Oil Field Services - Berenberg · Oil Field Services ... Technip (all Buys) and on Saipem and...

BERENBERG EQUITY RESEARCH

Oil Field Services

Bottom-up analysis points to earnings growth

Part II: company initiations

Asad Farid, CFA

Analyst

+44 20 3207 7932

[email protected]

Jaideep Pandya

Analyst

+44 20 3207 7890

[email protected]

10 July 2013

Oil & Gas

Oil Field Services Oil & Gas

For our disclosures in respect of section 34b of the German Securities Trading Act (Wertpapierhandelsgesetz – WpHG) and our disclaimer please see the end of this document. Please note that the use of this research report is subject to the conditions and restrictions set forth in the disclosures and the disclaimer at the end of this document.


Table of contents

Bottom-up analysis points to earnings growth 5

Executive summary 6

Concerns overplayed, strong structural growth potential intact 10

Company profile 11

Investment thesis 12

The value chain: exposure to both opex and capex 19

Product Solutions – pricing improvement 24

Field-Life Solutions – margin compression likely 43

Engineering Solutions – broadening of client base 49

Financial forecasts and segment analysis 51

Valuation 53

Financials 57

Quality earnings drive premium valuation 61

Company profile 62


Technip: a well-integrated value chain player 70

Restructuring – diversified and less sensitive to the oil price 73

Subsea E&C 80

Onshore/offshore E&C 92

Profitability 100

Financial estimates 102

Performance and valuation 104

Financials 107

Headed towards earnings recovery 111

Company profile 112


Demand dynamics 119

Assets 130


Profitability 136


Financial estimates 143

Financials 145

Risk reward trade-off deteriorating 149

Company profile 150


Onshore E&C – increasing headwinds 160

IES 169

Offshore OPO 174

Financials 176


Financials 182

Structurally challenged 186

Company background 187


Reasons to Hold 190

Value chain 195

Offshore E&C – the “new normal” 199

Onshore E&C – on the edge of a backlog cliff 213

Drilling 218

Financials and valuation 224

Financials 230

Contacts: Investment Banking 234

Disclosures in respect of section 34b of the German Securities Trading Act (Wertpapierhandelsgesetz – WpHG) 235


5

Bottom-up analysis points to earnings growth

In the last 10 years, the European oil services sector has outperformed the European integrated sector and the wider market by more than 3x following a 3.7x increase in the price of oil. More recent performance has been lacklustre, with the sector index declining by 19% ytd on the back of negative earnings momentum due to one-off contract losses.

In this note, we initiate coverage on Aker Solutions, Subsea 7 and Technip (all Buys) and on Saipem and Petrofac (both Holds). We are positive on the sector for three reasons.

o Demand outlook is robust: Consultant Infield projects subsea capex to grow at a CAGR of 15% over 2012-17.

o Oil beta has lowered: E&P capex decouples from the oil price when the latter surpasses USD100/bbl. Over 2008-12, E&P capex and the Brent oil price grew at CAGRs of 11%/3% respectively, while in 1998-2008 respective growth was 20%/23%. This is because even the most difficult projects (ie in the Arctic or in ultra-deepwater) are feasible above this price level.

o Consolidated market: The deepwater subsea installation and hardware markets are highly consolidated with strong entry barriers. If E&P demand grows, pricing/margins will expand.

Our sector approach: The conventional sector view is based on a top-down approach driven by oil price projections and associated global E&P capex. This macro level approach makes earnings momentum difficult to forecast. Our methodology is based on a bottom-up modelling of:

o revenues and the profitability of companies’ individual contracts;

o global E&P capex following analysis of the multi-year capex programmes and production targets of 13 large NOCs and IOCs.

Based on this analysis, we expect a margins recovery, which should help the sector re-rate back to levels in 2012 on 12-month forward P/E for the following reasons.

o Improved pricing on new contracts: The number of large contract awards (more than USD0.5bn) has risen since 2009. Market consolidation and strong demand has resulted in tight installation and hardware markets.

o Project phasing: Better quality contracts won since 2011 will be in their late execution phase from 2014 onwards. This will provide a positive skew to margins – profit recognition is highest at the late execution phase.

o Phasing out of bad contracts: Low-margin contracts won in 2009/10 are now at a late execution phase. From 2014, their share of the backlog should fall sharply and hence lift overall margins.

We prefer stocks with exposure to 1) the hardware and subsea installation sectors, 2) Brazil and West Africa, and 3) national oil companies (NOCs) and integrated oil companies (IOCs) such as Petrobras, Statoil and Total over smaller independents.

Stock preferences

o Aker Solutions (Buy): Strong exposure to hardware.

o Subsea 7 (Buy): Recovery in earnings momentum due to phasing out of low-margin contracts and opportunities to grow.

o Technip (Buy): Strength in subsea and diversified services.

o Saipem (Hold): Exposure to commoditising downstream and shallow water E&C projects plus legacy issues.

o Petrofac (Hold): Risky capex heavy growth strategy to enter subsea installation segment where it lacks competitive advantage.

Aker Solutions

Buy (initiation) Current price

NOK82.00 Price target

NOK115.00 9/07/2013 Oslo Close

Subsea 7


NOK107.50 Price target

NOK146.00 9/07/2013 Oslo Close

Technip


EUR80.90 Price target

EUR106.00 9/07/2013 Paris Close

Petrofac

Hold (initiation) Current price

GBp1,250 Price target

GBp1,370 9/07/2013 Oslo Close

Saipem

Hold (initiation) Current price

EUR14.30 Price target

EUR14.20 9/07/2013 Milan Close

Rating system: Absolute

10 July 2013

Asad Farid, CFA Analyst +44 20 3207 7932 [email protected]

Jaideep Pandya Analyst +44 20 3207 7890 [email protected]


6

Executive summary

Over the last decade, the European oil services sector has outperformed the European integrated oil majors and the market on the back of a 3.7x increase in the price of oil from 2003 levels. However, over the last two years, its performance has been far less impressive, mainly due to flagging earnings momentum (the result of various execution challenges) as well as the effects of project phasing (where low-margin contracts won in the tough operating environment of 2009-10 have entered the late execution phase). The price of oil during this period has traded sideways, while E&P capex growth has been strong at +20% pa.

