendments) | December 1, 2010 | |||
| IAS 32 – Financial Instruments – Presentation – Classification of Rights Issue | December 1, 2010 | |||
| IFRIC 19 – Extinguishing Financial Liabilities with Equity Instruments | December 1, 2010 | |||
| Improvements to IFRS – 2010 | Various | |||
| IAS 24 – Related Party Disclosures | January 1, 2011 | |||
| IFRIC 14 – The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction | January 1, 2011 | |||
| IFRS 9 – Financial Instruments | January 1, 2013 |
Management anticipates that the adoption of these standards and interpretations in future periods will not have a material impact on the financial statements of the Group.
3. Significant accounting policies
Basis of accounting
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’). They comply with Article 4 of the EU IAS Regulation.
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 annual financial statements for the year ended November 30, 2009 except where noted and are set out below.
Basis of consolidation
The Consolidated Financial Statements incorporate the financial statements of the Company and entities controlled by the Company (its subsidiaries) up to November 30, each year. Control is assumed to exist where the Company has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities.
Subsidiaries
The results of subsidiaries acquired or disposed of are included in the Consolidated Income Statement from the effective date of acquisition or up to the effective date of disposal, as appropriate.
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.
Non-controlling interests in the net assets of subsidiaries are identified separately from the Group’s equity therein. Non-controlling interests consist of the amount of those interests at the date of the original business combination and the non-controlling shareholders’ share of changes in equity since the date of the Combination.
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 the business.
|
88 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Investments in associates and joint ventures are accounted for using the equity method. Under this method, the investment is carried in the 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 in the normal course of business, net of discounts and sales related taxes.
Revenue from construction contracts is recognised in accordance with the Group’s accounting policy on construction contracts (see below). Revenue from rendering of services is recognised when services are provided.
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 contracts Long-term contracts are accounted for using the percentage-of-completion method. Revenue and gross profit are recognised each period based upon the advancement of the work-in-progress.
The percentage-of-completion method is calculated based on the ratio of costs incurred to date to total estimated costs, taking into account the level of completion. The percentage-of-completion method requires the Group to make reliable estimates of progress toward completion of contract revenues and contract costs. Provisions for anticipated losses are made in full in the period in which they become known. In rare circumstances where percentage-of-completion based on cost is not appropriate, the physical proportion of the contract work performed is used to measure the percentage-of-completion.
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 they will be recoverable.
|
||
|
A major portion of the Group’s revenue is billed under fixed-price contracts. However, due to the nature of the services performed, variation orders and claims are commonly billed 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. Revenue resulting from claims is recognised in contract revenue only when negotiations have reached an advanced stage such that it is probable 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.
Investment income Investment income is recognised when it is probable that the economic benefits will flow to the Group and the amount of income can be measured reliably. Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset’s net carrying amount on initial recognition.
Dry-dock, mobilisation and decommissioning expenditure Dry-dock expenditure incurred to maintain a vessel’s classification is capitalised as a distinct component of the asset and amortised over the period until the next dry-docking is scheduled for the asset (usually 2 1 / 2 to 5 years). All other repair and maintenance costs are recognised in the consolidated income statement as incurred.
Mobilisation expenditures which consist of expenditure incurred prior to the deployment of a vessel are classified as prepayments and expensed over the period of the lease charter.
Decommissioning expenditures incurred to restore a leased vessel to its original or agreed condition are classified as a provision when the Group recognises it has a present obligation and a reliable estimate can be made of the amount of the obligation. When the provision is recognised the increase in the provision due to the passage of time is recognised as a finance cost. |
|
|
seabed-to-surface
|
|
89
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
3. Significant accounting policies continued
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
Finance leases are capitalised at the inception of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments, each determined at the inception of the lease. The corresponding liability to the lessor is included in the balance sheet as a finance lease obligation.
Operating lease payments are recognised as an expense in the Consolidated Income Statement on a straight-line basis over the lease term unless another systematic basis is more representative of the time pattern of the user’s benefit. 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.
Refurbishment expenditure and improvements to leased assets are expensed in the Consolidated Income Statement unless they significantly increase the value of a leased asset under which circumstance this expenditure will be capitalised 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
Rental income, excluding charges for services such as insurance and maintenance, is recognised on a straight-line basis over the lease term unless another systematic basis is more representative of the time pattern in which the benefit derived from the leased asset is diminished. Costs incurred, including depreciation, in earning the lease income are recognised as an expense. Initial direct costs incurred in negotiating and arranging an operating lease are added to the carrying amount of the leased asset and recognised as an expense over the lease term on the same basis as the lease income.
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.
Transactions in foreign currencies are initially recorded at the functional currency rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated at the rate of exchange ruling at the balance sheet date. All differences are taken to net income or loss. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value is determined.
Foreign exchange revaluations on short-term inter-company balances are recognised in the consolidated income statement. Revaluations on long-term inter-company loans are recognised in the translation reserve.
The assets and liabilities of foreign operations are translated into US Dollars at the rate of exchange ruling at the balance sheet date and their income and expenditure items are translated at the weighted average exchange rates for the year. The exchange differences arising on the translation are taken directly to a separate component of equity. On disposal of a foreign entity, the deferred cumulative amount recognised in equity relating to that particular foreign operation is recognised in the Consolidated Income Statement.
Borrowing costs
Interest-bearing loans and overdrafts are recorded at the proceeds received, net of direct issue costs plus accrued interest less any repayments, and subsequently stated at amortised cost.
Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use.
Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.
All other borrowing costs are recognised in net income or loss in the period in which they are incurred.
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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. Payments in respect of such schemes are charged to the 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, with actuarial valuations carried out at each balance sheet date. Actuarial gains and losses are recognised in full in the period in which they occur in the consolidated statement of comprehensive income.
Past service cost is recognised immediately to the extent that the benefits are already vested, or amortised on a straight-line basis over the average period until the benefits become vested.
The retirement benefit obligations recognised in the balance sheet represent the present value of the defined benefit obligations adjusted for unrecognised past service costs, reduced by the fair value of scheme assets. Any asset resulting from this calculation is limited to past service costs, plus the present value of available refunds and reductions in future contributions to the scheme.
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 financial statements at their actuarial valuation.
Taxation Income tax The tax expense represents the sum of the tax currently payable and deferred tax.
The tax currently payable is based on the taxable net income for the year. Taxable net income differs from net income as reported in the consolidated income statement because it excludes items of income or expense that are taxable or deductible in other years 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 by the balance sheet date. Current tax relating to items recognised directly in equity is recognised in equity and not in net income or loss.
Income tax assets or liabilities are representative of respective taxes being owed or owing to the local tax authorities and additional tax provisions which have been recognised in the computation of the Group’s tax position. Full details of these positions are set out in Note 11 ‘Taxation’. |
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Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable net income, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable net incomes 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 affects neither the taxable net income nor the accounting net income. A deferred tax liability is not recognised on taxable temporary differences associated with investments in subsidiaries, branches and associates, and interest in joint ventures except to the extent that both the investor is able to control the timing of 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 and reduced to the extent that it is no longer probable that sufficient taxable net 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 substantially 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 equity, in which case the deferred tax is also dealt with in equity.
Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current income 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.
Deferred tax is recognised on unremitted earnings to the extent that profits will be distributed in the foreseeable future.
Other taxes Other taxes which include irrecoverable value added tax, sales tax and custom duties represent the amounts receivable or payable to local tax authorities in the countries where the Group operates and are included within net operating income. |
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Financial Review and Statements
Notes to the Consolidated Financial Statements continued
3. Significant accounting policies continued
Property, plant and equipment
Property, plant and equipment are stated at cost less accumulated depreciation and accumulated impairment losses. Such cost includes major spare parts acquired and held for future use on a ship or in a plant.
Assets under construction are carried at cost, less any recognised impairment loss. Cost includes external professional fees and borrowing costs capitalised in accordance with the Group’s accounting policy. Depreciation of these assets commences when the assets are ready for their intended use.
Depreciation is calculated on a straight-line basis over the useful life of the asset as follows:
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· Construction support vessels |
10 to 25 years | |
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· Operating equipment |
3 to 10 years | |
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· Buildings |
20 to 33 years | |
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· Other assets |
3 to 7 years | |
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· Land is not depreciated. |
Construction support vessels are depreciated to their estimated residual value. Costs for fitting out vessels are capitalised and amortised over a period equal to the remaining useful life of the related equipment.
Residual values, useful lives and methods of depreciation are reviewed at least annually, and adjusted if appropriate.
The gains or losses arising on disposal or retirement of assets are determined as the difference between any sales proceeds and the carrying amount of the asset. These are reflected in the income statement in the year that the asset is disposed of or retired.
Assets classified as held for sale
The Group classifies assets and disposal groups as being held for sale when the following criteria are met:
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· management has committed to a plan to sell the asset or disposal group; |
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· the asset or disposal group is available for immediate sale in its present condition; |
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· an active programme to locate a buyer and other actions required to complete the plan to sell the asset or disposal group has been initiated; |
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· the sale of the asset or disposal group is highly probable; |
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· transfer of the asset or disposal group is expected to qualify for recognition as a completed sale, within one year; |
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· the asset or disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value; and |
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· actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. |
Assets or disposal groups classified as held for sale are measured at the lower of their carrying value or fair value less costs of disposal. Non-current assets are not depreciated once they meet the criteria to be held for sale and are shown separately on the face of the consolidated balance sheet.
Discontinued operations
The Group classifies an asset or disposal group as a discontinued operation when:
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· it has been either disposed of or classified as held for sale; or |
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· it represents a single major line of business or geographical area of operation or is part of a coordinated plan for disposal. |
In the period an asset or disposal group has been disposed of, or is classified as held for sale, the results of the operation are reported as discontinued operations in the current and prior periods.
Tendering and bid costs
Costs incurred in the tendering process are expensed as incurred, except those costs which are incurred once the Group has achieved ‘preferred bidder’ status, when the project is considered highly probable of proceeding and a future benefit likely to occur. Subsequent costs are accumulated until the project is awarded, at which point they are included in project costs for net income recognition purposes.
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 profit or loss as incurred.
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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 (see below). 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(2008) are recognised at their fair value at 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’; and
• 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. Those provisional amounts are adjusted during the measurement period (see below), or additional assets or liabilities are recognised, to reflect new information obtained about 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 about 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 profit or loss as a bargain purchase gain.
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 date of initial acquisition. The cost of intangible assets acquired in a business combination is determined as their fair value at the date of their acquisition. Following initial recognition, intangible assets are reflected at cost less amortisation and impairment losses. Except for capitalised development costs, internally generated intangible assets are not capitalised. Development expenditure which does not meet the criteria for capitalisation is reflected in the Consolidated Income Statement in the year in which the expenditure is incurred.
Intangible assets with finite lives are amortised over their useful economic life and are assessed for impairment at least annually or 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 each financial year end as a minimum. 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:
• the technical feasibility of completing the asset such that it will be available for use or sale;
• the intention to complete the asset and use or sell it;
• the ability to use or sell the asset;
• how the asset will generate probable future economic benefits;
• the availability of resources to complete the asset; and
• the ability to measure the expenditure reliably during development. |
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Financial Review and Statements
Notes to the Consolidated Financial Statements continued
3. Significant accounting policies continued
Following initial recognition of the development expenditure as an internally generated intangible asset, the asset is reported at cost less any accumulated amortisation and impairment losses.
Amortisation of the asset begins when development is complete and the asset is available for use. It is amortised over the period of expected future benefit. During the period of development, the asset is tested for impairment at least annually or when indicators of impairment exist.
Software
Software is measured initially at purchase cost and amortised on a straight-line basis over its useful life of three years. The charge is included in administrative expenses in the consolidated income statement.
Lease access premiums
Lease access premiums are measured initially at cost and amortised on a straight-line basis over their useful life of 18 years. The charge is included in administrative expenses in the consolidated income statement.
Other
Other intangible assets are recognised at cost and have an indefinite useful life. The asset is tested annually for impairment or when there are indicators of impairment and carried at cost less any such charges.
Impairment of non-financial assets
At each balance sheet date the Group assesses whether there is an indication that an asset 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 to sell 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 belongs.
Where the carrying amount of an asset exceeds its recoverable value, the asset is considered impaired and is written down to its recoverable value. 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 the risks specific to the asset. In determining fair value less costs to sell, an appropriate valuation model is used.
Impairment losses of continuing operations 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 balance sheet date as to whether there is any indication that previously recognised impairment losses may no longer exist or may have decreased. If such an indication exists the Group makes an estimate of recoverable amount. A previously recognised impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss 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 loss been recognised for the asset in prior years. Such reversal is recognised in the Consolidated Income Statement.
The following criteria are also applied in assessing impairment of specific assets:
Goodwill
For the purpose of impairment testing, goodwill is allocated to each of the Group’s cash-generating units expected to benefit from the synergies of the Combination. Cash-generating units to which goodwill has been allocated are tested for impairment annually, or more frequently when there is an indication that the unit may be impaired. If the recoverable amount of the cash-generating unit is less than the carrying amount of the unit, the impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the unit and then to the other assets of the unit pro-rata on the basis of the carrying amount of each asset in the unit. An impairment loss recognised for goodwill is not reversed in a subsequent period.
On disposal of a subsidiary, the attributable amount of goodwill is included in the determination of the profit or loss on disposal.
Associates and joint ventures
At each balance sheet 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 amount is recognised in the Consolidated Income Statement.
Inventories
Inventories comprise materials, consumables and spares and are valued at the lower of cost and net realisable value. Costs incurred in bringing each product to its present location and condition are accounted for using the weighted average cost basis. Net realisable value is the estimated selling price in the ordinary course of business, less estimated costs of completion and estimated costs necessary to conclude the sale.
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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Financial instruments Overview A financial instrument is any contract that gives rise to a financial asset in one entity and a financial liability or equity instrument in another entity.
Financial assets are classified into the following categories:
• financial assets at ‘fair value through the profit or loss’ (FVTPL);
• ‘held to maturity’ investments;
• ‘available for sale’ (AFS) financial assets; and
• ‘loans and receivables’.
The classification depends on the nature and purpose of the financial assets and is determined at the time of initial recognition.
Financial liabilities and equity instruments are classified as either FVTPL or ‘other financial liabilities’ according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities and is recorded as the proceeds received, net of direct issue costs.
Initial recognition All financial assets are recognised in the Group’s balance sheet and subsequently derecognised on the trade date where the purchase or sale of the financial asset is under a contract whose terms require delivery of the investment within the timeframe established by the market concerned.
Financial liabilities are recognised in the Group’s balance sheet when the Group becomes a party to the contractual provisions of the instrument.
Initial measurement Financial instruments are initially measured at cost plus transaction costs, with the exception of assets classified at FVTPL which are measured at fair value. Changes in the fair value of investments classified at FVTPL are included in the Consolidated Income Statement. Changes in the fair value of investments classified as AFS are recognised directly in equity, until the investment is disposed of or is determined to be impaired, at which time the cumulative gains or losses previously recognised in equity are included in the Consolidated Income Statement for the period. Investment income on investments classified at FVTPL and AFS is recognised in the Consolidated Income Statement as it accrues.
Subsequent measurement After initial recognition, the fair values of financial instruments are measured on bid prices for assets held and offer prices for issued liabilities based on values quoted in active markets.
Impairment At each balance sheet date the Group assesses whether any indications exist that a financial asset or group of financial assets is impaired.
Impairment losses are recorded if there is objective evidence of impairment as a result of one or more events that occurred after the initial recognition of the asset (a ‘loss event’) and that loss event (or events) has an impact on the estimated future cash flows of the financial asset or group of financial assets that can be reliably estimated. The impairment is recognised through the Consolidated Income Statement.
In any subsequent period, if the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss will be reversed through the consolidated income statement if the asset is accounted for at amortised cost. Reversal of impairment of a debt instrument classified as available for sale is recognised in net income or loss while a reversal related to an equity instrument classified as available for sale is recognised in equity.
Derivatives The Group enters into both derivative financial instruments (derivatives) and non-derivative financial instruments in order to manage its foreign currency exposures. The principal derivatives used are forward foreign currency contracts.
All derivative transactions are undertaken and maintained in order to manage the interest and foreign currency risks associated with the Group’s underlying business activities and the financing of those activities.
Derivatives embedded in other financial instruments or other host contracts are treated as separate derivatives 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 in the Consolidated Balance Sheet with the host contract.
Changes in the fair value of derivatives that do not qualify for hedge accounting are recognised in the consolidated income statement within ‘other gains and losses’. Changes in the fair value of embedded derivatives are recognised in the Consolidated Income Statement within net operating income. |
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seabed-to-surface
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95
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Financial Review and Statements
Notes to the Consolidated Financial Statements continued
3. Significant accounting policies continued
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. Amounts deferred in equity in respect of cash flow hedges are subsequently recognised in the Consolidated Income Statement in the same period in which the hedged item affects net income. Where a non-financial asset or a non-financial liability results from a forecasted transaction or firm commitment being hedged, the amount deferred in equity is included in the initial measurement of that non-monetary asset or liability.
Hedge accounting is discontinued when the hedging instrument expires or is sold, terminated, exercised, or no longer qualifies for hedge accounting. 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. If a forecasted hedged transaction is no longer expected to occur, the net cumulative gains or losses recognised in equity are transferred to the Consolidated Income Statement immediately.
Restricted cash balances
Restricted cash balances comprise funds held in a separate bank account which will be used to settle accrued taxation liabilities, and deposits made by the Group as security for certain third-party obligations. Cash balances that are subject to restrictions that expire after more than one year are classified under non-current assets.
Cash and cash equivalents
Cash and cash equivalents in the 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. Bank overdrafts are included within current borrowings.
Trade receivables and other receivables
The Group assesses at each balance sheet date whether any indications 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 will not be able to collect all of the amounts due under the original terms of the invoice. The carrying amount of the receivable is reduced with the loss recognised in other operating income. Impaired debts are derecognised when they are assessed as uncollectible.
Loans receivable and other receivables are carried at amortised cost using the effective interest rate method. Interest income, together with gains and losses when the loans and receivables are derecognised or impaired, is recognised in the consolidated income statement.
Convertible loan notes
The component of the convertible loan notes issued by the Group that exhibits characteristics of a liability is recognised as a liability in the balance sheet, net of transaction costs. On issuance of the convertible loan notes, the fair value of the liability component is determined using a market rate for an equivalent non-convertible loan note; and this amount is classified as a financial liability measured at amortised cost until it is extinguished on conversion or redemption.
The fair value of the instrument, which is generally the net proceeds less the fair value of the liability, is allocated to the conversion option which is recognised and included in shareholders’ equity, net of transaction costs. The carrying value of the conversion option is not remeasured.
Transaction costs are apportioned between the liability and equity components of the convertible loan notes based on the allocation of proceeds to the liability and equity components when the instruments are first recognised.
Treasury shares
Own equity instruments which are reacquired (treasury shares) are deducted from equity at cost. No gains or losses are recognised in the consolidated income statement on the purchase, sale, issue or cancellation of the Group’s own equity instruments.
Financial guarantee liabilities
Financial guarantee liabilities issued by the Group are those contracts that require a payment to be made to reimburse the holder for a loss it incurs because the specified debtor (generally an associate or joint venture of the Group) fails to fulfil a commitment in accordance with the terms of a debt instrument.
Initially a financial guarantee contract is recognised as a liability at fair value, adjusted for transaction costs that are directly attributable to the issue of the guarantee. Subsequently, the liability is measured at the higher of the best estimate of the expenditure required to settle the present obligation at the balance sheet date, and the amount initially recognised.
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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Provisions Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past 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. 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 rate 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.
Restructuring charges The Group accounts for restructuring charges, including statutory legal requirements to pay redundancy costs, when they can be reliably measured and there is a legal or constructive obligation. The Group recognises a provision for redundancy 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.
Legal claims In the ordinary course of business the Group is subject to various claims, suits and complaints. In consultation with internal and external advisers, management will provide for a loss in the financial statements if it is probable that a liability has been incurred at the date of the consolidated financial statements and the amount of the loss can be reliably estimated.
Share-based payments Certain employees of the Group receive part of their remuneration in the form of share options, shares and cash bonuses based on 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 equity-settled transactions at each balance sheet date, until the vesting date, reflects the extent to which the vesting period has expired and the Group’s best estimate of the number of equity instruments that will ultimately vest. The cumulative expense also includes the estimated future charge to be borne by the employer entity in respect of social security contributions, based on the intrinsic unrealised value of the stock option using the stock 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.
Cash-settled share-based payments are measured at fair value on the date on which the scheme has been granted. The cost is recognised and remeasured at the balance sheet date until the liability is settled and the date of settlement with any changes in fair value recognised in the consolidated income statement.
Earnings per share Earnings per share is computed using the weighted average number of common shares and common share equivalents outstanding during each period. The dilutive effect of outstanding options and performance shares is reflected as additional share dilution in the computation of diluted earnings per share. The convertible notes are included in the diluted earnings per share 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 about 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 in the period in which the estimate is revised if the revision affects only that period or in the period of revision and future periods if the revision affects both current and future periods.
Revenue recognition on long-term contracts Substantially all of the Group’s projects are accounted for using the percentage-of-completion method, which is standard for the Group’s industry. Contract revenues and total cost estimates are reviewed and revised periodically as work progresses. Adjustments based on the percentage-of-completion method are reflected in contract revenues in the reporting period. 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 against current earnings; amounts in prior periods are not restated. Such a charge or credit may be significant depending on the size of the project or 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 financial statements, which may result in an adjustment of the financial statements based on events, favourable or unfavourable occurring after the balance sheet date. However, if a condition arises after the balance sheet date which is of a non-adjusting nature the results recognised in the financial statements will not be adjusted. |
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Financial Review and Statements
Notes to the Consolidated Financial Statements continued
4. Critical accounting judgements and key sources of estimation uncertainty continued
The percentage-of-completion method requires the Group to make reliable estimates of progress toward completion of contracts and contract revenues and contract costs. The Group believes it assesses its business risks in a manner that allows it to evaluate the outcome of projects for purposes of making reliable estimates. Often the outcome of a project is more favourable than originally expected, due to increases in scope or efficiencies achieved during execution. The Group’s business risks have involved, and will continue to involve, unforeseen difficulties including weather, economic instability, labour strikes, localised civil unrest, and engineering and logistical changes, particularly in major projects. The Group does not believe its business is subject to the types of inherent hazards, conditions or external factors that raise questions about contract estimates and about the ability of either the contractor or client to perform its obligations that would indicate that the use of the percentage-of-completion method is not preferable.
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 can be dependent on the outcome of negotiations. Therefore, claims are recognised in contract revenue only when negotiations have reached an advanced stage such that it is probable that the client will accept the claim and the amount can be measured reliably.
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, particularly when it has been upgraded.
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 use their judgement in determining asset utilisation, profitability, remaining life, and the discount rate when performing the calculation.
Impairment of investments in and advances to associates and joint ventures
Investments in associates and joint ventures are reviewed periodically to assess whether there is objective evidence that the carrying value of the investment is impaired. In making this assessment, the Group considers whether or not they are able to recover the carrying value of the investment.
A provision is made against non-collectibility of loans and advances made to associates and joint ventures when there is objective evidence that the Group will be unable to collect all amounts due according to the contractual terms of the agreement.
Recognition of provisions and disclosure of contingent liabilities
The Group is subject to various claims, suits and complaints involving, clients, subcontractors, employees, and tax authorities and others in the ordinary course of business. In consultation with internal and external advisers, management will recognise a provision if information available prior to issuance of the financial statements indicates that it is probable that a liability had been incurred at the balance sheet date, and the amount of the loss can be reasonably estimated. Contingent liabilities for which a possible obligation exists are disclosed but not recognised.
Where the provision relates to a large population of items, the use of an ‘expected value’ is appropriate to arrive at a best estimate of the obligation. The expected value takes account of all possible outcomes, using probabilities to weight the outcomes. Where there is a continuous range of possible outcomes, and each point in that range is as likely as any other, the mid-point of the range is used.
Taxation
The Group is subject to taxation in numerous jurisdictions and significant judgement is required in calculating the consolidated tax provision. There are many 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. Where the final tax outcome of these matters is different from the amounts that were initially recorded, the difference will impact the tax charge in the period in which the outcome is determined. Full details of all judgements and other issues considered are set out in Note 11 ‘Taxation’.
|
98 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Fair value of derivatives and other financial instruments As described in Note 34 ‘Financial instruments’, Management use their judgement in selecting an appropriate valuation technique for financial instruments not quoted on an active market. Valuation techniques commonly used by market practitioners are applied. For derivative financial instruments, assumptions are made based on quoted market rates adjusted for specific features of the instrument. Other financial instruments are valued using a discounted cash flow analysis based on assumptions supported, where possible, by observable market prices or rates. Details of the assumptions used and of the results of sensitivity analyses regarding these assumptions are provided in Note 34 ‘Financial instruments’.
Share based payments In determining the fair value and associated cost of share based payments and other employee benefit schemes, Management use their judgement in selecting an appropriate valuation technique and assumptions regarding, amongst others, future share price volatility, risk of forfeiture and employee compensation adjustments. The final cost of each award will be determined upon vesting of the various schemes, at which point the appropriate adjustments will be made. Details of the schemes are provided in Note 36 ‘Share based payments’.
Defined benefit pension scheme valuations Management utilises the services of various qualified actuaries to calculate an estimate of the defined benefit pension liability for the funded and unfunded schemes. Details of the financial and actuarial assumptions used by the qualified actuaries in determining the pension liability are provided in Note 37 ‘Retirement benefit obligations’.
5. Revenue An analysis of the Group’s revenue is as follows:
|
|
|||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 |
|
||||||||||||
|
Continuing operations: |
||||||||||||||||
|
Lump-sum contracts |
1,530.9 | 1,815.5 | 2,228.8 | |||||||||||||
|
Day-rate contracts |
838.1 | 393.3 | 293.6 | |||||||||||||
|
Continuing operations revenue |
2,369.0 | 2,208.8 | 2,522.4 | |||||||||||||
|
Net other operating income |
– | – | 3.4 | |||||||||||||
|
Investment income from bank deposits |
9.8 | 6.4 | 17.9 | |||||||||||||
|
Other revenue |
9.8 | 6.4 | 21.3 | |||||||||||||
|
Discontinued operations: |
||||||||||||||||
|
Lump-sum contracts (see Note 12) |
83.4 | 114.8 | 281.8 | |||||||||||||
|
Discontinued operations revenue |
83.4 | 114.8 | 281.8 | |||||||||||||
|
Total revenue |
2,462.2 | 2,330.0 | 2,825.5 | |||||||||||||
|
A portion of the Group’s revenue is denominated in foreign currencies and is cash flow hedged. The amounts disclosed above for revenue include the recycling of the effective amount of the foreign currency derivatives that are used to hedge foreign currency revenue (refer to Note 34 ‘Financial instruments’).
6. Segment information For management and reporting purposes, the Group was organised into five geographical regions or divisions which were representative of its principal activities. In addition there was a Corporate segment which managed activities that served more than one segment. After completion of the acquisition of Subsea 7 Inc. on January 7, 2011, these segments have changed. For a description of the Group’s segments after the acquisition, refer to Note 40 ‘Post balance sheet events’.
The chief operating decision maker was the Chief Executive Officer of the Group. He was assisted by the Chief Operating Officer, the Vice Presidents of each geographical segment and other members of the Corporate Management Team. The Vice Presidents were responsible for managing all aspects of the projects within the geographical region, from initial tender to completion. Where projects were serviced by more than one segment, the costs and associated revenues were allocated to segments on the basis of the work actually performed by each segment.
The accounting policies of the reportable segments were the same as the Group’s accounting policies described in Note 3 ‘Significant accounting policies’. Segment profit represents net operating income/(loss) earned by each segment and included the Group’s share of net income of associates and joint ventures and central administration costs, including directors’ salaries. |
|
|||||||||||||||
|
seabed-to-surface
|
|
99
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
6. Segment information continued
Business segments prior to the acquisition based on geographical segments or divisions are defined below:
Territory 1
Acergy Northern Europe and Canada (NEC)
Included activities in Northern Europe and Eastern Canada, and had offices in Aberdeen, Scotland, United Kingdom; Stavanger, Norway; St Johns, Canada; and Moscow, Russia.
Acergy Asia and Middle East (AME)
This segment included activities in Asia Pacific, India, and the Middle East and had its offices in Singapore, Beijing, China and Perth, Australia. It also included the joint venture SapuraAcergy.
Territory 2
Acergy Africa and Mediterranean (AFMED)
Included activities in Africa and Mediterranean and had its office in Suresnes, France and also operated fabrication yards in Nigeria, Angola and Gabon. It also included the associates Dalia and Oceon.
Acergy North America and Mexico (NAMEX)
Included activities in the US, Mexico, Central America and Western Canada, and had its office in Houston, Texas, US.
Acergy South America (SAM)
This segment included activities in South America and the islands of the southern Atlantic Ocean and had its office in Rio de Janeiro, Brazil and operations in Macae, Brazil.
Corporate
Acergy Corporate (CORP)
This segment included activities that served more than one segment. These included: marine assets which have global mobility including construction and flow line lay support ships, ROVs and other mobile assets that are not allocated to any one segment; management of offshore personnel; captive insurance activities; management and corporate services provided for the benefit of all of the Group’s businesses. It also included the joint ventures NKT Flexibles and SHL.
The Group’s discontinued operations have been shown separately from the reportable geographical business segments.
Additional information is shown in Note 12 ‘Discontinued operations’ and Note 21 ‘Assets classified as held for sale’.
|
100 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
Summarised financial information concerning each reportable geographical business segment is as follows:
For the fiscal year ended November 30, 2010
| TERRITORY 1 | TERRITORY 2 | |||||||||||||||||||||||||||||||||||||
| Total | ||||||||||||||||||||||||||||||||||||||
| continuing | Discontinued | |||||||||||||||||||||||||||||||||||||
|
(in $ millions) |
NEC | AME | AFMED | NAMEX | SAM | CORP | operations | operations | (e) | |||||||||||||||||||||||||||||
|
Revenue ( a,b,c ) |
568.1 | 179.8 | 1,361.4 | 34.6 | 214.3 | 10.8 | 2,369.0 | 83.4 | ||||||||||||||||||||||||||||||
|
Operating expenses (d) |
(423.2 | ) | (99.1 | ) | (954.1 | ) | (22.6 | ) | (177.2 | ) | (24.8 | ) | (1,701.0 | ) | (23.7 | ) | ||||||||||||||||||||||
|
Share of net income of associates and joint ventures |
– | 28.5 | 1.8 | – | – | 44.5 | 74.8 | – | ||||||||||||||||||||||||||||||
|
Depreciation, mobilisation and amortisation expenses |
(15.5 | ) | (1.3 | ) | (34.0 | ) | – | (33.5 | ) | (35.1 | ) | (119.4 | ) | – | ||||||||||||||||||||||||
|
Reversal of impairment/(impairment) of intangible assets |
– | – | 1.9 | – | – | (7.0 | ) | (5.1 | ) | – | ||||||||||||||||||||||||||||
|
Reversal of impairment of property, plant and equipment (f) |
– | – | 1.3 | – | – | – | 1.3 | – | ||||||||||||||||||||||||||||||
|
Research and development expense |
– | – | – | – | – | (5.2 | ) | (5.2 | ) | – | ||||||||||||||||||||||||||||
|
Net operating income/(loss) from operations |
83.6 | 83.5 | 307.7 | (0.4 | ) | 8.4 | (46.7 | ) | 436.1 | 59.7 | ||||||||||||||||||||||||||||
|
Investment income from bank deposits |
9.8 | – | ||||||||||||||||||||||||||||||||||||
|
Other gains and losses |
(18.0 | ) | (0.2 | ) | ||||||||||||||||||||||||||||||||||
|
Finance costs |
(28.7 | ) | – | |||||||||||||||||||||||||||||||||||
|
Income before taxes |
399.2 | 59.5 | ||||||||||||||||||||||||||||||||||||
|
(a) |
Revenue represents only external revenues earned by each segment. An analysis of inter-segment revenues has not been included as this information is not regularly provided to the chief operating decision maker. |
|
||||||||||||||||||||||||||||||||||||
|
(b) |
Two clients in the year ended November 30, 2010 accounted for more than 10% of the Group’s revenue from continuing operations. The revenue from these clients was $428.1 million and $409.6 million and was attributable to Acergy AFMED, Acergy NEC, Acergy NAMEX and Acergy AME (refer to Note 34 ‘Financial Instruments’). |
|
||||||||||||||||||||||||||||||||||||
|
(c) |
Revenue consists of $1,238.6 million for SURF activity, $887.8 million of Conventional activity, and $242.6 million of IMR/Survey activity. |
|
||||||||||||||||||||||||||||||||||||
|
(d) |
The amount for Acergy NAMEX includes inter-regional expenditure sharing arrangements. |
|
||||||||||||||||||||||||||||||||||||
|
(e) |
See Note 12 ‘Discontinued operations’ for further information. |
|
||||||||||||||||||||||||||||||||||||
|
(f) |
Sonamet reversal of Impairment raised in fiscal year 2009. |
|
||||||||||||||||||||||||||||||||||||
|
For the fiscal year ended November 30, 2009 |
|
|||||||||||||||||||||||||||||||||||||
| TERRITORY 1 |
TERRITORY 2 |
|
||||||||||||||||||||||||||||||||||||
|
(in $ millions) |
NEC | AME | AFMED | NAMEX | SAM | CORP |
|
Total
continuing operations |
|
|
Discontinued
operations |
(e) |
||||||||||||||||||||||||||
|
Revenue ( a,b,c ) |
648.8 | 206.0 | 999.7 | 57.8 | 288.8 | 7.7 | 2,208.8 | 114.8 | ||||||||||||||||||||||||||||||
|
Operating expenses (d) |
(519.7 | ) | (156.9 | ) | (746.5 | ) | (19.1 | ) | (224.7 | ) | (16.9 | ) | (1,683.8 | ) | (99.3 | ) | ||||||||||||||||||||||
|
Share of net income of associates and joint ventures |
0.7 | 9.7 | 1.9 | – | – | 36.7 | 49.0 | – | ||||||||||||||||||||||||||||||
|
Depreciation, mobilisation and amortisation expenses |
(12.8 | ) | (10.5 | ) | (38.5 | ) | (6.2 | ) | (22.3 | ) | (40.7 | ) | (131.0 | ) | (0.1 | ) | ||||||||||||||||||||||
|
Impairment of property, plant and equipment |
– | – | (2.0 | ) | – | – | (9.8 | ) | (11.8 | ) | (1.0 | ) | ||||||||||||||||||||||||||
|
Impairment of intangible assets |
– | – | (2.8 | ) | – | – | – | (2.8 | ) | – | ||||||||||||||||||||||||||||
|
Research and development expense |
– | – | – | – | – | (6.2 | ) | (6.2 | ) | – | ||||||||||||||||||||||||||||
|
Net operating income from operations |
67.4 | 37.8 | 171.3 | 26.0 | 37.5 | 2.7 | 342.7 | 15.5 | ||||||||||||||||||||||||||||||
|
Investment income from bank deposits |
6.4 | |||||||||||||||||||||||||||||||||||||
|
Other gains and losses |
43.6 | (1.6 | ) | |||||||||||||||||||||||||||||||||||
|
Finance costs |
(31.4 | ) | ||||||||||||||||||||||||||||||||||||
|
Income before taxes |
361.3 | 13.9 | ||||||||||||||||||||||||||||||||||||
|
(a) |
Revenue represents only external revenues earned by each segment. An analysis of inter-segment revenues has not been included as this information is not regularly provided to the chief operating decision maker. |
|
||||||||||||||||||||||||||||||||||||
|
(b) |
Two clients in the year ended November 30, 2009 accounted for more than 10% of the Group’s revenue from continuing operations. The revenue from these clients was $550.2 million and $325.4 million and was attributable to Acergy AFMED and Acergy NEC (refer to Note 34 ‘Financial Instruments’). |
|
||||||||||||||||||||||||||||||||||||
|
(c) |
Revenue consists of $1,615.8 million for SURF activity, $388.2 million of Conventional activity, and $204.8 million of IMR/Survey activity. |
|
||||||||||||||||||||||||||||||||||||
|
(d) |
The amount for Acergy NAMEX includes inter-regional expenditure sharing arrangements. |
|
||||||||||||||||||||||||||||||||||||
|
(e) |
See Note 12 ‘Discontinued operations’ for further information. |
|
||||||||||||||||||||||||||||||||||||
|
seabed-to-surface
|
|
101
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
6. Segment information continued
For the fiscal year ended November 30, 2008
| TERRITORY 1 |
TERRITORY 2 |
|||||||||||||||||||||||||||||||
| Total | ||||||||||||||||||||||||||||||||
| continuing | Discontinued | |||||||||||||||||||||||||||||||
|
(in $ millions) |
NEC | AME | AFMED | NAMEX | SAM | CORP | operations | operations | (e) | |||||||||||||||||||||||
|
Revenue ( a,b,c ) |
843.1 | 180.8 | 1,175.9 | 4.4 | 320.1 | (1.9 | ) | 2,522.4 | 281.8 | |||||||||||||||||||||||
| Operating expenses (d) | (574.5 | ) | (129.0 | ) | (897.1 | ) | 17.2 | (268.9 | ) | (21.9 | ) | (1,874.2 | ) | (304.4 | ) | |||||||||||||||||
| Share of net income of associates and joint ventures | 3.5 | (15.4 | ) | (0.3 | ) | – | – | 75.2 | 63.0 | – | ||||||||||||||||||||||
| Depreciation, mobilisation and amortisation expenses | (10.2 | ) | (6.9 | ) | (31.6 | ) | – | (19.2 | ) | (42.5 | ) | (110.4 | ) | (8.0 | ) | |||||||||||||||||
| Impairment of property, plant and equipment | (1.8 | ) | – | – | – | – | – | (1.8 | ) | (1.0 | ) | |||||||||||||||||||||
| Reversal of impairment of property, plant and equipment | – | – | – | – | – | – | – | 14.3 | ||||||||||||||||||||||||
| Research and development expense | – | – | – | – | – | (6.8 | ) | (6.8 | ) | – | ||||||||||||||||||||||
| Net operating income/(loss) from operations | 192.0 | 14.4 | 183.7 | 10.5 | 22.6 | 37.6 | 460.8 | (22.5 | ) | |||||||||||||||||||||||
| Investment income from bank deposits | 17.9 | – | ||||||||||||||||||||||||||||||
| Other gains and losses | 44.1 | (1.1 | ) | |||||||||||||||||||||||||||||
| Finance costs | (30.5 | ) | (1.0 | ) | ||||||||||||||||||||||||||||
| Income before taxes | 492.3 | (24.6 | ) | |||||||||||||||||||||||||||||
| (a) | Revenue represents only external revenues earned by each segment. An analysis of inter-segment revenues has not been included as this information is not regularly provided to the chief operating decision maker. |
| (b) | Two clients in the year ended November 30, 2008 accounted for more than 10% of the Group’s revenue from continuing operations. The revenue from these clients was $709.9 million and $299.6 million and was attributable to Acergy AFMED and Acergy NEC. |
| (c) | Revenue consists of $1,832.4 million for SURF activity, $442.0 million of Conventional activity, and $248.0 million of IMR/Survey activity. |
| (d) | The amount for Acergy NAMEX includes inter-regional expenditure sharing arrangements. |
| (e) | See Note 12 ‘Discontinued operations’ for further information. |
The disclosures required by IFRS 8 paragraph 33 in respect of geographic information are not reported here since the necessary information is not available and the cost to develop it would be excessive.
7. Net operating income
Net operating income from continuing operations includes:
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||
|
Research and development costs recognised as an expense |
5.2 | 6.2 | 6.8 | |||||||||
|
Employee benefits |
664.6 | 669.5 | 799.6 | |||||||||
|
Pension settlement |
– | – | (33.3 | ) | ||||||||
|
8. Auditors’ remuneration |
||||||||||||
|
The following table sets forth aggregate fees billed to the Group by the principal accounting firm, Deloitte S.A. and other member firms of Deloitte Touche Tohmatsu Limited (Deloitte), in each of the fiscal years 2010, 2009 and 2008: |
|
|||||||||||
|
For the fiscal year (in $ millions) |
2010 | 2009 | 2008 | |||||||||
|
Audit fees |
3.4 | 3.7 | 4.1 | |||||||||
|
Audit-related fees |
0.4 | 0.5 | 0.9 | |||||||||
|
Tax fees |
2.1 | 1.4 | 2.1 | |||||||||
|
Other fees |
0.4 | – | – | |||||||||
|
Total |
6.3 | 5.6 | 7.1 | |||||||||
Audit fees
Audit fees principally constitute fees billed for professional services rendered by Deloitte for the audit of the consolidated and individual statutory financial statements for each of fiscal years 2010, 2009 and 2008. The amounts include fees associated with attestation in respect of the Sarbanes-Oxley Act of 2002.
Audit-related fees
Audit-related fees constitute fees billed for assurance and related services by Deloitte that are reasonably related to the performance of the audit of the consolidated financial statements, other than the services reported above under ‘Audit fees’, in each of fiscal years 2010, 2009 and 2008. In fiscal year 2008, audit-related fees principally consisted of fees relating to IFRS transition advice and audits, and internal control advice, and the limited scope procedures performed in respect of the Group’s quarterly financial results announcements during fiscal years 2010, 2009 and 2008.
|
102 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
Tax fees Tax fees constitute fees billed for professional services rendered by Deloitte for tax compliance and tax advice in each of fiscal years 2010, 2009 and 2008. In fiscal years 2010, 2009 and 2008, tax advisory fees principally consisted of services provided to UK, Dutch, Singaporean, US and Brazilian subsidiaries, in addition to services related to consolidated Group matters.
Other fees Other fees constitute fees billed for Combination transaction services rendered by Deloitte in fiscal year 2010.
Audit Committee Pre-Approval Policy and Procedures The Audit Committee adopted a policy on November 18, 2002 to pre-approve all audit and non-audit services provided by the independent public accountants provided to the Group or its subsidiaries prior to the engagement of the independent public accountants with respect to such services. Prior to engagement, the Audit Committee pre-approves the independent public accountants’ services within each category. The Audit Committee may delegate one or more members who are independent directors of the Board to pre-approve the engagement of the independent public accountants. If one or more members of the Audit Committee delegated to do so have pre-approved the engagement of the independent public accountants, the approval of this engagement will be placed on the agenda of the next Audit Committee meeting for review and ratification. The Audit Committee pre-approved all audit and non-audit services provided to the Group and to its subsidiaries during the periods listed above. |
|
|||||||||||||||
|
9. Other gains and losses |
||||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||||||
|
Gains on disposal of property, plant and equipment |
0.2 | 0.4 | 5.4 | |||||||||||||
|
Net foreign currency exchange (losses)/gains |
(18.2 | ) | 43.2 | 39.0 | ||||||||||||
|
Reclassification of foreign currency adjustments upon liquidation of entities |
– | – | (0.3 | ) | ||||||||||||
|
Total |
(18.0 | ) | 43.6 | 44.1 | ||||||||||||
|
10. Finance costs |
||||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||||||
|
Interest on borrowings |
11.0 | 4.7 | 4.2 | |||||||||||||
|
Interest on convertible loan notes (see Note 28) |
31.0 | 29.5 | 28.4 | |||||||||||||
|
(Reversing)/unwinding of discount on provisions (see Note 31) |
(0.3 | ) | 0.3 | 0.2 | ||||||||||||
|
Total borrowing costs |
41.7 | 34.5 | 32.8 |
|
|
|
||||||||||
|
Less: amounts included in the cost of qualifying assets |
(13.7 | ) | (0.5 | ) | (3.0 | ) | ||||||||||
| 28.0 | 34.0 | 29.8 | ||||||||||||||
|
Interest on tax liabilities |
0.7 | (2.6 | ) | 0.7 | ||||||||||||
|
Total |
28.7 | 31.4 | 30.5 | |||||||||||||
|
$11.9 million of borrowing costs included in the cost of qualifying assets during the year arose on the general borrowing pool and is calculated by applying a capitalisation rate of 7.35% (2009 and 2008: 7.35%) to expenditure on such assets. |
|
|||||||||||||||
|
Interest on tax liabilities for 2009 was a negative charge of $2.6 million as result of the release of the 2007 accruals made in relation to the French tax audit. |
|
|||||||||||||||
|
11. Taxation Tax recognised in the consolidated income statement |
|
|||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||||||
|
Tax charged in the income statement: |
||||||||||||||||
|
Current tax: |
||||||||||||||||
|
Corporation tax on profits for the year |
157.6 | 124.6 | 109.7 | |||||||||||||
|
Adjustments in respect of prior years |
(1.4 | ) | (8.6 | ) | 3.0 | |||||||||||
|
Total current tax |
156.2 | 116.0 | 112.7 | |||||||||||||
|
Deferred tax due to origination and reversal of temporary differences |
(10.5 | ) | (6.5 | ) | 47.8 | |||||||||||
|
Total |
145.7 | 109.5 | 160.5 | |||||||||||||
|
Attributable to: |
||||||||||||||||
|
Continuing operations |
130.8 | 102.8 | 162.6 | |||||||||||||
|
Discontinued operations |
14.9 | 6.7 | (2.1 | ) | ||||||||||||
|
Total |
145.7 | 109.5 | 160.5 | |||||||||||||
|
seabed-to-surface
|
|
103
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
11. Taxation continued
Tax recognised in the consolidated statement of comprehensive income
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||
|
Tax relating to items charged/(credited) to comprehensive income: |
||||||||||||
|
Current tax: |
||||||||||||
|
Exchange differences |
0.8 | (19.6 | ) | 16.4 | ||||||||
|
Income tax recognised directly in comprehensive income |
0.8 | (19.6 | ) | 16.4 | ||||||||
|
Deferred tax: |
||||||||||||
|
Net (gain)/loss on revaluation of cash flow hedges |
(6.2 | ) | 12.3 | (8.5 | ) | |||||||
|
Actuarial losses on defined benefit pension schemes |
(0.2 | ) | (0.8 | ) | (1.1 | ) | ||||||
|
Deferred tax recognised directly in comprehensive income |
(6.4 | ) | 11.5 | (9.6 | ) | |||||||
|
Total |
(5.6 | ) | (8.1 | ) | 6.8 | |||||||
|
Tax recognised in the consolidated statement of changes in equity |
||||||||||||
|
For the fiscal year (in $ millions) |
2010 | 2009 | 2008 | |||||||||
|
Deferred tax: |
||||||||||||
|
Share based payments |
(0.5 | ) | (1.3 | ) | 1.7 | |||||||
|
Total |
(0.5 | ) | (1.3 | ) | 1.7 | |||||||
Reconciliation of the total tax charge
As at November 30, 2010, the Company was a 1929 Luxembourg Holding Company. Luxembourg tax law provides for a special tax regime for 1929 Holding Companies and consequently the Company was subject to de minimis tax in Luxembourg. On January 1, 2011, the 1929 regime ceased to apply and the Company became a normally taxed Luxembourg company. Income taxes have been provided based on the tax laws and rates in the countries where business operations have been established and earn income. The Group’s tax charge is determined by applying the statutory tax rate to the net income earned in each of the jurisdictions in which the Group operates, taking account of permanent differences between book and tax net incomes.
The Group’s tax charge has been reconciled to a tax rate for the fiscal year 2010 of 28% (2009: 28%; 2008: 28%), being the expected blended statutory rate taking into consideration the jurisdictions in which the Group operates.
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||
|
Income before taxes on continuing operations |
399.2 | 361.3 | 492.3 | |||||||||
|
Tax at the blended statutory tax rate of 28% (2009: 28%, 2008: 28%) |
111.8 | 101.2 | 137.8 | |||||||||
|
Effects of: |
||||||||||||
|
Benefit of Tonnage tax regime (see below) |
(7.0 | ) | (6.0 | ) | (7.5 | ) | ||||||
|
Different tax rates of subsidiaries operating in other jurisdictions (tax rate differences) |
13.6 | 10.6 | 11.6 | |||||||||
|
Share based payments |
– | 0.6 | 5.3 | |||||||||
|
Adjustments related to prior years |
(1.4 | ) | (8.0 | ) | 3.0 | |||||||
|
Movement in non-provided deferred tax |
1.5 | (16.0 | ) | (4.1 | ) | |||||||
|
Net incomes not subject to tax |
(0.3 | ) | (9.0 | ) | 4.3 | |||||||
|
Tax effect of share of net income of associates and joint ventures |
(6.7 | ) | (0.1 | ) | (4.1 | ) | ||||||
|
Withholding taxes |
19.2 | 26.5 | 16.2 | |||||||||
|
Expenses not deductible for tax purposes |
– | – | 0.3 | |||||||||
|
Other permanent differences |
0.1 | 3.0 | (0.2 | ) | ||||||||
|
Tax charge in the income statement |
130.8 | 102.8 | 162.6 | |||||||||
|
104 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
Deferred tax
Analysis of the movements in net deferred tax balance during the year:
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 |
|
||||||||||||||||
|
At December 1 |
(30.6 | ) | (16.3) | 24.3 | ||||||||||||||||
|
Credited/(charged) to: |
||||||||||||||||||||
|
– Consolidated income statement |
10.5 | 6.5 | (47.8 | ) | ||||||||||||||||
|
– Consolidated statement of comprehensive income |
|
6.4 | (11.5) | 9.6 | ||||||||||||||||
|
– Consolidated statement of changes in equity |
0.5 | 1.3 | (1.7 | ) | ||||||||||||||||
|
Transfer to current tax |
(8.6 | ) | (9.1) | – | ||||||||||||||||
|
Exchange differences |
0.5 | (1.5) | (0.7 | ) | ||||||||||||||||
|
At November 30 |
(21.3 | ) | (30.6) | (16.3 | ) | |||||||||||||||
| Deferred tax assets and liabilities in respect of continuing operations, before offset of balances within countries, are as follows: | ||||||||||||||||||||
|
As at November 30, 2010
|
|
|||||||||||||||||||
| (in $ millions) |
Deferred tax
asset |
Deferred tax
liability |
Net recognised
deferred tax asset/(liability) |
Amount credited/
(charged) in income statement |
||||||||||||||||
| Property, plant and equipment | 2.3 | (15.9 | ) | (13.6 | ) | (7.1 | ) | |||||||||||||
| Accrued expenses | 27.6 | (28.7 | ) | (1.1 | ) | 20.7 | ||||||||||||||
| Share based payments | 4.6 | – | 4.6 | 1.8 | ||||||||||||||||
| Convertible loan notes | – | (17.7 | ) | (17.7 | ) | – | ||||||||||||||
| Tax losses | 6.5 | – | 6.5 | (4.9 | ) | |||||||||||||||
|
Total |
41.0 | (62.3 | ) | (21.3 | ) | 10.5 | ||||||||||||||
|
As at November 30, 2009 |
|
|||||||||||||||||||
| (in $ millions) |
Deferred tax
asset |
Deferred tax
liability |
Net recognised
deferred tax asset/(liability) |
Amount credited/
(charged) in income statement |
||||||||||||||||
| Property, plant and equipment | 2.5 | (9.0 | ) | (6.5 | ) | 5.4 | ||||||||||||||
| Accrued expenses | 14.2 | (34.2 | ) | (20.0 | ) | (5.9 | ) | |||||||||||||
| Share based payments | 2.2 | – | 2.2 | 0.4 | ||||||||||||||||
| Convertible loan notes | – | (17.7 | ) | (17.7 | ) | – | ||||||||||||||
| Tax losses | 11.4 | – | 11.4 | 6.6 | ||||||||||||||||
|
Total |
30.3 | (60.9 | ) | (30.6 | ) | 6.5 | ||||||||||||||
|
As at November 30, 2008 |
|
|||||||||||||||||||
| (in $ millions) |
Deferred tax
asset |
Deferred tax
liability |
Net recognised
|
Amount credited/
(charged) in income statement |
||||||||||||||||
| Property, plant and equipment | 1.1 | (13.0 | ) | (11.9 | ) | 5.4 | ||||||||||||||
| Accrued expenses | 44.3 | (36.3 | ) | 8.0 | (49.9 | ) | ||||||||||||||
| Share based payments | 0.5 | – | 0.5 | (3.4 | ) | |||||||||||||||
| Convertible loan notes | – | (17.7 | ) | (17.7 | ) | – | ||||||||||||||
| Tax losses | 4.8 | – | 4.8 | 0.1 | ||||||||||||||||
|
Total |
50.7 | (67.0 | ) | (16.3 | ) | (47.8 | ) | |||||||||||||
|
Deferred tax is analysed in the Consolidated Balance Sheet, after offset of balances within countries, as: |
|
|||||||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||||||||||
|
Deferred tax assets |
22.8 | 19.3 | 39.8 | |||||||||||||||||
|
Deferred tax liabilities |
(44.1 | ) | (49.9) | (56.1 | ) | |||||||||||||||
|
Total |
(21.3 | ) | (30.6) | (16.3 | ) | |||||||||||||||
|
seabed-to-surface
|
|
105
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
11. Taxation continued
At the balance sheet date, the Group has tax losses of $128.4 million (2009: $148.0 million) available for offset against future taxable profits. A deferred tax asset has been recognised in respect of $23.2 million (2009: $40.7 million) of such losses. No deferred tax asset has been recognised in respect of the remaining $105.2 million (2009: $107.3 million) due to the uncertainty of future taxable profits. In addition the Group has unrecognised deferred tax assets of approximately $46.8 million (2009: $40.0 million) in respect of other temporary differences.
Net operating losses (NOLs) including Internal Revenue Code (IRC) s.163j in the US
NOLs to carry forward in various countries will expire as follows:
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||
|
Within five years |
2.5 | 2.4 | 0.1 | |||
|
16 to 20 years |
54.6 | 55.5 | 82.7 | |||
|
Without time limit |
71.3 | 90.1 | 111.8 | |||
|
Total |
128.4 | 148.0 | 194.6 |
The majority of NOLs are concentrated in the US where the ability to carry forward NOLs is subject to a limitation as a consequence of Stolt Nielsen S.A. (SNSA) having sold its remaining stock in the Company in 2005. As at November 30, 2010, it is considered likely that, subject to future profitability, the Group will be able to access US NOLs arising both before and after the date of the change of control of $54.7 million (2009: $55.5 million). In addition to the US NOLs the Group has IRC s.163j suspended interest deductions of $45.3 million (2009: $45.5 million). However, with a history of incurring losses for tax purposes in the US, none of the NOLs and IRC s.163j suspended interest deductions in the US have been recognised as a deferred tax asset. It should be noted that on completion of the Combination with Subsea 7 Inc. it is considered likely that there will be another change of control event which will further restrict the Group’s ability to utilise the NOLs in the US.
Tonnage tax regime
The tax charge reflects a net benefit in fiscal year 2010 of $7.0 million (2009: $6.0 million) as a result of being taxable under the current UK Tonnage tax regime, as compared to the UK tax that would be payable had an election to join the Tonnage tax regime not been made.
Tax contingencies and provisions
Operations are carried out in several countries, through subsidiaries and branches of subsidiaries, and are subject to the jurisdiction of a significant number of taxing authorities. Furthermore, the offshore mobile nature of the Group’s operations means that the Group routinely has to deal with complex transfer pricing, permanent establishment and other similar international tax issues as well as competing tax systems where tax treaties may not exist.
In the ordinary course of events operations will be subject to audit, enquiry and possible re-assessment by different tax authorities. Management provides taxes for the amounts that it considers probable of being payable as a result of these audits and for which a reasonable estimate may be made. Management also separately considers whether taxes payable in relation to filings not yet subject to audit may be higher than the amounts stated in the filed tax return, and makes additional provisions for probable risks if appropriate. As forecasting the ultimate outcome includes some uncertainty, the risk exists that adjustments will be recognised to the Group’s tax provisions in later years as and when these and other matters are finalised with the appropriate tax authorities.
In 2010, operations in various countries were subject to enquiries, audits and disputes, including, but not limited to, those in Angola, Australia, Brazil, Canada, Congo, Denmark, France, Gabon, Indonesia, Nigeria, the UK and US. These audits are all at various stages of completion. The Group’s operating entities in these countries have co-operated fully with the relevant tax authorities while seeking to defend their tax positions.
The tax audit in France, which commenced in February 2007 and continued into fiscal year 2010, has been resolved closing all years up to November 30, 2006.
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 taxing authorities often leads to uncertainty on tax positions.
As a result of the above, in the fiscal year 2010, the Group recorded a net tax increase of $6.4 million (2009: $10.2 million) in respect of ongoing tax audits and in respect of the Group’s review of its uncertain tax positions. The charge arises both from adjustments that the Group has agreed with the relevant tax authorities and re-estimates that it has made.
Whilst the Group has made the incremental provisions noted in the preceding paragraph, reflecting its view of the most likely outcomes, 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.
|
106 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| 12. Discontinued operations | ||||||||||
| On November 27, 2008, the Group entered into an agreement with Saipem (Portugal) Comercio Maritimo S.U. Lda to dispose of Acergy Piper , a semi-submersible pipelay barge, for $78.0 million. The disposal was driven by a desire to continue to focus the Group on its core operations. The disposal was completed on January 9, 2009. | ||||||||||
|
Acergy Piper was the Group’s sole operating unit in the Trunklines market which involved the offshore market installation of large-diameter pipelines used to carry oil and gas over large distances. The disposal of the barge therefore represents the Group’s discontinuance of this operation. |
||||||||||
|
In 2010, the Group continued to generate revenues through the Trunklines operation due to additional related work on the Mexilhao Project that does not require Acergy Piper . This project was complete as at November 30, 2010. |
||||||||||
|
The results of the discontinued operations, which have been included in the Consolidated Income Statement, were as follows:
|
||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||
|
Revenue |
83.4 | 114.8 | 281.8 | |||||||
|
Expenses (a) |
(23.9) | (99.9) | (320.7) | |||||||
|
Impairment (charge)/reversal |
– | (1.0) | 14.3 | |||||||
|
Income/(loss) before tax |
59.5 | 13.9 | (24.6) | |||||||
|
Taxation (charge)/credit on discontinued operations |
(14.9) | (6.7) | 2.1 | |||||||
|
Net income/(loss) from discontinued operations |
44.6 | 7.2 | (22.5) | |||||||
|
(a) Includes operating expenses, administrative expenses, finance costs and other gains and losses. |
||||||||||
|
The impact on the segments of the discontinued operations which have been included in the Consolidated Income Statement were as follows:
|
||||||||||
| 2010 |
|
|||||||||
| For the fiscal year (in $ millions) | NEC | SAM | CORP |
Total
discontinued operations |
||||||
|
Revenue |
– | 83.4 | – | 83.4 | ||||||
|
Expenses (a) |
– | (23.9) | – | (23.9) | ||||||
|
Income before tax |
– | 59.5 | – | 59.5 | ||||||
|
Taxation charge on discontinued operations |
– | (14.9) | – | (14.9) | ||||||
|
Net income/(loss) from discontinued operations |
– | 44.6 | – | 44.6 | ||||||
|
(a) Includes operating expenses, administrative expenses, finance costs and other gains and losses.
|
||||||||||
| 2009 | ||||||||||
| For the fiscal year (in $ millions) | NEC | SAM | CORP |
Total
discontinued operations |
||||||
|
Revenue |
– | 114.8 | – | 114.8 | ||||||
|
Expenses (a) |
– | (97.4) | (2.5) | (99.9) | ||||||
|
Impairment charge |
– | – | (1.0) | (1.0) | ||||||
|
Income/(loss) before tax |
– | 17.4 | (3.5) | 13.9 | ||||||
|
Taxation charge on discontinued operations |
– | (6.7) | – | (6.7) | ||||||
|
Net income/(loss) from discontinued operations |
– | 10.7 | (3.5) | 7.2 | ||||||
|
(a) Includes operating expenses, administrative expenses, finance costs and other gains and losses.
|
||||||||||
|
2008 |
||||||||||
| For the fiscal year (in $ millions) | NEC | SAM | CORP |
Total
discontinued operations |
||||||
|
Revenue |
5.6 | 275.9 | 0.3 | 281.8 | ||||||
|
Expenses (a) |
(36.0) | (284.4) | (0.3) | (320.7) | ||||||
|
Impairment reversal |
14.3 | – | – | 14.3 | ||||||
|
Loss before tax |
(16.1) | (8.5) | – | (24.6) | ||||||
|
Taxation credit on discontinued operations |
2.1 | – | – | 2.1 | ||||||
|
Net loss from discontinued operations |
(14.0) | (8.5) | – | (22.5) | ||||||
|
(a) Includes operating expenses, administrative expenses, finance costs and other gains and losses.
|
||||||||||
| Discontinued operations generated $23.2 million (2009: $18.7 million, 2008: used $5.6 million) of the Group’s net operating cash flows, and generated $0.1 million (2009: $Nil, 2008: $1.4 million) in respect of investing activities. | ||||||||||
|
seabed-to-surface
|
|
107
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
13. Earnings per share
Basic earnings per share
Basic earnings per share amounts are calculated by dividing the net income attributable to equity holders of the parent for continuing and discontinued operations by the weighted average number of common shares in issue during the fiscal year excluding ordinary shares purchased by the Company and held as treasury shares (Note 25 ‘Own shares’) as follows:
| For the fiscal year |
2010 $ per share |
2009 $ per share |
2008
$ per share |
|||
|
Basic earnings per share: |
||||||
| From continuing operations | 1.20 | 1.30 | 1.76 | |||
| From discontinued operations | 0.24 | 0.04 | (0.12) | |||
| Total basic earnings per share | 1.45 | 1.34 | 1.64 |
The earnings and weighted average number of common shares used in the calculation of basic earnings per share are as follows:
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||
| Net income for the year from continuing operations | 220.8 | 237.8 | 323.9 | |||
| Net income/(loss) from discontinued operations (see Note 12) | 44.6 | 7.2 | (22.5) | |||
| Net income attributable to equity holders of the parent | 265.4 | 245.0 | 301.4 | |||
|
2010
Number of
|
2009
Number of
|
2008
Number of
|
||||
| Weighted average number of common shares for the purpose of basic earnings per share | 183,500,710 | 182,956,010 | 184,142,708 | |||
Diluted earnings per share
Diluted earnings per share is calculated by adjusting the weighted average number of ordinary shares outstanding to assume conversion of all dilutive potential ordinary shares. The Company has two categories of dilutive potential ordinary shares: convertible loan notes and share options. The convertible loan notes are assumed to have been converted into ordinary shares and the net profit is adjusted to eliminate the interest expense less the tax effect. For the share options, a calculation is done 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.
| For the fiscal year |
2010 $ per share |
2009 $ per share |
2008
$ per share |
|||
|
Diluted earnings per share: |
||||||
| From continuing operations | 1.16 | 1.29 | 1.70 | |||
| From discontinued operations | 0.22 | 0.04 | (0.11) | |||
| Total diluted earnings per share | 1.38 | 1.33 | 1.59 |
The earnings and weighted average number of common shares used in the calculation of diluted earnings per share are as follows:
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||
| Net income for the year from continuing operations | 220.8 | 237.8 | 323.9 | |||
| Interest on convertible loan notes less amounts capitalised to qualifying assets | 19.0 | – | 28.4 | |||
| Net income/(loss) for the year from discontinued operations (see Note 12) | 44.6 | 7.2 | (22.5) | |||
| Earnings used in the calculation of diluted earnings per share | 284.4 | 245.0 | 329.8 | |||
|
2010
Number of
|
2009
Number of
|
2008
Number of
|
||||
| Weighted average number of common shares used in the calculation of basic earnings per share | 183,500,710 | 182,956,010 | 184,142,708 | |||
| Convertible loan notes | 22,184,506 | – | 21,258,503 | |||
| Share options | 1,020,820 | 835,150 | 2,134,846 | |||
| Weighted average number of common shares used in the calculation of diluted earnings per share | 206,706,036 | 183,791,160 | 207,536,057 | |||
|
108 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
In fiscal year 2009 the potential common shares of 22,016,733 for the convertible loan notes were excluded from the weighted average number of common shares as their effect was anti-dilutive.
|
||||||||||
|
In fiscal year 2010 1,552,625 shares relating to share option plans (2009: 2,810,948 and 2008: 1,923,234 shares) that could potentially dilute the weighted average earnings per share, were excluded from the calculation of diluted earnings per share due to being anti-dilutive for the period.
|
||||||||||
|
For potential dilutive effects of post-balance sheet events refer to Note 40 ‘Post balance sheet events’.
|
||||||||||
| 14. Dividends | ||||||||||
|
In light of the development of the combined business and the Group’s investment opportunities, the Board has proposed not to pay a dividend for the 2010 fiscal year. The Board is reviewing methods of balancing the optimal use of cash in light of the opportunities available.
|
||||||||||
|
The final dividend for the fiscal year ended November 30, 2009 of $0.23 per share and a total of $42.2 million was paid in June 2010.
|
||||||||||
|
15. Intangible assets
|
||||||||||
| For the fiscal year (in $ millions) | Software |
Lease access
premiums |
Other
intangibles |
Total | ||||||
| Cost: | ||||||||||
| At December 1, 2008 | – | 4.7 | 0.9 | 5.6 | ||||||
| Reclassified from property, plant and equipment (see Note 16) | 19.3 | – | – | 19.3 | ||||||
| Additions | 6.3 | – | 0.1 | 6.4 | ||||||
| Exchange differences | 1.9 | – | – | 1.9 | ||||||
| Reclassified as held for sale (see Note 21) | – | (4.7) | (0.1) | (4.8) | ||||||
| At November 30, 2009 | 27.5 | – | 0.9 | 28.4 | ||||||
| Additions | 6.2 | – | – | 6.2 | ||||||
| Exchange differences | (1.6) | – | – | (1.6) | ||||||
|
At November 30, 2010 |
32.1 | – | 0.9 | 33.0 | ||||||
|
Amortisation: |
||||||||||
| At December 1, 2008 | – | 1.8 | – | 1.8 | ||||||
| Reclassified from property, plant and equipment (see Note 16) | 15.6 | – | – | 15.6 | ||||||
| Charge for the year | 1.9 | 0.1 | – | 2.0 |
|
|||||
| Exchange differences | 1.5 | – | – | 1.5 | ||||||
| Impairment | – | 2.8 | – | 2.8 | ||||||
| Reclassified as held for sale (see Note 21) | – | (4.7) | – | (4.7) | ||||||
| At November 30, 2009 | 19.0 | – | – | 19.0 | ||||||
| Charge for the year | 1.6 | – | – | 1.6 | ||||||
| Exchange differences | (0.7) | – | – | (0.7) | ||||||
| Impairment (a) | 7.0 | – | – | 7.0 | ||||||
|
At November 30, 2010 |
26.9 | – | – | 26.9 | ||||||
|
Carrying amount: |
||||||||||
| At November 30, 2009 | 8.5 | – | 0.9 | 9.4 | ||||||
|
At November 30, 2010 |
5.2 | – | 0.9 | 6.1 | ||||||
|
(a) Software development costs with a carrying value of $7.0 million, with doubtful future economic benefits following the announcement of the acquisition of Subsea 7 Inc., were impaired during the year. |
||||||||||
|
seabed-to-surface
|
|
109
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
16. Property, plant and equipment
| For the fiscal year (in $ millions) |
Construction
support vessels |
Operating
equipment |
Land and
buildings |
Other assets |
Total | |||||
|
Cost: |
||||||||||
|
At December 1, 2008 |
665.2 | 695.7 | 26.2 | 49.6 | 1,436.7 | |||||
|
Reclassified as intangible assets (see Note 15) |
– | (11.8) | – | (7.5) | (19.3) | |||||
|
Additions |
53.2 | 60.6 | 13.1 | 4.7 | 131.6 | |||||
|
Exchange differences |
9.8 | 13.5 | 1.4 | 2.8 | 27.5 | |||||
|
Disposals |
(1.2) | (9.9) | (0.1) | (0.8) | (12.0) | |||||
|
Reclassified as held for sale |
– | (94.3) | (34.7) | (3.3) | (132.3) | |||||
|
Transfers |
9.1 | 4.8 | (3.8) | (10.1) | – | |||||
|
At November 30, 2009 |
736.1 | 658.6 | 2.1 | 35.4 | 1,432.2 | |||||
|
Additions |
472.6 | 115.0 | 0.4 | 4.8 | 592.8 | |||||
|
Exchange differences |
(3.4) | (11.2) | (0.1) | (2.4) | (17.1) | |||||
|
Disposals |
(22.8) | (9.0) | (2.1) | (2.6) | (36.5) | |||||
|
Transfers |
83.6 | (98.3) | 7.2 | 7.5 | – | |||||
|
At November 30, 2010 |
1,266.1 | 655.1 | 7.5 | 42.7 | 1,971.4 | |||||
|
Accumulated depreciation: |
||||||||||
|
At December 1, 2008 |
266.4 | 228.5 | 8.0 | 26.2 | 529.1 | |||||
|
Reclassified as intangible assets (see Note 15) |
– | (11.8) | – | (3.8) | (15.6) | |||||
|
Charge for the year |
47.5 | 69.7 | 0.4 | 7.0 | 124.6 | |||||
|
Exchange differences |
2.9 | 6.6 | 1.0 | 2.2 | 12.7 | |||||
|
Impairment |
– | 12.2 | 0.6 | – | 12.8 | |||||
|
Eliminated on disposals |
(2.4) | (8.4) | (0.1) | (0.6) | (11.5) | |||||
|
Reclassified as held for sale |
– | (29.7) | (9.0) | (3.0) | (41.7) | |||||
|
Transfers |
1.9 | (1.2) | 1.7 | (2.4) | – | |||||
|
At November 30, 2009 |
316.3 | 265.9 | 2.6 | 25.6 | 610.4 | |||||
|
Charge for the year |
56.2 | 52.7 | 0.7 | 6.6 | 116.2 | |||||
|
Exchange differences |
(1.6) | (5.5) | – | (1.7) | (8.8) | |||||
|
Eliminated on disposals |
(14.4) | (7.8) | (0.5) | (2.5) | (25.2) | |||||
|
Transfers |
42.5 | (43.9) | (0.7) | 2.1 | – | |||||
|
At November 30, 2010 |
399.0 | 261.4 | 2.1 | 30.1 | 692.6 | |||||
|
Carrying amount: |
||||||||||
|
At November 30, 2009 |
419.8 | 392.7 | (0.5) | 9.8 | 821.8 | |||||
|
At November 30, 2010 |
867.1 | 393.7 | 5.4 | 12.6 | 1,278.8 | |||||
Borealis is an asset under construction. The amount capitalised in 2010 was $295.9 million (2009 $Nil).
In fiscal year 2010 there were no impairment charges to operations in respect of property, plant and equipment.
In fiscal year 2009 impairment charges were charged to operations in respect of property, plant and equipment assets of $12.8 million. The impairments were due to:
| Ÿ | Under-utilised operating equipment – $9.8 million: A pipeline end handling system ($4.0 million) and a reel drive system ($5.8 million) were identified to be under-utilised with no anticipated utilisation for 2010 onwards. In the fourth quarter of 2009 an impairment charge of $9.8 million was recorded to reduce the net book value of the asset to $Nil. |
| Ÿ | Operating equipment – $1.0 million: the equipment represents four generators and generating sets which were purchased for Acergy Piper . Following the classification of Acergy Piper as an asset held for sale in the fourth quarter of 2008, an impairment charge of $1.0 million was recorded to reduce the net book value to $2.0 million as it was anticipated the generators would be under-utilised in the future. Due to continued under-utilisation a further impairment charge of $1.0 million was recorded to reduce the net book value to $1.0 million at November 30, 2009. |
| Ÿ | Prior to the classification of the Sonamet subsidiaries as assets held for sale (refer to Note 21 ‘Assets classified as held for sale’), an impairment of $2.0 million was recorded. |
|
110 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| 17. Interest in associates and joint ventures | ||||||||||||||||||||||||||
|
Investment in associates and joint ventures
|
||||||||||||||||||||||||||
| As at November 30 (in $ millions) | Year End |
Country/Place of
Registration |
Acergy Business
Segment |
Ownership % | 2010 | 2009 | ||||||||||||||||||||
| Dalia (a) | December 31 | France | AFMED | Associate | 17.5 | 2.1 | 3.6 | |||||||||||||||||||
| Oceon | December 31 | Nigeria | AFMED | Associate | 40 | – | – | |||||||||||||||||||
| SapuraAcergy | January 31 | Malaysia | AME | Joint Venture | 50 | 15.6 | – | |||||||||||||||||||
| SHL | Cyprus/ | |||||||||||||||||||||||||
| December 31 | Netherlands | CORP | Joint Venture | 50 | 102.8 | 77.6 | ||||||||||||||||||||
| NKT Flexibles | December 31 | Denmark | CORP | Joint Venture | 49 | 94.6 | 109.1 | |||||||||||||||||||
| Total | 215.1 | 190.3 | ||||||||||||||||||||||||
|
(a) Subsea 7 owns 17.5% and has a significant influence in Dalia. Subsea 7 has a veto on decision-making as decisions require unanimous agreement.
|
||||||||||||||||||||||||||
|
The movement in the balance of equity investments, including long-term advances during the fiscal years 2010 and 2009 was as follows:
|
||||||||||||||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | ||||||||||||||||||||||||
| At December 1 | 190.3 | 140.2 | ||||||||||||||||||||||||
| Share of net income of associates and joint ventures | 74.8 | 49.0 | ||||||||||||||||||||||||
| Dividends distributed to the Group | (30.2) | (28.0) | ||||||||||||||||||||||||
| Increase in investment | 14.0 | 20.6 | ||||||||||||||||||||||||
| Reclassification of negative equity balance | (12.1) | (7.7) | ||||||||||||||||||||||||
| Change in fair value of derivative instruments | (5.1) | (1.7) | ||||||||||||||||||||||||
| Exchange differences | (16.6) | 17.9 | ||||||||||||||||||||||||
| At November 30 | 215.1 | 190.3 | ||||||||||||||||||||||||
|
Share of net income of associates and joint ventures:
|
||||||||||||||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||||||||||||||||
| Dalia | 1.4 | 2.9 | 0.6 | |||||||||||||||||||||||
| Oceon | 0.4 | (0.9) | (0.9) | |||||||||||||||||||||||
| Acergy/Subsea 7 | – | 0.6 | 3.5 | |||||||||||||||||||||||
| SapuraAcergy | 28.5 | 9.7 | (15.4) |
|
||||||||||||||||||||||
| SHL | 30.8 | 15.0 | 29.6 | |||||||||||||||||||||||
| NKT Flexibles | 13.7 | 21.7 | 45.6 | |||||||||||||||||||||||
| Total | 74.8 | 49.0 | 63.0 | |||||||||||||||||||||||
|
No long-lived asset impairment charges were recorded by the Group’s associates and joint ventures during fiscal years 2010, 2009, and 2008. |
||||||||||||||||||||||||||
|
Taxation in respect of the NKT Flexibles joint venture, which has a legal status of a partnership, has been included in the results of the relevant subsidiaries, which hold the investments in the joint venture. Undistributed reserves of all other joint ventures will not be taxed on distribution. |
||||||||||||||||||||||||||
|
Dividends distributed to the Group |
||||||||||||||||||||||||||
| In fiscal year 2010 the Group received a total of $30.2 million dividends from three joint ventures (SHL, NKT Flexibles and Dalia). $14.0 million of the SHL dividend was used to increase the Group’s investment in this venture. | ||||||||||||||||||||||||||
|
In fiscal year 2009 the Group received a total of $28.0 million dividends from three joint ventures (Acergy/Subsea 7, SHL and Dalia). $20.6 million of the SHL dividend was used to increase the Group’s investment in this venture. |
||||||||||||||||||||||||||
|
seabed-to-surface
|
|
111
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
17. Interest in associates and joint ventures continued
Increase in investment
In fiscal year 2010 the Group invested an additional $14.0 million (2009: $20.6 million) to increase its investment in SHL. The Group has additional commitments to the SHL and SapuraAcergy joint ventures as described in Note 34 ‘Commitments and contingent liabilities’.
A cash advance of $Nil (2009: $5.0 million) was provided to SapuraAcergy during the year.
Significant restrictions
All dividends paid by SHL prior to the delivery of the new vessel Oleg Strashnov , expected in the first half of 2011, are reinvested into the joint venture.
SapuraAcergy is regulated by the central bank of Malaysia in respect of the repatriation of funds. Dividends are not subject to withholding taxes.
Capital commitments
SHL has entered into a ship building contract for the heavy lift vessel, Oleg Strashnov , amounting to € 286.0 million ($363.0 million). As at November 30, 2010 instalments representing 85% of the contract value had been paid (2009: 65%). The investment is financed by a Revolving Credit and Guarantee Facility comprising € 140 million ($178.0 million) and $180 million available for cash drawings and $33 million available for the issuance of guarantees.
Reclassification of negative equity balance
The Group accrues losses in excess of the investment value when it is committed to providing ongoing financial support to the joint venture.
The Group’s share of any net liabilities of joint ventures is offset against long-term funding provided to that joint venture. Any additional share of net liabilities is classified as other non-current liabilities. In fiscal year 2010 a reversal of $11.6 million (2009: reversal of $8.4 million) was recorded against long-term funding, relating to SapuraAcergy losses previously offset against funding. A reversal of $0.5 million (2009: reclassification of $0.7 million) was recorded against other non-current liabilities relating to Oceon losses previously offset against liabilities.
Impact of currency translation
This arises from the translation of investments in the equity of joint ventures which have a functional currency other than the US dollar, and relates mainly to NKT Flexibles.
Summarised financial information
Summarised financial information for associates and joint ventures, representing 100% of the respective amounts included in their financial statements including IFRS adjustments, is as follows:
|
Aggregated financial data for associates and joint ventures |
||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||
|
Revenue |
880.5 | 616.8 | 757.7 | |||
|
Operating expenses |
(542.9) | (330.0) | (524.5) | |||
|
Gross profit |
337.6 | 286.8 | 233.2 | |||
|
Other income |
14.9 | 6.2 | 64.8 | |||
|
Other expenses |
(153.5) | (161.2) | (139.3) | |||
|
Net income |
199.0 | 131.8 | 158.7 | |||
|
Aggregated balance sheet data for associates and joint ventures |
||||||
| As at November 30 (in $ millions) | 2010 | 2009 | 2008 | |||
|
Current assets |
725.2 | 656.2 | 516.3 | |||
|
Non-current assets |
864.1 | 786.9 | 593.1 | |||
|
Total assets |
1,589.3 | 1,443.1 | 1,109.4 | |||
|
Current liabilities |
460.1 | 508.5 | 341.4 | |||
|
Non-current liabilities |
610.4 | 504.5 | 442.3 | |||
|
Total liabilities |
1,070.5 | 1,013.0 | 783.7 | |||
Transactions with associates and joint ventures
Certain contractual services are conducted with joint ventures for commercial reasons.
In fiscal year 2010 the income statement data for the joint ventures presented above includes general and administrative charges of $13.9 million (2009: $38.0 million, 2008: $47.4 million).
In fiscal year 2010, joint ventures received $17.0 million (2009: $15.5 million, 2008: $28.2 million) in respect of goods and services provided.
|
112 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| The Group’s balance sheet included: | ||||||||
|
As at November 30 (in $ millions) |
2010 | 2009 | ||||||
| Non-current amounts due from associates and joint ventures | 43.2 | 32.7 | ||||||
| Trade receivables with associates and joint ventures | 23.5 | 46.1 | ||||||
| Allowance for doubtful debts | (1.0) | (2.1) | ||||||
| Net trade receivables | 22.5 | 44.0 | ||||||
| Trade payables with associates and joint ventures | – | 0.2 | ||||||
| Net receivables with associates and joint ventures | 65.7 | 76.9 | ||||||
|
For guarantee arrangements with joint ventures see Note 27 ‘Borrowings’.
|
||||||||
| 18. Advances and receivables | ||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||
| Non-current amounts due from associates and joint ventures (see Note 17) | 43.2 | 32.7 | ||||||
| Capitalised fees for long-term loan facilities | 7.3 | 2.8 | ||||||
| Deposits held by third parties | 4.8 | 0.4 | ||||||
| Prepaid expenses | 7.4 | 7.4 | ||||||
| Total | 62.7 | 43.3 | ||||||
|
The fees for the loan facilities (refer to Note 27 ‘Borrowings’) are deferred and expensed over the periods for which each loan facility is held.