We expect an earnings recovery from 2014 onwards due to the phasing out of low-margin contracts and the improving quality of the sector’s order book for. Pricing, we think, is improving for subsea installation and hardware on the back of strong growth in global E&P capex and due to the highly consolidated nature of the sector. We expect that E&P spend will remain strong over the next five years, driven by investment in deepwater and ultra-deepwater offshore fields.

We think that subsectors and associated services with high technological content will tend to outperform. We prefer the offshore exploration and construction (E&C) and hardware subsectors over the downstream E&C subsectors.

Today, we initiate coverage on five companies in the oil field services (OFS) sector: Aker Solutions (Aker), Subsea 7, Technip, Petrofac and Saipem (please also see our separate OFS sector overview note entitled Bottom-up analysis points to earnings growth – Part I: sector overview, also published today).

Within this coverage universe, we have Buy ratings on Aker, Subsea 7 and Technip.

Aker is a leading supplier of high-end subsea field equipment and drilling systems for deepwater rigs and a market leader (with a 40% market share) in after-life services, especially in the Norwegian Continental Shelf (NCS) area. The key reasons for our Buy rating on Aker are as follows.

• Aker has strong positioning in the value chain, where it has exposure to both subsea hardware capex and after-life opex. The hardware market is tight and prices are trending upwards (pricing for Christmas trees, for example, is up by 14% for 2010-2012). There is rising demand for deepwater equipment (Christmas tree demand growth: a CAGR of 12% between 2013 and 2016) and drilling packages, which are both product areas in which Aker specialises, and should support earnings momentum in the future.

• The structure of the hardware market is conducive to incumbents in that technological barriers to entry are high and the market is already highly consolidated, with the top five players controlling more than 80% of the market. This should help incumbents such as Aker maintain high margins.

• We forecast that Aker’s sales and EBITDA will grow at a three-year CAGR of 12.9% and 14.7% respectively over 2012-15. This should be supported by improvements in project execution and a reduction in quality costs (which are costs associated with poor project execution) as well as by an aggressive capex plan to boost manufacturing capacity.

• Valuation is undemanding; the stock is trading at a 12-month forward P/E of 7.3x, well below the average of ~12x over the last three years. Our DCF-based target P/E ratio is 10.3x based on 2014 EPS estimates.


7

Subsea 7 is a global leader in subsea field development with a particular expertise in the subsea, umbilicals, risers and flowlines (SURF) sector. The company is a pure installer with associated rigid pipe manufacturing and spooling facilities. Our Buy recommendation is based on the following.

The company is gathering upward earnings momentum, due to the phasing out of loss-making and low-margin Brazilian contracts. The intrinsic margins on revenue streams generated by the current order book are set to rise from 2014 onwards.

Subsea 7 has a sector-leading asset base, including 40 deepwater and ultra-deepwater vessels, along with a strong position in the high-margin West Africa area. We believe that its strong asset base, established track record and geographical reach will help the company leverage on the strong anticipated growth in the subsea installation segment, which is expected to grow at a 15.4% CAGR over 2012-17. Market consolidation should also help limit any downward pressure on pricing, in our view.

The stock has de-rated and is down 19% ytd due primarily to one-off loss provisions on a single bad contract. It is trading at a 12-month forward P/E of 8.3x (based on Berenberg’s 2014 EPS estimates) as compared to the five-year historical average of 14.5x. Similarly, its discount to its closest peer Technip has grown to 11% versus a five-year average premium of 2%. The DCF-based price target of NOK146 assumes a terminal growth rate of 1% and a WACC of 9.8%.

Technip is a leading global oil services contractor with a dominant position in subsea installation and field hardware (flexible pipes and umbilicals), and with engineering expertise in high-end onshore LNG, gas to liquid (GTL) and petrochemicals projects. The key reasons for our Buy rating on Technip are as follows.

• Technip has a diversified product portfolio including hardware (flexible pipes), installation (34 vessels) and front-end engineering (via subsidiaries Genesis and Stone & Webster) and a balanced order book (46% in the high-growth subsea division and 54% in the onshore/offshore division), which gives it a competitive edge over its peers. It has a wide geographical coverage, with a strong presence in the subsea installation market in the North Sea (where it is the joint market leader), Brazil (market leader), the Gulf of Mexico (GoM) (a top three player) and West Africa (a top three player).

• It has a strong technology and engineering focus, including a leading market share in flexible pipe systems for field development and expertise in floating LNG (FLNG) – both of these product areas are expected to see strong growth due to strong E&P spending in deepwater/ultra-deepwater capex.

• We forecast that Technip’s sales and EBITDA will grow at a three-year CAGR of 14% and 16% respectively over 2012-15. We expect this growth to be supported by a strong project bid pipeline in both West Africa and Brazil, which are its core markets. Pricing improvement in hardware should also support earnings momentum.

• The stock is de-rated, despite its strong financial performance, and is trading at a 12-month forward P/E of 10.8x, which is well below the five-year historical average of ~14x. Our DCF-based price target of EUR106 offers an upside of 31%.


8

We have Hold ratings on Petrofac and Saipem and believe they are fairly valued in light of their respective evolving risk-return profiles.

Petrofac is strongly positioned in the mid-tech downstream arena in the Middle East, North Africa and central Asia, and also has upstream equity exposure and a strong position in the management of offshore infrastructure in the UK North Sea and Asia-Pacific. Our Hold recommendation on Petrofac is based on the following.

• Petrofac has a risky capex-heavy growth strategy to enter the SURF market. Given that Petrofac does not have any execution track record or competitive advantage and also lacks local content, we feel it will be difficult for the company to penetrate the SURF market. Furthermore, following the entry of several new players (which between them will introduce 12 new high-end vessels by 2016), we think profitability in the SURF market will come under pressure in the medium term.