Prepaid expenses are incurred in the normal course of business and represent expenditure which will be recognised in a period exceeding twelve months.
|
||||||||
| 19. Inventories | ||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | 2008 | |||||
| Materials and spares | 13.8 | 13.2 | 25.4 | |||||
| Consumables | 10.3 | 9.2 | 13.1 | |||||
| Total | 24.1 | 22.4 | 38.5 | |||||
|
Total amount of inventory charged to income statement |
22.9 | 44.6 | 60.6 | |||||
| Write-down on inventory charged to income statement | 0.5 | 0.2 | 3.3 | |||||
|
The inventories include a provision for obsolescence as at November 30, 2010 of $4.1 million (2009: $3.1 million, 2008: $3.5 million). During the fiscal year 2010 $Nil (2009: $0.2 million, 2008: $2.0 million) of the provision for obsolescence was reversed due to slow moving items which were subsequently consumed during the fiscal year.
|
|
|||||||
|
There are no inventories pledged as security for liabilities.
|
||||||||
| 20. Trade and other receivables | ||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | 2008 | |||||
| Trade receivables (see Note 34) | 248.7 | 202.0 | 298.7 | |||||
| Allowance for doubtful debts | (1.5) | (0.4) | (1.1) | |||||
| Net trade receivables | 247.2 | 201.6 | 297.6 | |||||
| Current amounts due from associates and joint ventures (see Note 17) | 22.5 | 44.0 | 22.8 | |||||
| Advances to suppliers | 9.9 | 8.0 | 8.6 | |||||
| Other taxes receivable | 47.1 | 18.0 | 14.2 | |||||
| Other receivables | 55.3 | 26.3 | 11.3 | |||||
| Total | 382.0 | 297.9 | 354.5 | |||||
|
The average credit period taken during 2010 was 45 days (2009: 37 days).
|
||||||||
|
Details of how the Group manages its credit risk and further analysis of the trade receivables balance can be found in Note 34 ‘Financial instruments’.
|
||||||||
| Other taxes receivable are for sales tax, withholding tax, social security and other indirect taxes. | ||||||||
|
seabed-to-surface
|
|
113
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
20. Trade and other receivables continued
Other receivables include amounts receivable from employees and insurance claims. Included in 2010 is the insurance claim in respect of the fire on Acergy Falcon .
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||
|
At December 1 |
(0.4) | (1.1) | (2.2) | |||||||||
|
Movement in provision |
(1.1) | – | 0.7 | |||||||||
|
Expense for the year |
– | 0.7 | 0.4 | |||||||||
|
At November 30 |
(1.5) | (0.4) | (1.1) | |||||||||
21. Assets classified as held for sale
Assets held for sale as at November 30, 2010 were:
| • | Investments in Sonamet and Sonacergy: On July 23, 2009, the Group entered into a sale agreement to dispose of 19% of its ownership interest in each of Sonamet Industrial, S.A (‘Sonamet’) and Sonacergy – Servicos E Construcoes Petroliferas Lda (Zona Franca Da Madeira) (‘Sonacergy’), in Acergy AFMED. Sonamet operates a fabrication yard for clients, including Subsea 7, operating in the offshore oil and gas industry in Angola. Sonacergy provides overseas logistics services and support to Sonamet. The disposal of a 19% interest in each of Sonamet and Sonacergy will result in a reduction of the 55% ownership interest the Group held in each at November 30, 2010, to 36% at which point the investment will be equity accounted. The finalisation of this sale is conditional upon the completion of certain conditions precedent, none of which are in the control of Subsea 7, which were still outstanding at November 30, 2010. There is no indication that the sale will not proceed as anticipated and the Group expects completion during 2011. The Group believes continued disclosure as an asset held for sale is appropriate. |
At November 30, 2009 the carrying value of the net assets of Sonamet and Sonacergy was assessed for impairment and determined to be greater than the fair value less costs to sell. Therefore an impairment charge of $4.8 million was recognised in the income statement in net operating income.
At November 30, 2010 a decrease in the net asset value of assets held for sale resulted in a reversal of $3.2 million of the impairment charge recognised in 2009. This reversal has been recognised in the income statement in net operating income.
| • | Acergy Piper : An impairment charge of $1.0 million was recognised in 2009 in net income from discontinued operations, in respect of equipment in Acergy NEC relating to, but not included in, the sale of Acergy Piper in January 2009. |
Assets held for sale as at November 30, 2009 included:
| • | Balikpapan: land, buildings and office equipment in Acergy AME. The sale was completed during November 2010. |
| • | Concrete products: sale of business assets in Acergy NAMEX. The sale was completed during February 2010. |
At November 30, 2010 the major classes of assets and liabilities comprising the 100% interest of the operations classified as held for sale were as follows:
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||
|
Property, plant and equipment |
127.5 | 91.7 | ||||||
|
Goodwill and other intangible assets |
1.9 | – | ||||||
|
Advances and receivables |
– | 1.1 | ||||||
|
Inventories |
14.2 | 14.0 | ||||||
|
Trade and other receivables |
45.9 | 34.3 | ||||||
|
Other accrued income and prepaid expenses |
2.3 | 18.9 | ||||||
|
Cash and cash equivalents |
63.7 | 103.6 | ||||||
|
Total assets classified as held for sale |
255.5 | 263.6 | ||||||
|
Non-current portion of borrowings |
12.8 | 12.1 | ||||||
|
Trade and other payables |
79.4 | 80.3 | ||||||
|
Current portion of borrowings |
4.7 | 6.3 | ||||||
|
Current tax liabilities |
2.1 | – | ||||||
|
Deferred revenue |
35.5 | 76.2 | ||||||
|
Total liabilities associated with assets classified as held for sale |
134.5 | 174.9 | ||||||
|
Net assets of disposal groups |
121.0 | 88.7 | ||||||
|
114 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| $15 million loan facility | ||||||||||||||||||||
| On May 26, 2008 Sonamet entered into a $15.0 million loan facility with BAI-Banco African de Investimentos S.A. for the construction of facilities at the company’s Lobito yard. After an initial 20 months repayment grace period the loan is repayable in equal instalments over 66 months, with a final maturity of July 26, 2015. The loan carries interest at six months LIBOR plus 2% per year, but subject to a minimum rate of 7% and a maximum rate of 8%. The facility is not guaranteed by Subsea 7 S.A. nor any of its other subsidiaries. As at November 30, 2010 $12.8 million (2009: $8.9 million) was drawn on this facility and there are no covenants over this facility. | ||||||||||||||||||||
| Other facilities | ||||||||||||||||||||
| A $4.7 million (2009: $9.5 million) unsecured loan provided by Sonangol to Sonamet bearing interest at a fixed rate of 2.75% per year and is repayable in annual instalments for a remaining period of one year as at November 30, 2010. | ||||||||||||||||||||
| Other guarantee arrangements | ||||||||||||||||||||
| There is also an unsecured local line in Maderia for the sole use of Sonacergy. The line is with Banco Espirito Santo S.A. for $8.5 million. The bonds under this facility were issued to guarantee the project performance of the subsidiary to third parties in the normal course of business. The amount issued under this facility as at November 30, 2010 was $8.5 million (2009: $8.5 million). | ||||||||||||||||||||
| The allocation of assets and liabilities held for sale by segment is as follows: | ||||||||||||||||||||
| As at November 30 (in $ millions) |
2010
Assets |
2010
Liabilities |
2009
Assets |
2009
Liabilities |
||||||||||||||||
|
Acergy AFMED |
254.5 | 134.5 | 261.4 | 174.9 | ||||||||||||||||
|
Acergy AME |
– | – | 1.1 | – | ||||||||||||||||
|
Acergy NEC |
1.0 | – | 1.0 | – | ||||||||||||||||
|
Acergy NAMEX |
– | – | 0.1 | – | ||||||||||||||||
|
Total assets and liabilities held for sale |
255.5 | 134.5 | 263.6 | 174.9 | ||||||||||||||||
| 22. Other accrued income and prepaid expenses | ||||||||||||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||||||||||||
|
Amounts due from contract clients (see Note 23) |
|
112.1 | 144.4 | |||||||||||||||||
|
Unbilled revenue |
|
96.3 | 54.7 | |||||||||||||||||
|
Prepaid expenses |
|
33.9 | 13.7 | |||||||||||||||||
|
Total |
|
242.3 | 212.8 | |||||||||||||||||
|
Unbilled revenue relates to completed work other than lump-sum construction contracts, which has not yet been billed to customers.
|
|
|
||||||||||||||||||
|
Prepaid expenses are incurred in the normal course of business and represent expenditure which has been deferred and which will be recognised within the next fiscal year.
|
|
|||||||||||||||||||
| 23. Construction contracts | ||||||||||||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||||||||||||
|
Contracts in progress at balance sheet date: |
|
|||||||||||||||||||
|
Amounts due from contract clients included in other accrued income and prepaid expenses (see Note 22) |
|
112.1 | 144.4 | |||||||||||||||||
|
Deferred revenue recognised under construction contracts (see Note 38) |
|
(198.4) | (241.2) | |||||||||||||||||
|
Total |
|
(86.3) | (96.8) | |||||||||||||||||
|
Contract costs incurred plus recognised net profits less recognised losses to date |
|
2,656.8 | 3,535.0 | |||||||||||||||||
|
Less: progress billings |
|
(2,743.1) | (3,631.8) | |||||||||||||||||
|
Total |
|
(86.3) | (96.8) | |||||||||||||||||
| As at November 30, 2010 retentions held by customers for contract work amounted to $3.1 million (2009: $13.0 million). Advances received from customers for contract work amounted to $19.4 million (2009: $38.6 million) (refer to Note 38 ‘Deferred revenue’). | ||||||||||||||||||||
| As at November 30, 2010 a total of $10.1 million (2009: $7.9 million) was recorded for losses expected at completion. | ||||||||||||||||||||
|
seabed-to-surface
|
|
115
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
24. Issued share capital
Authorised shares
| As at November 30 |
2010
Number of
|
2010
in $ millions |
2009
Number of
|
2009 in $ millions |
||||||||||||
|
Authorised common shares, $2.00 par value |
450,000,000 | 900.0 | 230,000,000 | 460.0 | ||||||||||||
| At the Extraordinary General Meeting of shareholders held on November 9, 2010 the Articles of Incorporation were amended to increase the authorised share capital from 230 million to 450 million common shares effective immediately. | ||||||||||||||||
| Issued shares | ||||||||||||||||
| As at November 30 |
2010
Number of
|
2010
in $ millions |
2009
Number of
|
2009 in $ millions |
||||||||||||
|
Fully paid and issued common shares |
194,953,972 | 389.9 | 194,953,972 | 389.9 | ||||||||||||
|
The issued common shares consist of: |
||||||||||||||||
|
Common shares excluding own shares (see below) |
183,939,210 | 367.9 | 183,207,042 | 366.4 | ||||||||||||
|
Own shares (see Note 25) |
11,014,762 | 22.0 | 11,746,930 | 23.5 | ||||||||||||
|
Total |
194,953,972 | 389.9 | 194,953,972 | 389.9 | ||||||||||||
| The Company has one class of ordinary shares which carry no right to fixed income. | ||||||||||||||||
| The common shares (excluding own shares) outstanding are as follows: | ||||||||||||||||
| For the fiscal year |
2010
Number of shares |
2009
Number of
|
||||||||||||||
|
Balance at December 1 |
183,207,042 | 182,816,093 | ||||||||||||||
|
Own shares reissued (see Note 25) |
732,168 | 390,949 | ||||||||||||||
|
Balance at November 30 |
183,939,210 | 183,207,042 | ||||||||||||||
| 25. Own shares | ||||||||||||||||
| The summary of ‘own shares’ represents the purchase of the Company’s own common shares at the market price on the date of purchase and the movements are shown in the table below: | ||||||||||||||||
| For the fiscal year |
2010
Number of shares |
2010
in $ millions |
2009
Number of
|
2009 in $ millions |
||||||||||||
|
Balance at December 1 |
11,746,930 | 222.6 | 12,137,879 | 229.4 | ||||||||||||
|
Number of shares reissued (a) |
(732,168) | (13.4) | (390,949) | (6.8) | ||||||||||||
|
Balance at November 30 |
11,014,762 | 209.2 | 11,746,930 | 222.6 | ||||||||||||
| Consisting of: | ||||||||||||||||
|
Common shares held as treasury shares |
– | 10,867,809 | ||||||||||||||
|
Common shares held as treasury shares by an indirect wholly-owned subsidiary |
11,014,762 | 879,121 | ||||||||||||||
|
Total |
11,014,762 | 11,746,930 | ||||||||||||||
(a) Delivered from the treasury shares held.
As of November 30, 2010, Acergy S.A. (now Subsea 7 S.A.) owned 10,431,762 common shares indirectly (as treasury shares), representing 5.35% of the total number of issued shares. These shares were owned as treasury shares through Subsea 7’s indirect subsidiary Acergy Investing Limited. A further 583,000 common shares were held by an employee benefit trust to satisfy performance shares under the Group’s 2009 Long-term Incentive Plan. No shares were repurchased during fiscal year 2010 (2009: Nil).
|
116 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| 26. Non-controlling interests | ||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | ||||||||||
|
At December 1 |
31.2 | 13.7 | ||||||||||
|
Share of net income for the year |
47.6 | 20.7 | ||||||||||
|
Dividends |
(20.0) | (4.9) | ||||||||||
|
Foreign currency exchange rate changes |
(2.0) | 1.7 | ||||||||||
|
At November 30 |
56.8 | 31.2 | ||||||||||
| Subsea 7’s respective interest in subsidiaries which are not wholly owned is as follows: | ||||||||||||
|
2010
% |
2009
% |
|||||||||||
|
Sonamet – Industrial SA |
55.0 | 55.0 | ||||||||||
|
Sonacergy – Servicos E Construcoes Petroliferas Lda |
55.0 | 55.0 | ||||||||||
|
Pelagic Nigeria Limited |
80.0 | 80.0 | ||||||||||
|
Offshore Installer Nigeria Limited |
60.0 | 60.0 | ||||||||||
|
Acergy Havila Limited |
50.0 | 50.0 | ||||||||||
|
Globestar Engineering Company (Nigeria) Limited |
96.2 | 96.2 | ||||||||||
| 27. Borrowings | ||||||||||||
| Borrowings consist of: | ||||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||||
|
$500 million 2.25% convertible loan notes due 2013 (see Note 28) |
435.3 | 415.6 | ||||||||||
|
Other |
– | 0.2 | ||||||||||
|
Total |
435.3 | 415.8 | ||||||||||
|
Consisting of: |
||||||||||||
|
Non-current portion of borrowings |
435.3 | 415.8 | ||||||||||
|
Current portion of borrowings |
– | – | ||||||||||
|
Total |
435.3 | 415.8 | ||||||||||
|
Commitment fees for any unused lines of credit expensed during fiscal year 2010 were $1.6 million (2009: $0.7 million). The weighted average interest rate paid on the $1 billion multi-currency revolving credit and guarantee facility was nil%. |
|
|
||||||||||
|
Facilities |
|
|||||||||||
| The $1 billion multi-currency revolving credit and guarantee facility | ||||||||||||
| On August 10, 2010 Acergy S.A. (now Subsea 7 S.A.) executed a $1 billion multi-currency revolving credit and guarantee facility with a number of banks. The facility can be used in full for the issuance of guarantees, or for a combination of guarantees and cash drawings subject to a $500 million sub-limit for cash drawings. The $1 billion facility is guaranteed by Subsea 7 S.A. (formerly Acergy S.A.), Class 3 Shipping Limited, Acergy Shipping Limited and Subsea 7 Treasury (UK) Limited (formerly Acergy Treasury Limited). Final maturity will be August 10, 2015. However, in accordance with the terms of the agreement, performance guarantees can be issued with up to 78 months duration up to one month prior to the final maturity date of the facility, subject to the Group providing cash cover for any guarantees outstanding following the final maturity date. | ||||||||||||
| The $1 billion facility contains financial covenants in respect of leverage, interest coverage and gearing ratios. The requirements of the financial covenants must be met on a consolidated basis on the last day of each quarterly interval. In addition to the financial covenants, the facility contains affirmative covenants, negative pledges and events of defaults which are customary for facilities of this nature and consistent with past practice. Such covenants specifically limit mergers or transfers, incurrence of other indebtedness, class 1 acquisitions, loans outside the Group and change of business. On September 28, 2010 the banks consented to retain their commitment under the $1 billion facility following the proposed Combination with Subsea 7 Inc. Debt existing within the Subsea 7 Inc. group on the date of the Acquisition will be managed within the terms and conditions of the $1 billion facility. | ||||||||||||
|
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|
117
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
27. Borrowings continued
The $1 billion facility also contains events of default provisions which include payment defaults (subject to a three day grace period), breach of financial covenants, breach of other obligations, breach of representations and warranties, insolvency, illegality, unenforceability, conditions subsequent, curtailment of business, claims against an obligor’s assets, appropriation of an obligor’s assets, cross-defaults to other indebtedness in excess of $10 million, failure to maintain exchange listing, material adverse change, auditor’s qualification, repudiation and material litigation.
Interest on the $1 billion facility is payable at LIBOR plus a margin which is linked to the Group’s leverage, measured as the ratio of net debt to EBITDA, and which may range from 1.75% to 2.75% per year. The fee applicable for guarantees is linked to the same ratio of net debt to EBITDA and may range from 1.75% to 2.75% per year in respect of financial guarantees and 0.88% to 1.38% in respect of performance guarantees. The margin and guarantee fee are reset quarterly in line with changes in Subsea 7’s leverage.
As part of the terms of the $1 billion facility, the $400 million amended and restated revolving credit and guarantee facility and the $200 million multi-currency revolving guarantee facility in place up to August 10, 2010 were cancelled and any amounts utilised on that date were transferred to the $1 billion facility.
The NOK 977.5 million Loan and Guarantee Facility (the ‘NOK 977.5 million facility’)
Acergy Havila Limited is a 50/50 joint venture between Acergy (Gibraltar) Limited (wholly owned by Subsea 7 S.A.) and Havila Shipping Pte Ltd. (wholly owned by Havila Shipping ASA). On October 14, 2008 the Company completed a loan and guarantee facility for post-delivery financing of up to NOK 977.5 million ($157.6 million) for the purchase of a dive support vessel to be owned by the joint venture, when it is delivered in 2011. The final termination date of the facility is no later than February 28, 2021.
The NOK 977.5 million facility contains the financial covenant that the joint venture’s current assets exceed current liabilities. This requirement must be met at the last day of each quarterly interval of each year. The facility also contains vessel covenants customary to a facility of this nature.
In addition to the above covenants, the facility also contains events of default which include payment defaults (subject to a three day grace period), breach of the financial covenant, breach of other obligations, breach of representations, insolvency, illegality, repudiation, material adverse effect, cross-defaults to other indebtedness in excess of $2.5 million for Acergy Havila Limited and in excess of $5.0 million for Subsea 7 S.A. and failure by Subsea 7 S.A. to maintain exchange listing. The facility also contains negative pledges with respect to accounts receivable and cash.
Security on the facility is provided by a first priority mortgage on the vessel. A charter guarantee has been provided by Subsea 7 S.A. In the event of an event of default occurring this turns into a several guarantee to be shared 50/50 by Subsea 7 S.A. and Havila Shipping ASA.
The facility’s commitment fee is set at a rate of 0.40%. Upon delivery of the vessel loan interest will be payable at NIBOR plus a margin of 1.65%, and guarantee fee of 1.65%.
Utilisation of the $1 billion facility (2009: $400 million and $200 million facilities) and the NOK 977.5 million facility
| As at November 30 (in $ millions) |
2010
Utilised |
2010
Unutilised |
2010
Total |
2009
Utilised |
2009
Unutilised |
2009
Total |
||||||||||||||||||
|
Cash loans |
– | 509.3 | 509.3 | – | 179.6 | 179.6 | ||||||||||||||||||
|
Guarantee facilities |
330.3 | 318.0 | 648.3 | 505.6 | 63.3 | 568.9 | ||||||||||||||||||
|
Total |
330.3 | 827.3 | 1,157.6 | 505.6 | 242.9 | 748.5 | ||||||||||||||||||
Bank overdraft and short-term lines of credit
The overdraft facilities consist of $35.5 million (2009: $36.1 million) of which $nil (2009: $nil) were drawn as at November 30, 2010.
Other facilities
In addition to the amounts available under the $1 billion facility, the Group has a $30.0 million (2009: $30.0 million) bank guarantee facility with Credit Industriel et Commercial Bank of which $9.0 million (2009: $8.0 million) was utilised as at November 30, 2010.
There are three unsecured local lines of credit in Nigeria for the sole use of Globestar Engineering Company (Nigeria) Limited, being $13.3 million with United Bank of Africa plc, $9.9 million with First Bank of Nigeria plc, and $6.6 million with Zenith Bank plc. The bonds under these facilities were issued to guarantee the project performance of the subsidiary to third parties in the normal course of business. The total amount issued under these facilities as at November 30, 2010 was $7.7 million (2009: $0.7 million).
The Group had past arrangements with a number of financial institutions to issue bank guarantees on its behalf. As at November 30, 2010, the aggregate amount of guarantees issued under these old facilities was $14.4 million (2009: $14.5 billion). There was no availability for further issuances under these facilities.
|
118 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| Guarantee arrangements with joint ventures | ||
| SapuraAcergy Assets Pte Limited (‘SAPL’), previously known as Nautical Vessels Pte Limited, is a 50/50-owned joint venture between Nautical Essence Sdn. Bhd. (wholly owned by SapuraCrest Petroleum Berhad) and Acergy (Gibraltar) Limited (wholly owned by Subsea 7 S.A.). | ||
| In 2007 the respective parent companies issued a Charter Guarantee guaranteeing the charter payments from the charterer of Sapura 3000, SapuraAcergy Sdn. Bhd. vessel to the vessel owner, SAPL. The limit of the guarantee is, at any time the sum of the outstanding amounts under the $240 million Facility Agreement of SAPL less $100 million. Any call under the guarantee will not result in a lump sum payment being made, but the guarantors, severally, will have to service the debt by way of charter payments due from the charterer to the ship owner until the termination date of the loan, which is February 2, 2015. | ||
| SapuraAcergy Sdn. Bhd. (‘SASB’) is a 50/50-owned joint venture between Nautical Essence Sdn. Bhd. (wholly owned by SapuraCrest Petroleum Berhad) and Acergy (Gibraltar) Limited (wholly owned by Subsea 7 S.A.). SASB has entered into a $181.3 million multi-currency facility for the financing of the Gumusut Project. Both Subsea 7 S.A. and SapuraCrest Petroleum Berhad have issued several guarantees for 50% of the financing respectively. The facility consists of $44.0 million available for the issuance of bank guarantees, $60.0 million available for letters of credit, and two revolving credit facilities for $57.3 million and $20.0 million respectively. At November 30, 2010 the amount available for bank guarantees was fully drawn, $16.8 million was drawn under the letter of credit facility and $12.0 million was drawn under the $20.0 million revolving credit facility. There were no drawings under the $57.3 million revolving credit facility. | ||
| 28. Convertible loan notes | ||
| On October 11, 2006 Acergy S.A. (now Subsea 7 S.A.) issued a $500.0 million in aggregate principal amount of 2.25% convertible loan notes due 2013. The issuance was completed on October 11, 2006 with the receipt of net proceeds after deduction of issuance related costs of $490.8 million. The issuance costs of $9.2 million have been split between the liability and equity components. | ||
| The convertible loan notes have an annual interest rate of 2.25% payable semi-annually in arrears on April 11 and October 11 of each year up to and including fiscal year 2013. They were issued at 100% of their principal amount and unless previously redeemed, converted or cancelled will mature on October 11, 2013 at 100% of their principal amount. The convertible loan notes are admitted to trading on the Euro MTF Market of the Luxembourg Stock Exchange. | ||
| The noteholders were granted an option which allows them to convert the convertible loan notes into common shares with an initial conversion price of $24.05 per share equivalent to 20,790,021 common shares, or at the date of issue approximately 10.7% of Acergy S.A.’s (now Subsea 7 S.A) issued share capital (excluding treasury shares held as at October 11, 2006). All $500.0 million of notes remain outstanding as at November 30, 2010 with a conversion price at that date of $22.37 (2009: $22.71) per share following the payment of the dividends since issuance, equivalent to 22,351,363 (2009: 22,016,733) common shares, or approximately 12.2% (2009:11.3%) of the Group’s issued share capital as of November 30, 2010. The conversion price will continue to be adjusted in line with its terms and conditions including payment of dividends. | ||
|
There is also an option for the Company to call the convertible loan notes after October 25, 2010, if the price of the common shares exceeds 130% of the then prevailing conversion price over the above specified period.
|
|
|
|
The following is a summary of certain other terms and conditions that apply to the Group convertible loan notes:
|
||
|
• the convertible loan notes 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 notes will rank equally with other debt issuance;
• a cross default provision subject to a minimum threshold of $10.0 million and other events of default in connection with non-payment of the convertible loan notes;
• various undertakings in connection with the term of any further issuance of common shares, continuance of the listing of the shares and the convertible loan notes on recognised stock exchanges; and
• provisions for the adjustment of the conversion price in certain circumstances. |
||
| There were no conversions of these convertible loan notes as of November 30, 2010 (2009: Nil). | ||
|
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|
|
119
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
28. Convertible loan notes continued
The net proceeds received from the issue of the convertible loan notes have been split between the liability element and an equity component, representing the fair value of the embedded option to convert the liability into equity of the Group, as follows:
| (in $ millions) | ||||||||
|
Principal value of convertible loan notes issued |
500.0 | |||||||
|
Proceeds of issue (net of apportioned transaction costs) |
490.8 | |||||||
|
Liability component at date of issue |
(362.4 | ) | ||||||
|
Equity component |
128.4 | |||||||
|
Deferred tax |
(17.7 | ) | ||||||
|
Transfer to equity reserve |
110.7 | |||||||
|
The liability component is as follows: |
||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | ||||||
|
Liability component at December 1 |
415.6 | 397.4 | ||||||
|
Interest charged (see Note 10) |
31.0 | 29.5 | ||||||
|
Interest paid |
(11.3 | ) | (11.3 | ) | ||||
|
Liability component at November 30 |
435.3 | 415.6 | ||||||
The interest charged in the year is calculated by applying an effective rate of 7.35%. The liability component is measured at amortised cost. The difference between the carrying amount of the liability component at the date of issue and the amount reported in the balance sheet at November 30, 2010 represents the effective interest rate less interest paid to that date.
29. Other non-current liabilities
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||
|
Amounts due to non-controlling shareholders of subsidiaries |
3.9 | 1.4 | ||||||
|
Accrued salaries and benefits |
5.3 | 3.4 | ||||||
|
Other |
1.2 | 2.2 | ||||||
|
Total |
10.4 | 7.0 | ||||||
| 30. Trade and other liabilities | ||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||
|
Invoice accruals |
320.7 | 244.6 | ||||||
|
Trade payables |
167.7 | 169.7 | ||||||
|
Accrued salaries and benefits |
147.0 | 143.0 | ||||||
|
Withholding taxes |
15.7 | 22.3 | ||||||
|
Interest on taxes owed |
– | 9.1 | ||||||
|
Interest and dividends payable |
0.6 | 1.7 | ||||||
|
Other taxes payable |
1.5 | 2.7 | ||||||
|
Other current liabilities |
20.1 | 31.0 | ||||||
|
Total |
673.3 | 624.1 | ||||||
The average credit period for purchases is 71 days (2009: 84 days).
|
120 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
31. Provisions
| For the fiscal year (in $ millions) | Legal | Decommissioning | Restructuring | Other | Total | |||||||||||||||||||
|
At December 1, 2008 |
9.3 | 5.4 | – | 8.5 | 23.2 | |||||||||||||||||||
|
Additional provision in the year |
1.4 | 8.4 | – | 7.2 | 17.0 | |||||||||||||||||||
|
Utilisation of provision |
(0.5 | ) | (1.0 | ) | – | (3.4 | ) | (4.9 | ) | |||||||||||||||
|
Unused amounts reversed during the year |
(1.9 | ) | – | – | (1.5 | ) | (3.4 | ) | ||||||||||||||||
|
(Reversing)/unwinding of discount rate (see Note 10) |
– | 0.3 | – | – | 0.3 | |||||||||||||||||||
|
Exchange differences |
0.5 | – | – | 0.5 | 1.0 | |||||||||||||||||||
|
At November 30, 2009 |
8.8 | 13.1 | – | 11.3 | 33.2 | |||||||||||||||||||
|
Additional provision in the year |
1.8 | 2.0 | 13.0 | 12.7 | 29.5 | |||||||||||||||||||
|
Utilisation of provision |
(1.4 | ) | (7.5 | ) | – | (3.7 | ) | (12.6 | ) | |||||||||||||||
|
Unused amounts reversed during the year |
– | (5.2 | ) | – | (5.8 | ) | (11.0 | ) | ||||||||||||||||
|
(Reversing)/unwinding of discount rate (see Note 10) |
– | (0.3 | ) | – | – | (0.3 | ) | |||||||||||||||||
|
Exchange differences |
(0.2 | ) | – | – | (0.1 | ) | (0.3 | ) | ||||||||||||||||
|
At November 30, 2010 |
9.0 | 2.1 | 13.0 | 14.4 | 38.5 | |||||||||||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||||||||||||||||
|
Consists of: |
||||||||||||||||||||||||
|
Non-current provisions |
12.4 | 10.6 | ||||||||||||||||||||||
|
Current provisions |
26.1 | 22.6 | ||||||||||||||||||||||
|
Total |
38.5 | 33.2 | ||||||||||||||||||||||
| The legal provision comprises a number of claims made against the Group. These include employee disputes, personal injury cases and lease disputes, where the timing of resolution is uncertain and the liability has been estimated by the Group’s legal advisors. | ||||||||||||||||||||||||
|
The decommissioning provision is in relation to the obligation to remove items of property, plant and equipment from Skandi Acergy at the end of its charter period. The related costs to the provision are expected to be incurred post fiscal year 2011. |
|
|||||||||||||||||||||||
|
The restructuring provision has arisen as a result of preparing the Group for the acquisition which completed on January 7, 2011. It is anticipated that the provision will be utilised in full by the end of fiscal year 2011. |
|
|||||||||||||||||||||||
| The other provisions mainly relate to tax claims (see Note 11 ‘Taxation’). |
|
|
|
|||||||||||||||||||||
|
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|
|
121
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
32. Commitments and contingent liabilities
Commitments
These consist of:
| · |
Commitment to purchase of property, plant and equipment from external suppliers as at November 30, 2010 for $299.4 million (2009: $181.6 million) of which $147.6 million (2009: $Nil) relates to the construction of Borealis. |
| · |
Commitment to purchase of intangible software from external suppliers as at November 30, 2010 for $Nil (2009: $12.6 million). |
| · |
Operating lease commitments as indicated in Note 33 ‘Operating lease arrangements’. |
| · |
A loan facility to the joint venture Seaway Heavy Lifting (SHL) of an amount up to $10 million. |
Contingent liabilities
During 2009 the Group’s Brazilian business was audited and formally assessed for ICMS tax (import duty) by the Brazilian tax authorities (Secretaria Fazenda Estado Rio de Janeiro). The amount assessed including penalties and interest as at November 30, 2010 amounted to BRL 136.0 million ($79.2 million). At November 30, 2009 the amount assessed including penalties and interest amounted to BRL 107.6 million ($61.7 million). The Group intends to challenge this assessment and will revert to the courts if necessary. No provision has been made for any payment as the Group does not believe that likelihood of payment is probable.
In the 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 several long-term projects at any given time. The Group records 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 it 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 make additional expenditures in excess of reserves that it may establish. In the ordinary course of business, various claims, suits and complaints have been filed against the Group in addition to the ones 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 they should not materially affect its consolidated financial position.
33. Operating lease arrangements
The Group as lessee
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||
|
Minimum lease payments under operating leases recognised in operating expenses for the year |
77.2 | 129.4 | 130.9 | |||||||||
The total operating lease commitments as at November 30, 2010 were $372.8 million (2009: $530.0 million). These consisted of charter hire obligations towards certain construction support, diving support, survey and inspection ships of $189.7 million (2009: $304.9 million). The remaining obligations related to office facilities and equipment as at November 30, 2010 of $183.1 million (2009: $225.1 million).
The Group had outstanding commitments for future minimum lease payments under non-cancellable operating leases, which fall due as follows:
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||
|
Within one year |
68.2 | 109.9 | ||||||
|
Years two to five inclusive |
223.3 | 309.9 | ||||||
|
After five years |
81.3 | 110.2 | ||||||
|
Total |
372.8 | 530.0 | ||||||
The following renewal options have been excluded from the outstanding commitments:
| · |
Acergy Viking – ten renewal options consisting of two options for two years and eight options for one year; with purchase options after eight, eleven, fourteen and seventeen years; |
| · |
Skandi Acergy – four renewal options consisting of two options for two years each and two options for one year each. |
|
122 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| The Group as sub-lessor | ||||||||||||
| Income from sub-leases earned during the year was $8.0 million (2009: $47.2 million) and relates to shipping charters and property. | ||||||||||||
| At the balance sheet date, the Group had contracted with tenants for the following future minimum lease payments: | ||||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||||
|
Within one year |
9.0 | 107.5 | ||||||||||
|
Years two to five inclusive |
3.3 | 319.1 | ||||||||||
|
Total |
12.3 | 426.6 | ||||||||||
| The Group as lessor | ||||||||||||
| For contracts that meet the definition of leases, the rental income earned during the fiscal year 2010 was $182.5 million (2009: $79.7 million) and related to shipping charters. Pertinacia and Polar Queen, which were both leased in 2009 and acquired in 2010, have been assigned to new long-term shipping charters. | ||||||||||||
|
The Group had contracted with its lessees for the following future minimum lease receipts: |
|
|||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||||
|
Within one year |
185.0 | 59.5 | ||||||||||
|
Years two to five inclusive |
364.6 | – | ||||||||||
|
Total |
549.6 | 59.5 | ||||||||||
| 34. Financial instruments | ||||||||||||
| Significant accounting policies | ||||||||||||
| Details of the significant accounting policies and methods adopted, including the criteria for recognition, the basis of measurement and the basis on which income and expenses are recognised, in respect of each class of financial asset, financial liability and equity instrument are disclosed in Note 3 ‘Significant accounting policies’. | ||||||||||||
| 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 financial instruments to hedge these risk exposures. The use of financial instruments is governed by the Group’s policies approved by the Board, which provide written policies on foreign exchange risk, interest rate risk, credit risk, the use of non-derivative financial instruments, and the investment of excess liquidity.
|
|
|
||||||||||
| The Group reviews compliance with policies and exposure limits on a continuous 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 (see below) and interest rates (see below). 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 change to the Group’s exposure to market risks or the manner in which it manages and measures the risk in the current year. |
|
|||||||||||
|
Foreign currency risk management |
||||||||||||
|
The Group undertakes certain transactions denominated in foreign currencies. Hence, exposures to exchange rate fluctuations arise. Exchange rate exposures are managed within approved policy parameters utilising forward foreign exchange contracts.
|
|
|||||||||||
| The Group’s reporting currency is the US Dollar. The majority of net operating expenses and income are denominated in the functional currency of the individual subsidiaries operating in different regions, namely: | ||||||||||||
|
• Acergy AFMED – US Dollar, Euro and Nigerian Naira; |
||||||||||||
|
• Acergy NEC – US Dollar, British Pound Sterling, Norwegian Krone and Canadian Dollar; |
||||||||||||
|
• Acergy NAMEX – US Dollar; |
||||||||||||
|
• Acergy SAM – Brazilian Real and US Dollar; and |
||||||||||||
|
• Acergy AME – US Dollar and Australian Dollar. |
||||||||||||
|
seabed-to-surface
|
|
123
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
34. Financial instruments continued
The Group does not use derivative instruments to hedge the exposure to exchange rate fluctuations from its net investments in foreign subsidiaries, primarily in the United Kingdom, Norway, France and Brazil, and from its share of the local currency earnings in its operations in Acergy AFMED, Acergy NEC, and Acergy SAM.
The Group conducts operations in many countries and, as a result, is exposed to currency fluctuations through generation of revenue and expenditure in the normal course of business. Hence, exposures to exchange rate fluctuations arise. The Group’s currency rate exposure policy prescribes the range of allowable hedging activity. The Group primarily uses forward foreign exchange contracts to hedge capital expenditures and operational non-functional currency exposures on a continuing basis for periods consistent with its committed exposures.
The carrying amounts of the Group’s primary foreign currency denominated monetary assets and monetary liabilities, including foreign exchange derivatives, receivables and borrowings issued in a currency different from the functional currency of the issuer, and inter-company foreign currency denominated receivables, payables, and loans at the balance sheet date are as follows:
| Assets | Liabilities | |||||||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | 2010 | 2009 | ||||||||||||
|
British Pound Sterling |
198.4 | 255.9 | 370.2 | 316.8 | ||||||||||||
|
Euro |
384.2 | 866.9 | 456.0 | 829.2 | ||||||||||||
|
Norwegian Krone |
83.2 | 143.9 | 57.7 | 39.7 | ||||||||||||
|
US Dollar |
544.4 | 748.4 | 1,092.5 | 650.8 | ||||||||||||
Foreign currency sensitivity analysis
The Group operates in various geographical locations and is exposed to a number of currencies dependent upon the functional currency of individual subsidiaries as indicated in the foreign currency risk section above.
The Group considers that its principal currency exposure is to movements in the US Dollar against other currencies on the basis that the US Dollar is the Group’s reporting currency, the functional currency of many of its subsidiaries and the transaction currency of a significant volume of the Group’s cash flows. The Group has performed sensitivity analyses to indicate how profit or loss and equity would have been 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 analysis of the impact on profit and loss in each year is based on monetary assets and liabilities in the balance sheet at the end of each respective year.
The Group analysis of the impact on equity includes the profit and loss movements from above in addition to the impacts on the translation reserve in respect of inter-company balances that form part of the net investment in a foreign operation and the hedging reserve in respect of designated hedges.
The sensitivity analysis includes the impact of exchange rate movements on foreign currency derivatives. The amounts disclosed have not been adjusted for the impact of taxation.
Based on the above, a 10% increase in the US Dollar exchange rate against other currencies in which the Group transacts would reduce net foreign currency exchange losses reported in other gains and losses by $23.6 million (2009: loss $12.3 million). The impact on equity would be a decrease in reported net assets of $40.9 million (2009: reduction $8.6 million). The higher foreign currency exchange rate sensitivity in profit in 2010 compared with 2009 is attributable primarily to reclassification of certain monetary items forming part of the net investment in foreign operations, and therefore an equity exposure, at the previous Balance Sheet date. Equity is more sensitive in 2010 primarily due to large value hedging instruments in respect of future US Dollar revenues in an Acergy AFMED Euro functional entity.