• Petrofac has excessive exposure to the Middle East and Africa (c57% of onshore E&C construction sales) where margins are structurally decreasing due to tight competition. This makes margin contraction likely over the medium term if Petrofac is to reverse backlog erosion on a sustainable basis. We forecast an EBITDA margin drop of 0.25% for 2012 versus 2015.

• The higher capex commitment being made by Petrofac to build up its offshore fleet, and the resultant cash flow and balance sheet stress, could compromise growth in its high-margin Integrated Energy Services (IES) division, which will also be undergoing a heavy capex phase over the next three years. We forecast gearing (net debt to equity) will rise to 46% by 2015 compared with the net cash position at the end of 2012.

• We forecast that Petrofac’s ROCE will decline from 30% in 2012 to 16% by 2015 as a result of 1) margin compression in onshore E&C and 2) the high start-up investment needed to enter the SURF segment over the next five years.

• Trading at a 12-month forward P/E of 9.5x for 2014, Petrofac does offer value (a 27% discount for 12-month forward to the historical average) but given that a) the outlook for profitability in its core business (onshore E&C) is negative and b) the aggressive capex plan will put pressure on ROCE and the balance sheet, we remain cautious about the stock.

Saipem is one of three oil services contractors with a global coverage and has a diversified offering comprising offshore and onshore engineering and construction as well as drilling services. Our Hold recommendation is based on the following.

• Saipem is positioned at the low-tech end of the value chain, which is seeing an increase in competition. In onshore, it has lost market share and is struggling to compete with cost-efficient South Korean peers which have access to the Asian value chain. This has led to a sharp erosion in the backlog and margin compression. We think margin improvement will be at the expense of growth.

• In offshore, it has poor exposure to the high-margin deepwater subsea installation market, at which an increasing proportion of future E&C capex is likely to be aimed, especially with the maturation of the subsea factory concept. It has stuck to shallow water trunklay and platform installation work using an ageing vessel fleet which demands high maintenance capex.


9

• Saipem also lacks flexible pipelay installation capability, which is Petrobras’s preferred field development method in a region where Saipem intends to grow. While non-core, its drilling division has performed well, but growth will be limited as the capex programme is largely complete.

• We expect sales and EBITDA to grow at a three-year CAGR of 0.8% and -5.1% respectively, which is lower than consensus over 2012-15. Our DCF-based valuation of EUR14.2 implies a downside of 1%.

Investment recommendations

Source: Berenberg estimates

Companies

Market

capitalization

(local bn)

Recommen

dation

Target

price

Share

priceUpside P/E

EV/EBIT

DAEV/EBIT

Aker Solutions (NOK) 22.5 Buy 115 82 40% 7.4 5.2 6.8

Technip (EUR) 9.1 Buy 106 81 31% 10.8 5.9 7.3

Subsea 7 (NOK) 37.8 Buy 146 108 36% 8.3 3.7 5.0

Saipem (EUR) 6.3 Hold 14.2 14.3 -1% 13.7 7.2 13.4

Petrofac (GBP) 4.3 Hold 13.7 12.5 9% 9.6 6.8 8.1

Sector average 23% 9.9

Sector weighted average 14%

Based on Berenberg 2014 est.

Aker Solutions ASA Oil & Gas

10

Concerns overplayed, strong structural growth potential intact

• We initiate coverage on Aker with a Buy recommendation and a price target of NOK115. Our price target is based on a DCF (WACC: 10.6%; terminal growth: 1.5%) and implies 40% upside from the current share price.

• After a strong performance in 2012, the stock has de-rated by 27% ytd on the back of the re-emergence of quality issues and earlier uncertainty regarding the renegotiation on a large rig (Cat-B) contract with Statoil. We think that these concerns have been overplayed and that Aker’s structural growth is intact, with the share price dip representing a good investment opportunity.

• We expect Aker to be able to maintain a sales CAGR of 12.9% over the next three years on the back of 1) strong equipment and services demand from upcoming deepwater oil and gas developments, 2) its ongoing capacity expansion to cater to the deepwater thrust in Asia and 3) likely pricing improvement in its Product Solutions division.

• We think that restructuring will bridge the margin gap with its peers FMC and Cameron, as its EBITDA margins have substantially lagged these peers’ up to now. On the back of the ongoing restructuring, which is lowering quality costs (costs associated with poor project execution) for the company, the margin differentials between Aker and its larger, more established peers should narrow over time.

• We expect valuation to converge with the sector as the one-off quality costs in 2013 are absorbed and as the restructuring effects start to show. Further, Aker’s high opex exposure, through its strengths in after-life field services, provides it with earnings sustainability which is unmatched by its peers. We think that this deserves a valuation premium considering the current uncertainty in the oil markets.

• Estimates: We anticipate that sales and EBITDA will grow at a three-year CAGR of 12.9% and 14.7% respectively and we are on sales/EBITDA estimates that are 4.6%/2.8% higher than consensus on average for 2013-2015 respectively.

Buy (initiation) Rating system

Current price

NOK 82.60

Absolute

Price target

NOK 115.00 09/07/2013 Oslo Close Market cap NOK 22,045 m Reuters AKSO.OL Bloomberg AKSO NO Share data

Shares outstanding (m) 269 Enterprise value (NOK m) 32,016 Daily trading volume 1,070,000

Performance data

High 52 weeks (NOK) 124 Low 52 weeks (NOK) 81 Relative performance to SXXP OBX 1 month -3.0 % -5.9 % 3 months -27.1 % -25.7 % 12 months -20.2 % -13.1 %

Key data

Price/book value 1.8 Net gearing 0.7% CAGR sales 2012-2015 12.9% CAGR EPS 2012-2015 17.9%

Business activities: A global oil services company which provides engineering services technologies, product and field life solutions

Non-institutional shareholders: Aker Kvaerner Holding - 40.27%

10 July 2013


Jaideep Pandya

Analyst +44 20 3207 7890 [email protected]

Y/E 31.12., NOK m 2011 2012 2013E 2014E 2015E

Sales 36,474 44,922 50,558 57,415 64,602

EBITDA 3,445 4,739 4,718 6,184 7,148

EBIT 2,569 3,573 3,363 4,733 5,647

Clean net income 1,629 2,373 2,140 3,044 3,741

Clean EPS 5.99 8.72 7.88 11.20 13.77

DPS 3.90 4.00 3.26 5.66 6.95

EBITDA margin 9.4% 10.5% 9.3% 10.8% 11.1%

EBIT margin 7.0% 8.0% 6.7% 8.2% 8.7%

ROE 51.6% 22.3% 17.5% 23.8% 24.7%

ROACE 11.7% 14.4% 10.2% 15.0% 16.2%

P/E 14.1 10.8 10.4 7.3 6.0

EV/CF (x) 6.8 15.1 12.3 7.2 7.2

EV/EBITDA (x) 8.2 6.9 6.8 5.1 4.6

EV/EBIT (x) 11.0 9.2 9.5 6.7 5.8

EV/Sales(x) 0.8 0.7 0.6 0.6 0.5

Free Cash flow yield 1.9% -4.6% -3.3% 4.8% 2.3%

Dividend yield 4.6% 4.2% 4.0% 6.9% 8.5%

Source: Company data, Berenberg


11

Company profile

Aker is a leading European oil services company with a focus on engineering; it is also a provider of oil and gas equipment for drilling, production and processing. It is also strong in field development in the after-market, especially in the Norwegian continental shelf (NCS) area, and provides maintenance and modification services along with well intervention services to oil and gas infrastructure in the region.

Aker operates a number of subsidiaries, each of which are focused on different segments of the upstream space. The company entered the oil industry during the 1960s and gradually built a diverse portfolio of services. These include 1) design and engineering, 2) manufacture of equipment for offshore oil drilling, 3) field development (trees, control systems, well heads, umbilicals, mooring and loading), and 4) field management and modifications (MMO) and well invention services (WIS). So, from a value chain perspective, it is a subsea field equipment and offshore drilling equipment supplier as well as a provider of after-life field services.

Aker’s revenue split 2012 EBITDA split 2012

Source: Company data, Berenberg estimates

Aker’s revenues lack geographical diversification. Two regions stand out – Europe (mainly Norway) and Asia, which in 2012 represented 54% and 11% of total revenues respectively. Aker is a major supplier of drilling and topside packages to Asian construction yards and hence the region has been a major revenue contributor. Aker’s over-reliance on Statoil is reflected in the high revenue contribution from Norway. Aker is Statoil’s preferred partner in developing Norway’s offshore oil and gas fields. For its part, the Americas contributed only 14% of revenues.

Revenue split by geography Capex split by geography


Product Solutions

57%Field Life Solutions

33%

Engineering Solutions

10%

Product Solutions

53%Field Life Solutions

35%

Engineering Solutions

12%

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40%

60%

80%

100%

2004 2005 2006 2007 2008 2009 2010 2011 2012

Norway Europe North America

South America Asia (inc. Australia) Other

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Norway Rest of Europe North America



12

Investment thesis

We are initiating coverage on Aker with a Buy recommendation and price target of NOK115. Our price target is based on a DCF (WACC: 10.6%; terminal growth rate: 1.5%).

Aker is a European company, listed on the Oslo Stock Exchange. The company is involved in 1) design and engineering, 2) manufacture of equipment for offshore oil drilling field development and 3) after-market field MMO and well intervention services. The company is especially strong in the NCS, which formed 43% of overall revenues in 2012, and is the preferred contractor for Statoil, with which it has a number of frame agreements for both equipment and field services. Aker is defensive considering its high opex exposure (through its after-life field services), as it is less sensitive to movements in oil prices. This provides stability to its long-term earning stream.

In 2012, Aker generated NOK45bn in revenues, EBITDA of NOK4.7bn (a 10.5% margin) and net profit of NOK2.3bn. In the past three years, the company has maintained revenue growth of 7% CAGR and 10% EBITDA growth. It has high balance sheet leverage with net debt of NOK10bn (2.2x 2012 EBITDA).

Our investment thesis is based on the following three points.

1. The company is regaining lost market share in the subsea division in Latin America and expanding production capacity in Asia to target the deepwater thrust in the region. We foresee strong earnings momentum over 2013-15 and forecast sales and EBITDA to grow at a three-year CAGR of 12.9% and 14.7% respectively over 2013-15. Our estimates are 4.6% and 2.8% higher than Bloomberg consensus for sales and EBITDA growth CAGR respectively over 2013-15.

2. We think execution concerns about Aker have been overplayed and expect the overall quantum of quality costs to decline in 2013 despite a spike in Q1 2013. Aker has been successful in improving quality controls in its subsea and drilling divisions and we think that it would be able to replicate this improvement in its umbilicals and MMO divisions following the process review and management reshuffle that it has initiated. We are confident about the sustainability of Aker’s operating margins given the high barriers to entry and consolidated nature of the equipment supplier business. Market tightness and the likely resolution of quality issues will likely provide further margin upside.

3. Valuation is attractive. Aker has de-rated by 27% ytd and is trading at a 12-month forward PE of 7.3x (Berenberg numbers). Its discount to FMC, its closest peer, has grown to 57% against a five-year average of 47%. We think that this valuation gap is unjustified and expect it to narrow as the one-off impact of the current problems is absorbed and is followed by improved underlying performance.


13

Reasons to buy

Reason #1: Defensive bet with high growth potential The overall environment for the oil and gas sector is becoming increasingly uncertain. Although we doubt that the capex cycle has peaked, considering the aggressive production targets of integrated oil companies (IOCs) and national oil companies (NOCs), oil companies are adopting a more cautious approach in sanctioning new mega projects. This has been made evident by project delays in West Africa and cancellation of important ones in the GoM. Cost inflation, oil price weakness and the resulting fall in net profit per barrel of the major E&P companies is creating a tougher contracting environment. This is visible in the falling margins in the offshore installation business. What makes Aker unique is a product/service portfolio which is both defensive and growth-orientated.

Its Product Solutions division, which provides equipment for drilling and field development (trees, manifolds, control systems and umbilicals, among others), is highly consolidated and has high barriers to entry (such as technology, capital and regulations). Moreover, Aker’s focus is on the high-end deepwater segment, which is experiencing the strongest growth within the offshore space.