Forward foreign exchange contracts
The Group enters into primarily standard forward foreign exchange contracts with maturities of up to five years, to manage the risk associated with transactions when there is a minimum level of exposure risk. These transactions consist of highly probable cash flow exposure relating to operating income and expenditure and capital expenditure.
|
124 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| The following table details the forward foreign currency contracts outstanding as at the balance sheet date: | ||||||||||||||||||||||||||
|
As at November 30, 2010
|
|
|||||||||||||||||||||||||
|
Foreign Currency Value By Contract Maturity |
US Dollar 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 | ||||||||||||||||||||
|
Australian Dollar |
– | – | 1.3 | – | – | – | ||||||||||||||||||||
|
Brazilian Real |
9.6 | 0.8 | – | – | 0.7 | – | ||||||||||||||||||||
|
British Pound Sterling |
10.1 | 5.2 | 48.5 | – | (1.5) | 0.3 | ||||||||||||||||||||
|
Canadian Dollar |
32.8 | – | – | – | (0.2) | – | ||||||||||||||||||||
|
Danish Krone |
40.2 | – | 24.0 | – | (0.4) | – | ||||||||||||||||||||
|
Euro |
195.1 | – | 18.7 | – | (7.5) | |||||||||||||||||||||
|
Norwegian Krone |
150.1 | 265.4 | 219.3 | – | (1.1) | (2.6) | ||||||||||||||||||||
|
Singapore Dollar |
– | – | 2.8 | – | – | – | ||||||||||||||||||||
|
US Dollar |
96.1 | 30.8 | 290.3 | 421.1 | (6.2) | (6.3) | ||||||||||||||||||||
|
Total |
(16.2) | (8.6) | ||||||||||||||||||||||||
|
As at November 30, 2009
|
||||||||||||||||||||||||||
|
Foreign Currency Value By Contract Maturity |
US Dollar 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 | ||||||||||||||||||||
|
Brazilian Real |
11.1 | – | – | – | 1.8 | – | ||||||||||||||||||||
|
British Pound Sterling |
37.8 | 6.8 | 91.8 | – | (3.6) | (1.3) | ||||||||||||||||||||
|
Danish Krone |
31.5 | – | 47.2 | – | (0.3) | – | ||||||||||||||||||||
|
Euro |
254.4 | 19.6 | 12.7 | – | 4.2 | 0.3 | ||||||||||||||||||||
|
New Zealand Dollar |
– | – | 4.7 | – | – | – | ||||||||||||||||||||
|
Norwegian Krone |
138.2 | 403.5 | – | – | 1.2 | 2.6 | ||||||||||||||||||||
|
Singapore Dollar |
13.3 | – | – | – | – | – | ||||||||||||||||||||
|
US Dollar |
177.0 | 32.2 | 211.2 | 98.1 | (5.5) | 1.6 |
|
|||||||||||||||||||
|
Total |
(2.2) | 3.2 | ||||||||||||||||||||||||
|
Hedge accounting |
|
|||||||||||||||||||||||||
| The following table details the outstanding forward foreign exchange currency contracts which are designated as hedging instruments as at reporting date: | ||||||||||||||||||||||||||
|
As at November 30, 2010
|
|
|||||||||||||||||||||||||
|
Foreign Currency Value By Contract Maturity |
US Dollar 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 | ||||||||||||||||||||
|
Cash flow hedges: |
||||||||||||||||||||||||||
|
British Pound Sterling |
5.0 | 5.3 | – | – | 0.3 | 0.2 | ||||||||||||||||||||
|
Danish Krone |
– | – | – | – | – | – | ||||||||||||||||||||
|
Euro |
21.5 | – | 18.7 | – | (3.5) | – | ||||||||||||||||||||
|
Norwegian Krone |
150.1 | 265.4 | – | – | (1.0) | (2.6) | ||||||||||||||||||||
|
US Dollar |
40.1 | 30.8 | 285.3 | 421.1 | (9.0) | (6.3) | ||||||||||||||||||||
|
Total |
(13.2) | (8.7) | ||||||||||||||||||||||||
|
seabed-to-surface
|
|
125
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
34. Financial instruments continued
As at November 30, 2009
|
Foreign Currency Value By Contract Maturity |
US Dollar 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 | ||||||||||||||||||||||
|
Cash flow hedges: |
||||||||||||||||||||||||||||
|
British Pound Sterling |
3.7 | – | – | – | (0.2 | ) | – | |||||||||||||||||||||
|
Danish Krone |
31.5 | – | 42.7 | – | (0.3 | ) | – | |||||||||||||||||||||
|
Euro |
11.6 | – | – | – | 0.5 | – | ||||||||||||||||||||||
|
Norwegian Krone |
138.2 | 403.5 | – | – | 1.2 | 2.6 | ||||||||||||||||||||||
|
US Dollar |
110.6 | 19.2 | 178.5 | 94.4 | (2.7 | ) | 2.2 | |||||||||||||||||||||
|
Total |
(1.5 | ) | 4.8 | |||||||||||||||||||||||||
The Group earns revenue in currencies other than the functional currency of the contracting entity; at the reporting date the main such transactions are US Dollar revenues for customer contracts in the Acergy AFMED region. The Consolidated Income Statement is impacted when the services are performed by the Group and the related receivable is consequently recognised. The hedging reserve balance at November 30, 2010 is a loss of $22.9 million (2009: loss of $3.6 million) arising on hedges maturing on or before February 28, 2014. There is no significant difference between the period of cash flow and that of consolidated income statement impact.
The Group incurs operating expenses in currencies other than the functional currency of the operating entity; at the reporting date the main such transactions are a NOK vessel charter and ‘one-off’ project expenses in US Dollars (primarily for projects in the Acergy AFMED region). The Consolidated Income Statement is impacted when the supplier performs the underlying service and the related liability is consequently recognised. The hedging reserve balance at November 30, 2010 is a gain of $7.1 million (2009: gain of $5.9 million) arising on hedges maturing on or before February 28, 2014. There is no material difference between the period of the Consolidated Cash Flow statement and that of the Consolidated Income Statement impact.
The Group invests capital expenditure amounts in respect of fixed assets which are in currencies other than the functional currency of the asset owning entity. The Group’s policy is to adjust, at initial recognition, the carrying amount of the fixed asset. The impact on the income statement is in accordance with the depreciation schedule of the related fixed assets. The hedging reserve balance at November 30, 2010 is a gain of $0.1 million (2009: gain of $0.1 million) arising on hedges maturing on or before April 13, 2011. The impact on the Consolidated Income Statement is expected to occur linearly within the 15 years to November 30, 2025.
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 derivatives is deferred in equity within ‘other reserves’ as hedging reserves. The resulting cumulative gains or losses will be recycled 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 Recognised Income and Expense.
The gains or losses relating to the ineffective portion of cash flow hedges is recognised in the Consolidated Income Statement and amounted to a gain of $0.1 million (2009: loss of $0.1 million).
The hedging reserve represents hedging gains and losses recognised on the effective portion of cash flow hedges as follows:
| For the fiscal year (in $ million) | 2010 | 2009 | ||||||
|
As at December 1 |
2.4 | (11.6 | ) | |||||
|
Gains/(losses) on the effective portion of derivatives deferred to equity: |
||||||||
|
hedges on capital expenditure |
0.3 | 0.5 | ||||||
|
hedges on revenue |
(38.4 | ) | 30.8 | |||||
|
hedges of operating expenses |
(2.7 | ) | (14.9 | ) | ||||
|
income tax gains/(losses) recognised in equity |
6.2 | (12.3 | ) | |||||
|
Cumulative deferred (gains)/losses transferred to Consolidated income statement (see below): |
||||||||
|
hedges on revenue |
12.9 | 10.2 | ||||||
|
hedges of operating expenses |
3.8 | (0.5 | ) | |||||
|
Cumulative deferred gains/(losses) transferred to initial carrying amount: |
||||||||
|
hedges on capital expenditure |
(0.2 | ) | 0.2 | |||||
|
Balance at November 30 |
(15.7 | ) | 2.4 | |||||
|
126 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| Cumulative gains/(losses) transferred from the hedging reserve to the Consolidated income statement | ||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | ||||||
|
Cumulative deferred (losses) recognised in revenue |
(10.8) | (12.4) | ||||||
|
Cumulative deferred (losses)/gains recognised in operating expenses |
(3.2) | 2.0 | ||||||
|
Cumulative deferred (losses)/gains recognised in other gains and losses |
(2.7) | 0.7 | ||||||
|
Total |
(16.7) | (9.7) | ||||||
|
Transfers to the Consolidated Income Statement in respect of forecast transactions no longer expected to occur was $Nil (2009: $Nil). |
||||||||
|
Interest rate risk management |
||||||||
| The Group places surplus funds on the money markets to generate an investment return for short durations only, 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 borrows funds at fixed and variable interest rates and has certain revolving credit and guarantee facilities (refer to Note 27 ‘Borrowings’). |
||||||||
|
The Group’s exposure to interest rates on financial assets and financial liabilities is detailed in the liquidity risk management section of this Note. |
||||||||
|
Interest rate sensitivity analysis |
||||||||
| Interest on the facilities discussed in Note 27 ‘Borrowings’ is payable at LIBOR plus a margin which is linked to the ratio of net debt to EBITDA and ranges from 0.8% to 1.9% per year. As at November 30, 2010 the Group had significant cash deposits leaving it in net cash position at a margin of 0.8% and it would have required a significant reduction in EBITDA during fiscal year 2010 to move the Group to the highest threshold. | ||||||||
|
The Group’s income and equity balances are not significantly impacted by changes to interest rates. |
||||||||
|
Credit risk management |
||||||||
| Credit risk arises from the financial assets of the Group, which comprise cash and cash equivalents, trade and other receivables, derivative instruments and the granting of financial guarantees. 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 only dealing with creditworthy counterparties and obtaining sufficient collateral, where appropriate, as a means of mitigating the risk of financial loss from defaults. | ||||||||
|
The Group only invests with institutions that are rated the equivalent of investment grade and above, except for an insignificant amount of cash held at a lower than investment grade institution. This information is supplied by independent rating agencies. The Group’s exposure and the credit ratings of its counterparties are continuously monitored and the aggregate value of transactions concluded is spread amongst approved counterparties. Credit exposure is controlled by counterparty limits that are reviewed and approved by the risk management committee annually. 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. |
|
|||||||
|
Net trade receivables (refer to Note 20 ‘Trade and other receivables’) consist of a large number of clients, spread across geographical areas. Ongoing credit evaluation is performed on the financial condition of accounts receivable. The following table places clients in three debtor categories of outstanding balances as at November 30: |
||||||||
|
As at November 30 |
||||||||
| 2010 | 2009 | |||||||
| Trade debtor category |
Debtor category
percentage |
Debtor category
percentage |
||||||
|
National oil and gas companies |
5% | 21% | ||||||
|
International oil and gas companies |
75% | 61% | ||||||
|
Independent oil and gas companies |
20% | 18% | ||||||
|
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 whereas both international and independent oil and gas companies have a majority of public or private ownership. International oil and gas companies are generally greater in size and scope than independent oil and gas companies although distinction between them ultimately relates to the way the company describes itself. |
||||||||
|
seabed-to-surface
|
|
127
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
34. Financial instruments continued
The following table details the maturity analysis for trade receivables.
As at November 30, 2010
| (in $ millions) |
Less than
1 month |
1-3 months |
3 months
to 1 year |
1-5 years | 5+ years | Total | ||||||||||||||||||
|
Trade receivables |
156.9 | 72.3 | 18.0 | – | – | 247.2 | ||||||||||||||||||
|
Trade receivables considered impaired |
– | – | – | 1.5 | – | 1.5 | ||||||||||||||||||
|
Total trade receivables |
156.9 | 72.3 | 18.0 | 1.5 | – | 248.7 | ||||||||||||||||||
| As at November 30, 2009 | ||||||||||||||||||||||||
| (in $ millions) |
Less than
1 month |
1-3 months |
3 months
to 1 year |
1-5 years | 5+ years | Total | ||||||||||||||||||
|
Trade receivables |
165.5 | 14.4 | 21.7 | – | – | 201.6 | ||||||||||||||||||
|
Trade receivables considered impaired |
– | – | – | 0.4 | – | 0.4 | ||||||||||||||||||
|
Total trade receivables |
165.5 | 14.4 | 21.7 | 0.4 | – | 202.0 | ||||||||||||||||||
Trade receivables balances beyond the one month ageing category in the table above are considered past due but not impaired. The credit quality of these amounts is considered sound. 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 values of the cash and cash equivalents, debtors, and derivative assets accounts.
Concentration of credit risk
The Group depends on certain significant clients. During fiscal year 2010 two clients (2009: two clients) contributed to more than 10% of the Group’s revenue from continuing operations. The contribution from these clients was $837.7 million or 35% (2009: $875.6 million or 40%). The amounts of the receivables balance of the Group’s five major clients as at November 30 are shown in the table below:
|
As at November 30 (in $ millions) Counterparty |
2010 | |||
|
Client A |
119.6 | |||
|
Client B |
37.8 | |||
|
Client C |
13.5 | |||
|
Client D |
13.2 | |||
|
Client E |
11.0 | |||
|
As at November 30 (in $ millions) Counterparty |
2009 | |||
|
Client F |
50.6 | |||
|
Client G |
35.8 | |||
|
Client H |
25.7 | |||
|
Client I |
24.0 | |||
|
Client J |
23.7 | |||
The client mix for outstanding accounts receivable balances in 2010 is not the same as 2009.
The Group does not have any significant credit risk exposure to any single counterparty as at November 30, 2010. 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 year end, an insignificant amount of cash was held at a low credit-rating bank.
The table below shows the carrying value of amounts on deposit at the balance sheet date using the Standard and Poor’s credit rating.
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||
| Counterparty | Carrying amount | Carrying amount | ||||||
|
Counterparties rated AAA |
– | 206.8 | ||||||
|
Counterparties rated AA- to AA+ |
153.5 | 232.1 | ||||||
|
Counterparties rated A- to A+ |
43.5 | 157.8 | ||||||
|
Counterparties rated BBB + or below |
12.0 | – | ||||||
|
128 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| Liquidity risk management |
|
|||||||||||||||||||||||||
| Ultimate responsibility for liquidity risk management rests with the Board, which has built an appropriate liquidity risk management framework for the management of the Group’s short, medium and long-term funding and liquidity management requirements. The Group manages liquidity risk by maintaining what it believes are adequate reserves, banking facilities and reserve borrowing facilities, by continuously monitoring forecast and actual cash flows and matching the maturity profiles of financial assets and liabilities. Included in Note 27 ‘Borrowings’ is a listing of undrawn facilities that the Group has at its disposal. | ||||||||||||||||||||||||||
|
Liquidity and interest risk tables |
|
|||||||||||||||||||||||||
| The following tables detail the Group’s remaining contractual maturity for its non-derivative financial liabilities. | ||||||||||||||||||||||||||
|
The tables have been drawn up based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Group can be required to pay. The table consists of the principal cash flows: |
|
|||||||||||||||||||||||||
|
As at November 30, 2010 |
|
|||||||||||||||||||||||||
| (in $ millions) |
Less than
1 month |
1-3 months |
3 months
to 1 year |
1-5 years | 5+ years | Total | ||||||||||||||||||||
|
Trade payables |
103.1 | 41.8 | 22.0 | 0.8 | – | 167.7 | ||||||||||||||||||||
|
Convertible loan notes |
– | – | 11.3 | 522.5 | – | 533.8 | ||||||||||||||||||||
|
As at November 30, 2009 |
|
|||||||||||||||||||||||||
| (in $ millions) |
Less than
1 month |
1-3 months |
3 months
to 1 year |
1-5 years | 5+ years | Total | ||||||||||||||||||||
|
Trade payables |
54.7 | 109.5 | 5.5 | – | – | 169.7 | ||||||||||||||||||||
|
Convertible loan notes |
– | – | 11.3 | 533.7 | – | 545.0 | ||||||||||||||||||||
|
The following table details the Group’s liquidity analysis for its derivative financial instruments. The table has been drawn up based on the undiscounted net cash outflows/(inflows) on the derivative instruments that settle on a net basis and the undiscounted gross outflows and (inflows) on those derivatives 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 November 30, 2010 | ||||||||||||||||||||||||||
| (in $ millions) |
Less than
1 month |
1-3 months |
3 months
to 1 year |
1-5 years | 5+ years | Total | ||||||||||||||||||||
|
Net settled |
||||||||||||||||||||||||||
|
Foreign exchange forward contracts |
– | 0.2 | 1.3 | – | – | 1.5 | ||||||||||||||||||||
|
Gross settled |
||||||||||||||||||||||||||
|
Foreign exchange forward contract payments |
276.4 | 135.4 | 335.0 | 413.0 | – | 1,159.8 | ||||||||||||||||||||
|
Foreign exchange forward contract receipts |
(270.4) | (127.3) | (322.7) | (406.7) | – | (1,127.1) | ||||||||||||||||||||
|
Total |
6.0 | 8.3 | 13.6 | 6.3 | – | 34.2 | ||||||||||||||||||||
|
As at November 30, 2009 |
||||||||||||||||||||||||||
| (in $ millions) |
Less than
1 month |
1-3 months |
3 months
to 1 year |
1-5 years | 5+ years | Total | ||||||||||||||||||||
|
Net settled |
||||||||||||||||||||||||||
|
Foreign exchange forward contracts |
1.4 | 4.6 | 0.2 | 0.5 | – | 6.7 | ||||||||||||||||||||
|
Gross settled |
||||||||||||||||||||||||||
|
Foreign exchange forward contract payments |
93.1 | 199.3 | 126.8 | 93.7 | – | 512.9 | ||||||||||||||||||||
|
Foreign exchange forward contract receipts |
(91.8) | (190.2) | (121.4) | (91.3) | – | (494.7) | ||||||||||||||||||||
|
Total |
2.7 | 13.7 | 5.6 | 2.9 | – | 24.9 | ||||||||||||||||||||
|
Fair value of financial instruments |
|
|||||||||||||||||||||||||
| The fair values of financial assets and financial liabilities are determined as follows: | ||||||||||||||||||||||||||
|
• foreign currency forward contracts are measured using quoted forward exchange rates and yield curves derived from quoted interest rates matching maturities of the contract;
• the fair value of financial assets and financial liabilities with standard terms and conditions and traded on active liquid markets is determined with reference to quoted market prices;
• the fair value of other financial assets and financial liabilities (excluding derivative instruments) is 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; |
|
|||||||||||||||||||||||||
|
seabed-to-surface
|
|
129
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
34. Financial instruments continued
| · |
the fair value of derivative instruments is 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 derivatives, and option pricing models for optional derivatives; and |
| · |
the fair value of financial guarantee contracts is determined using option pricing models where the main assumptions are the probability of default by the specified counterparty extrapolated from market-based credit information and the amount of loss, given the default. Except as detailed in the following table, the carrying amounts of financial assets and financial liabilities recorded at amortised cost in the financial statements approximate their fair values: |
| As at November 30 (in $ millions) |
2010
Carrying amount |
2010
Fair value |
2009
Carrying amount |
2009
Fair value |
||||||||||||
|
Financial assets: |
||||||||||||||||
|
Financial assets at FVTPL: |
||||||||||||||||
|
Cash and cash equivalents |
484.3 | 484.3 | 907.6 | 907.6 | ||||||||||||
|
Restricted cash deposits |
3.0 | 3.0 | 19.6 | 19.6 | ||||||||||||
|
Fair value through profit or loss |
8.9 | 8.9 | 11.0 | 11.0 | ||||||||||||
|
Derivative instruments in designated hedge accounting relationships |
3.9 | 3.9 | 14.1 | 14.1 | ||||||||||||
|
Loans and receivables: |
||||||||||||||||
|
Net trade receivables (see Note 20) |
247.2 | 247.2 | 201.6 | 201.6 | ||||||||||||
|
Employee loans |
1.2 | 1.2 | 1.7 | 1.7 | ||||||||||||
|
Financial liabilities: |
||||||||||||||||
|
Financial liabilities at FVTPL: |
||||||||||||||||
|
Fair value through profit or loss |
11.8 | 11.8 | 13.3 | 13.3 | ||||||||||||
|
Derivative instruments in designated hedge accounting relationships |
25.8 | 25.8 | 10.8 | 10.8 | ||||||||||||
|
Loans and receivables: |
||||||||||||||||
|
Borrowings – Other debt (including current portion) |
– | – | 0.2 | 0.2 | ||||||||||||
|
Borrowings – Convertible notes |
435.3 | 470.5 | 415.6 | 438.7 | ||||||||||||
Risk exposure and responses
|
Fair value As at November 30 (in $ millions) |
2010
Quoted market price (Level 1) |
2010
Valuation
|
2010
Valuation
(Level 3) |
2009
Quoted market price (Level 1) |
2009
Valuation
|
2009
Valuation
(Level 3) |
||||||||||||||||||
| Financial assets: | ||||||||||||||||||||||||
| Fair value through profit or loss | – | 8.9 | – | – | 11.0 | – | ||||||||||||||||||
|
Derivative instruments in designated hedge accounting relationships |
– | 3.9 | – | – | 14.1 | – | ||||||||||||||||||
| Financial liabilities: | ||||||||||||||||||||||||
| Fair value through profit or loss | – | 11.8 | – | – | 13.3 | – | ||||||||||||||||||
| Derivative instruments in designated hedge accounting relationships | – | 25.8 | – | – | 10.8 | – | ||||||||||||||||||
Assumptions used in determining fair value of financial assets and liabilities
Restricted cash deposits
The carrying amounts of restricted cash deposits approximate their fair value which is based on actual deposits held with financial institutions.
Net trade receivables
The fair value of trade receivables is based on their carrying value which is representative of outstanding debtor amounts owing and includes taking into consideration any amounts of possible doubtful debt.
Employee loans
The carrying amounts of employee loans approximate their fair value. The value of these debts is based on actual amounts to be repaid in the future.
Borrowings – Convertible loan notes
The fair value of the liability component of convertible loan notes is determined assuming redemption on October 11, 2013 and using the market interest rate available to the Group as at the Balance Sheet date.
|
130 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| Forward foreign exchange contracts | ||||||||||||||
| The fair value of outstanding financial instruments (as indicated above in the table as FVTPL and derivative instruments) is calculated, using appropriate market information and valuation methodologies. In some cases, judgement is required to develop the estimates of fair values, thus the estimates provided herein are not necessarily indicative of the amounts that could be realised in a current market exchange. | ||||||||||||||
|
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 stakeholders through the optimisation of the debt and equity balance. | ||||||||||||||
|
The capital structure of the Group consists of debt, which includes borrowings disclosed in Note 27, cash and cash equivalents and equity attributable to equity holders of the parent, comprising issued capital, reserves and retained earnings. |
|
|||||||||||||
|
The group monitors capital on the basis of debt service ratio (net debt/Adjusted EBITDA) and debt volume (net debt/enterprise value). Net debt is calculated by the principal value of convertible note borrowings plus deferred revenue and operating lease arrangements, less cash and cash equivalents. Enterprise value is the market capitalisation plus net debt. |
|
|||||||||||||
|
Debt service |
||||||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||||||
|
Principal value of convertible loan note borrowings (Note 28) |
|
500.0 | 500.0 | |||||||||||
|
Deferred revenue (Note 38) |
|
217.8 | 279.8 | |||||||||||
|
Operating lease arrangements (Note 33) |
|
372.8 | 530.0 | |||||||||||
|
Cash and cash equivalents |
|
(484.3) | (907.6) | |||||||||||
|
Net debt |
|
606.3 | 402.2 | |||||||||||
|
Adjusted EBITDA |
|
619.0 | 504.9 | |||||||||||
|
Debt service ratio |
|
0.98x | 0.80x | |||||||||||
|
Debt volume |
||||||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||||||
|
Net debt (as above) |
|
606.3 | 402.2 | |||||||||||
|
Enterprise value |
|
4,378.9 | 3,234.7 | |||||||||||
|
Debt volume |
|
14% | 12% | |||||||||||
|
35. Related party transactions |
|
|
||||||||||||
| Key management personnel | ||||||||||||||
| Key management personnel include the Board, the Vice Presidents of each of the five business segments or divisions and other members of the Group’s Corporate Management Team. The remuneration of these personnel is determined by the Compensation Committee having regard to the performance of individuals and market trends. | ||||||||||||||
|
The remuneration of key management personnel during the year was as follows: |
|
|||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||||
|
Salaries and other short-term employee benefits |
12.6 | 12.1 | 12.4 | |||||||||||
|
Termination benefits |
2.0 | – | – | |||||||||||
|
Share based payment |
3.4 | 1.8 | 0.8 | |||||||||||
|
Post-employment benefits |
0.5 | 1.6 | 0.8 | |||||||||||
|
Other long-term benefits |
3.1 | 0.3 | 0.4 | |||||||||||
|
Total |
21.6 | 15.8 | 14.4 | |||||||||||
|
Transactions with key management personnel |
|
|||||||||||||
| The global support centre was relocated during fiscal year 2008 from Sunbury-on-Thames to Hammersmith in the United Kingdom. One of the key management personnel received relocation assistance which took the form of a $0.1 million reimbursement of professional fees and associated relocation costs, $0.1 million mortgage assistance and a guaranteed receipt of the market value of a property in Sunbury-on-Thames from the date of announcement of the relocation. The property was sold to a third party in the third quarter of fiscal year 2008 resulting in a loss of less than $0.1 million. | ||||||||||||||
|
During the fourth quarter of fiscal year 2008 share options were exercised by one member of the key management personnel. The Group paid $0.3 million of payroll taxes associated with this exercise which was subsequently reimbursed on December 1, 2008. The amount is therefore considered to be a loan to a related party as at November 30, 2008. |
|
|||||||||||||
|
During fiscal year 2008, 352,500 share options were granted to key management personnel. On December 1, 2008 options granted in the fiscal year 2008 to the non-executive directors were cancelled as part of the Group’s continuous effort of improving corporate governance procedures. |
|
|||||||||||||
|
seabed-to-surface
|
|
131
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
35. Related party transactions continued
During fiscal year 2010, key management personnel were awarded the rights to 465,000 shares under the 2009 Long-Term Incentive Plan. Refer to Note 36 – ‘Share based payments’ for details.
Loans and trade receivables with related parties
As disclosed in Note 17 ‘Interest in associates and joint ventures’, the Group has provided loans to associates and joint venture entities at rates comparable to the average commercial rate of interest amounting to $43.2 million (2009: $32.7 million) and trade receivables of $22.5 million (2009: $44.0 million).
There were no loans to key management personnel in 2010 (2009: nil).
Employee loans consisting primarily of salary and travel advances to employees in furtherance of the Group’s business amounted to $2.3 million (2009: $1.7 million).
Trading transactions
During the year, the Group entered into transactions with joint ventures and associates which are reported in Note 17 ‘Interest in associates and joint ventures’ and are made on terms equivalent to those that prevail in arm’s length transactions and are made only if such terms can be substantiated.
36. Share based payments
Equity-settled share option plan
The Group operates a share option plan which was approved in April 2003 (the ‘2003 Plan’). This plan includes an additional option plan for key directors and employees resident in France as a sub-plan (the ‘French Plan’), and additional options which are granted under the Senior Management Incentive Plan (SMIP). A Compensation Committee appointed by the Board administers these plans. Options are awarded at the discretion of the Compensation Committee to directors and key employees.
Under the 2003 Plan options up to but not exceeding 6.3 million common shares can be granted. Following shareholder approval at the Extraordinary General Meeting held on December 18, 2008, the 2003 Plan was expanded to cover up to 8.7 million shares. This plan replaced the previous plan (the ‘1993 Plan’). Any options granted under the French Plan are included as part of this limit. Other than options granted under the SMIP, options under the 2003 Plan (and therefore also under the French Plan) may be granted, 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. Such options vest 25% on the first anniversary of the grant date, with an additional 25% vesting on each subsequent anniversary. The cost of these non-performance share options are therefore recognised using the graded vesting attribution method. Share option exercises are satisfied by either issuing new shares or 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.
In fiscal year 2010 no common share options were granted (2009: nil common share options), and no options were granted under the French Plan (2009: nil options).
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 December 17, 2009. The 2009 LTIP is an essential component of the Company’s compensation policy, and was designed to place the Company on a par with competitors in terms of recruitment and retention abilities. The 2009 LTIP provides for whole share awards, which vest after three years, based on the performance conditions set out below:
Performance conditions are based on relative Total Shareholder Return (‘TSR’) against a specified comparator group of 13 companies determined over a three year period. This comparator group included Subsea 7 Inc., which ceased to form part of the comparator group upon Completion. The Company would have to deliver TSR above the median for any awards to vest. At the median level, only 30% of the maximum award would vest. The maximum award would only be achieved if the Company achieved top decile TSR (i.e. if, when added to the comparator group, the Company was first or second, in terms of TSR performance). In addition, individual award caps have been introduced. No senior executive or other employee may be granted shares under the 2009 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 his or her annual base salary as of the first day of said year. Additionally, a holding requirement for senior executives has been introduced. Senior executives must hold 50% of all awards that vest until they have built up a shareholding of 1.5 x salary, which must be maintained.
The first tranche of awards under the 2009 LTIP was made on April 8, 2010. Awards were made over 970,000 performance shares, subject to the 2009 LTIP’s performance conditions, in conjunction with which 583,000 were transferred to an Employee Benefit Trust at the closing share price on the Oslo Stock Exchange on April 9, 2010 from Treasury Shares previously held indirectly by Acergy Investing Limited. The fair market value per share on the date of the award was $19.83. The 2009 LTIP currently covers approximately 100 senior managers and key employees. Grants are determined by the Company’s Compensation Committee, which is responsible for operating and administering the plan. The 2009 LTIP has a five-year term with awards being made annually. The aggregate number of shares subject to all awards which may be granted in any calendar year is limited to 0.5% of issued and outstanding share capital on January 1 of each such calendar year.
|
132 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| Senior Management Incentive Plan | ||
| As a condition to a bonding facility agreement which was finalised in 2004, there was a requirement to put in place a Key Staff Retention Plan, now called the Senior Management Incentive Plan (‘SMIP’), in order to secure the services of certain senior executives. The SMIP provided for deferred compensation as a combination of cash and performance-based share options, linked to the attainment of a number of strategic objectives for each of the fiscal years 2004, 2005, and 2006. The objectives fixed in the plan, and agreed by the Compensation Committee, included targets for net profit, management team retention, bonding lines, internal controls over accounting and audit activities, business growth and restructuring. During the fiscal year 2007 the Compensation Committee determined that 98.3% of the objectives had been met and therefore the performance-based share options vested on February 28, 2007 and the cash compensation was paid. No compensation was awarded for fiscal year 2008 and no further awards will be made under this plan. The options under the SMIP are exercisable until ten years after their date of grant. | ||
|
Special Incentive Plan 2009 |
||
| Subsequent to November 30, 2009, but prior to the adoption of the 2009 Long-Term Incentive Plan, described above, and as an interim measure, the Company put in place the Special Incentive Plan 2009 (‘SIP 2009’), a cash-settled incentive plan designed to provide awards to selected executives and key employees, thus further aligning their interests with those of shareholders. Awards under the SIP 2009 are in the form of a cash bonus, payable in April 2012, of between zero and twelve months’ base salary, dependent on the Company’s average share price as quoted on NASDAQ between January 1, 2012 and March 31, 2012. If the average share price over that period is $8.75 or less, no cash bonus will be payable. If the average share price over that period is $35.00 or more, a cash bonus equal to twelve months’ base salary will be payable. If the average share price over that period is between $8.75 and $35.00, a cash bonus equal to between zero and twelve months’ base salary will be payable, calculated on a straight-line basis pro rata to the share price. Awards under the SIP 2009 are capped at the equivalent of twelve months’ base salary. No other performance criteria apply. | ||
|
Restricted Share Plan |
||
| In March 2008 the Board approved and adopted a restricted share plan to provide a retention incentive to selected senior executives. The plan stipulates that the number of free shares (without any cash compensation) that may be awarded under the plan may not exceed an average of 350,000 common shares over a three year period. During the three year restricted plan period, participants not permitted to sell or transfer shares but will be entitled to dividends which will be held by the Company until the restricted period lapses during fiscal year 2011. In April 2008, 65,000 restricted shares were issued to selected senior executives as part of the retention incentive of the plan. These shares had a fair value of $22.23, representing the market price on the date of issue. No further restricted shares have been issued under the Restricted Share Plan. | ||
|
2010 Long Term Incentive Plan |
|
|
| During fiscal year 2010 the Board approved and adopted a Long Term Incentive Plan (‘Cash Plan’) for selected employees as a cash bonus. The cash settlement is based on the share price movement over the specified three year vesting period to April 2013 for the nominal allocated number of shares to each employee. No shares have been held under this scheme. The cash bonus is capped at 6 months of the employees’ salary or 12 months of the employees’ salary depending on their employee rank. | ||
|
2010 Executive Deferred Incentive Scheme |
||
| During fiscal year 2010 the Board approved and adopted a new deferred incentive scheme for selected senior employees. The scheme enabled executives to defer, on a voluntary basis, up to 50% of their annual bonus into the shares of the Company which will be matched in cash at the end of the three year period, subject to performance conditions. The value of the bonus deferred was used to purchase 44,015 shares based on a prevailing share price on April 16, 2010 of $19.69. Participants who continue to be employed by the Group and hold the shares until March 31, 2013 will receive a cash payment consisting of two elements. There will be a guaranteed payment of 50% of the gross amount deferred and a variable element of up to 100% of the gross amount deferred, but conditional upon reaching target Total Shareholder Return over the three year period to March 2013. | ||
|
2009 Executive Deferred Incentive Scheme |
||
| During fiscal year 2009 the Board approved and adopted a deferred incentive scheme for selected senior executives. The scheme enabled the executives to defer, on a voluntary basis, up to 50% of their annual bonus into shares of the Company, which will be matched in cash at the end of the three year period, subject to performance conditions. The value of the bonus deferred was used to purchase 58,374 shares based upon the prevailing share price on April 17, 2009 which was $7.64. The matched element is conditional upon achieving target Total Shareholder Return over the three years to March 2012 and is conditional on the shares being held for three years. |
|
seabed-to-surface
|
|
133
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
36. Share based payments continued
2008 Executive Deferred Incentive Scheme
During fiscal year 2008 the Board approved and adopted a deferred incentive scheme for selected senior executives including stipulating the number of shares that may be awarded. The scheme enabled the executives to defer, on a voluntary basis, up to 50% of their annual bonus into shares of the Company which will be matched in shares at the end of three years subject to performance conditions. The value of the bonus deferred was used to purchase 17,797 shares based upon the prevailing share price on March 31, 2008 which was $21.35. The matched element was conditional upon the growth of earnings per share over the three years to November 30, 2010. The 2008 Executive Deferred Incentive Scheme did not meet the required performance conditions; therefore no matched shares were issued under this scheme.
Option activity including the SMIP, are as follows:
| For the fiscal year |
Number of
options 2010 |
Weighted
2010 |
Number of
options 2009 |
Weighted
2009 |
Number of
2008 |
Weighted
2008 |
||||||||||||||||||
|
Outstanding at December 1 |
3,777,494 | 13.28 | 4,517,312 | 12.51 | 5,115,696 | 8.64 | ||||||||||||||||||
|
Granted |
– | – | – | – | 1,052,500 | 22.67 | ||||||||||||||||||
|
Exercised |
(732,168 | ) | 6.57 | (389,824 | ) | 4.18 | (1,088,952 | ) | 3.83 | |||||||||||||||
|
Forfeited |
(201,061 | ) | 13.41 | (269,494 | ) | 14.49 | (228,339 | ) | 16.28 | |||||||||||||||
|
Expired |
(76,424 | ) | 10.56 | (80,500 | ) | 10.05 | (333,593 | ) | 11.23 | |||||||||||||||
|
Outstanding at November 30 |
2,767,841 | 15.00 | 3,777,494 | 13.28 | 4,517,312 | 12.51 | ||||||||||||||||||
|
Exercisable at the end of the period |
2,349,093 | 13.59 | 2,864,725 | 10.65 | 2,686,308 | 8.29 | ||||||||||||||||||
The weighted average fair value of options granted during the 2010 fiscal year was Nil (2009: Nil).
The weighted average exercise market price at exercise date of options exercised during the 2010 fiscal year was $18.85 (2009: $10.71).
The fair value of each option granted under the 2003 Plan is estimated as of the date of grant using the Black-Scholes option pricing model with weighted average assumptions as follows:
| For the fiscal year | 2010 | 2009 | 2008 | |||||||||
|
Weighted average share price (in $) |
– | – | 22.67 | |||||||||
|
Weighted average exercise price (in $) |
– | – | 22.67 | |||||||||
|
Expected volatility |
– | – | 55.9% | |||||||||
|
Expected life |
– | – | 5 years | |||||||||
|
Risk free rate |
– | – | 2.5% | |||||||||
|
Expected dividends (in $) |
– | – | 0.21 | |||||||||
The expected life of an option is determined by taking into consideration the vesting period of options, the observed historical pattern of share option exercises, the effect of non-transferability and exercise restrictions. The expected volatility over the expected term of the options is estimated from the Group’s historical volatility. For fiscal year 2008 the expected dividend took into account the expected dividends over the four year vesting period assuming a growth rate of 5% over the $0.21 dividend declared during the year.
The fair value of each share granted under the Equity Plan is estimated as of the grant date using the Monte Carlo pricing model with weighted average assumptions as follows:
| For the fiscal year | 2010 | |||
|
Weighted average share price (in $) |
10.46 | |||
|
Expected volatility |
51.4% | |||
|
Expected life |
3 years | |||
|
Risk free rate |
2.7% | |||
|
Expected dividends (in $) |
0.22 | |||
The expected life of the share is the vesting period on which the shares will be issued after the vesting period is complete, provided the performance criteria is met. The expected volatility over the expected term is estimated from the Company’s historical volatility. For the fiscal year 2010 the expected dividend took into account the expected dividends over the three year vesting period assuming growth of 5% over the dividend yield of 2.6%.
|
134 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
The following table summarises information about share options outstanding as at November 30, 2010:
|
|
|||||||||||||
| Options outstanding | ||||||||||||||
| Common shares (range of exercise prices) |
Options
outstanding |
Weighted
(in years) |
Weighted average exercise price (in $) |
|||||||||||
|
$17.01 – 26.16 |
1,537,625 | 6.69 | 21.25 | |||||||||||
|
$10.01 – 17.00 |
524,833 | 4.42 | 10.79 | |||||||||||
|
$3.01 – 10.00 |
337,858 | 3.48 | 5.82 | |||||||||||
|
$1.19 – 3.00 |
367,525 | 2.97 | 2.04 | |||||||||||
|
Total |
2,767,841 | 5.37 | 15.00 | |||||||||||
|
There are no shares vested under the Equity Plan and all remain outstanding. |
|
|||||||||||||
|
The following table summarises the compensation expense recognised during the year: |
|
|||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | |||||||||||
| Expense arising from equity-settled share based payment transactions | 5.8 | 5.0 | 3.8 | |||||||||||
| Expense arising from cash-settled share based payment transactions | 5.3 | 0.2 | 0.1 | |||||||||||
| Total | 11.1 | 5.2 | 3.9 | |||||||||||
|
Recognised cash-settled share based payment liability |
|
|||||||||||||
| The carrying amount of the liability relating to the cash-settled share-based payment at November 30, 2010 is $4.9m (2009: $0.2m). No cash awards vested during the period ended November 30, 2010 (2009: Nil). | ||||||||||||||
|
37. Retirement benefit obligations |
|
|||||||||||||
| The Group operates both defined contribution and defined benefit pension plans, depending on location, covering certain qualifying employees. | ||||||||||||||
|
Contributions under the defined contribution pension plans are determined as a percentage of gross salary. The expense relating to these plans for fiscal year 2010 was $20.4 million (2009: $21.7 million, 2008: $24.2 million). |
|
|||||||||||||
|
The Group operates both funded and unfunded defined benefit pension plans. The benefits under the defined benefit pension plans are based on years of service and salary levels at retirement age. Plan assets of the funded schemes primarily comprise marketable securities. |
|
|||||||||||||
|
The amount included in the balance sheet arising from the Group’s obligations in respect of its defined benefit retirement benefit schemes is as follows:
|
|
|
||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | ||||||||||||
|
Present value of defined benefit obligations |
|
52.6 | 49.9 | |||||||||||
|
Fair value of plan assets in defined scheme |
|
(36.6) | (36.9) | |||||||||||
|
Deficit in defined scheme |
|
16.0 | 13.0 | |||||||||||
|
Present value of unfunded defined benefit obligation |
|
11.3 | 11.7 | |||||||||||
|
Past service cost not yet recognised in balance sheet |
|
1.5 | 2.5 | |||||||||||
|
Net liability recognised in the balance sheet |
|
28.8 | 27.2 | |||||||||||
|
seabed-to-surface
|
|
135
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
37. Retirement benefit obligations continued
The following table provides a reconciliation of the retirement benefit obligations:
| Norway | United Kingdom | France | Total | |||||||||||||||||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | ||||||||||||||||||||||||
| Change in present value of defined benefit obligation: | ||||||||||||||||||||||||||||||||
|
At December 1 |
26.4 | 16.1 | 25.2 | 19.1 | 10.0 | 7.6 | 61.6 | 42.8 | ||||||||||||||||||||||||
|
Service costs |
0.8 | 1.0 | 0.3 | 0.3 | 0.6 | 0.7 | 1.7 | 2.0 | ||||||||||||||||||||||||
|
Interest cost |
1.0 | 0.8 | 1.3 | 1.4 | 0.5 | 0.5 | 2.8 | 2.7 | ||||||||||||||||||||||||
|
Actuarial losses/(gains) |
4.2 | 5.0 | (0.2 | ) | 4.6 | 1.8 | 0.4 | 5.8 | 10.0 | |||||||||||||||||||||||
|
Benefits paid |
(0.8 | ) | (0.9 | ) | (0.8 | ) | (1.6 | ) | (0.8 | ) | (0.6 | ) | (2.4 | ) | (3.1 | ) | ||||||||||||||||
|
Norwegian national insurance |
0.5 | 0.1 | – | – | – | – | 0.5 | 0.1 | ||||||||||||||||||||||||
|
Other |
(0.8 | ) | – | – | – | – | – | (0.8 | ) | – | ||||||||||||||||||||||
|
Exchange differences |
(2.5 | ) | 4.3 | (1.4 | ) | 1.4 | (1.4 | ) | 1.4 | (5.3 | ) | 7.1 | ||||||||||||||||||||
|
At November 30 |
28.8 | 26.4 | 24.4 | 25.2 | 10.7 | 10.0 | 63.9 | 61.6 | ||||||||||||||||||||||||
|
Change in fair value of plan assets: |
||||||||||||||||||||||||||||||||
|
At December 1 |
20.7 | 12.6 | 16.2 | 12.2 | – | – | 36.9 | 24.8 | ||||||||||||||||||||||||
|
Estimated return on plan assets |
1.1 | 0.8 | 1.2 | 1.0 | – | – | 2.3 | 1.8 | ||||||||||||||||||||||||
|
Actuarial (losses)/gains |
(1.9 | ) | 4.7 | 0.5 | 2.5 | – | – | (1.4 | ) | 7.2 | ||||||||||||||||||||||
|
Members’ contribution |
1.4 | – | 1.0 | 1.2 | – | – | 2.4 | 1.2 | ||||||||||||||||||||||||
|
Company contributions |
– | 0.5 | – | – | – | – | – | 0.5 | ||||||||||||||||||||||||
|
Benefits paid |
(0.7 | ) | (0.8 | ) | (0.8 | ) | (1.6 | ) | – | – | (1.5 | ) | (2.4 | ) | ||||||||||||||||||
|
Other |
0.7 | (0.2 | ) | – | – | – | – | 0.7 | (0.2 | ) | ||||||||||||||||||||||
|
Exchange differences |
(1.9 | ) | 3.1 | (0.9 | ) | 0.9 | – | – | (2.8 | ) | 4.0 | |||||||||||||||||||||
|
At November 30 |
19.4 | 20.7 | 17.2 | 16.2 | – | – | 36.6 | 36.9 | ||||||||||||||||||||||||
|
Funded status |
(9.4 | ) | (5.7 | ) | (7.2 | ) | (9.0 | ) | (10.7 | ) | (10.0 | ) | (27.3 | ) | (24.7 | ) | ||||||||||||||||
|
Past service costs not yet recognised in |
||||||||||||||||||||||||||||||||
|
Balance Sheet |
– | – | – | – | – | – | (1.5 | ) | (2.5 | ) | ||||||||||||||||||||||
|
Overall status |
– | – | – | – | – | – | (28.8 | ) | (27.2 | ) | ||||||||||||||||||||||
Included within the defined benefit obligation are amounts arising from plans which are unfunded. The unfunded plans are the French plan and one Norwegian plan with an obligation of $0.6 million (2009: $1.6 million).
The expected return on scheme assets has been determined after considering the expected return on each of the main asset classes separately, and then taking a weighted average by asset value.
|
136 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
The principal assumptions used for the purposes of the actuarial valuations were as follows:
Year ended November 30, 2010
|
|
|||||||||||||||||||||
| (in %) | Norway | United Kingdom | France |
Total – weighted
average |
||||||||||||||||||
|
Key assumptions used: |
||||||||||||||||||||||
|
Pension increase |
0.5 – 3.8 | 3.1 | – | 2.8 | ||||||||||||||||||
|
Discount rate |
3.2 | 5.5 | 4.0 | 4.2 | ||||||||||||||||||
|
Expected return on scheme assets |
4.6 | 7.7 | – | 6.1 | ||||||||||||||||||
|
Rate of compensation increase |
4.0 | 4.9 | 4.5 | 4.4 | ||||||||||||||||||
| Year ended November 30, 2009 | ||||||||||||||||||||||
| (in %) | Norway | United Kingdom | France |
Total – weighted
average |
||||||||||||||||||
|
Key assumptions used: |
||||||||||||||||||||||
|
Pension increase |
1.3 – 4.0 | 3.0 | – | 3.0 | ||||||||||||||||||
|
Discount rate |
4.4 | 5.4 | 5.3 | 4.9 | ||||||||||||||||||
|
Expected return on scheme assets |
5.6 | 7.5 | – | 6.4 | ||||||||||||||||||
|
Rate of compensation increase |
4.3 | 4.8 | 4.9 | 4.6 | ||||||||||||||||||
| Year ended November 30, 2008 | ||||||||||||||||||||||
| (in %) | Norway | United Kingdom | France |
Total – weighted
average |
||||||||||||||||||
|
Key assumptions used: |
||||||||||||||||||||||
|
Pension increase |
2.0 – 4.25 | 3.0 | – | 3.2 | ||||||||||||||||||
|
Discount rate |
4.3 | 7.0 | 6.0 | 5.8 | ||||||||||||||||||
|
Expected return on scheme assets |
6.3 | 7.6 | – | 6.9 | ||||||||||||||||||
|
Rate of compensation increase |
4.5 | 4.3 | 4.9 | 4.5 | ||||||||||||||||||
|
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 scheme retirement age was as follows:
|
|
|||||||||||||||||||||
| As at balance sheet date | 20 years post balance sheet date |
|
||||||||||||||||||||
| Retirement Benefit Scheme | Retirement Age | Sex | 2010 | 2009 | 2010 | 2009 | ||||||||||||||||
|
Norway Sailor scheme |
60 years | Male | 23.5 | 23.3 | 25.5 | 25.3 | ||||||||||||||||
| Female | 26.3 | 26.1 | 28.5 | 28.3 | ||||||||||||||||||
|
Norway Office scheme |
67 years | Male | 17.7 | 17.5 | 19.5 | 19.3 | ||||||||||||||||
| Female | 20.1 | 19.9 | 22.2 | 22.0 | ||||||||||||||||||
|
United Kingdom scheme |
65 years | Male | 21.0 | 20.9 | 22.9 | 22.8 | ||||||||||||||||
| Female | 23.6 | 23.5 | 25.5 | 25.4 | ||||||||||||||||||
|
France scheme |
65 years | Male | 18.9 | 18.9 | 22.9 | 22.9 | ||||||||||||||||
| Female | 22.7 | 22.7 | 27.2 | 27.2 | ||||||||||||||||||
|
seabed-to-surface
|
|
137
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
37. Retirement benefit obligations continued
Amounts recognised in the Consolidated Income Statement within operating expenses and administrative expenses in respect of these defined benefit schemes are as follows:
| Year ended November 30, 2010 | ||||||||||||||||
| (in $ millions) | Norway | United Kingdom | France | Total | ||||||||||||
|
Service cost |
0.8 | 0.3 | 0.6 | 1.7 | ||||||||||||
|
Interest cost |
1.0 | 1.3 | 0.4 | 2.7 | ||||||||||||
|
Expected return on plan assets |
(1.1 | ) | (1.2 | ) | – | (2.3 | ) | |||||||||
|
Past service cost |
(1.9 | ) | – | (0.8 | ) | (2.7 | ) | |||||||||
|
Norwegian national insurance and other expenses |
0.1 | – | – | 0.1 | ||||||||||||
|
Total |
(1.1 | ) | 0.4 | 0.2 | (0.5 | ) | ||||||||||
| Year ended November 30, 2009 | ||||||||||||||||
| (in $ millions) | Norway | United Kingdom | France | Total | ||||||||||||
|
Service cost |
1.0 | 0.3 | 0.7 | 2.0 | ||||||||||||
|
Interest cost |
0.8 | 1.4 | 0.5 | 2.7 | ||||||||||||
|
Expected return on plan assets |
(0.8 | ) | (1.0 | ) | – | (1.8 | ) | |||||||||
|
Past service cost |
– | – | (0.8 | ) | (0.8 | ) | ||||||||||
|
Norwegian national insurance and other expenses |
0.1 | – | – | 0.1 | ||||||||||||
|
Total |
1.1 | 0.7 | 0.4 | 2.2 | ||||||||||||
| Year ended November 30, 2008 | ||||||||||||||||
| (in $ millions) | Norway | United Kingdom | France | Total | ||||||||||||
|
Service cost |
8.3 | 0.2 | 0.7 | 9.2 | ||||||||||||
|
Interest cost |
2.6 | 1.3 | 0.4 | 4.3 | ||||||||||||
|
Expected return on plan assets |
(1.8 | ) | (1.2 | ) | – | (3.0 | ) | |||||||||
|
Past service cost |
– | – | (0.7 | ) | (0.7 | ) | ||||||||||
|
Settlement |
(33.3 | ) | – | – | (33.3 | ) | ||||||||||
|
Norwegian national insurance and other expenses |
1.3 | – | – | 1.3 | ||||||||||||
|
Total |
(22.9 | ) | 0.3 | 0.4 | (22.2 | ) | ||||||||||
The estimated amounts of contributions expected to be paid to schemes during fiscal year 2011 is $1.6 million.
Actuarial gains and losses have been reported in the Statement of Comprehensive Income. The net cumulative amount after tax of actuarial losses recognised in the Statement of Comprehensive Income is $43.7 million (2009: $37.2 million, 2008: $35.2 million), after tax effects of $12.1 million (2009: $11.8 million, 2008: $11.0 million).
The actual return on scheme assets was $0.9 million (2009: actual return of $9.0 million).
The major categories of plan assets at November 30, 2010 for each category are as follows:
| As at November 30, 2010 | ||||||||||||
| (in $ millions) | Norway | United Kingdom | Total | |||||||||
|
Equity instruments |
2.4 | 4.6 | 7.0 | |||||||||
|
Bonds |
9.3 | 7.7 | 17.0 | |||||||||
|
Real estate |
3.7 | – | 3.7 | |||||||||
|
Derivative Investments |
4.1 | 4.6 | 8.7 | |||||||||
|
Other assets |
– | 0.2 | 0.2 | |||||||||
|
Total |
19.5 | 17.1 | 36.6 | |||||||||
|
138 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| As at November 30, 2009 | ||||||||||||||||||||
| (in $ millions) | Norway | United Kingdom | Total | |||||||||||||||||
|
Equity instruments |
|
2.0 | 12.5 | 14.5 | ||||||||||||||||
|
Bonds |
|
11.4 | 3.8 | 15.2 | ||||||||||||||||
|
Real estate |
|
3.6 | – | 3.6 | ||||||||||||||||
|
Other assets |
|
3.8 | (0.2 | ) | 3.6 | |||||||||||||||
|
Total |
|
20.8 | 16.1 | 36.9 | ||||||||||||||||
| As at November 30, 2008 | ||||||||||||||||||||
| (in $ millions) | Norway | United Kingdom | Total | |||||||||||||||||
|
Equity instruments |
|
0.8 | 8.7 | 9.5 | ||||||||||||||||
|
Bonds |
|
7.7 | 3.4 | 11.1 | ||||||||||||||||
|
Real estate |
|
2.1 | – | 2.1 | ||||||||||||||||
|
Other assets |
|
2.0 | 0.1 | 2.1 | ||||||||||||||||
|
Total |
|
12.6 | 12.2 | 24.8 | ||||||||||||||||
| The overall expected rate of return is a weighted average of the expected returns of the various categories of plan assets held. This takes into account the evaluation of the plans assets, the plans proposed asset allocation, historical trends and experience and current and expected market conditions. | ||||||||||||||||||||
| Experience adjustments are the actual gains/losses that arise because of differences between the actual assumptions made at the beginning of the period and the actual experience during the period. | ||||||||||||||||||||
| The history of experience adjustments is as follows: | ||||||||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
|
Present value of defined benefit obligations |
63.9 | 61.6 | 42.8 | 110.2 | ||||||||||||||||
|
Fair value of scheme assets |
(36.6 | ) | (36.9 | ) | (24.8 | ) | (62.2 | ) | ||||||||||||
|
Deficit in the scheme |
27.3 | 24.7 | 18.0 | 48.0 | ||||||||||||||||
|
Experience adjustments on scheme liabilities |
(5.8 | ) | (10.0 | ) | (1.3 | ) | 4.8 | |||||||||||||
|
Experience adjustments on scheme assets |
1.4 | (7.2 | ) | (8.7 | ) | (0.1 | ) | |||||||||||||
|
Net experience adjustment |
(4.4 | ) | (17.2 | ) | (10.0 | ) | 4.7 |
|
||||||||||||
|
38. Deferred revenue |
||||||||||||||||||||
|
Revenue deferred relating to the Group’s obligations are as indicated:
|
|
|||||||||||||||||||
| As at November 30 (in $ millions) | 2010 | 2009 | ||||||||||||||||||
|
Construction contracts (see Note 22) |
|
198.4 | 241.2 | |||||||||||||||||
|
Advances received from clients (see below) |
|
19.4 | 38.6 | |||||||||||||||||
|
Total |
|
217.8 | 279.8 | |||||||||||||||||
|
Construction contracts are the gross amount due to clients for contract work billed prior to progress of work performed. This is adjusted for estimated losses at completion. |
|
|||||||||||||||||||
|
Advances received from clients are amounts received before the related work is performed. |
|
|||||||||||||||||||
| Advances received from clients are recognised as follows: | ||||||||||||||||||||
| For the fiscal year (in $ millions) | 2010 | 2009 | ||||||||||||||||||
|
Balance at December 1 |
|
38.6 | 59.8 | |||||||||||||||||
|
Revenue deferred in respect of advances received |
|
3.6 | 19.2 | |||||||||||||||||
|
Revenue recognised on discharge of obligation |
|
(22.8 | ) | (32.1 | ) | |||||||||||||||
|
Less: assets classified as held for sale |
|
– | (8.3 | ) | ||||||||||||||||
|
Balance at November 30 |
|
19.4 | 38.6 | |||||||||||||||||
|
seabed-to-surface
|
|
139
|
Financial Review and Statements
Notes to the Consolidated Financial Statements continued
| 39. Cash flow from operating activities | ||||||||||||||||
| For the fiscal year November 30 (in $ millions) | Notes | 2010 | 2009 | 2008 | ||||||||||||
|
Cash flow from operating activities: |
||||||||||||||||
|
Net income |
313.0 | 265.7 | 307.2 | |||||||||||||
|
Adjustments for: |
||||||||||||||||
|
Depreciation of property, plant and equipment |
16 | 116.2 | 124.6 | 115.8 | ||||||||||||
|
Net (reversal of impairment)/impairment of property, plant and equipment |
17 | (1.3 | ) | 12.8 | (11.5 | ) | ||||||||||
|
Amortisation of intangible assets |
15 | 1.6 | 2.0 | 0.2 | ||||||||||||
|
Net impairment of intangible assets |
5.1 | 2.8 | – | |||||||||||||
|
Share in net income of associates and joint ventures |
17 | (74.8 | ) | (49.0 | ) | (63.0 | ) | |||||||||
|
Mobilisation costs |
1.6 | 4.5 | 2.4 | |||||||||||||
|
Share based payments and retirement obligations |
9.5 | 5.2 | 3.9 | |||||||||||||
|
Finance costs |
28.7 | 29.5 | 28.4 | |||||||||||||
|
Inventories (written off)/written back |
(0.5 | ) | 0.3 | 0.9 | ||||||||||||
|
Taxation |
145.7 | 109.5 | 160.5 | |||||||||||||
|
Losses/(gains) on disposal of property, plant and equipment |
– | 1.1 | (5.4 | ) | ||||||||||||
|
Foreign exchange (gain)/loss |
(82.1 | ) | 28.6 | (45.5 | ) | |||||||||||
|
Foreign currency on liquidation of entities |
– | – | 0.3 | |||||||||||||
| 462.7 | 537.6 | 494.2 | ||||||||||||||
| Changes in operating assets and liabilities, net of acquisitions: | ||||||||||||||||
|
(Increase)/decrease in inventories |
(1.6 | ) | 2.4 | (10.8 | ) | |||||||||||
|
(Increase)/decrease in trade and other receivables |
(120.6 | ) | 94.8 | (59.0 | ) | |||||||||||
|
Increase in accrued salaries and benefits |
11.3 | 10.5 | 2.3 | |||||||||||||
|
(Decrease)/increase in trade and other liabilities |
(56.2 | ) | (53.3 | ) | 294.9 | |||||||||||
|
Net realised mark-to-market hedging transactions |
(18.2 | ) | 14.0 | (14.9 | ) | |||||||||||
| (185.3 | ) | 68.4 | 212.5 | |||||||||||||
|
Income taxes paid
|
|
(137.4
|
)
|
|
(59.9
|
)
|
|
(213.6
|
)
|
|||||||
|
Net cash generated from operating activities |
140.0 | 546.1 | 493.1 | |||||||||||||
40. Post balance sheet events
Following shareholder approval of the proposed Articles of Incorporation at the Combination Extraordinary General Meeting on November 9, 2010, the fiscal year which started on December 1, 2010 will end on December 31, 2011. Thereafter, future fiscal years shall commence on January 1 and end on December 31.
At an Extraordinary General Meeting of Shareholders held on December 20, 2010, Mr. Long was appointed as an Independent Director of Subsea 7 S.A., effective upon completion of the Acquisition. Mr. Long’s appointment became effective on January 7, 2011.
On December 21, 2010 the UK Office of Fair Trading (‘OFT’) announced that it was considering undertakings from Acergy S.A. and Subsea 7 Inc. in lieu of referring the proposed merger to the UK Competition Commission. This followed the submission of a notification to the OFT regarding the proposed merger on September 23, 2010. The undertakings under consideration are the divestiture of one rigid pipelay vessel; Acergy Falcon and potentially one diving support vessel. The OFT’s announcement followed prior unconditional clearances received from the relevant authorities in the US, Norway and Australia. Competition clearance is still being sought in Brazil.
The Luxembourg tax law which provided for a special tax regime for 1929 Holding Companies expired on December 31, 2010. As of January 1, 2011, the 1929 regime ceased to exist and Subsea 7 S.A. became an ordinary taxable Luxembourg company.
Post balance sheet events following the Acquisition
The acquisition by Acergy S.A. of Subsea 7 Inc. was completed on January 7, 2011 after closing of the Oslo Børs. The Company issued 156,839,759 new shares to the Subsea 7 Inc. shareholders in consideration for the issue to the Company of all Subsea 7 Inc. shares, at which point, the shares of Subsea 7 Inc. were delisted. The fair value of the newly issued shares was $25.19 per share, resulting in an aggregate consideration of $3.95 billion.
Upon completion the Company’s name changed to Subsea 7 S.A. and the restated Articles of Incorporation approved by Acergy S.A.’s shareholders on November 9, 2010 and the appointment of the Board became effective. The first day of trading in the shares of the new Company, Subsea 7 S.A., was January 10, 2011.
|
140 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| The revenue for the combined Group for fiscal year 2010 as though the acquisition had been effected as at December 1, 2009 would have been $4.4 billion. | ||
|
The process of fair valuing the assets and liabilities of Subsea 7 Inc. was not completed by February 23, 2011, the date of this Report. As a result, the initial accounting for the acquisition is not complete. The Group is therefore not able to disclose the following information regarding the acquisition: |
||
|
• the gross contractual amount, fair value amount, or any estimated contractual cash flows that are not expected to be collected in respect of the receivables acquired;
• the amounts recognised as of the acquisition date for each major class of assets and liabilities acquired;
• the existence of or the values relating to any contingent liabilities recognised in accordance with IAS 37 on acquisition;
• the amount of goodwill acquired and the amount of goodwill that is expected to be deductible for tax purposes; and
• the net income for the combined Group for fiscal year 2010 as though the acquisition had been effected as at December 1, 2009. |
||
|
The goodwill arising from the acquisition is attributable to the added client base and vessel fleet, in addition to synergies expected from combining operations arising from the creation of the combined Group. |
||
|
Acquisition-related costs of $15.1 million and restructuring costs of $12.7 million have been included in administration expenses in the Consolidated Income Statement of Subsea 7 for fiscal year 2010. |
||
|
Change of segments |
||
| Following completion, Subsea 7 has changed its reporting segments. For management and reporting purposes, Subsea 7 is organised into four territories, which are representative of its principal activities. In addition, there is the corporate segment (Corporate) which includes all activities that serve more than one region. These include the activities of the SHL and NKT joint ventures. Also included are: management of offshore personnel; captive insurance activities; and management and corporate services provided for the benefit of the whole Group, including design engineering, finance and legal departments. All assets are allocated to a territory; including vessels which have global mobility which were previously attributed to the ‘Acergy Corporate’ segment. | ||
|
Below is a summary of the Segmental Reporting for fiscal year 2011: |
||
|
• North Sea, Mediterranean & Canada (NSMC) |
||
|
• Africa & Gulf of Mexico (AFGoM) |
||
|
• Brazil (BRAZIL) |
||
|
• Asia Pacific & Middle East (APME); including SapuraAcergy |
||
|
• Corporate (CORP); including NKT Flexibles and SHL |
|
|
|
Other post balance sheet events |
||
| Subsea 7 S.A. announced the award of a five year Frame Agreement, plus two one year options by Statoil ASA in the Norwegian and North Seas starting mid 2011. The estimated contract value of this Frame Agreement is $260 million. As a result of this contract award, Subsea 7 has entered into an eight year contract with Eidesvik Offshore ASA for the provision of a new IMR vessel, which is expected to be delivered in the fourth quarter of 2012. | ||
|
On February 15, 2011 the Company announced its intention to apply for voluntary delisting from NASDAQ and to deregister and terminate its reporting obligations under the Securities and Exchange Act of 1934. Delisting is expected to be effective on March 7, 2011. |
||
|
On February 21, 2011, Subsea 7 Inc. cancelled the outstanding commitments under its revolving credit facilities with DnB NOR Bank ASA ($50.0 million), HSBC Bank plc ($50.0 million) and Bank of Scotland plc ($50.0 million). Subsea 7 Inc. has no loan facilities available at the date of this report. |
||
|
On February 16, 2011 a NOK 920 million loan agreement with Eksportfinans ASA was executed. This facility utilised the guarantee element of the NOK 977.5 million facility, and will be used to part finance the Seven Havila (formerly Havila) which was delivered on February 23, 2011. |
||
|
In late February 2011 the Group was informed by its 49% owned subsidiary NKT Flexibles that steel delivered by one of its suppliers in the period 2006-2010 may not have been within the agreed product specifications despite evidence of certification. The issue is currently being investigated and at this stage it is not possible to determine any potential economic or other consequences for NKT Flexibles or the Group. |
|
seabed-to-surface
|
|
141
|
Additional Information
Special Note Regarding Forward Looking Statements
Certain statements made in this Report and some of the documents incorporated by reference in this Report may include ‘forward-looking statements’ within the meaning of Section 27A of the Securities Act of 1933, as amended (the ‘Securities Act’), and Section 21E of the US Securities Exchange Act of 1934, as amended (the ‘Exchange Act’). 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’, ‘seek’, and similar expressions.
These statements include, but are not limited to, statements as to:
| • | the impact of the Combination of Subsea 7 S.A. (formerly Acergy S.A.) and Subsea 7 Inc., including the expected benefits and synergies from the Combination and the impact the integration process, on the future operation of the Group; |
| • | the impact of the current economic climate on our clients’ behaviour, government regulations and our business and competitive position; |
| • | the expected execution and amount of projects in our backlog; |
| • | our outlook for 2011, including anticipated contract awards, execution and activity levels, the size and complexity of new projects and expected revenue and margins; |
| • | the expected completion date, estimated progress to completion, and estimated revenue on our projects; |
| • | the utilisation of our assets, including the expected date of delivery and intended use of certain vessels; |
| • | the expected growth in the industry in which we operate and our ability for growth over the medium and long-term, including trends in the markets in which we operate; |
| • | the expected demand for our products and services and factors affecting such demand; |
| • | our intention to maintain the focus on improving our control environment; |
| • | the expected amount and timing of any future dividend payments; |
| • | the sufficiency of our expected sources of cash and effectiveness of our liquidity risk management framework; |
| • | our planned capital expenditure, equity investments and resources for such future expenditure; |
| • | our reliance on and the expected relationship with certain clients, including negotiations regarding claims and variation costs; |
| • | the extent of our obligations under certain commitments and contingent liabilities; |
| • | the expected date and value of hedging transactions and financial instruments and future contractual obligations arising therefrom; |
| • | our business and financial strategies, including certain cost-reduction initiatives, and the expected impact thereof; |
| • | the adequacy of our insurance policies and indemnity arrangements; |
| • | the future level of activity expected in our joint ventures, the access to cash held by our joint ventures, and the potential liability for failure of our joint venture partners to fulfil their obligations; |
| • | foreign currency fluctuations; |
| • | changes or developments of different government regulations and the potential or expected effect on us or our clients, including our ability to operate under different tax regimes, adapt to changes in such tax regimes and ability to defend our tax positions in potential or ongoing investigations or audits; |
| • | our critical accounting policies and their effectiveness; |
| • | expected corporate reporting, reporting dates, meeting dates and other communications with shareholders; |
| • | anticipated future compliance with debt covenants; |
| • | our intention to delist from NASDAQ and deregister and terminate our reporting obligations under the Securities Exchange Act of 1934, the timing and effectiveness of notices and filings to be made in connection with the delisting and deregistration process and the expected benefits therefrom; and |
| • | our ability to obtain funding from various sources and our expected use of cash and credit facilities. |
|
142 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
|
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 ‘Risks and Uncertainties’, ‘Financial review’ and the quantitative and qualitative information disclosures about Market Risk contained in Note 34 ‘Financial instruments’ to the Consolidated Financial Statements. The following factors, and others which are discussed in our public filings with the US Securities and Exchange Commission (the ‘SEC’) including this Report, 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 accounting for projects 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; (xxi) other factors which are described from time to time in our public filings with the SEC; (xxii) actions by regulatory authorities or other third parties; (xxiii) the impact of required divestitures or other conditions or restrictions imposed or arising out of the antitrust reviews in the UK and Brazil and (xxiv) unanticipated costs and difficulties related to the integration of Acergy S.A. and Subsea 7 Inc. and our ability to achieve benefits therefrom.
|
||
| 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. | ||
|
Selected Financial Data
Basis of presentation |
||
|
In this Report, the terms ‘we’, ‘us’, ‘our’, ‘Group’, ‘Company’ and ‘Subsea 7’ refer to Subsea 7 S.A. and, unless the context otherwise requires, its consolidated subsidiaries. References to Subsea 7 activities by years refer to fiscal years ended November 30. The Group’s common shares are traded on NASDAQ in the form of American Depositary Shares (‘ADSs’) (each ADS representing one common share) under the ticker symbol ‘SUBC’ and are listed on Oslo Børs under the ticker symbol ‘SUBC’.
|
||
| The selected consolidated financial data set forth below is for the five years ended, and as at, November 30, 2010, 2009, 2008, 2007 and 2006. The information for the three years ended, and as at, November 30, 2010, 2009 and 2008 is derived from the audited Consolidated Financial Statements included in this Report and prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. The information for the year ended, and as at November 30, 2007 has been derived from our audited Consolidated Financial Statements for that period and the year ended, and as at November 30, 2006 is derived from unaudited financial information and is prepared in accordance with US GAAP and is re-presented to reflect the ‘discontinued operations’ of Acergy Piper. Since the disposal of Acergy Piper, a semi-submersible pipelay barge and the Group’s sole Trunkline business asset, which was completed on January 9, 2009, the results of the Trunkline business are required to be reported as ‘discontinued operations’ in all periods presented. For fiscal years 2010, 2009, 2008 and 2007 this has been reported in accordance with IFRS. To report the discontinued operations for fiscal year 2006 required a re-presentation of the prior financial results as reported under US GAAP. All financial data in this Report, unless otherwise stated, reflects the operations of Acergy S.A. (now Subsea 7 S.A.) prior to the Combination with Subsea 7 Inc. and does not reflect the operations of the combined Group on a pro forma basis. | ||
|
|
seabed-to-surface
|
|
143
|
Additional Information
The financial information for Acergy (now Subsea 7) presented below is summarised and should be read together with the Consolidated Financial Statements.
| For the fiscal year (in $ millions, except share data) | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||
| IFRS | IFRS | IFRS | IFRS | US GAAP | ||||||||||||||||
|
Consolidated Income Statement data: |
||||||||||||||||||||
|
Continuing operations: |
||||||||||||||||||||
|
Revenue |
2,369.0 | 2,208.8 | 2,522.4 | 2,406.3 | 1,933.3 | |||||||||||||||
|
Operating expenses |
(1,701.0 | ) | (1,683.8 | ) | (1,874.2 | ) | (1,859.1 | ) | (1,539.3 | ) | ||||||||||
|
Gross profit |
668.0 | 525.0 | 648.2 | 547.2 | 394.0 | |||||||||||||||
|
Administrative expenses |
(306.7 | ) | (231.3 | ) | (253.8 | ) | (227.6 | ) | (140.8 | ) | ||||||||||
|
Net other operating income/(expense) |
– | – | 3.4 | 0.4 | (1.5 | ) | ||||||||||||||
|
Share of net income of associates and joint ventures |
74.8 | 49.0 | 63.0 | 31.5 | – | |||||||||||||||
|
Net operating income from continuing operations |
436.1 | 342.7 | 460.8 | 351.5 | 251.7 | |||||||||||||||
|
Investment income from bank deposits |
9.8 | 6.4 | 17.9 | 30.8 | 18.8 | |||||||||||||||
|
Other gains and losses |
(18.0 | ) | 43.6 | 44.1 | 0.6 | 0.5 | ||||||||||||||
|
Finance costs |
(28.7 | ) | (31.4 | ) | (30.5 | ) | (39.0 | ) | (4.2 | ) | ||||||||||
|
Income before taxes |
399.2 | 361.3 | 492.3 | 343.9 | 266.8 | |||||||||||||||
|
Taxation |
(130.8 | ) | (102.8 | ) | (162.6 | ) | (215.1 | ) | (65.6 | ) | ||||||||||
|
Income from continuing operations |
268.4 | 258.5 | 329.7 | 128.8 | 201.2 | |||||||||||||||
|
Net income/(loss) from discontinued operations |
44.6 | 7.2 | (22.5 | ) | 5.7 | 42.8 | ||||||||||||||
|
Net income |
313.0 | 265.7 | 307.2 | 134.5 | 244.0 | |||||||||||||||
|
Net income attributable to: |
||||||||||||||||||||
|
Equity holders of parent |
265.4 | 245.0 | 301.4 | 127.3 | 236.7 | |||||||||||||||
|
Non-controlling interests |
47.6 | 20.7 | 5.8 | 7.2 | 7.3 | |||||||||||||||
| 313.0 | 265.7 | 307.2 | 134.5 | 244.0 | ||||||||||||||||
|
Earnings/(loss) per share |
$ per share | $ per share | $ per share | $ per share | $ per share | |||||||||||||||
|
Basic: |
||||||||||||||||||||
|
Continuing operations |
1.20 | 1.30 | 1.76 | 0.65 | 1.01 | |||||||||||||||
|
Discontinued operations |
0.24 | 0.04 | (0.12 | ) | 0.03 | 0.22 | ||||||||||||||
|
Net income |
1.45 | 1.34 | 1.64 | 0.68 | 1.23 | |||||||||||||||
|
Diluted: |
||||||||||||||||||||
|
Continuing operations |
1.16 | 1.29 | 1.70 | 0.63 | 0.97 | |||||||||||||||
|
Discontinued operations |
0.22 | 0.04 | (0.11 | ) | 0.03 | 0.21 | ||||||||||||||
|
Net income |
1.38 | 1.33 | 1.59 | 0.66 | 1.18 | |||||||||||||||
|
144 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| For the fiscal year (in $ millions) | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||||
| IFRS | IFRS | IFRS | IFRS | US GAAP | ||||||||||||||||||
|
Consolidated Cash Flow Statement data: |
||||||||||||||||||||||
|
Net cash generated from operating activities |
140.0 | 546.1 | 493.1 | 251.3 | 38.2 | |||||||||||||||||
|
Net cash used in investing activities |
(493.3 | ) | (100.4 | ) | (286.7 | ) | (220.8 | ) | (117.3 | ) | ||||||||||||
|
Net cash (used in)/provided by financing activities |
(84.5 | ) | (52.0 | ) | (186.1 | ) | (190.0 | ) | 468.8 | |||||||||||||
|
Net (decrease)/increase in cash and cash equivalents |
(437.8 | ) | 393.7 | 20.3 | (159.5 | ) | 389.7 | |||||||||||||||
|
Other financial data: |
||||||||||||||||||||||
| Depreciation, mobilisation and amortisation expense from continuing operations | (119.6 | ) | (131.0 | ) | (110.4 | ) | (86.1 | ) | (53.4 | ) | ||||||||||||
| Impairment of intangible assets from continuing operations | (5.1 | ) | (2.8 | ) | – | – | – | |||||||||||||||
| Impairment of property, plant and equipment from continuing operations | – | (11.8 | ) | (1.8 | ) | (0.3 | ) | (2.1 | ) | |||||||||||||
| Net reversal of impairment of property, plant and equipment from discontinued operations | – | – | 13.3 | – | – | |||||||||||||||||
| As at November 30 (in $ millions, except for per share data) | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||||
| IFRS | IFRS | IFRS | IFRS | US GAAP | ||||||||||||||||||
|
Consolidated Balance Sheet data: |
||||||||||||||||||||||
|
Non-current assets |
1,586.2 | 1,090.1 | 1,139.3 | 1,025.1 | 828.5 | |||||||||||||||||
|
Current assets |
1,403.3 | 1,743.0 | 1,331.8 | 1,401.7 | 1,380.7 | |||||||||||||||||
|
Total assets |
2,989.5 | 2,833.1 | 2,471.1 | 2,426.8 | 2,209.2 | |||||||||||||||||
|
Non-current liabilities |
539.7 | 512.7 | 555.5 | 507.6 | 596.6 | |||||||||||||||||
|
Current liabilities |
1,190.5 | 1,221.2 | 1,114.2 | 1,100.2 | 912.9 | |||||||||||||||||
|
Total liabilities |
1,730.2 | 1,733.9 | 1,669.7 | 1,607.8 | 1,509.5 | |||||||||||||||||
|
Total equity and liabilities |
2,989.5 | 2,833.1 | 2,471.1 | 2,426.8 | 2,209.2 | |||||||||||||||||
|
Total borrowings |
435.3 | 415.8 | 419.3 | 389.8 | 507.1 | |||||||||||||||||
|
Deferred tax assets |
22.8 | 19.3 | 39.8 | 59.9 | 31.0 | |||||||||||||||||
|
Deferred tax liabilities |
44.1 | 49.9 | 56.1 | 35.6 | 13.5 | |||||||||||||||||
|
Total equity |
1,259.3 | 1,099.2 | 801.4 | 819.0 | 699.7 | |||||||||||||||||
| Issued share capital, excluding own shares but including paid in surplus | 898.7 | 893.8 | 888.6 | 882.8 | 878.8 | |||||||||||||||||
| Issued share capital, including own shares and paid in surplus | 689.5 | 671.2 | 659.2 | 771.6 | 846.5 | |||||||||||||||||
|
Dividend per share (declared and paid) |
0.23 | 0.22 | 0.21 | 0.20 | – | |||||||||||||||||
|
Further details of these selected financial data can be found in the Consolidated Financial Statements and notes thereto on pages 81 to 141. |
|
|||||||||||||||||||||
|
|
||||||||||||||||||||||
|
seabed-to-surface
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|
145
|
Additional Information
Adjusted EBITDA and Adjusted EBITDA Margins
The Group calculates adjusted earnings before interest, income taxation, depreciation and amortisation (‘Adjusted EBITDA’) from continuing operations as net income from continuing operations plus finance costs, other gains and losses, taxation, depreciation and amortisation and adjusted to exclude investment income and impairment of property, plant and equipment and intangibles. Adjusted EBITDA margin from continuing operations is defined as Adjusted EBITDA divided by revenue from continuing operations. Adjusted EBITDA for discontinued operations is calculated as per the methodology outlined above. Adjusted EBITDA for total operations is the total of continuing operations and discontinued operations.
Adjusted EBITDA is a non-IFRS measure that represents EBITDA before additional specific items that are considered to hinder comparison of the Group’s performance either year-on-year or with other businesses. The additional specific items excluded from Adjusted EBITDA are other gains and losses and impairment of property, plant and equipment and intangibles. These items are excluded from Adjusted EBITDA because they are individually or collectively material items that are not considered representative of the performance of the businesses during the periods presented. Other gains and losses principally relate to disposals of property, plant and equipment and net foreign exchange gains or losses. Impairments of property, plant and equipment represent the excess of the assets’ carrying amount that is expected to be recovered from their use in the future.
The Adjusted EBITDA measures and Adjusted EBITDA margins have not been prepared in accordance with International Financial Reporting Standards (‘IFRS’) as issued by the International Accounting Standards Board (‘IASB’) nor as adopted for use in the European Union (‘EU’). These measures exclude items that can have a significant effect on the Group’s profit 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) or as a measure of the Group’s liquidity.
Management believes that Adjusted EBITDA and Adjusted EBITDA margin from continuing operations are important indicators of the operational strength and the performance of the business. These non-IFRS measures provide management with a meaningful comparison amongst its various regions, as they eliminate the effects of financing and depreciation. Management believes that the presentation of Adjusted EBITDA from continuing operations 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 from continuing operations 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 from continuing operations as presented by the Group may not be comparable to similarly titled measures reported by other companies.