The pricing power of the companies within this segment has been rising in recent years given the consolidated nature of the business. Three players dominate subsea equipment (FMC, Cameron and Aker) and only two players do so in drilling solutions (NOV and Aker). In addition, complex projects demand high-spec (ie the ability to work in/under extreme pressures and temperatures) and expensive equipment for drilling and field development. Tree, manifold and drilling system prices have risen since 2009; meanwhile, the flow of orders has increased. In Q1 2013, Aker booked record order intake in its product solutions of NOK20bn, compared to NOK29bn booked in the whole of 2012. This increases revenue visibility for the company and will generate strong top-line growth in 2013 and beyond.

International prices for subsea trees and manifolds (USDm per unit) has risen sharply since 2009

Source: Infield Subsea Report, Berenberg estimates

Aker also has strong exposure to the stable after-life field development market, in which long-term contracts are the norm, providing stability to its revenue streams. Its Life of Field Solutions division provides maintenance and modification services for offshore oil and gas facilities and also provides well intervention services. At

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10.0

20.0

30.0

40.0

50.0

60.0

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1.0

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10.0

2007 2008 2009 2010 2011 2012

Subsea Trees Manifold (RHS)


14

the same time, around 20% of Aker’s product solutions revenues also come from after-life field work, ie the maintenance and replacement of subsea field equipment. High opex exposure through its after market services, which formed 44% of revenues in 2012, counter-balances the volatility of its equipment business. In addition, Aker’s concentrated client portfolio, with its tilt towards NOCs such as Statoil and Petrobras, further lowers its sensitivity to oil prices.

In addition, Life of Field Solutions (ie MMO and WIS) contracts are cost-reimbursable, which de-risks Aker’s lump sum product solutions contract portfolio.

Reason #2: Restructuring to help bridge the margin gap with peers Quality issues in Aker’s umbilicals and MMO divisions have been the main reason for the sharp de-rating of the stock. Although we agree that these issues raise questions about the company’s execution capability, at the same time it represents an opportunity for it to raise margins. We expect EBITDA margin expansion of 81bp to 11.4% by 2017, from 10.5% in 2012.

We think that despite the recent setback, Aker’s restructuring is clearly making progress. It has been able to resolve the execution challenges in the drilling riser business (which arose in 2010) and those at the new subsea equipment manufacturing plant in Brazil. As a result, quality costs fell from NOK3bn in 2010 to NOK750m in 2012. Despite the spike in quality costs in Q1 2013, which rose to NOK215m, we expect the overall quantum to be lower than that in 2012. We think that Aker will learn from this experience to resolve the recent quality costs arising from capacity constraints and poor load management at its umbilicals offering and from subsupplier problems (faulty cables) in MMO.

Aker has already begun a revaluation of its processes to solve execution challenges and better manage growth. For example, it has made changes to the management team in umbilicals, in response to problems with load management and cost slippage on contracts. Tom Munkejord was appointed to head the division in Q1 2013. Munkejord had previously successfully led the turnaround of Aker’s driller riser business, which had experienced similar problems of mismanaged growth. In the last quarter, Aker also brought in Roy Dyrseth from NOV to head its Drilling Technologies division. The division has experienced a sharp drop in orders intake so far in 2013.

With the Ekofisk platform to be delivered by the end of H1 2013, the drag on earnings is expected to be only short-term in nature. In the long term, Aker will need to reassess its subsupplier arrangements to avoid the recurrence of these issues. Greater communication with the suppliers and improved controls and checks at different stages of project execution could provide long-term dividends to the company.

Aker’s EBITDA margins have substantially lagged its peers FMC and Cameron in recent years. We believe that margin differentials between it and its larger, more established peers should narrow over time on the back of the ongoing restructuring, which is helping to lower the company’s quality costs (costs associated with poor project execution). In addition, Aker’s high opex exposure in after-life field services provides earnings sustainability which is not matched by its peers. We think that this merits a valuation premium, considering the uncertainty created by the current weakness in oil prices in terms of capex cycle continuity.


15

Reduction in quality costs through improved execution should help bridge the margin gap with peers

Source: Company data

Reason #3: Valuation is attractive Our price target of NOK115 is based on DCF (WACC: 10.6%; terminal growth rate: 1.5%) and implies an upside of 40% versus yesterday’s close. The price target implies a P/E ratio of 10.3x our 2014 EPS estimate of NOK11.2. This is in line with the historical average trading range of 10-12x.

Historical P/E trading range

Source: DataStream

Aker has historically traded at a discount to the sector in general and to its two peers, FMC and Cameron, in particular, on price earnings multiples. On a 12-month forward P/E multiple, Aker’s discount to the EU Oil Equipment & Services Index has expanded by 17% to 24% since the start of 2013. In our view, Aker’s attractive market position in Europe, capacity expansion in Asia, high opex exposure (recurrent revenues) and restructuring benefits should lead to a narrowing of the recent enlargement in valuation discount.

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2009 2010 2011 2012

FMC TECH Camaron Aker


16

Aker’s discount to the EU Oil Equipment & Services Index has increased by 17% to 24% on a 12-month forward P/E since the start of 2013

Source: DataStream

Aker’s valuation is the cheapest among its peers and its relative discount has enlarged on 12-month forward P/E

Source: DataStream

Aker trades at a significant discount versus peers

Source: DataStream

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Aker EU oil equip & services index

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Aker FMC Cameron NOV

Hardware E&C peers

Market

capitalization

(local bn)

PriceYTD

change

12M

Forward PE

EV/EBIT

DAEV/Sales EV/EBIT

Dividend yield

(%)

Aker Solutions (NOK) 22.45 81.95 -27% 8.94 8.46 0.59 6.73 4.88

FMC Technologies (USD) 13.47 56.81 33% 21.62 17.84 1.69 12.21 0.00

Cameron (USD) 15.79 63.65 13% 14.49 12.71 1.39 8.56 0.00

National Oilwell Varco

(USD)31.10 72.79 6% 11.87 8.02 1.24 7.03 1.43


17

Strong catalysts in the short to medium term Following the recent battering of the stock, we see strong catalysts in the short to medium term which could improve investor confidence and help the stock re-rate. These include the following.