Adjusted EBITDA reconciliation for Acergy (now Subsea 7)
| For the fiscal year ended | 2010 | 2009 | 2008 | |||||||||||||||||||||||||||||||||
| Continuing | Discontinued |
Total
Operations |
Continuing | Discontinued |
Total
Operations |
Continuing | Discontinued |
Total
Operations |
||||||||||||||||||||||||||||
|
Net income |
268.4 | 44.6 | 313.0 | 258.5 | 7.2 | 265.7 | 329.7 | (22.5 | ) | 307.2 | ||||||||||||||||||||||||||
|
Depreciation and amortisation |
119.4 | – | 119.4 | 131.0 | 0.1 | 131.1 | 110.4 | 8.0 | 118.4 | |||||||||||||||||||||||||||
|
Impairments |
3.8 | – | 3.8 | 14.6 | 1.0 | 15.6 | 1.8 | (13.3 | ) | (11.5) | ||||||||||||||||||||||||||
|
Investment income |
(9.8 | ) | – | (9.8 | ) | (6.4 | ) | – | (6.4 | ) | (17.9 | ) | – | (17.9) | ||||||||||||||||||||||
|
Other gains and losses |
18.0 | 0.2 | 18.2 | (43.6 | ) | 1.6 | (42.0 | ) | (44.1 | ) | 1.1 | (43.0) | ||||||||||||||||||||||||
|
Finance costs |
28.7 | – | 28.7 | 31.4 | – | 31.4 | 30.5 | 1.0 | 31.5 | |||||||||||||||||||||||||||
|
Taxation |
130.8 | 14.9 | 145.7 | 102.8 | 6.7 | 109.5 | 162.6 | (2.1 | ) | 160.5 | ||||||||||||||||||||||||||
|
Adjusted EBITDA |
559.3 | 59.7 | 619.0 | 488.3 | 16.6 | 504.9 | 573.0 | (27.8 | ) | 545.2 | ||||||||||||||||||||||||||
|
Revenue |
2,369.0 | 83.4 | 2,452.4 | 2,208.8 | 114.8 | 2,323.6 | 2,522.4 | 281.8 | 2,804.2 | |||||||||||||||||||||||||||
|
Adjusted EBITDA margin |
23.6% | 71.6% | 25.2% | 22.1% | 14.5% | 21.7% | 22.7% | (9.9% | ) | 19.4% | ||||||||||||||||||||||||||
Other Information
Significant subsidiaries
Significant subsidiaries (excluding joint ventures) for Acergy (now Subsea 7) as at November 30, 2010 are set out in the table below.
| Company name | Country of incorporation | Percentage of ownership | ||||||
|
Acergy Shipping Limited |
Isle of Man | 100% | ||||||
|
Subsea 7 Contracting (Norway) AS |
Norway | 100% | ||||||
|
Subsea 7 West Africa SAS |
France | 100% | ||||||
|
Subsea 7 Angola S.A. |
France | 100% | ||||||
|
Class 3 Shipping Limited |
Bermuda | 100% | ||||||
In addition, the Group has interests in a number of joint ventures, which are described in the ‘Financial Review – Investments in Associates and Joint Ventures’ on page 76.
|
146 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| Subsequent to the Combination with Subsea 7 Inc., on January 7, 2011, the information below has been updated to reflect the new combined Group. | ||
|
Risks and insurance |
||
| The Group’s operations are subject to all the risks normally associated with offshore development and operations and could result in damage to or loss of property, suspension of operations or injury or death to employees or third parties. The Group believes it insures assets at appropriate levels, subject to self-insured deductibles. Such assets include all capital items such as vessels, major equipment and land-based property. The determination of the appropriate level of insurance coverage is made on an individual asset basis taking into account several factors, including the age, market value, cash flow value and replacement value of the asset in hand. | ||
| The Group’s operations are conducted in hazardous environments where accidents involving catastrophic damage or loss of life could result, and litigation arising from such an event may result in the Group being named a defendant in lawsuits asserting large claims. The Group insures itself against liability arising from its operations, including loss of or damage to third-party property, death or injury to employees and/or third parties, statutory workers’ compensation protection and pollution. However, there can be no assurance that the amount of insurance the Group carries is sufficient to protect fully in all events and a successful liability claim for which it is under-insured or uninsured could have a material adverse effect. The Group is exposed to substantial hazards, risks and delays that are inherent in the offshore services business for which liabilities may potentially exceed its insurance coverage and contractual indemnity provisions. | ||
|
Government regulations |
||
| The Group is subject to international conventions and governmental regulations that strictly regulate various aspects of its operations. The maritime laws and the health and safety regulations of the jurisdictions in which the Group operates govern operations in these areas. A system of management policies and procedures, which describes all business processes, is designed to meet best practice and covers all legislative requirements in the jurisdictions in which the Group operates. In addition, the guidelines set by the International Marine Contractor Association are closely followed. | ||
|
The International Maritime Organisation has made the regulations of the International Safety Management (‘ISM’) Code mandatory. The ISM Code provides an international standard for the safe management and operation of vessels, pollution prevention and certain crew and ship or barge certifications. The Group believes that it is in compliance with these standards to the extent they are applicable to its operations.
Compliance with current health, environmental, safety and other laws and regulations is a normal part of the business. These laws change frequently and the Group incurs costs to maintain compliance with such laws. Although these costs have not had a material impact on its financial condition or results of operations in recent years, there can be no assurance that they will not have such an impact in the future. Moreover, although the Group’s objective is to maintain compliance with all such laws and regulations that are applicable to the Group, there can be no assurance that all material costs, liabilities and penalties imposed as a result of governmental regulation are avoided in the future.
In addition, the Group is required by various governmental and other regulatory agencies, to obtain certain permits, licenses and certificates with respect to its equipment and operations. The permits, licences and certificates required in its operations depend upon a number of factors but are normally of a type required of all operators in a given jurisdiction. The Group believes that it has or can readily obtain almost all permits, licenses and certificates necessary to conduct its operations. |
||
| Some countries require that the Group enters into joint venture or similar business arrangements with local individuals or businesses in order to conduct business in such countries. | ||
| The Group’s operations are affected from time to time and to varying degrees by political developments and federal and local laws and regulations. In particular, oil and gas production operations and economics are affected by price control, tax and other laws relating to the petroleum industry, by changes in such laws and by constantly changing administrative regulations. Such developments may directly or indirectly affect the operations of the Group and those of its clients. | ||
| In April 2010, the Deepwater Horizon rig engaged in deepwater drilling operations at the Macondo well in the US Gulf of Mexico sank after a blowout, resulting in the discharge of substantial amounts of oil into the US Gulf of Mexico. Subsequently, the US Department of Interior imposed a temporary drilling moratorium on offshore deepwater drilling operations and took other regulatory actions to suspend drilling in the US Gulf of Mexico. The Group has not experienced a material impact on its operations as a result of the Macondo incident. However, this incident may result in further regulation or restriction of offshore oil and gas exploration and development activity in the US Gulf of Mexico and elsewhere. Furthermore, the imposition of a moratorium on exploration or development in certain region could negatively affect the economics of currently planned activity in these areas and demand for the Group’s services, which may affect the business and operations of the Group. |
|
|
|
The Group conducts business in certain countries known to experience governmental corruption. Although it is committed to conducting business in a legal and ethical manner in compliance with local and international statutory requirements and standards applicable to its business, there is a risk that employees or representatives may take actions that violate either the US Foreign Corrupt Practices Act, the UK Bribery Act or other legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable laws and regulations. Such violations could result in monetary or other penalties against the Company or its subsidiaries and could damage its reputation and, therefore, its ability to do business. See ‘Risk Factors – Financial and Compliance Risks’. |
||
|
seabed-to-surface
|
|
147
|
Additional Information
Inspection by a classification society and dry-docking
The hull and machinery of most of the Group’s vessels must be ‘classed’ by a classification society authorised by its country of registry. The classification society certifies that the vessel is safe and seaworthy in accordance with the classification rules as well as with applicable rules and regulations of the country of registry of the vessel and the international conventions of which that country is a member. Those of the Group’s vessels that do not require to be so ‘classed’ comply with applicable regulations.
Each classed vessel is inspected by a surveyor of the classification society. A visual inspection is carried out annually to ascertain the general condition of the vessel or relevant items. Intermediate surveys are carried out at the second or third annual survey. This intermediate survey includes a visual inspection of the hull structure, machinery and electrical installations and equipment. Renewal surveys, which involve a major inspection of the hull structure, machinery installations and equipment, are carried out at five-year intervals. A classed vessel is also required to be dry-docked at least once every five years for inspection of the underwater parts of the vessel, and depending on age and class notation, at an intermediate stage between the second and third years. For example, Seven Atlantic will be docked every five years whereas Seven Pelican will be docked every two to three years, and in fiscal year 2008 Acergy Polaris was dry-docked for seven months for its 30 year reclassification. Should any non-compliance be found, the classification society surveyor will issue its report as to appropriate repairs, which must be made by the vessel owner within the time limit prescribed. Insurance underwriters make it a condition of insurance coverage that a classed vessel is ‘in class’. All the Group’s vessels met that condition as at November 30, 2010.
Employees
The Group’s workforce varies based on the workload at any particular time. The following table presents the breakdown of permanent and temporary employees by region as at November 30, 2010, 2009 and 2008 respectively:
| As at November 30 |
2010
Permanent |
2010
Temporary |
2009
Permanent |
2009
Temporary |
2008
Permanent |
2008
Temporary |
||||||||||||||||||
|
Acergy AFMED |
1,773 | 1,600 | 1,384 | 1,408 | 1,578 | 1,133 | ||||||||||||||||||
|
Acergy NEC |
634 | 66 | 703 | 43 | 815 | 122 | ||||||||||||||||||
|
Acergy NAMEX |
87 | 1 | 111 | – | 166 | 10 | ||||||||||||||||||
|
Acergy SAM |
754 | 25 | 765 | 19 | 680 | 51 | ||||||||||||||||||
|
Acergy AME |
147 | 9 | 165 | 94 | 228 | 109 | ||||||||||||||||||
|
Acergy CORP (b) |
1,347 | 747 | 1,279 | 414 | 1,185 | 367 | ||||||||||||||||||
|
Total |
4,742 | 2,448 | (a) | 4,407 | 1,978 | 4,652 | 1,792 | |||||||||||||||||
| (a) | The average number of temporary employees for fiscal year 2010 was 2,307. |
| (b) | Acergy CORP incorporates the majority of Offshore Resources including personnel based onshore directly supporting the vessel and crewing management. |
A significant number of employees are represented by labour unions. As part of the normal course of business, a number of union agreements came up for annual renegotiation at their formal contractual end during 2010. The Group believes that it maintains a good relationship with all employees and their unions. In addition, many workers, including most divers, are hired on a contract basis and are available on short notice.
The increase in personnel is due to the success in gaining a number of key contracts by Acergy AFMED, particularly in West Africa. The use of temporary personnel provides the Group with appropriate flexibility to manage the workforce levels as the sector continues to face challenging short-term market conditions.
Other regions have sustained stable or reduced headcount in order to continue the management of costs and also reflecting the global distribution of projects.
Following the Combination on January 7, 2011, the new combined Group Subsea 7 S.A. had 8,346 permanent and 4,146 temporary employees, which are distributed as shown in the following table, which reflects the Group’s new segments:
| As at January 7 |
2011
Permanent |
2011
Temporary |
||||||
|
Africa and Gulf of Mexico |
2,101 | 1,646 | ||||||
|
Asia Pacific and Middle East |
302 | 170 | ||||||
|
Brazil |
1,811 | 88 | ||||||
|
North Sea, Mediterranean and Canada |
1,929 | 520 | ||||||
|
Corporate including Offshore Resources |
2,203 | 1,722 | ||||||
|
Total |
8,346 | 4,146 | ||||||
Supplies and raw materials
In general, the Group does not manufacture the components used in the offshore services that it provides, but rather procures and installs equipment manufactured or fabricated by others. The Group fabricates structures using components and equipment it procures, and this work is performed at its fabrication yard located in Warri, Nigeria and Sonamet’s yard in Lobito, Angola. When reel lay or bundles are used the Group fabricates pipes onshore at its spool bases in Vigra, Norway, Port Isabel, US, Ubu, Brazil, Luanda, Angola, and at its bundle fabrication in Wick, Scotland.
|
148 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| To the extent that the Group is exposed to raw materials or commodity related price risk, in respect of EPIC and/or lump sum contracts, dry-dock requirements or the cost of completion of vessels, the Group seeks to minimise the impact of price variations through contractual terms with clients and/or through the use of hedging or future contracts. | ||
| The procurement of goods and services represents a significant proportion of annual operating costs and has a direct impact on overall financial performance. When procuring supplies and raw materials the Group’s goal is therefore to take the following principles into consideration: | ||
|
• In placing a commitment with a supplier or subcontractor, the Group tries to secure the best commercial and operational arrangement, taking into account the costs, payment terms and risks, such as technical, quality, health, safety and environmental management, reliability, lead times and confidence of supply; |
||
|
• The Group operates as one organisation and leverages, whenever it can, knowledge, relationships, networks and buying power; |
||
|
• The procurement process is executed in accordance with its policies and procedures and adheres to the Code of Conduct; and |
||
|
• The Group actively develops and manages relationships with suppliers and subcontractors. The Group believes that strong relationships with vendors are key to gaining a competitive advantage as well as ensuring that their delivery goals are aligned with the needs of the business. |
||
|
Marketing |
||
| Marketing of the Group’s services is performed through the regional offices. The Group’s marketing strategy is focused on ensuring that the Group is invited to bid on all projects that are consistent with the Group’s strategy, and where competitive advantage on the basis of the ship ownership, fabrication capacity, engineering excellence or technological specialisation exists. The Group uses its industry know-how and relationships with clients to ensure the Group is aware of all projects in the markets that fit these criteria. | ||
| Most of the Group’s work is obtained through a competitive tendering process. When a target project is identified by the marketing team, the decision to prepare and submit a competitive bid is taken by regional and corporate management. | ||
|
Clients |
||
| The level of construction services required by any particular client depends on the size of that client’s capital expenditure budget devoted to construction plans in a particular year. Consequently, clients that account for a significant portion of contract revenue in one fiscal year may represent an immaterial portion of contract revenue in subsequent fiscal years. | ||
| The business typically involves a relatively concentrated number of significant projects in any year. Consequently, the Group expects that a limited number of clients will account for significant portions of revenue in any year. | ||
| In fiscal year 2010, the Group had 32 clients worldwide, of which 24 were major national and international oil and gas companies. Total, ExxonMobil and Petrobras accounted for 18%, 17% and 9% of the revenue from continuing operations respectively in fiscal year 2010, while in fiscal year 2009, Total, ExxonMobil and Petrobras accounted for 4%, 25% and 7% of the revenue from continuing operations respectively. During fiscal years 2010 and 2009, the ten largest clients accounted for 79% and 75% respectively of revenue from continuing operations, and over that period seven clients, Total, ExxonMobil, Petrobras, Angola LNG, Statoil, Chevron and Dong Energy consistently numbered among the ten largest clients. For further details, see Note 20 ‘Trade and other receivables’ and Note 34 ‘Financial instruments’ to the Consolidated Financial Statements. | ||
| Since the Combination with Subsea 7 Inc., the Group has a wider client base largely due to the i-Tech and Veripos divisions. However, the business is expected to remain concentrated on a small number of significant projects with a limited number of clients accounting for a significant portion of revenue in any year. | ||
|
Competition |
||
| The demand for OECM services is driven by the global nature of the oil and gas markets and most market participants operate on a worldwide basis. Consequently, the OECM industry remains highly competitive. | ||
| The contract price is one of the primary factors in determining which qualified contractor with available equipment will be awarded a contract. Clients also consider other criteria in their evaluations, such as the availability and technical capabilities of equipment and personnel, efficiency, condition of equipment, safety record and reputation. Furthermore, a local presence and a guaranteed minimum percentage of local content is a legal requirement in certain countries, and an important factor with significant political value in others. Notwithstanding this, the global nature of the OECM market allows for the manpower and equipment to be relocated to other locations across the globe, which allows for competition from a worldwide supplier base. The supply-side of the OECM market comprises many companies of different sizes, including several large global companies, but also numerous mid-size local and regional companies. |
|
|
|
Subsea 7 is one of the leading seabed-to-surface engineering, construction and services contractors, capable of providing a wide range of offshore project services on a worldwide basis in the major offshore oil and gas producing regions. Other global competitors in the OECM market include: Allseas, Global Industries, Heerema, Helix, J Ray McDermott, Saipem, Seastream and Technip. Subsea 7 faces strong competition from these offshore contractors. It also faces competition from smaller regional competitors and less integrated providers of offshore services. A number of contractors as well as ship owners have placed orders for additional vessels capable of working in the OECM market which might cause an excess of supply and the demand for services may be adversely affected. It is expected that any increase in demand may be met quickly by new vessels being deployed in the future. |
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Additional Information
Health, safety, environmental and security management
The Group conducts business in accordance with a well-defined set of processes, which comply with the International Management Code for the Safe Operation of Ships and for Pollution Prevention. Its Health, Safety, Environmental and Security philosophy is based on the international standards of OHSAS 18001 for occupational health and safety, ISO 14001 for environmental management and international best practice, government and industry standards for security. This ‘Management System’ is supported by management’s commitment, personal accountability, training, fairness and the measurement and analysis of performance measures. The Management System is designed to ensure that the employees and everyone the Group works with remains safe and healthy, that it effectively manages its environmental aspects and limits the damage to or loss of property and equipment. Each manager is responsible for taking the necessary steps to create and maintain a culture of continuous improvement.
The Management System also provides the necessary instructions, procedures and guidelines encompassing all areas of the Group’s operations to assure the quality of services to clients. The Group maintains a stringent quality assurance programme throughout the organisation in accordance with ISO 9001 2000, an international standard established by the International Organisation for Standardisation to certify quality assurance systems. The Group has introduced tools and processes to further drive the total quality management process across the organisation. Each segment has dedicated professional health, safety, environmental and quality assurance staff who are responsible for overseeing and supporting the projects in that particular segment.
Intellectual property
The Group holds a number of patents, trademarks, software and other intellectual property to support its engineering and operational activities.
As at November 30, 2010, 87 patents were in force in 15 countries, and the Group currently has a portfolio of 185 additional developments under patent application. A limited number of patents are held in common with other industrial partners. The Group also conducts some of its operations under licensing agreements allowing it to make use of specific techniques or equipment patented by third parties. The Group does not consider that any one patent or technology represents a significant percentage of revenue.
On January 7, 2011 the Group obtained an additional 3 trademarks and 24 patents in 4 countries and a portfolio of 73 additional developments under patent application through the combination with Subsea 7 Inc. Of these, a limited number of patents are held in common with other industrial partners.
The Group’s research and development programmes are focused on the requirements of clients, who are constantly seeking to develop oil and gas reserves in deeper waters, and on increasing the efficiency of offshore equipment and operations. The Group runs research and development programmes aimed at developing new technologies and extending existing technologies for the installation, repair and maintenance of offshore structures, particularly underwater pipelines and risers. The Group’s research and development activities are typically carried out internally using both dedicated research personnel and as part of specific offshore construction projects. External research and development is performed either through strategic technological alliances or via joint industry collaborative projects, where appropriate. The expenditures on Group-sponsored research and development, excluding programmes undertaken as part of specific offshore construction projects were approximately $5.2 million in fiscal year 2010 (2009: $6.2 million, 2008: $6.8 million).
Description of property
The Group operates a fleet of highly specialised vessels, barges and unmanned underwater ROVs, deployed in the world’s major offshore oil and gas exploration regions. Key assets in operation, as at November 30, 2010, included:
| • | 3 subsea construction vessels; |
| • | 6 flexible pipelay vessels; |
| • | 4 inspection, repair, maintenance and survey vessels; |
| • | 1 heavy lift and pipelay ship (operated by SapuraAcergy); |
| • | 1 heavy lift barge (operated by SHL); |
| • | 4 rigid pipelay vessels/barges; |
| • | 8 cargo barges; and |
| • | 30 work class and observation ROVs. |
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Major assets
The following table describes the major assets as at November 30, 2010:
| Name | Capabilities |
Year built/major
upgrade |
ROVs |
Length overall
(metres) |
Owned/
Chartered |
|||||||||||
|
Acergy Condor |
Flexible flowline and umbilical lay | 1982/1994/ | 2 | 141 | Owned | |||||||||||
| 1999/2002 | ||||||||||||||||
|
Acergy Discovery |
Flexible flowline lay, subsea construction | 1990 | 1 | 120 | Owned | |||||||||||
|
Acergy Eagle |
Flexible flowline lay, multi-purpose subsea construction | 1997 | 2 | 140 | Owned | |||||||||||
|
Acergy Falcon |
Rigid and flexible flowline and umbilical lay | 1976/1995/ | 2 | 162 | Owned | |||||||||||
| 1997/2001 | ||||||||||||||||
|
Acergy Harrier |
Subsea construction | 1985 | 2 | 84 | Owned | |||||||||||
|
Acergy Hawk |
Subsea construction | 1978 | – | 93 | Owned | |||||||||||
|
Acergy Legend |
ROV support, subsea construction | 1985/1998 | 2 | 73 | Owned | |||||||||||
|
Acergy Orion |
Pipelay barge | 1977/1984/ | – | 85 | Owned | |||||||||||
| 1997 | ||||||||||||||||
|
Acergy Osprey |
Subsea construction | 1984/1992/ | 1 | 102 | Owned | |||||||||||
| 1996/2003 | ||||||||||||||||
|
Acergy Petrel |
Pipeline inspection, ROV survey and ROV light intervention activities | 2003 | 1 | 76 | Owned | |||||||||||
|
Acergy Polaris |
Deepwater derrick/pipelay barge | 1979/1991/19 | 2 | 137 | Owned | |||||||||||
| 96/1999/2002 | ||||||||||||||||
| /2003/2006/ | ||||||||||||||||
| 2008 | ||||||||||||||||
|
Acergy Viking |
Pipeline inspection, ROV survey and ROV light intervention activities | 2007 | 1 | 98 | Chartered | (a) | ||||||||||
|
Antares |
Shallow water pipelay barge | 2010 | – | 119 | Owned | (b) | ||||||||||
|
Borealis |
Deepwater rigid and flexible flowline and umbilical lay and subsea construction | 2012 | 2 | 182 | Owned | (c) | ||||||||||
|
Far Saga |
ROV support, subsea construction | 2001 | 2 | 89 | Chartered | (d) | ||||||||||
|
Havila |
Diving support vessel | 2011 | 1 | 120 | Owned | (c)(e) | ||||||||||
|
Oleg Strashnov |
Heavy lift, 5,000-tonne crane | 2011 | – | 132 | Owned | (c)(j) | ||||||||||
|
Pertinacia |
Flexible flowline and umbilical lay | 2003/2007 | 2 | 130 | Owned | (g) | ||||||||||
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Polar Queen |
Flexible flowline and umbilical lay | 2001/2007 | 2 | 146 | Owned | (h) | ||||||||||
|
Sapura 3000 |
Deep water construction ship | 2008 | 2 | 151 | Owned | (f) | ||||||||||
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Skandi Acergy |
Construction ship with an ice-class hull | 2008 | 2 | 157 | Chartered | (i) | ||||||||||
|
Stanislav Yudin |
Heavy lift, 2,500-tonne crane | 1985 | – | 183 | Owned | (j) | ||||||||||
|
(a) Chartered from Eidesvik Shipping A.S. for eight years beginning December 2007 with ten annual options to extend until the end of 2027. |
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(b) Purchased on June 1, 2010.
(c) Under construction. |
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(d) Option with Farstad Supply A.S. until March 31, 2011 to pay on an as-used basis.
(e) Owned by Acergy Havila Limited.
(f) Owned and operated by the joint venture, SapuraAcergy.
(g) Previously chartered from Elettra TLC SpA and purchased on September 7, 2010.
(h) Previously chartered from GC Rieber Shipping Ltd and purchased on June 14, 2010.
(i) Chartered from DOFCON ASA August 8, 2008 until August 2016 with four renewal options at the end of 2016, two for two years and the other two for one year.
(j) Owned and operated by the joint venture, SHL. |
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All of the above are included in the major vessels apart from Stanislav Yudin and Oleg Strashnov which are owned by Seaway Heavy Lifting. |
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For a discussion of ship utilisation, see ‘Financial Review – Significant Factors Affecting Results of Operations and Financial Position – Vessel Utilisation’. |
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Additional Information
The Combination with Subsea 7 Inc. resulted in the expansion of the Group’s key assets to include:
| • | 9 construction/flexlay vessels; |
| • | 2 pipelay vessels; |
| • | 3 inspection, maintenance, repair and survey vessels; |
| • | 5 diving vessels; |
| • | 99 work class ROVs, plus 13 under construction; |
| • | 25 observation class ROVs. |
Major assets obtained through the Combination with Subsea 7 Inc.:
| Name | Capabilities | Year built/major upgrade | ROVs |
Length overall (metres) |
Owned/
Chartered |
|||||||||||||
|
Kommandor 3000 |
Flexible pipelay and construction | 1984/1998/ 1999 | 2 | 118 | Owned | |||||||||||||
|
Kommandor Subsea |
IMR and survey | 1986 | 3 | 69 | Owned | |||||||||||||
|
Lochnagar |
Flexible pipelay and construction | 1982/1998/ 2005 | 2 | 105 | Owned | |||||||||||||
|
Normand Seven |
Flexible pipelay and construction | 2007 | 2 | 130 | Chartered | (a) | ||||||||||||
|
Normand Subsea |
IMR and survey | 2009 | 7 | 113 | Chartered | (b) | ||||||||||||
|
Rockwater 1 |
Diving support | 1983 | 1 | 98 | Owned | |||||||||||||
|
Rockwater 2 |
Diving support | 1984 | 1 | 119 | Owned | |||||||||||||
|
Seisranger |
IMR and survey | 1993 | 2 | 85 | Chartered | (c) | ||||||||||||
|
Seven Atlantic |
Diving support | 2009 | 2 | 145 | Owned | |||||||||||||
|
Seven Navica |
Rigid/flexible pipelay | 1999 | – | 109 | Owned | |||||||||||||
|
Seven Oceans |
Rigid/flexible pipelay | 2007 | 2 | 157 | Owned | |||||||||||||
|
Seven Pacific |
Flexible pipelay and construction | 2010 | 2 | 134 | Owned | |||||||||||||
|
Seven Pelican |
Diving support | 1985 | 1 | 94 | Owned | |||||||||||||
|
Seven Seas |
Rigid/flexible pipelay and construction | 2008 | 2 | 153 | Owned | |||||||||||||
|
Seven Sisters |
Flexible pipelay and construction | 2008 | 2 | 104 | Chartered | (d) | ||||||||||||
|
Seven Spray |
Shallow diving support | 2007 | – | 12 | Owned | |||||||||||||
|
Skandi Neptune |
Flexible pipelay and construction | 2001/2005 | 2 | 104 | Chartered | (e) | ||||||||||||
|
Skandi Seven |
Flexible pipelay and construction | 2008 | 2 | (f) | 121 | Chartered | (f) | |||||||||||
|
Subsea Viking |
Flexible pipelay and construction | 1999 | 2 | 103 | Chartered | (g) | ||||||||||||
|
Toisa Polaris |
Diving support | 1999 | 3 | 114 | Chartered | (h) | ||||||||||||
| (a) | Chartered from Solstad Shipping A.S. for eight years beginning July 2007 with five annual options to extend until 2020. |
| (b) | Chartered from Solstad Shipping A.S. beginning 2009 until December 2014 with four one-year options to extend. |
| (c) | Chartered from Forland Shipping A.S. for the five years to December 2011 with two one-year options to extend. |
| (d) | Chartered from Siem Offshore Rederi AS for five years ending July 2013 with five one-year renewal options to extend. |
| (e) | Chartered from DOF UK Limited beginning 2005 until December 2010.The charter has been extended for three years from the completion of a crane upgrade which commenced in January 2011 with a further three one-year options to extend. |
| (f) | Vessel and two Work class ROVs chartered from DOF Subsea UK Limited beginning 2008 until December 2012 with two one-year renewal options to extend followed by one two-year renewal option. |
| (g) | Chartered from Eidesvik Shipping A.S. for five years ending April 2011 with one eight-month renewal option to extend followed by four one-year renewal options to extend. |
| (h) | Chartered from Toisa Limited for five years ending May 2011. |
The environmental regulations which affect the utilisation of the assets listed above are described in ‘Additional Information – Government Regulations’.
|
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Other properties
As at November 30, 2010 the Group owned or leased real estate properties to conduct its business as described below:
| Location | Function |
Office space
(square metres) |
Work or storage
space or land (square metres) |
Status | ||||||||||||||
|
Hammersmith, England, UK |
Offices | 1,957 | – | Leased | ||||||||||||||
|
Aberdeen, Scotland, UK |
Office, workshop and storage | 19,150 | 12,695 | Leased | ||||||||||||||
|
Cairo, Egypt |
Offices | 350 | – | Leased | ||||||||||||||
|
Suez, Egypt |
Yard and storage | – | 1,000 | Leased | ||||||||||||||
|
Houston, Texas |
Offices | 5,203 | – | Leased | ||||||||||||||
|
Galveston, Texas |
Storage | – | 2,500 | Leased | ||||||||||||||
|
Lagos, Nigeria |
Offices | 2,200 | – | Leased | ||||||||||||||
|
Onne, Nigeria |
Offices and industrial | 120 | 5,000 | Leased | ||||||||||||||
|
Port-Harcourt, Nigeria |
Offices | 245 | – | Leased | ||||||||||||||
|
Warri, Nigeria |
Offices, fabrication and storage | 1,765 | 222,582 | Leased | ||||||||||||||
|
Pointe Noire, Congo |
Offices and storage | 1,300 | – | Leased | ||||||||||||||
|
Lobito, Angola |
Offices, fabrication and storage | 5,945 | 554,431 | Leased | (a) | |||||||||||||
|
Luanda, Angola |
Offices | 400 | – | Leased | (a) | |||||||||||||
|
Luanda, Angola |
Offices and storage | 444 | 10,200 | Leased | ||||||||||||||
|
Madeira Island, Portugal |
Offices | 303 | – | Leased | (a) | |||||||||||||
|
Newfoundland, Canada |
Offices | 835 | – | Leased | ||||||||||||||
|
Perth, Australia |
Offices | 2,014 | – | Leased | ||||||||||||||
|
Port Gentil, Gabon |
Offices, workshop and land | 1,793 | – | Owned | ||||||||||||||
|
Ntchengue yard, Gabon |
Offices and storage | 790 | 16,954 | Owned | ||||||||||||||
|
Ntchengue yard, Gabon |
Yard | – | 413,517 | Leased | ||||||||||||||
|
Rio de Janeiro, Brazil |
Offices | 297 | – | Owned | ||||||||||||||
|
Rio de Janeiro, Brazil |
Offices | 1,349 | – | Leased | ||||||||||||||
|
Macae City, Brazil |
Offices, workshop, fabrication and storage | 2,508 | 14,112 | Owned | ||||||||||||||
|
Beijing |
Offices | 269 | – | Leased | ||||||||||||||
|
Singapore |
Offices, workshop and storage | 1,630 | 1,879 | Leased | ||||||||||||||
|
Kristiandsund, Norway |
Offices, yard | 280 | 360 | Leased | ||||||||||||||
|
Stavanger, Norway |
Offices | 12,869 | – | Leased | ||||||||||||||
|
Suresnes, France |
Offices | 21,548 | – | Leased | ||||||||||||||
|
(a)Part of Sonamet, which was classified as assets held for sale as at November 30, 2010 (refer to Note 21 ‘Assets held for sale’). |
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Additional Information
The Combination with Subsea 7 Inc. resulted in the addition of the following properties:
| Location | Function |
Office space
(square metres) |
Work, storage
space or land (square metres) |
Status | ||||||||||
|
Westhill, Scotland, UK |
Offices | 17,372 | – | Owned | ||||||||||
|
Aberdeen, Scotland, UK |
Office, workshop and storage | 2,356 | 48,562 | Owned | ||||||||||
|
Westhill, Scotland, UK |
Offices | 2,043 | – | Owned | ||||||||||
|
Wick, Scotland, UK |
Office, workshop, fabrication and storage | 1,055 | 297,550 | Leased | ||||||||||
|
Leith, Scotland, UK |
Workshop, fabrication and storage | – | 34,950 | Leased | ||||||||||
|
Sutton, England, UK |
Offices | 2,787 | – | Leased | ||||||||||
|
Glasgow, Scotland, UK |
Offices | 868 | 10,000 | Owned | ||||||||||
|
Glasgow, Scotland, UK |
Offices, workshop and storage | 761 | 4,000 | Leased | ||||||||||
|
Stavanger, Norway |
Offices | 12,261 | – | Owned | ||||||||||
|
Dusavik, Norway |
Offices, workspace and storage | 2,300 | 36,000 | Leased | ||||||||||
|
Vigra, Norway |
Offices, fabrication and storage | – | 295,000 | Owned | ||||||||||
|
Grimstad, Norway |
Offices | 3,850 | – | Leased | ||||||||||
|
Luanda, Angola |
Yard and offices | 400 | 70,000 | Leased | ||||||||||
|
Rotterdam, Netherlands |
Offices | 1,389 | – | Leased | ||||||||||
|
Ataka General Free Zone, Egypt |
Office plot | – | 1,000 | Leased | ||||||||||
|
Houston, Texas |
Offices and workshop | 5,374 | 191 | Leased | ||||||||||
|
Katy, Texas |
Office, workshop, and storage | 395 | 580 | Leased | ||||||||||
|
Shanghai, China |
Offices | 490 | – | Leased | ||||||||||
|
Ciudad del Carmen, Mexico |
Offices, warehouse and yard | 2,266 | 2,420 | Leased | ||||||||||
|
Port Isabel, Texas |
Spoolbase land | – | 109,200 | Leased | ||||||||||
|
Port Isabel, Texas |
Offices, fabrication and storage | 1,858 | 4,645 | Owned | ||||||||||
|
Kuala Lumpur, Malaysia |
Offices | 901 | – | Leased | ||||||||||
|
Perth, Australia |
Offices, yard and storage | 433 | 2355 | Leased | ||||||||||
|
Singapore |
Offices | 1533 | – | Leased | ||||||||||
|
Niteroi, Brazil |
Offices, workshop and storage | 7,000 | 9,000 | Owned | ||||||||||
|
Rio das Ostras, Brazil |
Offices, workshop and storage | 5,754 | 6,082 | Owned | ||||||||||
|
Andrade, Brazil |
Storage | – | 2,500 | Leased | ||||||||||
|
Parana, Brazil |
Spoolbase land | – | 26,000,000 | Owned | ||||||||||
|
Ubu, Brazil |
Offices, fabrication and storage | 5,000 | 86,000 | Leased | ||||||||||
|
Vila Velha, Brazil |
Offices and storage | 517 | 5,600 | Leased | ||||||||||
Investor Information
Overview
We are a seabed-to-surface engineering, construction and services contractor to the offshore energy industry worldwide. We provide integrated services, and we plan, design and deliver complex, projects in harsh and challenging environments.
Our 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. We operate internationally as one Group – globally aware and locally sensitive, sharing our expertise and experience to create innovative solutions.
We are more than solution providers; we are solution partners – ready to make long-term investments in our people, assets, know-how and relationships in support of our clients. We specialise in creating and applying innovative and efficient solutions in response to the technical complexities faced by our oil and gas clients as they explore and develop offshore production fields in increasingly deepwater and challenging environments. In doing so we provide services and products that add value for our clients throughout the entire life cycle of offshore oil and gas field exploration, development and production.
Service capabilities
We divide our business into the following principal service capabilities:
|
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| Subsea, Umbilicals, Risers and Flowlines (‘SURF’): | ||
| This comprises the engineering, fabrication, procurement, installation and construction work relating to oil and gas fields that are developed subsea, in which the production wellhead is on the seabed, usually in deepwater or harsh and challenging environments. This includes large multi-year, EPIC projects encompassing pipelay, riser and umbilical activities of a complete field development, tieback projects involving pipelaying, umbilical installation and, in some cases, trenching or ploughing, to connect a new or additional subsea development to an existing production facility. The installations of jumpers and spool pieces, as well as ‘hot-tapping’ including hyperbaric welding, are also typical SURF activities. This capability also includes construction and diving support ship charters and rental of equipment including construction support ROVs. | ||
|
Conventional and Conventional Refurbishment: |
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|
• Conventional comprises engineering, construction and installation activities relating to shallow water platforms attached to the seabed and their associated pipelines. Conventional projects involve shallow water activities and broadly proven technology, typically under long-term contracts or EPIC projects. Conventional activities include the design, construction and installation of fixed platforms. Subsea 7 also provides, in certain locations, extensive local content including the fabrication of platform jackets and topsides providing strong links with local communities and increased local employment in these countries. Subsea 7 currently executes Conventional type projects in West Africa, as well as in Asia Pacific through its joint venture SapuraAcergy. |
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• Conventional Refurbishment comprises a comprehensive range of maintenance and refurbishment, including platform and pipeline refurbishment, relating to shallow water platforms. Subsea 7 also provides, in certain locations, extensive local content including the pre-fabrication of refurbishment components, providing strong links with local communities and increased local employment in these countries. |
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|
Life-of-Field: |
||
| Life-of-Field projects include IMR and Survey. | ||
|
• IMR: Subsea 7 provides a comprehensive range of subsea inspection, maintenance and repair services to keep oil and gas fields worldwide producing at optimum capacity. Subsea 7’s services include platform surveys, debris removal and pipeline inspections using both divers and/or ROV inspection on producing oil and gas field infrastructure, as a regular activity throughout the life of the offshore field. Subsea 7 has a number of ongoing long-term maintenance contracts with leading operators, and also provides on-demand call-out services where required. |
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|
• Survey: Subsea 7 provides comprehensive support for both external clients and internal projects in the fields of construction support, platform and pipeline inspection and seabed mapping using specialised Survey vessels and Survey ROVs. The construction support activities include pre-lay, as-laid and as-trenched surveys, spool metrology, deepwater positioning and light installation works. Platform inspection is performed both underwater and on topsides.
i-Tech: i-Tech, a division of Subsea 7, is a provider of ROVs and remote intervention tooling services to the global exploration and production industry. Since Subsea 7 pioneered the use of the first ROV onboard a drill rig in 1980, i-Tech has been at the forefront of remote intervention technology. Subsea 7 operates an advanced fleet of more than 70 ROV systems and employs in excess of 650 highly skilled engineers, technicians, managers and business support personnel around the world. |
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|
Veripos: |
||
| Veripos, a division of Subsea 7, provides precise navigation and positioning services to the offshore industry. Its products and services, which include comprehensive training programmes, are widely used by professionals in key areas of the offshore industry – including seismic exploration, survey & construction, DP Marine and DP Drilling. | ||
|
Renewables: |
||
| Renewables comprises the project management, engineering and construction services to support offshore developments in the global renewables industry, focusing on energy from naturally replenished resources such as wind, sunlight, rain, tides and geothermal heat. |
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|
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Trunklines: |
||
| Trunklines involves the offshore installation of large diameter pipelines used to carry oil and gas over large distances, often intercontinental. The disposal of Acergy Piper in 2008, Subsea 7’s sole unit dedicated to trunkline projects, represents Subsea 7’s discontinuance of this operation as a stand-alone activity. However vessels such as Sapura 3000 can, and Borealis, when completed, are expected to occasionally be involved in trunkline projects. | ||
|
Organisation and register |
||
| Subsea 7 S.A. is a ‘société anonyme’, organised in the Grand Duchy of Luxembourg under the Company Law of 1915, as amended. It was incorporated in Luxembourg in 1993 as the holding company for all of its activities. | ||
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The registered office is located at 412F, route d’Esch, L-2086 Luxembourg and is registered in the Companies’ Register of the Luxembourg District Court under the designation R.C.S. Luxembourg B 43172. |
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Additional Information
The agent for US federal securities law purposes is Subsea 7 (US) LLC, 15990 North Barker’s Landing, Suite 200, Houston, Texas 77079, USA. The global support centre is c/o Subsea 7 M.S. Limited., 200 Hammersmith Road, Hammersmith, London, W6 7DL, UK.
History and development of Subsea 7 S.A.
Subsea 7 S.A. was created following the completion of the Combination of Acergy S.A. (now ‘Subsea 7 S.A.’) and Subsea 7 Inc. on January 7, 2011. Subsea 7 S.A. is a ‘société anonyme’ incorporated in the Grand Duchy of Luxembourg under the Luxembourg law of August 10, 1915 on commercial companies as amended and quoted on both NASDAQ and the regulated market of Oslo Børs.
A publicly traded company since May 1993, Acergy was established through the merger of the businesses of two leading diving support services companies, Comex Services S.A. and Stolt-Nielsen Seaway A/S, which were acquired by Stolt-Nielsen S.A. (‘SNSA’) in separate transactions in 1992. At the time of acquisition, Comex Services S.A. was a leading worldwide subsea services contractor, which pioneered deepwater saturation diving and subsea construction using both manned and unmanned techniques. Stolt-Nielsen Seaway A/S operated principally in the North Sea and pioneered the development and use of specially designed, technologically sophisticated diving support vessels and ROVs to support operations in hostile deepwater environments. SNSA sold its equity interest in January 2005.
In 2006, the name ‘Acergy S.A.’ was adopted. At the time, its business was principally that of a seabed-to-surface engineering and construction contractor to the oil and gas industry worldwide, providing integrated services, plans and, designs and delivering complex projects in harsh and challenging offshore environments.
In 2008 the decision was taken to dispose of Acergy’s Trunkline business, which was a non-core business segment consisting solely of Acergy Piper and was hence classified as discontinued operations for fiscal year 2008 and restated for fiscal year 2007. The sale of Acergy Piper to Saipem (Portugal) Comercio Maritimo S.U. Lda was completed in January 2009 for a sales consideration of $78.0 million.
On July 23, 2009 Acergy entered into a sale agreement to dispose of 19% of its ownership interest in Sonamet and Sonacergy. Sonamet operates a fabrication yard for clients, including Subsea 7, operating in the offshore oil and gas industry in Angola and Sonacergy provides overseas logistics services and support to Sonamet. The agreed disposal of 19% will result in a reduction of the 55% ownership interest Subsea 7 holds in each company to 36%. The finalisation of this sale is conditional upon the completion of certain conditions precedent, and is expected to occur in 2011.
On December 16, 2009 Acergy announced the acquisition of Borealis , a pipelay ship for operations in deepwater, currently being built at the Sembawang Shipyard in Singapore. Final completion and operational delivery of this ship is scheduled for the first half of 2012.
History and Development of Subsea 7 Inc.
Subsea 7 Inc. is a subsea contractor operating within the oil and gas industry. Subsea 7 Inc. performs total subsea field developments and provides design, engineering, construction, installation and maintenance of facilities for the subsea production of oil and gas. Subsea 7 Inc. was incorporated on January 10, 2002 under the name DSND Inc., and renamed Siem Offshore Inc. pursuant to a resolution of the General Meeting held on July 9, 2004. It was further renamed from Siem Offshore Inc. to Subsea 7 Inc. at the Annual General Meeting of the company held on July 15, 2005.
As a company incorporated in the Cayman Islands, Subsea 7 Inc. was subject to Cayman Islands laws and regulations, and was traded on the Oslo Børs until delisting occurred on January 7, 2011 following the completion of the Combination with Acergy S.A., renamed Subsea 7 S.A.
Subsea 7 Inc. traces its roots back to Det Søndenfjelds-Norske Dampskipselskap AS (‘DSND’) which was established in 1854. The main operation of the company until 1964 was shipping, with a focus on passenger transportation. In 1964, the company’s passenger liner service between Hamburg and Oslo was closed, and the company’s activity level was then limited until 1985.
DSND operated as an investment company between 1985 and 1995, with investments mostly in offshore related activities. By early 1990, DSND had taken ownership of several dynamically positioned offshore vessels. As a consequence, its Board wanted to cultivate the company’s investment profile and strategy, and other non-offshore related investments were gradually sold or spun-off from DSND.
By 1995, the company owned six special offshore vessels, of which two were for offshore construction, two for well maintenance and two for geo-technical drilling. It planned for further expansion into these three business areas through the addition of technology and human capital. DSND conducted eight acquisitions of assets or businesses between 1995 and 2002, which gave the company a significant position within the area of offshore maintenance and construction, both in terms of geography and resources. The acquisitions provided DSND with the skills and equipment to complete total construction contracts for deepwater subsea installations, as well as the installation of pipelines, floating production units and riser systems, and link-up and completion of subsea production installations. However, DSND experienced low capacity utilisation of its vessels, insufficient presence in several key markets and the lack of critical mass to bid for the largest tenders. A process to identify a complementary partner was therefore initiated in 2001.
On October 18, 2001, DSND announced that it was in discussions with Halliburton to combine their respective activities within subsea construction and related services. On May 23, 2002 the two companies announced that they had completed a final agreement for the creation of the 50/50 joint venture company Subsea 7 Holding Inc. (formerly named Subsea 7 Inc.), registered in the Cayman Islands. The agreement involved all substantial subsea-related assets, personnel and existing contracts from both companies to be included in the joint venture.
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| After the merger in May 2002, both Halliburton and DSND actively contributed to the further industrial development of the Subsea 7 Holding Inc. business. During this period Subsea 7 Holding Inc. also consolidated its non-subsea activities through the divestment of loss-making activities and by a more concentrated focus. The holding company was further relocated from Norway to the Cayman Islands in the fourth quarter of 2002 through a share swap. | ||||
| On November 15, 2004 the company announced that it had entered into heads of agreement with Halliburton to acquire the Halliburton Group’s 50% share of Subsea 7 Holding Inc. for $203 million in cash. Prior to completion of the transaction in January 2005, the company raised NOK 991 million in new equity, equivalent to $160 million, through a private placement of 41,300,000 new shares at a subscription price of NOK 24 per share. A subsequent repair offering was proposed to shareholders, holding less than 50,000 shares, who were not given the opportunity to participate in the private placement. An additional NOK 59 million was raised through this offering and the issuance of 2,458,549 new shares at a subscription price of NOK 24 per share. | ||||
| In July 2005 the company decided that it would be beneficial for the further development of both the subsea business and the non-subsea business, as well as to enhance shareholder value, to separate the subsea and non-subsea businesses and give them the opportunity to develop in distinct companies and under separate management. The company’s subsidiary Siem Supply Inc. which, following an internal restructuring contained all the non-subsea business of Subsea 7 Inc., was renamed Siem Offshore Inc. and the shares of Siem Offshore Inc. were distributed to the shareholders of Subsea 7 Inc. through a payment of dividend in specie in the form of repayment from the share premium account. On the distribution date, each shareholder in Subsea 7 Inc. received one share of Siem Offshore for each share in Subsea 7 Inc. | ||||
| Corporate Governance requirements | ||||
| As a company incorporated in Luxembourg, and quoted on both NASDAQ and Oslo Børs, Subsea 7 S.A. is subject to a number of different laws and regulations with respect to corporate governance. A key corporate governance activity undertaken by the Group concerns compliance with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002, which is applicable to all companies listed on a US national securities exchange and enforced by the SEC. The Group is committed to achieving high corporate governance standards at all times and believes the observance of those standards is in the best interest of all stakeholders. | ||||
| The Group acknowledges the division of roles between shareholders, the Board and the Executive Management Team. The Company further ensures good governance is adopted by holding regular Board meetings which the Executive Management Team attend to present strategic, operational and financial matters. | ||||
| So long as Subsea 7 S.A. remains listed on NASDAQ, the Group is subject to the NASDAQ Listing Rule 5600 series establishing certain corporate governance requirements for companies listed on NASDAQ. Pursuant to NASDAQ Listing Rule 5615(a)(3), as a foreign private issuer the Company may follow home country corporate governance practices in lieu of the requirements of the Rule 5600 series, provided that the group (i) complies with certain mandatory sections of the Rule 5600 series, (ii) discloses each requirement of Rule 5600 that it does not follow and describes the home country practice followed in lieu of such other requirement and (iii) delivers a letter to NASDAQ from the Group’s Luxembourg counsel certifying that the corporate governance practices that the Group does follow are not prohibited by Luxembourg law. The Group’s independent Luxembourg counsel has certified to NASDAQ that the Group’s corporate governance practices are not prohibited by Luxembourg law. | ||||
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The requirements of the Rule 5600 series that are not followed, and the Luxembourg corporate governance practices that the Company follows in lieu thereof, are described below:
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• Rule 5605(e)(1) requires that if there is a Nomination Committee, it be comprised solely of Independent Directors, as defined under in NASDAQ Listing Rule 5605(a)(2). In lieu of the requirements of Rule 5605(e)(1), the Company follows generally accepted business practices in Luxembourg, which do not have rules by which the Company is bound governing the composition of the Nomination Committee.
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• Rule 5605(d)(1) requires that the Compensation Committee be comprised solely of Independent Directors as defined under NASDAQ Listing Rule 5605(a)(2). In lieu of the requirements under Rule 5605(d)(1), the Company follows generally accepted business practices in Luxembourg.
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• Rule 5605(c)(2)(A) requires that the Audit Committee has at least three members, each of whom, among other things, must be independent as defined under NASDAQ Listing Rule 5605(a)(2) and meet the criteria for independence set forth in Rule 10A-3(b)(1) under the Securities Exchange Act of 1934, as amended, in lieu of the requirements of Rule 5605(c)(2)(A), the Company complies with home country practice, which allows for less than three Audit Committee members who are independent as set forth in Rule 10A – 3(b)(1) of the Securities Exchange Act 1934, as amended.
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• Rule 5605(b)(1) requires that the Board be comprised of a majority of Independent Directors as such term is defined in Rule 5605(a)(2). In lieu of the requirements of Rule 5605(b)(1), the Board is comprised of a majority of Independent Directors (as described on page 38 of this Report) which is consistent with business practices in Luxembourg.
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• Rule 5605(b)(2) requires regularly scheduled meetings at which only independent Directors, as defined in NASDAQ Listing Rule 5605(a)(2), are present (‘executive sessions’). In lieu of the requirements under Rule 5605(b)(2), the Company follows generally accepted business practices in Luxembourg, which do not have rules requiring regularly scheduled executive sessions and therefore permit the attendance at such executive sessions of Directors that are not independent. Notwithstanding the foregoing, as of the date of this Report, each of the Directors attending executive sessions satisfied the independence requirements established by the NASDAQ Listing Rules. |
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• Rule 5620(c) requires that the quorum for any meeting of the holders of common stock must not be less than 33 1/3% of the outstanding shares of common voting stock. In lieu of the requirements of Rule 5620(c), the Company follows generally accepted business practices in Luxembourg, which do not require a specific quorum for meetings of its shareholders, other than in specific cases required by Luxembourg law. |
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Additional Information
| • | Rule 5620(b) requires that the Company solicit proxies and provide proxy statements for all meetings of shareholders and provide copies of such proxy solicitation to NASDAQ. In lieu of the requirements of Rule 5620(b), the Company follows generally accepted business practices in Luxembourg, which do not require the provision of proxy statements for meetings of shareholders. |
| • | Rule 5635(c) requires the Company to obtain shareholder approval when certain plans or other equity compensation arrangements are established or materially amended. In lieu of the requirements of Rule 5635(c), the Company follows generally accepted business practices in Luxembourg, which do not require shareholder approval before the establishment or amendment of such plans or arrangements to the extent they relate to equity compensation of employees of the Company or Directors or employees of subsidiaries of the Company, as opposed to equity compensation of Directors of the Company in their capacity as such Directors. |
Other than as noted above, the Company complies with the corporate governance requirements of NASDAQ Listing Rule 5600. On February 15, 2011, Subsea 7 S.A. commenced procedures to delist from NASDAQ. For more information, refer to Note 40 ‘Post Balance Sheet Events’ to the Consolidated Financial Statements.
Articles of Incorporation
Set forth below is a description of the material provisions of the Articles of Incorporation and Luxembourg Company Law. At the Extraordinary General Meeting on November 9, 2010 the shareholders approved the recommendation made by the Board with respect to the adoption of amended Articles of Incorporation. The amendment of the Articles reflected the changes agreed for the Combination with Subsea 7 Inc. including the change of name of Acergy S.A. to Subsea 7 S.A., and the change of financial year starting on December 1, 2010 and ending December 31, 2011. Thereafter Subsea 7 S.A.’s financial year shall begin on the first day of January and end on the 31st day of December in each successive year. The following summary is qualified by reference to the Articles of Incorporation as amended on November 9, 2010 and applicable Luxembourg law.
Objects
Article 3 of the Articles of Incorporation sets forth the objects of the Company, namely to invest in subsidiaries which will predominantly provide subsea construction, maintenance, inspection, survey and engineering services, in particular for the offshore oil and gas and related industries. Subsea 7 may further itself provide such subsea construction, maintenance, inspection, survey and engineering services, and ancillary services.
Subsea 7 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, Subsea 7 may participate in any manner in all commercial, industrial, financial and other enterprises of Luxembourg of 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 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 purpose of Subsea 7, or companies which are subsidiaries of or associated with or affiliated to Subsea 7. In general it may undertake any operation directly or indirectly connected with these objects.
Directors
Under the Articles of Incorporation, the Board is to be composed of not less than three members, elected by a simple majority of outstanding shares represented at a general meeting of shareholders for a period not exceeding two years and until their successors are elected and at least three Directors have accepted.
The Articles of Incorporation do not mandate the retirement of Directors under an age limit requirement, nor do the Articles of Incorporation require a Director to be a shareholder of the Company.
Under Luxembourg law the Directors owe a duty of loyalty and care and must exercise the standard of care of a prudent and diligent business person.
The Articles of Incorporation provide that any Director who has a personal interest in a transaction must disclose such interest, must abstain from voting on such transaction and may not be counted for purposes of determining whether a quorum is present at the meeting. Such Director’s interest in any such transaction shall be reported at the next general meeting of shareholders. Any transaction other than in the ordinary course of business between Subsea 7 or a member of its Group and a person or entity (i) which holds or controls, alone or in concert with others, at least 5% of the voting rights in Subsea 7, or who is represented at the Board by a director, or (ii) in which a Director has direct or indirect interest in excess of 20% of such entity’s shares, must be approved by a majority of the unaffected Independent Directors. The affected Director(s) may not deliberate or vote in respect of such transaction and shall not be counted for purpose of whether a quorum is present.
The Articles of Incorporation provide that no Director may be counted for the quorum present, nor cast a vote in respect of Board resolutions, that shall relate to his own appointment to an office or position being remunerated within the Company or which shall lay down or amend the conditions thereof.
Authorised shares
The authorised share capital consists of 450,000,000 common shares, par value $2.00 per share. According to the Articles of Incorporation, the Board, or delegate(s) duly appointed by the Board, are authorised to issue additional common shares, at such times and on such terms and conditions, including issue price, as the Board or its delegates may in its or their discretion resolve, up to a maximum of 450,000,000 par value $2.00 per share common shares less the amount of common shares already issued at such time. When doing so, the Board may suppress the preferential subscription rights of the existing shareholders to the extent it deems advisable. This authorisation granted to the Board shall lapse five years after publication of the amendment of the Articles of Incorporation in the Luxembourg Official Gazette-M morial C. The amendments of the Articles of Incorporation regarding the above quoted authorised capital were approved at the Extraordinary General
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| Meeting of shareholders held on November 9, 2010 and publication of such amendment in the Official Gazette occurred on December 3, 2010. From time to time the Company takes such steps that are required to continue the authorised capital in effect. | ||||
| The Articles of Incorporation require all shares to be issued in registered form. All shares, when issued, were fully paid and non-assessable. | ||||
| Authority to acquire own shares (Treasury Shares) | ||||
| The shareholders of Acergy S.A. (now Subsea 7 S.A.) resolved at its Annual General Meeting of shareholders on May 28, 2010 to authorise Subsea 7, or any wholly owned subsidiary, to purchase common shares of Subsea 7 up to a maximum of 10% of the issued common shares net of the common shares previously repurchased and still held, at a price reflecting such open market price and on such other terms as shall be determined by the Board of Subsea 7, provided (a) the maximum price to be paid for such common shares shall not exceed the average closing price for such common shares on Oslo Børs (or the average closing price ADSs on NASDAQ if applicable) for the five most recent trading days prior to such purchase and (b) the minimum price to be paid for such common shares shall not be less than the par value of $2 per share and further provided such purchases are in conformity with article 49-2 of the Luxembourg law of August 10, 1915 on commercial companies, as amended, such authorisation being granted for purchases completed on or before August 31, 2011. | ||||
| No shares were repurchased during fiscal year 2010. | ||||
| Under applicable provisions of the Luxembourg Company Law, the common shares repurchased pursuant to the share buyback programme are held as treasury shares, meaning that these shares remain issued but are not entitled to vote. Further, in computing earnings per common share, these shares are not considered part of outstanding common shares. The cost of these shares is being accounted for as a deduction from shareholders’ equity. | ||||
| For more information relating to repurchases made thereunder, please see Note 25 ‘Own Shares’ to the Consolidated Financial Statements. | ||||
| Authority to cancel treasury shares | ||||
| At the Extraordinary General Meeting on August 4, 2009, the Board was granted authorisation to cancel shares which have been bought back or which may be bought back from time to time by the Company or any indirect subsidiary thereof as the Board sees fit and to make all consequential changes to the Articles of Incorporation to reflect the cancellation in the number of issued common shares. | ||||
| Preferential subscription rights (pre-emptive rights) | ||||
| In general, shareholders are entitled to preferential subscription rights under Luxembourg law in respect of the issuance of shares for cash. When issuing new shares out of the total authorised shares, the Board may, however, suppress the preferential subscription rights of shareholders to the extent it deems advisable. Shareholders are entitled to pre-emptive rights under Luxembourg law in respect of the issuance of shares for cash, unless shareholders decide otherwise at an extraordinary general meeting. The Articles of Incorporation, as amended following the shareholder approval at the Extraordinary General Meeting on November 9, 2010 and published on December 3, 2010, authorise the Board to suppress shareholders’ pre-emptive rights for a period of five years from such publication date. Shareholders may amend, renew or extend such authorisation. The authorisation by the Articles of Incorporation to issue new shares out of the total authorised shares granted to the Board will remain in effect until December 3, 2015. Upon the expiration of this authorisation without extension or renewal, the suppression of preferential subscription rights will also terminate and shareholders will be entitled to preferential subscription rights once again. | ||||
| Voting rights | ||||
| Each of our shares is entitled to one vote. Shareholders holding shares registered in the VPS, the central depository of Oslo Børs, or other such depository, may attend and vote at general meetings. Under Luxembourg law, shareholder action can generally be taken by a simple majority of common shares present or represented at a meeting, without regard to any minimum quorum requirements. Three exceptions to the general rule stated above regarding the requisite number of votes are (i) to amend the Articles of Incorporation which requires (a) two-thirds of votes of cast, and (b) when the meeting is first convened, a quorum of 50% of the outstanding shares entitled to vote; (ii) to change the country of incorporation to a country other than Luxembourg or to increase the contribution of the shareholders, which require the affirmative vote of 100% of the common shares; and (iii) any action for which the Articles of Incorporation requires more than a majority vote or quorum. | ||||
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Shareholder meetings and notice |
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| Under the Articles of Incorporation, the Company is required to hold an Annual General Meeting of shareholders in Luxembourg each year, on the fourth Friday in May in fiscal year 2011, and thereafter the fourth Friday in June. | ||||
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In addition, the Board may call any number of extraordinary general meetings, which may be held in Luxembourg or elsewhere, although any extraordinary general meeting convened to amend the Articles of Incorporation must be held in Luxembourg. The Board is further obliged to call a general meeting of shareholders to be held within thirty days after receipt of a written demand by shareholders representing at least one-tenth of the issued and outstanding shares entitled to vote thereat. Such shareholders may also require additions to the proposed agenda of any meeting of shareholders. |
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The Articles of Incorporation require notice of any general meeting to be sent by first class mail, postage prepaid, or via e-mail if such address has been indicated, to all shareholders at least twenty days prior to such meeting. Shareholders may be represented by written proxy, provided the written proxy is deposited with the Company at its registered office in Luxembourg, or with any director, at least five days before the meeting. |
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Additional Information
Dividends
Interim dividends can be declared in any fiscal year by the Board.
Certain Luxembourg legal requirements apply to the payment of interim dividends. The satisfaction of all legal requirements must be certified by an independent auditor. A final dividend, if proposed by the Board, requires approval by the shareholders at the annual general meeting. Interim and final dividends on common shares can be paid out of earnings, retained and current, as well as paid in surplus after satisfaction of the legal reserve as referred to hereinafter.
Luxembourg law authorises the payment of stock dividends if sufficient surplus exists to pay for the par value of the shares issued in connection with any stock dividend.
Luxembourg law requires that 5% of unconsolidated net profit each year be allocated to a legal reserve before declaration of dividends. This requirement continues until the reserve is 10% of issued capital, after which no further allocations are required until further increases of capital.
The legal reserve may also be satisfied by allocation of the required amount at the time of issuance of shares or by a transfer from paid-in surplus. The legal reserve is not available for dividends. The legal reserve for all existing common shares has been satisfied to date and appropriate allocations will be made to the legal reserve account at the time of each increase of capital.
Liquidation preference
Under the Articles of Incorporation, in the event of liquidation, all debts and obligations must first be paid, and thereafter all remaining assets are to be paid to the holders of common shares.
Change in control
There are no provisions in the Articles of Incorporation that would have the effect of delaying, deferring or preventing a change in control of Subsea 7 and that would only operate with respect to a merger, acquisition or corporate restructure involving the Company or any of its subsidiaries. However, it should be noted that the 2003 Plan and the French Plan provide that all options issued thereunder will vest upon the occurrence of certain change of control events. See Note 36 ‘Share based payments’ to the Consolidated Financial Statements.
Mandatory bid requirements
The Articles of Incorporation do not contain any provision requiring a shareholder who reaches a certain threshold of shares to make a mandatory bid for the other outstanding shares. Subsea 7’s Shares are listed on Oslo Børs which constitutes a regulated market for the purpose of the European Takeover Directive (2004/25/EC) (the ‘Takeover Directive’). Under the Takeover Directive, the authority competent to supervise any takeover bid on Subsea 7 is the Financial Supervisory Authority of Norway (KreditTilsynet). The Takeover Directive and Norwegian and Luxembourg law implementing the directive provide for the requirement that where a person, acting alone or in concert, acquires shares in the issuer which, when added to any existing holdings in shares give such person (or persons) voting rights sufficient for such person or persons to control the issuer, such person is obliged to make an offer for the remaining shares in the issuer.
Pursuant to the Takeover Directive, the threshold for obtaining control is a matter for Luxembourg law under which the control threshold is 33% of the voting rights attached to all issued shares in the issuer.
Pursuant to Luxembourg takeover law when an offer (mandatory or voluntary) is made to all of the holders of voting securities of the issuer and as a result of such offer, the offeror acquires 95% of the securities carrying voting rights and 95% of the voting rights, the offeror can require the holders of the remaining securities to sell those securities of the same class to the offeror. Similarly, Luxembourg takeover law provides that, when an offer (mandatory or voluntary) is made to all of the holders of voting securities of the issuer and as a result of such offer, the offeror acquires 90% of the securities carrying voting rights and 90% of the voting rights, each of the remaining security holders can require that the offeror purchases its securities of the same class.
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| Taxation | ||
| Luxembourg taxation | ||
| The following summary discusses certain Luxembourg tax considerations with respect to Subsea 7 and its shares held by certain resident and non-resident investors. This does not purport to be a comprehensive description of all of the tax considerations that may be relevant to any particular shareholder of Subsea 7, and does not purport to include tax considerations that arise from rules of general application or that are generally assumed to be known to the shareholders of Subsea 7. It is not intended to be, nor should it be construed to be, legal or tax advice. This summary is based on Luxembourg laws and regulations as at the date of this report and is subject to any change in law or regulations or changes in interpretation or application thereof that may take effect after such date. Each investor should therefore consult their own professional advisors as to the effects of state, local or foreign laws and regulations, including Luxembourg tax law and regulations, to which they may be subject. Double taxation treaties may contain rules affecting the description in this summary. | ||
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Luxembourg tax status of Subsea 7 S.A. until December 31, 2010 |
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| Subsea 7 S.A. is a company incorporated under Luxembourg law, and until December 31, 2010 had enjoyed the special tax status granted to billionaire holding companies under the Law of July 31, 1929 and the Grand Ducal Decree of December 17, 1938. These companies can carry out a limited number of activities, including the holding of shares and securities and the financing of affiliated companies. | ||
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During the fiscal year ended November 30, 2010 and up to December 31, 2010, the Company was taxed as a billionaire holding company and, as such, subject to a variable tax rate, calculated annually with half-yearly advance payments, which is based on certain interest expense, dividends and compensation paid to non-resident Directors during the period. These taxes are paid by Subsea 7 S.A. The tax was calculated as follows:
a) Where the total interest paid each year to holders of bonds and other comparable debt securities amounted to or exceeded € 2.4 million: |
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• 3% on interests paid to holders of bonds and other comparable debt securities; |
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• 1.8% on dividends and remuneration to non-resident Directors on the first € 1.2 million; |
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• 0.1% on any surplus dividends and remuneration to non-resident Directors.
b) Where the total interest paid each year to holders of bonds and other comparable debt securities was less than € 2.4 million: |
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• 3% on interests paid to holders of bonds and other comparable debt securities; |
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• 3% on dividends and remuneration to non-resident Directors, but to a maximum amount corresponding to the difference between € 2.4 million and the total interest paid to holders of bonds and other comparable debt securities; |
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• 1.8% on any surplus dividends and remuneration to non-resident Directors up to € 1.2 million distributed; |
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• 0.1% on surplus dividends and remuneration to non-resident Directors.
c) Billionaire holding companies were subject to a minimum annual charge of € 48,000. |
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For the fiscal years ended November 30, 2009 and 2008 this tax amounted to $350,000 and $351,000 respectively. For the year ended November 30, 2010 the amount provisioned was $411,000. The 2010 tax provision will be confirmed after March 2011. |
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As a billionaire holding company, Subsea 7 S.A. was not subject to any income tax, municipal tax, wealth tax or withholding tax in Luxembourg. The contribution tax of 1% previously levied on issues of share capital was abolished on January 1, 2009. |
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Most treaties concluded by Luxembourg with other countries were not applicable to Subsea 7 S.A. as a holding company subject to the Law of July 31, 1929, because such companies are specifically excluded from the scope of the application of these treaties. |
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Pursuant to a law of December 22, 2006, the laws and regulations relating to the tax regime for 1929 Luxembourg holding companies were abolished effective January 1, 2007. However, existing 1929 Luxembourg holding companies, including Subsea 7 S.A., continued to benefit from the tax regime for 1929 Luxembourg holding companies until December 31, 2010, subject to certain conditions. After the benefit of the status expired at midnight on December 31, 2010, Subsea 7 S.A. became an ordinary taxable Luxembourg company. |
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Tax status of Subsea 7 S.A. from January 1, 2011 |
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| As an ordinary taxable Luxembourg resident company, Subsea 7 S.A. will be subject to Luxembourg corporate income tax and municipal business tax. The fiscal year 2011 aggregate maximum applicable rate for a company established in Luxembourg-City is 28.8% (including a contribution to the unemployment fund) of taxable net profits. Net profits subject to tax include dividend income and capital gains, subject to certain exemptions. Subsea 7 is an ordinary taxable Luxembourg resident company and should therefore, from a Luxembourg tax perspective, be able to benefit from double taxation treaties and European directives in direct tax matters. | ||
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Subsea 7 S.A. will also be liable for annual net wealth tax (impôt sur la fortune) at a rate of 0.5% of the non exempted net wealth of Subsea 7 S.A |
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Additional Information
Distributions to holders
General
Holders of the shares will not become resident or be deemed to be resident in Luxembourg by reason only of holding Shares.
Withholding tax
From January 1, 2011, Subsea 7 S.A. became an ordinary taxable Luxembourg company. In Luxembourg, dividend distributions from ordinary taxable companies are subject to a withholding tax of 15%. Distributions by Subsea 7 S.A., sourced from a reduction of capital, as defined in Article 97 (3) of the Luxembourg law of December 4, 1967 (the ‘Luxembourg Income Tax Law’), including among others share premium, should not be subject to withholding tax provided no newly accumulated fiscal profits are recognised.
Where a withholding needs to be operated, the rate of the withholding tax may be reduced pursuant to the double tax treaty existing between Luxembourg and the country of residence of the relevant holder, subject to the fulfilment of the conditions set forth therein.
No withholding tax applies if the distribution is made to (i) a Luxembourg resident corporate holder (that is, a fully taxable collectivité within the meaning of Article 159 of the Luxembourg Income Tax Law), (ii) a corporation which is resident of a Member State of the European Union and is referred to by article 2 of the Council Directive of July 23, 1990 concerning the common fiscal regime applicable to parent and subsidiary companies of different member states (90/435/EEC), (iii) a corporation or a co-operative resident in Norway, Iceland or Liechtenstein and subject to a tax comparable to corporate income tax as provided by Luxembourg Income Tax Law, (iv) a corporation resident in Switzerland which is subject to corporate income tax in Switzerland without benefiting from an exemption, (v) a corporation subject to a tax comparable to corporate income tax as provided by Luxembourg Income Tax Law which is resident in a country that has concluded a tax treaty with Luxembourg and (vi) a Luxembourg permanent establishment of one of the above-mentioned categories, provided each time that at the date of payment, the holder holds directly or through a tax transparent vehicle, during an uninterrupted period of at least twelve months, Shares representing at least 10% of the share capital of Subsea 7 S.A or which had an acquisition price of at least € 1,200,000.
Non-resident holders
Holders of the Shares who are not resident in Luxembourg for Luxembourg tax purposes and who do not hold the Shares through a permanent establishment in Luxembourg are not liable to Luxembourg income tax on dividends paid by Subsea 7 S.A other than the withholding tax described above, if applicable.
Resident holders
With the exception of Luxembourg Resident Corporate Holders benefiting from the exemption referred to above, Luxembourg individual holders and Luxembourg Resident Corporate Holders subject to Luxembourg corporate income tax, must include distributions paid on Shares in their taxable income, 50% of the amount of such dividends being exempt from tax. The applicable withholding tax can, under certain conditions, entitle the relevant resident holder to a tax credit.
Sale or Disposal of Shares
Non-resident holders
Capital gains arising upon disposal of Shares by an investor who is a non-resident, and who does not have a permanent establishment in Luxembourg to which the Shares are attributable, and who is not resident in a country which has concluded a double tax treaty with Luxembourg which allocates the right of taxation to the country of residence of the investor, will only be subject to Luxembourg taxation on capital gains realised on a disposal of Shares, if such holder has, together with the holder’s spouse or civil partner and underage children, directly or indirectly held more than 10% of the capital of the Company at any time during the five years preceding the disposal, and either (1) the disposal of Shares occurs before their acquisition (e.g. a short-sale transaction) or within six months from their acquisition, or (2) such investor has been a resident for tax purposes for at least 15 years and has become a non-resident within the five years preceding the realisation of the gain.
Luxembourg resident individual holders
For Luxembourg resident individuals holding 10% or less of the share capital of Subsea 7 S.A., capital gains will only be taxable if they are realised on a sale of the Shares, which takes place before their acquisition (e.g. a short-sale transaction) or within the first six months following their acquisition. For a Luxembourg resident individual holding, together with the holder’s spouse or civil partner and underage children, directly or indirectly more than 10% of the capital of Subsea 7 S.A., capital gains will be taxable at a special rate, regardless of the holding period.
Luxembourg resident corporate holders
Capital gains realised upon the disposal of Shares by a fully taxable resident corporate holder will be subject to corporate income tax and municipal business tax. An exemption from such taxes may be available to the holder pursuant to Article 166 of Luxembourg Income Tax law subject to the fulfilment of the conditions set forth therein. The scope of the capital gains exemption can be limited in the cases provided by the Grand Ducal Decree of December 21, 2001.
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| Luxembourg net wealth tax | ||
| Non-resident holders | ||
| Luxembourg net wealth tax will not be levied on a non-resident holder with respect to the Shares held unless the Shares are attributable to an enterprise or part thereof which is carried on through a permanent establishment or a permanent representative in Luxembourg, in which case the Shares may be exempt from net wealth tax subject to the conditions set forth by Article 60 of the law of October 16, 1934 on the valuation of assets (Bewertungsgesetz), as amended. | ||
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Resident holders |
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| Net wealth tax is levied annually at the rate of 0.5% on the net wealth of commercial undertakings resident in Luxembourg. The Shares may be exempt from net wealth tax subject to the conditions set forth by Article 60 of the law of October 16, 1934 on the valuation of assets (Bewertungsgesetz), as amended. | ||
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Other Luxembourg taxes |
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| Stamp and registration taxes | ||
| No registration tax or stamp duty will be payable by a holder of Shares in Luxembourg solely upon the disposal of Shares by sale or exchange. | ||
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Estate and gift taxes |
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| No estate or inheritance tax is levied on the transfer of Shares upon the death of a holder of Shares in cases where the deceased was not a resident of Luxembourg for inheritance tax purposes and no gift tax is levied upon a gift of Shares if the gift is not passed before a Luxembourg notary or recorded in a deed registered in Luxembourg. Where a holder of Shares is a resident of Luxembourg for tax purposes at the time of the holder’s death, the Shares are included in the holder’s taxable estate for inheritance tax or estate tax purposes. | ||
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US federal income taxation |
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| The following summary describes the principal US federal income tax consequences relating to the acquisition, holding and disposition of the common shares of Acergy S.A. and/or Subsea 7 S.A. (the ‘Shares’) or ADSs. This summary addresses only the US federal income tax considerations of holders that will hold Shares or ADSs as capital assets. This summary does not address tax considerations applicable to holders that may be subject to special tax rules, including: | ||
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• certain financial institutions, insurance companies, real estate investment trusts, regulated investment companies, grantor trusts, dealers or traders in securities or currencies, tax-exempt entities;
• individual retirement accounts and other tax-deferred accounts;
• taxpayers that have elected to use mark-to-market accounting;
• persons that received Shares or ADSs as compensation for the performance of services;
• persons that will hold Shares or ADSs as part of a ‘hedging’ or ‘conversion’ transaction or as a position in a ‘straddle’ for US federal income tax purposes;
• certain former citizens or long-term residents of the United States;
• persons that have a ‘functional currency’ other than the US dollar; or
• holders that own, or are deemed to own, 10% or more, by voting power or value, of the outstanding equity interests of Subsea 7 S.A. for US federal income tax purposes. |
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Moreover, this description does not address the US federal estate and gift tax or alternative minimum tax consequences, nor any state, local or non-US tax consequences of the acquisition, holding or disposition of the Shares or ADSs. Each prospective purchaser should consult its tax advisor with respect to the US federal, state, local and foreign tax consequences of acquiring, holding and disposing of Shares or ADSs.
This summary is based on the Internal Revenue Code of 1986, as amended (the ‘Code’), existing, proposed and temporary US Treasury Regulations, and judicial and administrative interpretations thereof, in each case in effect and available on the date hereof. This description is also based in part on the representations of the depositary and the assumption that each obligation in the deposit agreement and any related agreement will be performed in accordance with its terms. All of the foregoing are subject to change, possibly with retroactive effect, and differing interpretations which could affect the tax consequences described herein. |
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|
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For purposes of this summary, a ‘US Holder’ is a beneficial owner of Shares or ADSs that, for US federal income tax purposes, is: |
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• an individual citizen or resident of the United States;
• a corporation, or an entity treated as a corporation, created or organized in or under the laws of the United States, any state thereof or the District of Columbia;
• an estate, the income of which is subject to US federal income taxation regardless of its source; or
• a trust if such trust validly elects to be treated as a US person for US federal income tax purposes or if (1) a court within the United States is able to exercise primary supervision over its administration and (2) one or more US persons have the authority to control all of the substantial decisions of such trust. |
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Additional Information
A ‘Non-US Holder’ is a beneficial owner of Shares or ADSs that is neither a US Holder nor a partnership, or other entity treated as a partnership for US federal income tax purposes.
If a partnership or any other entity treated as a partnership for US federal income tax purposes is a beneficial owner of Shares or ADSs, the tax treatment of such partnership, or a partner in such partnership, will generally depend on the status of the partner and on the activities of the partnership. If you are a partnership or a partner in a partnership that holds Shares or ADSs, you should consult your tax advisor.
We urge you to consult your tax advisor with respect to the US federal, state, local and foreign tax consequences of acquiring, holding and disposing of Shares or ADSs.
Ownership of ADSs in general
For US federal income tax purposes, a holder of ADSs generally will be treated as the owner of the Shares represented by such ADSs.
The US Treasury Department has expressed concern that depositaries for ADRs, or other intermediaries between the holders of shares of an issuer and the issuer, may be taking actions that are inconsistent with the claiming of US foreign tax credits by US holders of such receipts or shares. Accordingly, the analysis regarding the availability of a US foreign tax credit for Luxembourg taxes and sourcing rules described below could be affected by future actions that may be taken by the US Treasury Department.
Distributions
Subject to the discussion below under ‘Passive Foreign Investment Company Considerations’, if you are a US Holder, for US federal income tax purposes, the gross amount of any distribution made to you with respect to Shares or ADSs, (other than certain distributions, if any, of additional Shares distributed pro rata to all shareholders, including holders of ADSs, with respect to Shares or ADSs) will be includible in your income on the day on which the distributions are actually or constructively received by you (which in the case of ADSs will be the date such distribution is received by the depositary) as dividend income to the extent such distributions are paid out of current or accumulated earnings and profits as determined under US federal income tax principles. If a US Holder receives a dividend in a foreign currency (i.e., a currency other than the US dollar), any such dividend will be included in such holder’s gross income in an amount equal to the US dollar value of such foreign currency on the date of receipt, which, in the case of ADSs, is the date they are received by the depositary. If the dividend is converted into US dollars on the date of receipt, a US Holder generally should not be required to recognise foreign currency gain or loss in respect of the dividend income. A US Holder may have foreign currency gain or loss if the amount of such dividend is not converted into US dollars on the date of receipt. Such dividends will not be eligible for the dividends received deduction generally allowed to corporate US Holders.
Non-corporate US Holders generally will be taxed on such distributions at the lower rates applicable to long-term capital gains (i.e, gains from the sale of capital assets held for more than one year) with respect to taxable years beginning on or before December 31, 2012. However, a US Holder’s eligibility for such preferential rate would be subject to certain holding period requirements and the non-existence of certain risk reduction transactions with respect to the Shares or ADSs. Additionally, even if the Company were otherwise to meet the conditions for reduced rates of taxation on dividends, non-corporate US Holders still will not be entitled to such reduced rates of taxation if it is a passive foreign investment company in the taxable year such dividends are paid or in the preceding taxable year (see discussion under ‘Passive Foreign Investment Company Considerations’ below).
Subject to the discussion below under ‘Passive Foreign Investment Company Considerations’ to the extent, if any, that the amount of any distribution exceeds current and accumulated earnings and profits as determined under US federal income tax principles, it will be treated first as a tax-free return of capital, causing a reduction in the adjusted basis of Shares or ADSs (thereby increasing the amount of gain, or decreasing the amount of loss, to be recognised by you on a subsequent disposition of Shares or ADSs), and the balance in excess of adjusted basis will be taxed as capital gain recognised on a sale or exchange (as discussed below under ‘Sale or exchange of Shares or ADSs’). The Company does not maintain calculations of its earnings and profits under US federal income tax principles, and therefore a US Holder should expect that the entire amount of any distribution will generally be reported as dividend income to such US Holder.
If you are a US Holder, dividend income received by you with respect to Shares or ADSs will be treated as foreign source income, which may be relevant in calculating your foreign tax credit limitation. The limitation on foreign taxes eligible for credit is calculated separately with respect to specific baskets of income. For this purpose, dividend income should generally constitute ‘passive category income,’ or in the case of certain US Holders, ‘general category income.’ Further, in certain circumstances, if you have held Shares or ADSs for less than a specified minimum period during which you are not protected from risk of loss; or are obligated to make payments related to the dividends, you will not be allowed a foreign tax credit for foreign taxes imposed on dividend income with respect to Shares and ADSs. The rules governing the foreign tax credit are complex. You are urged to consult your tax advisor regarding the availability of the foreign tax credit under your particular circumstances.
Subject to the discussion below under ‘Backup Withholding Tax and Information Reporting Requirements,’ if you are a Non-US Holder of Shares or ADSs, you generally will not be subject to US federal income or withholding tax on dividends received on Shares or ADSs, unless such income is effectively connected with your conduct of a trade or business in the United States.