1. Successful commissioning of the Skandi Aker vessel, which is set to start well intervention work for Total in Angola in July 2013: A positive is the flexibility in the start date of this contract with Total, and hence, apart from incremental idle costs, Aker would not incur additional penalties from the client if commissioning is delayed.

2. In the medium to long term, the divestment of Aker Oil Field Services, which forms around 18% of the company’s capital base and has been a drag on its earnings, would be considered a positive for the stock. Apart from 2012, the division has been making a loss at the operating level since 2009. Aker plans to divest the division following the successful commissioning of Skandi Aker and clarity on the Cat-B project. A divestment decision could be made in early 2014, which in our view would be ROCE-accretive by ~3%.

Risks to the thesis 1. Aker has a concentrated client portfolio with high exposure to a few

IOCs, foremost of which is Statoil. Any revision by Statoil of its aggressive production targets and capex plans could adversely affect both opex-led work for Aker in the short term and limit future opportunities. A revision might take place for market-based external reasons, ie following a fall in oil prices or a change in the tax regime, which would make difficult projects unattractive, or for company-specific reasons, which could create financial stress for Aker.

2. Recurrence of quality issues in larger divisions such as Drilling Technologies or Subsea would be a setback to Aker’s financial performance and would cause the market to reassess the efficacy of its restructuring programme.

How far are we from consensus? We anticipate sales and EBITDA to grow at a three-year CAGR of 12.9% and 14.7% respectively. Our estimates for sales and EBITDA growth are 4.6% and 2.8% respectively higher than consensus estimates over 2013-15. Although we expect backlog additions to sustain top-line growth, we are relatively conservative compared to consensus on margins over a three-year horizon. We expect EBITDA margin expansion of 51bp by 2015 compared to consensus expectations of 108bp. Our relatively bearish view on margins is based on rising competition in its Life of Field Solutions business and that in the drilling division along with a weak oil price environment which increases the negotiating power of oil companies which could affect contractors’ margins.


18

Berenberg versus consensus

Source: Berenberg estimates, Bloomberg

2012 2013E 2014E 2015E 3Yr cagr

Sales (Beren.) 44,922 50,558 57,415 64,602 12.9%

Consensus 44,922 47,911 52,985 57,091 8.3%

EBITDA (Beren.) 4,739 4,718 6,184 7,148 14.7%

Consensus 4,739 4,625 5,916 6,642 11.9%

EPS (Beren) 8.72 7.88 11.20 13.77 16.5%

Consensus 8.72 7.41 10.60 12.58 13.0%


19

The value chain: exposure to both opex and capex

Aker operates a number of subsidiaries, each focused on different segments of the upstream space. The company entered the oil industry during the 1960s and gradually built a diverse portfolio of services. These include 1) design and engineering, 2) manufacture of equipment for offshore oil drilling, 3) field development, and 4) field management and modifications. So, from a value chain perspective, it is basically a subsea equipment supplier and a provider of after-life field services. This provides Aker with exposure to both the opex and capex cycles and makes it a defensive bet in the current oil price weakness.

One negative for Aker is its lack of diversification from a geographical perspective. Two regions stand out: Europe (mainly Norway) and Asia, which in 2012 represented 54% and 11% respectively of total revenues. Aker is a major supplier of drilling and topside packages to Asian construction yards and hence the region has been a major revenue contributor. Aker’s over-reliance on Statoil is reflected in the high revenue contribution of Norway. Aker is Statoil’s preferred partner in developing Norway’s offshore oil and gas fields. The company’s presence in other markets is a concern: its business in the Americas, for example, contributed only 14% of the company’s revenues.

However, this is likely to change, as the company is expanding both product and life-of-field solutions capacity in growth regions such as Asia-Pacific and Brazil. In our view, Aker’s high-end product portfolio provides it with a competitive edge, considering that offshore projects are becoming more complex and moving into deeper waters.

Revenue split by geography Capex split by geography


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20

Product Solutions: expertise in high-end subsea equipment

The Products Solutions division is involved in the engineering and manufacture of drilling, oil and gas processing, and subsurface and subsea field equipment. The largest revenue contributors are the Subsea and Drilling Technologies subdivisions, with respective shares of 48% and 34% in 2012. This was followed by Umbilicals at 8%, Process Systems at 6% and Mooring and Loading Systems at 4%.

Aker has been at the forefront of providing equipment for the complex near-Arctic projects in the NCS. This has given the company an expertise in high-tech subsea equipment for ultra-deepwater, extreme temperature and high pressure environments. This, we think, is especially useful from a growth and margin point of view in the medium to long term, as an increasing amount of international oil company capex is going towards developing resources in ultra-deepwater, whether in Brazil, West Africa, the GoM or Asia-Pacific.

Similarly, in drilling technologies, it has developed its niche in high-end equipment for deep and ultra-deepwater rigs, in which it has only one main competitor, NOV. In each segment of its equipment portfolio, it has gained a high market share which provides it with strong pricing power in a concentrated market.

The Subsea and Drilling Technologies subdivisions: The Subsea segment includes manufacturing and installation of subsea production and processing systems. This includes equipment such as trees (subsurface and subsea), well heads, control systems, manifolds, tie-in connectors and power distribution systems. The Drilling Technologies subdivision engineers, fabricates and installs complete drilling units for offshore rigs along with associated equipment such as drilling risers (clip risers), drilling control and simulations systems and drilling fluid management systems. A

Umbilicals: Aker is an industry leading provider of subsea umbilicals with 27% market share compared to 22% for Oceaneering and 17% for Technip. Aker manufactures the umbilicals at two facilities in Norway and the US. Its products include power umbilicals for providing power and control for subsea equipment as well as systems to provide electrical heating to flowlines and power cables.

Others: Aker’s Mooring and Loading Systems division products include chain jacks, hydraulic winches, loading arms, steer gearing and deck machinery (towing equipment). The Process Systems division provides equipment for the treatment of oil and gas produced by the onshore and offshore upstream sector. This includes equipment for oil separation, gas treatment (removal of water and acidic gases) and for treatment of heavy oil.