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| Sale or exchange of Shares or ADSs | ||
| Deposits and withdrawals of Shares by holders in exchange for ADSs will not result in the realisation of gain or loss for US federal income tax purposes. | ||
|
Subject to the discussion below under ‘Passive Foreign Investment Company Considerations’, if you are a US Holder, you will generally recognise gains or losses on the sale or exchange of Shares or ADSs equal to the difference between the amount realised on such sale or exchange and your adjusted tax basis in the Shares or ADSs. Subject to the discussion below under ‘Passive Foreign Investment Company Considerations,’ such gain or loss will be a capital gain or loss. If you are a non-corporate US Holder, the maximum marginal US federal income tax rate applicable to such gain will be lower than the maximum marginal US federal income tax rate applicable to ordinary income (other than certain dividends) if your holding period for such Shares or ADSs exceeds one year i.e. it is a long-term capital gain. If you are a US Holder, a gain or loss, if any, recognised by you generally will be treated as US source gain or loss, as the case may be, for US foreign tax credit purposes. The deductibility of capital losses is subject to limitations. |
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Generally, if you are a US Holder, the initial tax basis of your Shares will be the US dollar value of the non-US dollar denominated purchase price determined on the date of purchase. If the Shares are treated as traded on an ‘established securities market,’ and you are a cash basis US Holder, or, if you elect, an accrual basis US Holder, you will determine the US dollar value of the cost of such Shares by translating the amount paid at the spot rate of exchange on the settlement date of the purchase. The conversion of US dollars to a non-US dollar currency and the immediate use of that currency to purchase Shares generally will not result in a taxable gain or loss for a US Holder. If you are a US Holder, the initial tax basis of your ADSs generally will be the US dollar denominated purchase price determined on the date of purchase.
With respect to the sale or exchange of Shares or ADSs, the amount realised generally will be the US dollar value of the payment received determined on (1) the date of receipt of payment in the case of a cash basis US Holder and (2) the date of disposition in the case of an accrual basis US Holder. If the Shares or ADSs are treated as traded on an ‘established securities market,’ a cash basis taxpayer, (or, if it elects, an accrual basis taxpayer) will determine the US dollar value of the amount realised by translating the amount received at the spot rate of exchange on the settlement date of the sale. |
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Subject to the discussion below under ‘Backup Withholding Tax and Information Reporting Requirements,’ if you are a Non-US Holder, generally you will not be subject to US federal income or withholding tax on any gain realised on the sale or exchange of such Shares or ADSs unless (1) such gain is effectively connected with your conduct of a trade or business in the United States or (2) if you are an individual Non-US Holder, you are present in the United States for 183 days or more in the taxable year of the sale or exchange and certain other conditions are met. |
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New legislation |
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| Recently enacted legislation requires certain US Holders who are individuals, estates or trusts to pay an additional 3.8% tax on, among other things, dividends and capital gains from the sale or other disposition of Shares or ADSs for taxable years beginning after December 31, 2012. In addition, for taxable years beginning after March 18, 2010, new legislation requires certain US Holders who are individuals to report information relating to an interest in Shares or ADSs, subject to certain exceptions, including an exception for Shares or ADSs held in a custodial account maintained with a US financial institution. US Holders are urged to consult their tax advisors regarding the effect, if any, of new US federal income tax legislation on their ownership and disposition of Shares or ADSs. | ||
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Passive Foreign Investment Company considerations |
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| A non-US corporation will be classified as a ‘passive foreign investment company’, or a PFIC, for US federal income tax purposes in any taxable year in which, after applying certain look-through rules, either: | ||
|
• at least 75 percent of its gross income is ‘passive income’; or
• at least 50 percent of the average value of its gross assets is attributable to assets that produce ‘passive income’ or are held for the production of passive income. |
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Passive income for this purpose generally includes dividends, interest, royalties, rents and gains from commodities and securities transactions. In determining whether we are a PFIC, a pro rata portion of the income and assets of each subsidiary in which we own, directly or indirectly, at least a 25% interest (by value) is taken into account. |
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Based in part on estimates of gross income and the value of gross assets and the nature of the business, the Company believes that it will not be classified as a PFIC for the current taxable year. The status in future years will depend on assets and activities in those years. The Company has no reason to believe that assets or activities will change in a manner that would cause it to be classified as a PFIC, but there can be no assurance that it will not be considered a PFIC for any taxable year. If the Company becomes a PFIC, and you are a US Holder, you generally would be subject to imputed interest charges and other disadvantageous tax treatment (including the denial of the taxation of qualified dividends at the lower rates applicable to long-term capital gains, as discussed above under ‘Distributions’) with respect to any gain from the sale or exchange of, and certain distributions with respect to, your Shares or ADSs. |
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If the Company is to become a PFIC, you could make a variety of elections that may alleviate certain tax consequences referred to above, and one of these elections may be made retroactively. However, the Company does not expect that the conditions necessary for making certain of such elections with respect to the Shares or ADSs will be met. You should consult your tax advisor regarding the tax consequences that would arise if the Company is or becomes a PFIC. |
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Additional Information
Backup withholding tax and information reporting requirements
US backup withholding tax and information reporting requirements generally apply to certain payments to certain holders. Information reporting will apply to the distributions on, and to proceeds from the sale or redemption of, Shares or ADSs made within the United States, or by a US payer or US middleman to a holder of Shares or ADSs, other than an exempt recipient, a payee that is not a US person that provides an appropriate certification and certain other persons. A payer will be required to withhold backup withholding tax from any distributions on, or the proceeds from the sale or redemption of, Shares or ADSs within the United States, or by a US payer or US middleman to a holder, other than an exempt recipient, if such holder fails to furnish its correct taxpayer identification number or otherwise fails to comply with, or establish an exemption from, such backup withholding tax requirements. The backup withholding tax rate is 28% for years through 2012.
Backup withholding is not an additional tax. If you are a US Holder, you generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed your US federal income tax liability by filing a refund claim with the Internal Revenue Service. You will be entitled to credit any amounts withheld under the backup withholding rules against your US federal income tax liability provided that you furnish the required information to the Internal Revenue Service in a timely manner.
The above summary is not intended to constitute a complete analysis of all US federal income tax consequences relating to the acquisition, holding and disposition of Shares or ADSs. We urge you to consult your tax advisor concerning the tax consequences of your particular situation.
Trading markets
Subsea 7 S.A.’s shares trade in the form of ADSs in the United States on NASDAQ under the symbol ‘SUBC’ and are listed in Norway on Oslo Børs under the symbol ‘SUBC’, following completion of the combination between Subsea 7 S.A. (formerly Acergy S.A.) and Subsea 7 Inc. on January 7, 2011. The first day of trading in the Shares and ADSs of Subsea 7 S.A. was Monday January 10, 2011. On February 15, 2011, Subsea 7 S.A. commenced procedures to delist from NASDAQ. For more information, refer to Note 40 ‘Post balance sheet events’ to the Consolidated Financial Statements.
Prior to the combination, Subsea 7 S.A.’s shares traded in the form of ADSs in the United States on NASDAQ under the symbol ‘ACGY’ and the Oslo Børs under the symbol ‘ACY.’ Subsea 7 Inc.’s shares were listed on the Oslo Børs under the symbol ‘SUB’ until Subsea 7 Inc.’s shares were delisted on January 7, 2011.
The following table sets forth the high and low last reported prices for Subsea 7 S.A.’s (formerly Acergy S.A.’s) ADSs on NASDAQ and the prices for Subsea 7 S.A.’s (formerly Acergy S.A.’s) and Subsea 7 Inc.’s shares reported on Oslo Børs during the indicated periods.
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Subsea 7 S.A. ADSs NASDAQ Global Select Market |
Subsea 7 S.A.shares
Oslo Børs |
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| High | Low | High | Low | |||||||||||||
| ($) | ($) | (NOK) | (NOK) | |||||||||||||
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Monthly highs and lows January 2011 (since January 10, 2011) |
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January 2011 |
25.31 | 23.12 | 150.00 | 132.50 | ||||||||||||
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|
Acergy S.A. ADSs
NASDAQ Global Select Market |
Acergy S.A. shares
Oslo Børs |
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| High | Low | High | Low | |||||||||||||||||||||
| ($) | ($) | (NOK) | (NOK) | |||||||||||||||||||||
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Annual highs and lows (fiscal years) |
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2006 |
20.50 | 10.76 | 131.00 | 70.25 | ||||||||||||||||||||
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2007 |
30.66 | 17.01 | 170.25 | 110.50 | ||||||||||||||||||||
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2008 |
28.07 | 3.78 | 140.00 | 25.60 | ||||||||||||||||||||
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2009 |
15.18 | 4.33 | 85.45 | 31.75 | ||||||||||||||||||||
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2010 |
22.78 | 13.66 | 134.40 | 85.60 | ||||||||||||||||||||
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Quarterly highs and lows |
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Fiscal year 2008 |
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First quarter |
23.61 | 17.40 | 125.25 | 94.00 | ||||||||||||||||||||
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Second quarter |
28.07 | 19.37 | 140.00 | 104.00 | ||||||||||||||||||||
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Third quarter |
26.02 | 15.73 | 133.00 | 81.90 | ||||||||||||||||||||
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Fourth quarter |
15.47 | 3.78 | 88.70 | 25.60 | ||||||||||||||||||||
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Fiscal year 2009 |
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First quarter |
6.77 | 4.72 | 46.90 | 33.45 | ||||||||||||||||||||
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Second quarter |
10.34 | 4.33 | 63.50 | 31.75 | ||||||||||||||||||||
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Third quarter |
11.39 | 8.64 | 71.70 | 57.00 | ||||||||||||||||||||
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Fourth quarter |
15.18 | 9.61 | 85.45 | 59.00 | ||||||||||||||||||||
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Fiscal year 2010 |
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First quarter |
16.95 | 14.88 | 99.90 | 85.60 | ||||||||||||||||||||
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Second quarter |
20.45 | 13.97 | 120.00 | 90.00 | ||||||||||||||||||||
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Third quarter |
17.92 | 13.66 | 110.50 | 90.00 | ||||||||||||||||||||
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Fourth quarter |
22.78 | 16.19 | 134.40 | 101.20 | ||||||||||||||||||||
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Monthly highs and lows – since August 2010 to |
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January 7, 2011 |
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August 2010 |
17.92 | 15.00 | 106.70 | 93.55 | ||||||||||||||||||||
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September 2010 |
18.45 | 16.19 | 108.50 | 101.20 | ||||||||||||||||||||
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October 2010 |
20.34 | 18.93 | 118.50 | 110.00 | ||||||||||||||||||||
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November 2010 |
22.78 | 20.07 | 134.40 | 123.10 | ||||||||||||||||||||
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December 2010 |
24.36 | 21.32 | 145.50 | 130.30 | ||||||||||||||||||||
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January 2011 |
25.71 | 24.79 | 152.50 | 144.60 | ||||||||||||||||||||
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Source: Thomson Reuters |
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Additional Information
The bid prices reported for these periods reflect inter-dealer prices, rounded to the nearest cent, and do not include retail mark-ups, markdowns or commissions, and may not represent actual transactions.
On January 31, 2011 the last reported sale price of Subsea 7 S.A. ADSs on NASDAQ was $24.50 per ADS and the closing price of Subsea 7 S.A.’s Shares on Oslo Børs was NOK 140.50 per share.
Major shareholders
Subsea 7 S.A. Major Shareholders
Set forth below is information concerning the percentage of voting rights of all persons who held 5% or more of the issued share capital of Subsea 7 S.A., as a result of Completion of the Combination between Subsea 7 S.A. (formerly Acergy S.A.) and Subsea 7 Inc. which occurred on January 7, 2011.
| Subsea 7 S.A. - Name of shareholder | Number of shares owned | Percentage of voting rights (b) | ||||||
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Holdings as of January 7, 2011 (a) |
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Siem Industries Inc. |
69,681,932 | 19.8% | ||||||
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Folketrygdfondet |
32,284,762 | 9.2% | ||||||
| (a) | Subsea 7 S.A. was notified that as a result of the completion of the Combination on January 7, 2011 Capital World Investors crossed downwards the 5% threshold reportable pursuant to the Luxembourg law of January 11, 2008 on transparency requirements. At the time of notification they held 13,430,000 Shares or 3.82% of the total voting rights. |
| (b) | All shares carry equal voting rights. The percentage of voting rights shown above represents the number of shares owned as a percentage of issued share capital. |
As of January 31, 2011, all of Subsea 7 S.A.’s 351,793,731 common shares were registered in the VPS, in the names of 6,602 shareholders. Excluding issued shares registered in the name of Deutsche Bank Trust Company Americas as depositary for the ADS, it is estimated that the free float of common shares on Oslo Børs was 328,702,856 shares as of January 31, 2011.
At the close of business on January 31, 2011, 351,793,731 Shares were in issue and 339,754,005 Shares were outstanding, including those held through ADSs. Of the issued shares or share equivalents 96,018,660 (27% of the voting rights) were held by 153 holders with registered addresses in the US, including 23,090,875 held in the form of ADSs. Since certain of such shares and ADS are held by nominees, the number of identified holders may not be representative of the number of beneficial owners in the US or the shares held by them.
Documents on display
The Group is subject to the informational requirements of the Exchange Act applicable to foreign private issuers and, in accordance with these requirements, we file reports with the SEC. As a foreign private issuer, we are exempt from the rules under the Exchange Act relating to the furnishing and content of proxy statements, and the Group’s officers, Directors and principal shareholders are exempt from the reporting and short swing profit recovery provisions contained in Section 16 of the Exchange Act. In addition, we are not required under the Exchange Act to file periodic reports and financial statements with the SEC as frequently or as promptly as US companies whose securities are registered under the Exchange Act.
You may read and copy any documents that the Group files with the SEC, including this Report and the related exhibits, without charge at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549-2736. You may also obtain copies of the documents at prescribed rates by writing to the public reference room of the Commission at 100 F Street, N.E., Washington, D.C. 20549-2736.
Please call the Commission at (202) 551 8090 for further information on the public reference room. In addition, the documents incorporated by reference into this Report are publicly available through the web site maintained by the SEC at www.sec.gov.
Documents concerning Subsea 7 S.A. that are referred to in this Report may be inspected at the office 412F, route d’Esch, L-2086 Luxembourg.
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| Key Investor Information and Contacts | ||
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Investor Relations This section provides an outline of the Group’s communication strategy towards shareholders, contact details for the Investor Relations team, Transfer Agents, Registrars and Depositary Bank. |
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Subsea 7 S.A. is a Company registered in Luxembourg whose stock trades on NASDAQ and the Oslo Børs. On February 15, 2011, Subsea 7 S.A. commenced procedures to delist from NASDAQ. For more information, please refer to Note 40 ‘Post balance sheet events’ to the Consolidated Financial Statements. The Group reports quarterly in accordance with International Financial Reporting Standards. |
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Subsea 7’s Executive Management devotes a considerable amount of their time to communication with shareholders and analysts by means of quarterly earnings reports and associated presentations and conference calls. A playback facility for conference calls is available for seven days after each call and a conference call transcript is published on the Group’s website. |
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Roadshows, by the Chief Executive Officer and Chief Financial Officer in Europe and the United States, take place twice a year, following the full year results published in February and again in September or October. The Investor Relations team is available to meet investors and those who may become investors at any time either in London or elsewhere as necessary. |
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The Group has three nominated people who manage the dissemination of price sensitive information. These are Jean Cahuzac (Chief Executive Officer), Simon Crowe (Chief Financial Officer) and Karen Menzel (Investor Relations Director). Requests for meetings with Management, questions concerning Group performance or other issues should be made directly through Investor Relations.
The Group’s website can be accessed at www.subsea7.com. The Investor Centre provides comprehensive information for investors including financial reports, news and disclosures, analyst coverage and stock price information. An e-mail alert service is provided which notifies those who elect to use this service to new information posted on this site. |
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Visit our online Annual Report at:
www.subsea7.com |
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Additional Information
Investor Relations and press enquiries
Shareholders, securities analysts, portfolio managers, representatives of financial institutions and the press may contact:
Karen Menzel
Investor Relations Director
e-mail: karen.menzel@subsea7.com
T: +44 (0) 20 8210 5568
Financial information
Copies of Stock Exchange announcements (including press releases, quarterly and semi-annually earnings releases, Annual Report, Annual Reports on Form 20-F and separate Company financial statements for Subsea 7 S.A.) are available on the Group’s website www.subsea7.com or by contacting:
Karen Menzel
Investor Relations Director
e-mail: karen.menzel@subsea7.com
T: +44 (0) 20 8210 5568
Stock listings
Common shares – Traded on Oslo Børs under symbol SUBC and on NASDAQ as an American Depositary Receipt (‘ADR’) under symbol SUBC. On February 15, 2011, Subsea 7 S.A. commenced procedures to delist from NASDAQ. For more information, please refer to Note 40 ‘Post balance sheet events’ to the Consolidated Financial Statements.
DnB NOR Bank ASA
Standen 21
NO-0021 Oslo
Norway
T: +47 22 48 12 17
F: +47 22 94 90 20
Subsea 7 S.A. has a sponsored Level II ADR facility for which Deutsche Bank Trust Company Americas acts as Depositary. Each ADR represents one (1) ordinary share of the Company. The ADRs are quoted and traded on NASDAQ under the ticker symbol SUBC. Following delisting from NASDAQ the Company’s ADR facility will continue as a level I ADR facility for which Deutsche Bank will act as depository. For enquiries, beneficial ADR holders may contact the Deutsche Bank Trust Company Americas Broker Service.
Registered ADR holders may contact the shareholder services:
Deutsche Bank Trust Company Americas
27th Floor
60 Wall Street
New York, NY 10005
Shareholder Service: + 1 866 249 2593 (toll free for U.S. residents only)
Broker Service Desk: +44 207 547 6500 or +1 212 250 9100
Further information is also available at http://www.adr.db.com
Country of incorporation
Luxembourg
Financial Calendar
Subsea 7 S.A. intentions to publish its quarterly financial results for 2011 on the following dates:
| Q1 2011 Results | May 11, 2011 | |||||||
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Q2 2011 Results |
August 10, 2011 | |||||||
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Q3 2011 Results |
November 2, 2011 | |||||||
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Q4 & FY 2011 Results |
February 2012 |
Annual General Meeting
May 27, 2011
412F, route d’Esch
L-2086 Luxembourg
Website
www.subsea7.com
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Subsea 7 S.A. Annual Report and Financial Statements 2010
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Additional Information
Cross-reference to Form 20-F
|
This Annual Report contains information for the Company’s Annual Report on Form 20-F for 2010 filed with the SEC. The cross-reference table below indicates where each item of Form 20-F is included in this Annual Report. No other information in this document is included in the 2010 Form 20-F or incorporated by reference into any filing by the Company under the Securities Act.
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| Item | Description | Location | Page | |||||||
| 1 | Identity Of Directors, Senior Management and Advisers | Not Applicable | N/A | |||||||
| 2 | Offer Statistics and Expected Timetable | Not Applicable | N/A | |||||||
| 3 | Key Information | |||||||||
| 3A | Selected Financial Data | Selected Financial Data | 143-146 | |||||||
| 3B | Capitalisation and indebtedness | Not Applicable | N/A | |||||||
| 3C | Reasons for the offer and use of proceeds | Not Applicable | N/A | |||||||
| 3D | Risk Factors | Risk Factors | 28-33 | |||||||
| 4 | Information on the Company | |||||||||
| 4A | History and development of the Company | Organisation and register/History and development of Subsea 7 S.A./ | 155-157 | |||||||
| Investment and capital expenditure/Divestitures | 63-64 | |||||||||
| 4B | Business Overview | Risk and insurance/Government regulations/ Supplies and raw materials/Marketing/Clients/ Competition/Health, safety, environmental and security management/Intellectual property | 147-159 | |||||||
| Market Review/Overview/Service Capabilities/ | 20-21, 154-155 | |||||||||
| Seasonality/Business segments’ results | 58, 65-73 | |||||||||
| 4C | Organisational Structure | Significant subsidiaries | 146 | |||||||
| 4D | Property, plants and equipment | Investment and capital expenditure/ | 63-64 | |||||||
| Description of property | 150-154 | |||||||||
| 4A | Unresolved Staff Comments | Not Applicable | N/A | |||||||
| 5 | Operating and Financial Review and Prospects | |||||||||
| 5A | Operating Results | Financial Review | 60-78 | |||||||
| 5B | Liquidity and capital resources | Liquidity and capital resources/ | 73-75 | |||||||
| Note 34 – Financial instruments | 123-131 | |||||||||
| 5C | Research and development, patents and licenses etc | Intellectual property | 150 | |||||||
| 5D | Trend information | Chairman’s Statement/Chief Executive Officer’s Review/ | 14-18 | |||||||
| Outlook/Significant Factors affecting the results of operations and financial position | 57, 58-60 | |||||||||
| 5E | Off-balance sheet arrangements | Off balance sheet arrangements | 75-77 | |||||||
| 5F | Tabular disclosure of contractual obligations | Contractual obligations/ | 77 | |||||||
| Note 32 – Commitments and contingent liabilities | 122 | |||||||||
| 5G | Safe harbour | Special Note Regarding Forward Looking Statements | 142-143 | |||||||
| 6 | Directors, Senior Management and Employees | |||||||||
| 6A | Directors and senior management | Board of Directors/Executive Management Team | 34-35, 36 | |||||||
| 6B | Compensation | Remuneration Report | 49-52 | |||||||
| 6C | Board practice | The Board/Audit Committee/ | 38-39 | |||||||
| Corporate Governance and Nomination Committee/ | 39 | |||||||||
| Compensation Committee | 40 | |||||||||
| Board of Directors/Executive Management Team | 34-35, 36 |
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| 6D | Employees | Employees | 148 | |||||||
| 6E | Share Ownership | Directors’ Interests, Executive Management Team | 40, 42 | |||||||
| Share ownership of Corporate Management Team | 52 | |||||||||
| 7 | Major Shareholders and Related Party Transactions | |||||||||
| 7A | Major Shareholders | Major shareholders | 168 | |||||||
| 7B | Related Party transactions | Note 17 – Interest in associates and joint ventures/ | 111-113 | |||||||
| Note 35 – Related party transactions | 131-132 | |||||||||
| 7C | Interests of experts and counsel | Not Applicable | N/A | |||||||
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171
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Additional Information
Cross-reference to Form 20-F continued
| Item | Description | Location | Page | |||||||
| 8 | Financial Information | |||||||||
| 8A | Consolidated Statements and other | See Item 18 – Financial Statements/ | ||||||||
| Financial Information | Legal matters/ | 77 | ||||||||
| Note 11 – Taxation/ | 103-106 | |||||||||
| Dividend policy | 41 | |||||||||
| 8B | Significant changes | Note 40 – Post balance sheet events | 140-141 | |||||||
| 9 | The Offer and listing | |||||||||
| 9A | Offer and listing details | Trading markets | 166-168 | |||||||
| 9B | Plan of distribution | Not Applicable | N/A | |||||||
| 9C | Markets | Trading markets | 166-168 | |||||||
| 9D | Selling shareholders | Not Applicable | N/A | |||||||
| 9E | Dilution | Not Applicable | N/A | |||||||
| 9F | Expenses of the issue | Not Applicable | N/A | |||||||
| 10 | Additional Information | |||||||||
| 10A | Share capital | Not Applicable | N/A | |||||||
| 10B | Memorandum and articles of association | Organisation and register/Articles of Incorporation | 155-156, 158-160 | |||||||
| 10C | Material Contracts | Market Risks/Operational Risks | 28-30 | |||||||
| Description of Indebtedness | 75 | |||||||||
| 10D | Exchange Controls | Articles of Incorporation | 158-160 | |||||||
| 10E | Taxation | Taxation | 161-166 | |||||||
| 10F | Dividends and paying agents | Not Applicable | N/A | |||||||
| 10G | Statement by experts | Not Applicable | N/A | |||||||
| 10H | Documents on display | Documents on display | 168 | |||||||
| 10I | Subsidiary Information | Significant subsidiaries | 146 | |||||||
| 11 | Quantitative and qualitative disclosure about market risk | Note 34 – Financial instruments | 123-131 | |||||||
| 12 | Description of securities other than equity securities | Not Applicable | N/A | |||||||
| 13 | Defaults, dividend arrearages and delinquencies | None | – | |||||||
| 14 | Material modifications to the rights of security holders and use of proceeds | None | – | |||||||
| 15 | Controls and Procedures | Internal Controls/ | 28 | |||||||
| Management Report on Internal Controls | Exhibit 15.1 | |||||||||
| Attestation Report of the Registered Public Accounting Firm | 80 | |||||||||
| 16 | Reserved | |||||||||
| 16A | Audit committee financial experts | Audit Committee | 39 | |||||||
| 16B | Code of ethics | Ethics, Integrity and Corporate Social Responsibility | 41 | |||||||
| 16C | Principal Accountant Fees and Services | Note 8 – Auditors’ remuneration | 102-103 | |||||||
| 16D | Exemptions from listing standards for audit Committees | Corporate Governance requirements | 157-158 | |||||||
| 16E | Purchases of equity securities by the issuer and affiliated purchasers | Note 25 – Own shares | 116 | |||||||
| 16F | Change in registrant’s certifying accountant | Not Applicable | N/A | |||||||
| 16G | Corporate governance | Corporate Governance requirements | 157-158 | |||||||
| 17 | Financial Statements | See Item 18 | N/A | |||||||
| 18 | Financial Statements | Consolidated Financial Statements/ | 81-141 | |||||||
| Report of Independent Registered Accounting Firm | 79 | |||||||||
| 19 | Exhibits | 179 | ||||||||
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172 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
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Glossary of legal terms
| Acergy S.A. | Acergy S.A. prior to the Combination which completed following the closure of the Oslo Børs on January 7, 2011. | |||
| ADR | American Depositary Receipt (one Subsea 7 S.A. ADR represents one Subsea 7 S.A. ADS). | |||
| ADS | American Depositary Shares of Subsea 7 S.A. | |||
| Articles of Incorporation | The articles of incorporation of Subsea 7 S.A. | |||
| Board or Board of Directors | The Board of Directors of Subsea 7 S.A. | |||
| Combination/Acquisition | 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 Acergy Shares to the Subsea 7 Inc. Shareholders, which took place on January 7, 2011 after the close of Oslo Børs. Under IFRS the Combination is accounted for as an acquisition. | |||
| Combination Agreement | Business Combination Agreement among Acergy S.A. and Subsea 7 Inc. dated June 20, 2010. | |||
| Company | Subsea 7 S.A. (formerly Acergy S.A.) | |||
| Dalia | Dalia Floater Angola SNC, TSS and Dalia SNC. | |||
| Executive Management Team | The executive management team of Subsea 7 S.A. comprised of the Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, Executive Vice President – Human Resources, General Counsel and Executive Vice President – Commercial. | |||
| Group | Subsea 7 and its subsidiaries. | |||
| NASDAQ or NASDAQ GSM | National Association of Securities Dealers Automated Quotations Global Select Market. | |||
| NKT Flexibles | NKT Flexibles I/S. | |||
| NOK | Norwegian Krone, the lawful currency of Norway. | |||
| Oceon | Global Oceon Engineers Nigeria Limited. | |||
| Oslo Børs | Oslo Børs ASA, a regulated market for securities trading in Norway. | |||
| Relationship Agreement | Relationship Agreement among Subsea 7 Inc. and Acergy S.A. and Siem Industries Inc. dated June 20, 2010. | |||
| Report | Subsea 7 S.A. Annual Report and Financial Statements 2010. | |||
| SapuraAcergy | SapuraAcergy Assets Pte Limited and SapuraAcergy Sdn Bhd. | |||
| SEC | US Securities and Exchange Commission. | |||
| Shares | Common shares of Acergy S.A. and/or Subsea 7 S.A. | |||
| SHL/Seaway Heavy Lifting | Seaway Heavy Lifting Holding Limited, Seaway Heavy Lifting Limited and Seaway Heavy Lifting Engineering BV. | |||
| Sonamet | Investments in Sonamet Industrial S.A and Servicos E Construcoes Petroliferas Lda (Zona Franca Da Madeira). | |||
| 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 the offices of Maples Corporate Services Limited, PO Box 10718, George Town, Grand Cayman, KY1-1106, Cayman Islands. | |||
| Subsea 7 S.A. | Subsea 7 S.A. (formerly Acergy S.A.), a company incorporated under laws of Luxembourg registered with the Registre de Commerce et des Sociétés in Luxembourg under number B 43 172 with registered office at 412F, route d’Esch, L-2086, Luxembourg. | |||
| UK | The United Kingdom. |
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| US | The United States of America. | |||
| VPS | Verdipapirsentralen, the Norwegian central securities depositary. | |||
| $ or US Dollars | The lawful currency of the United States of America. | |||
| € | Euro, being the lawful currency of the Member States of the European Union that adopted the single currency in accordance with the Treaty of Rome establishing the European Economic Community, as amended. | |||
| www.subsea7.com | Website of Subsea 7. The contents of the website are not incorporated by reference. | |||
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173
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Additional Information
Table of Definitions continued
Glossary of business terms
| $1 billion facility | The Subsea 7 S.A. $1 billion multi-currency revolving credit and guarantee facility, executed on August 10, 2010. | |||
| $400 million facility | The Subsea 7 S.A. $400 million amended and restated revolving credit and guarantee facility. This facility was cancelled on August 10, 2010 and all amounts utilised on the execution date have been transferred to the $1 billion facility. | |||
| $200 million facility | The Subsea 7 S.A. $200 million multi-currency revolving guarantee facility. This facility was cancelled on August 10, 2010 and all amounts utilised on the execution date have been transferred to the $1 billion facility. | |||
| NOK 977.5 million facility | The Subsea 7 S.A NOK 977.5 million Loan and Guarantee Facility. | |||
| Acergy AFMED | Acergy Africa & Mediterranean, which was a business segment in the Group prior to the segment changes from the date of the Combination. | |||
| Acergy AME | Acergy Asia & Middle East, which was a business segment in the Group prior to the segment changes from the date of the Combination. | |||
| Acergy Corporate | Acergy Corporate, which was a business segment in the Group prior to the segment changes from the date of the Combination. | |||
| Acergy NAMEX | Acergy North America & Mexico, which was a business segment in the Group prior to the segment changes from the date of the Combination. | |||
| Acergy NEC | Acergy Northern Europe & Canada, which was a business segment in the Group prior to the segment changes from the date of the Combination. | |||
| Acergy SAM | Acergy South America, which was a business segment in the Group prior to the segment changes from the date of the Combination. | |||
| Adjusted EBITDA | Adjusted earnings before interest, income taxation, depreciation and amortisation (‘Adjusted EBITDA’) from continuing operations is calculated as net income from continuing operations plus finance costs, other gains and losses, taxation, depreciation and amortisation and adjusted to exclude investment income and impairment of property, plant and equipment and intangibles. Adjusted EBITDA margin from continuing operations is defined as Adjusted EBITDA divided by revenue from continuing operations. Adjusted EBITDA for discontinued operations is calculated as per the methodology outlined above. Adjusted EBITDA for total operations is the total of continuing operations and discontinued operations. Adjusted EBITDA is a non-IFRS measure that represents EBITDA before additional specific items that are considered to hinder comparison of the Group’s performance either year-on-year or with other businesses. The additional specific items excluded from adjusted EBITDA are other gains and losses and impairment of property, plant and equipment and intangibles. These items are excluded from Adjusted EBITDA because they are individually or collectively material items that are not considered representative of the performance of the businesses during the periods presented. Other gains and losses principally relate to disposals of property, plant and equipment and net foreign exchange gains (losses), and impairments of property, plant and equipment represent the excess of the assets’ carrying amount that is expected to be recovered from their use in the future. | |||
| Backlog | Expected future revenue under in hand projects only where an award has been formally signed. Backlog relating to discontinued operations and Backlog awarded to associates/joint ventures are excluded from Backlog figures, unless otherwise stated. | |||
| Conventional or Conventional Field Development | The projects relating to the fabrication and installation of fixed platforms and their umbilicals, flowlines and associated pipelines (surface/shallow water developments). | |||
| Conventional Refurbishment | The maintenance and refurbishment of Conventional topside facilities. | |||
| Day Rate contract | A contract in which the contractor is remunerated by the customer 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. | |||
| DP | Dynamic Positioning. | |||
| DP3 | Class 3 Dynamic Positioning. (DP3 is the highest equipment class for dynamic positioning and requires vessels to maintain automatic and manual position and heading control under specified maximum environmental conditions, during and following any single fault including loss of a compartment due to fire or flood. It further requires at least two independent computer systems with a separate backup system separated by A60 class division.) | |||
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174 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
|
| DSV | Diving Support Vessel. | |||
| E&P | Exploration and Production. | |||
| EBITDA | Earnings before interest, taxes, depreciation and amortisation. | |||
| EBT | Employee benefit trust. | |||
| EEA | The European Economic Area. | |||
| EPIC | Engineering, Procurement, Installation and Commissioning. | |||
| Flowline | A pipeline carrying oil, gas or water that connects the subsea wellhead to a manifold or to surface production facilities. | |||
| FPSO | A floating production, storage and offloading unit. A floating vessel used by the offshore industry for the processing and storage of oil and gas. | |||
| HMRC | Her Majesty’s Revenue & Customs, the principal tax authority in the United Kingdom. | |||
| IFRS | The International Financial Reporting Standards as adopted by the European Union. | |||
| IMR | Inspection, Maintenance and Repair (see also definition of ‘Life-of-Field’). | |||
| i-Tech | A division of Subsea 7 that provides remotely operated vehicles and remote intervention tooling services to the global exploration & production industry. | |||
| J-Lay | A pipelay method consisting of welding single lengths of steel pipe onboard a pipelay vessel (either 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. | |||
| LIBOR | London InterBank Offered Rate. A daily reference rate based on the interest rates at which banks borrow unsecured funds from other banks in the London wholesale money market. | |||
| Life-of-Field or LoF | 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 ‘IMR’). | |||
| LNG | Liquefied natural gas which is natural gas (predominantly methane) that has been converted temporarily to liquid form for ease of storage or transport. | |||
| Lump Sum contract | A contract in which the contractor is remunerated by the customer at a fixed Lump Sum 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 customer in the contract, is for the contractor’s account. | |||
| NIBOR | The Norwegian InterBank Offered Rate. A daily reference rate based on the interest rates at which banks borrow unsecured funds from other banks in the Norwegian wholesale money market. | |||
| NOLs | Net Operating Losses. | |||
| OECM | Offshore engineering, construction, and maintenance. | |||
| PFIC | A passive foreign investment company for US federal income tax purposes. | |||
| PLEMs | Pipeline End Manifolds. | |||
| PLETs | Pipeline End Terminations. | |||
| Riser | A pipe through which liquid travels upward from the seabed to a surface production facility. |
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| ROV(s) | Remotely Operated Vehicle(s). | |||
| S-Lay | A pipelay method consisting of continuously welding single lengths of steel pipe onboard 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. | |||
| Spoolbase | A shore-based facility used to facilitate continuous pipe laying for offshore oil and gas production. A spoolbase facility allows the welding of single joints of pipe, predominantly steel pipe of 4” to 18” diameter, into predetermined lengths for spooling onto a pipe-laying vessel. | |||
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175
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Additional Information
Table of Definitions continued
Glossary of business terms continued
| Subsea Field Projects | 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, or Subsea Umbilicals, Risers and Flowlines | Subsea Umbilicals, Risers and Flowlines, which includes infrastructure related to subsea trees or floating production platforms, regardless of water depth, including pipelines, risers, umbilicals, moorings, and other subsea structures such as PLEMs and PLETs . | |||
| Survey | The term used to describe platform and pipeline inspection and construction support (including pre-lay, as-laid and as-trenched-surveys, spool metrology, deepwater positioning and light installation works). | |||
| Territory 1 | Comprises Acergy NEC, and Acergy AME. | |||
| Territory 2 | Comprises Acergy AFMED, Acergy NAMEX and Acergy SAM. | |||
| Tonnage Tax | An optional tax regime for shipping companies offered by HMRC that was introduced into the UK tax system as part of Finance Act 2000. | |||
| Trunkline | The projects relating to the installation of large diameter export pipelines worldwide (typically pipelines in excess of 24”). | |||
| Total Shareholder Return | A measure to show returns an investor would realise from holding shares in a company and is defined as ((price at end of fiscal year – price at beginning of fiscal year) + dividend paid in year)/price at beginning of fiscal year. | |||
| 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. | |||
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176 |
Subsea 7 S.A. Annual Report and Financial Statements 2010
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www.subsea7.com
SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
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Subsea 7 S.A. |
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By: |
/s/ Kristian Siem |
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Name: Kristian Siem Title: Chairman of the Board |
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By: |
/s/ Simon Crowe |
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Name: Simon Crowe Title: Chief Financial Officer |
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Date: March 2, 2011
Exhibits
| 1.1 |
Amended Articles of Incorporation of Subsea 7 S.A., dated as of January 11, 2011, filed herewith. |
|
| 2.2 |
Form of Supplemental Agreement to Deposit Agreement by and among the Registrant, Deutsche Bank Trust Company Americas, as successor depositary, and all holders and beneficial owners from time to time of American Depositary Shares evidenced by American Depositary Receipts issued thereunder. Incorporated by reference to Exhibit 99.A2 to the Registrant’s Registration Statement on Form F-6 (File No. 333-123139) filed with the Securities and Exchange Commission on March 4, 2005. |
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| 2.3 |
Form of American Depositary Receipt (included in Exhibit 2.2). |
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| 2.4 |
Form of Indenture for the issuance of senior debt securities (including the form of senior debt securities). Incorporated by reference to Exhibit 4.2 of the Registrant’s registration statement on Form F-3/A (Registration No. 333-86288), filed with the Securities and Exchange Commission on July 31, 2002. |
|
| 2.5 |
Form of Indenture for the issuance of subordinated debt securities (including the form of subordinated debt securities). Incorporated by reference to Exhibit 4.3 of the Registrant’s registration statement on Form F-3/A (Registration No. 333-86288), filed with the Securities and Exchange Commission on August 29, 2002. |
|
| 2.6 |
Trust Deed, dated as at October 11, 2006, by and among the Registrant and The Bank of New York. Incorporated by reference to Exhibit 2.6 to the Registrant’s Annual Report on Form 20-F (File No. 000-21742) filed with the Securities Exchange Commission on April 18, 2007. |
|
| 2.7 |
US$275,000,000 Bond Issue among Subsea 7 Inc. (Borrower and Subsea 7 S.A. (Co-Borrower) and Norsk Tillitsmann ASA (Loan Trustee), dated January, 6, 2011, filed herewith. |
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| 2.8 |
Deed Poll, dated at January, 6, 2011 among Acergy S.A. (as the Company) and Subsea 7 Inc. (as the Issuer), filed herewith. |
|
| 4.1 |
Amendment and Restatement Deed dated August 10, 2006. Incorporated by reference to Exhibit 99.1 of the Registrant’s Form 6-K, filed with the Securities and Exchange Commission on August 22, 2006. |
|
| 4.2 |
US$1,000,000,000 Multicurrency Credit and Guarantee Facility Agreement among Subsea 7 Treasury (Uk) Limited (Borrower), Subsea 7 S.A., Acergy Shipping Limited and Class 3 Shipping Limited (Guarantors), arranged by ING Bank N.V. and DNB NOR Bank ASA with ING Bank N.V. (Agent) and Nordea Bank Finland PLC (Issuing Bank), dated August 10, 2010, filed herewith. |
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| 4.3 |
Relationship Agreement Subsea 7 Inc. and Acergy S.A. and Siem Industries Inc. as dated on June 20, 2010, filed herewith. |
|
| 4.4 |
Business Combination between Acergy S.A and Subsea 7 Inc. as dated June 20, 2010, filed herewith. |
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| 8.1 |
Significant subsidiaries as at the end of the year covered by this Report: see page 158 “Significant Subsidiaries.” |
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| 9.1 |
Consent of Deloitte LLP, Independent Registered Public Accounting Firm. |
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| 12.1 |
Certification of the principal executive officer required by Rule 13a-14(a) or Rule 15d-14(a), pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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| 12.2 |
Certification of the principal financial officer required by Rule 13a-14(a) or Rule 15d-14(a), pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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13.1 |
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted |
|
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pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* |
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13.2 |
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* |
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14.1 |
Consent of Elvinger, Hoss & Prussen. |
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|
15.1 |
Management’s Report on Internal Control over Financial Reporting. |
|
| * |
This document is being furnished in accordance with SEC Release Nos. 33-8212 and 34-47551. |
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The Combination is an excellent strategic fit, strongly supported by industry fundamentals. The combined Group is today more in harmony with the size of the projects we perform for our clients. We are well positioned to
capture future growth opportunities in the global subsea market.