Field-Life Solutions: opex exposure provides earning resilience

The Field-Life Solutions division provides services for enhanced oil and gas recovery from existing fields. The division can be divided into three business segments: MMO, WIS and Oil Field Services and Marine Assets (OMA).

MMO has the biggest share of the divisional revenues and contributed 77% to the divisional top line in 2012. MMO is involved in providing services for upgrading oil and gas facilities for enhanced hydrocarbon recovery and to extend the life of the field. MMO also includes integrity management of oil and gas infrastructure, which includes inspection, monitoring and maintenance. The core markets for MMO are the oil and gas assets in the mature basins in the North Sea and Asia-Pacific where both ageing infrastructure and mature fields require investment to reverse


21

production declines. Aker is also now targeting the GoM and Canada to boost and diversify its MMO revenue stream.

Aker’s well intervention services comprises pumping services, wireline, coiled tubing, well engineering and pipeline commissioning and decommissioning. These services are used for logging, injection, pressure-testing and control, scale removal, well clean-up and pressure control applications, among others.

Exposure is well positioned in the NCS, where Aker has a market share of 40%. Service contracts are based on long-term frame contracts which are cost-reimbursable in nature. This strength in after-life field services provides Aker with exposure to NOC opex which is more resilient to the vagaries of the oil price. At the same time, the long-term reimbursable nature of the contracts provides good earning visibility to Aker. This is in contrast to its peers within the equipment supply chain whose after-market exposure is more limited. Thus, if Aker is able to improve project execution, we think its earnings quality and sustainability would demand a valuation premium.

2012 Revenue split of Field-Life Solutions


Engineering Solutions: growth from a low base

Aker’s Engineering Solutions division carries engineering work for projects in the North Sea region (the UK and Norway). Work includes concept screening, feasibility studies, field planning, project execution strategy, detailed engineering and procurement and construction management. It is currently executing contracts for Statoil, Staatsolie (Suriname NOC) and ENI.

The division has exhibited volatile performance since 2009 with the book-to-bill fluctuating at around one. Margins have also been under pressure since 2012, mainly due to poor capacity utilisation.

It recently lost out on major NCS contracts as a engineering subcontractor to Kvaerner. Management is now aiming to diversify its narrow client base in order to increase margin. We believe that this is possible considering Aker’s strengths and high market share as both a high-end equipment supplier and a major player in after-life field services. We think that Aker has significant room to develop its expertise in this area, as has been shown by its peer Technip.

MMO77%

WIS16%

OMA7%


22

Competitors: Aker well positioned in a concentrated market

Aker has a number of different competitors across the upstream oil and gas value chain. Its three closest peers are FMC, Cameron and NOV, which all provide services such as drilling equipment, subsea equipment (Christmas tree, well heads, control systems, umbilicals), mooring systems and subsea installation services. The following table gives a list of other competitors in the oil and gas services and equipment supply chain.

Aker’s top three closest competitors are FMC, Cameron and NOV

Source: Aker Solutions capital market day presentation 2012

Aker is well positioned in most of its key market segments. The equipment supplier market has a concentrated structure, with 3-4 dominant players having more than 90% of the market. This, in our view, is a function of the high barriers to entry resulting from high investment costs, skilled labour and proprietary technologies. Aker’s sizeable market position in these concentrated market structures positions it well to realise high margins in the prevailing high-demand growth environment. Aker currently lags its peers in terms of margin, and we think that this highlights potential for enhanced profitability growth.

Aker has a solid 13% market share in Christmas trees, which gives it a fourth-place ranking behind FMC, Cameron and GE. However, in subsea controls, it ranks first globally with a 33% market share. Aker is followed by FMC and GE with respective market shares of 27% and 19%.


23

Market share of Christmas tree segment, 2008 to September 2012: global #4

Market share of subsea controls 2008 to September 2012: global #1

Source: Aker Solutions capital market day presentation 2012

Similarly, it is the leader in umbilicals with 27% of the market, followed by Oceaneering at 22% and Technip at 17%. The company has two manufacturing facilities located in Moss Norway and in Mobile, US. These two sites have a combined manufacturing capacity of 600-100km of umbilicals per year. It is investing NOK505m in raising its subsea and umbilicals capacity. In the drilling equipment market, there are only three main players: Aker ranks second with a market share of 27%. Over 2008 to 2013, the company has delivered 35 units, compared with 92 units by industry leader NOV.

Market share of umbilicals 2008 to September 2012: global #1

Market share of drilling topside for rigs 2008 to September 2012 (behind NOV)

Source: Aker capital market day presentation 2012

Aker Solutions,

13%

Cameron, 30%

Dril-Quip, 4%

GE Oil & Gas, 15%

Other, 1%

FMC Technologies,37%

Aker Solutions,

33%

Cameron, 13%

GE Oil & Gas, 19%

Other, 8%

FMC Technologies, 27%

Aker Solutions,

27%

Technip Duco, 17%

Nexans, 11%

Prysmian, 9%

Parker, 6%

Other, 9%

Oceaneering Umt Solutions, 22%

71

27

2

NOV AKSO Huisman

Share %

Units 92 35 3


24

Product Solutions – pricing improvement

Divisional financial estimates

Source: Company data and Berenberg estimates

We expect Product Solutions divisional sales to grow at a three-year CAGR of 15.5% over 2012-15 and expect a sequential increase in the share of the division in total revenues. Within product solutions, we expect Subsea and Umbilicals to exhibit the fastest growth at 18% pa followed by Drilling Technologies at 13%. The smaller subdivisions – Process Systems, and Mooring and Loading Systems (MLS) – are expected to grow at 11% and 4% pa respectively.

Considering the maturity profile of the divisional backlog and based on our assessment of the market, Aker’s expansion plans and the potential bidding opportunities in its core market, we think that these growth forecasts are achievable. Our revenue forecast implies an order intake which will average NOK37bn pa. In Q1 2013, order intake stood at NOK20bn, which, along with the potential improvement in order intake in Drilling Technologies and better capacity utilisation in Umbilicals gives us confidence that the backlog accretion we are anticipating will be achieved.

At the same time, we expect margin expansion for the division to increase from 9% in 2012 to 12% in 2015. This expansion will, in our view, come on the back of a restructuring programme which management has initiated to improve execution and reduce quality costs. At the same time, healthy demand and oligopolistic market conditions would encourage margin expansion, in our view.

In the following section, we give a comprehensive overview of the demand and supply dynamics within Product Solutions, Aker’s growth strategy and upcoming bidding opportunities in the primary oil and gas regions. This forms the core of our bottom-up modelling, on which our divisional top line and EBITDA estimates are based.

NOK mn 2010 2011 2012 2013E 2014E 2015E

3 yr growth

cagr 2012-

15E

Sales 18,398 19,706 25,291 29,856 33,978 38,955 15.5%

As % group 55% 54% 56% 59% 59% 60% n.a.

Sales growth 7% 28% 18% 14% 15% n.a.

EBITDA 1,591 1,136 2,336 2,957 3,665 4,494 24.4%

As % group 48% 33% 49% 63% 59% 62% n.a.

EBITDA margin (%) 9% 6% 9% 10% 11% 12% n.a.


25

We expect order intake to average at NOK38bn pa over 2013-15


Demand dynamics: Offshore oil and gas production currently accounts for more than one-third of global production, of which a quarter comes from deep and ultra-deepwater projects. Technological advances in subsea production and processing are facilitating this thrust into deeper and harsher environments. Growth is broad-based and not only limited to the traditional deepwater “golden triangle” (the GoM, West Africa and Brazil). The two traditionally shallow water subsea markets – the north-west European continental shelf (NWECS) and Asia – are increasingly moving towards greater water depths. Also, mega-deepwater gas discoveries in east Africa (off Mozambique and Tanzania) have opened another frontier, which will be developed over the next 5-10 years. Pemex and NOCs in the Middle East are also increasingly exploring deeper basins in the GoM and the Red Sea.

With offshore projects becoming technically more complex, the associated field development capex is rising, a trend which will likely continue. These projects demand higher field development capex due to associated demand for higher spec (work under extreme pressure and temperature) and hence expensive drilling rigs, field development vessels and subsea equipment (Christmas trees, well heads, manifolds and umbilical). Technological advances have made it possible for long subsea tie-backs of marginal fields to existing infrastructure. This has been the chosen strategy in established basins like the US GoM and the North Sea, and will play an increasing role in tapping the Arctic resources and also in Brazil.

Since 2009, global subsea capex has grown at an average rate of 7% pa. Based on the projects which are to start over the next five years, we expect the rate of capex growth to rise to and average 11% pa. The number of subsea tree orders, which can be taken as a proxy of overall activity in the offshore space, is now reaching the peak levels of 2005-06. Indeed, orders in 2013 may exceed those levels. External consultant Infield expects the tree market to grow at 10% pa, with tree installation rising to 500 per year by 2016. The ongoing development of major deepwater discoveries made in Brazil, Norway and the Barents Sea over the last decade requires high-end subsea equipment which can operate in high pressure and colder environments. It has also created drilling demand to support field development. Looking at the capex plans of the large offshore drilling contractors, the number of floater newbuilds is expected to be in the region of 20-30 over 2015-20.

Higher demand as well as the rising complexity of field equipment has resulted in a tight supplier market. As can be seen in the following chart, the pricing of

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26

important subsea equipment like trees and manifolds has been on an upward trend. Given the consolidated nature of the market and the high technological and regulatory barriers to entry, we would expect this trend to persist (at the current oil price level) over the next two years.

International prices of subsea trees and manifolds (USDm per unit)

Source: Infield Subsea Report, Berenberg estimates

Aker is well placed to benefit from these structural trends. Its core markets of the North Sea, Brazil and Asia are expected to grow strongly over the next five years (see graph below). Aker is coming out of a high capex phase, with the completion of capacity expansion at its Norwegian and Asia subsea manufacturing plants. It is thus in a good position to fulfil the demand for subsea field development equipment and drilling packages that the upcoming projects are likely to create.

Subsea capex (USDbn) by geography Subsea tree order per annum

Source: Infield Subsea Report

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Global subsea tree manufacturing capacity by manufacturer

Subsea tree orders by manufacturer

Source: Infield Subsea Report

Outlook: top line

Project mix

In this segment, we conduct project-by-project modelling for the four subdivisions of the Product Solutions division to construct a backlog revenue schedule for each. Similar to what we have done for the other divisions, we then consider the schedule in the light of our assessment of upcoming contracts, Aker’s growth plans and strategy, and then predict the resultant probability of success for these projects.

Subsea: Looking at the revenue schedule of the projects currently in the subsea backlog, we estimate that 45% of the backlog will be completed this year and a further 30% in 2014. This is primarily because subsea equipment contracts take on average 1-2 years to complete, and hence revenue visibility for the Product Solutions division is on average lower than for full engineering, procurement, installation and construction (EPIC) contractors discussed elsewhere.

Aker Solutions,

17%

Cameron, 24%

Dril-Quip, 6%

FMC, 36%

GE, 17%

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28

Subsea backlog revenue maturity model


Umbilicals: Aker currently has a market-leading 40% share of the global umbilicals market and is executing 17 umbilicals supply contracts for projects in Norway, Asia and the GoM. The company has experienced poor capacity utilisation at its Mobile umbilicals manufacturing plant in the US due to delays in project awards. We think that this will improve from 2013 onwards, considering the number of umbilicals awards picked up in the latter half of 2012 and the pace at which the market is growing. In the medium to long term, we think that the company’s focus on expanding in the Asian market will help it sustain strong growth in the segment. Aker has postponed its investment decision to open a new manufacturing plant of the same scale as that in Norway and the US in Malaysia. We expect the project to be sanctioned once the company resolves problems at the other two plants.

Start date Clientvalue

(NOK m)Location 2012 2013 2014 2015 2016 2017

Sapinhoá and Lula Nordeste pre-salt field 27/03/2013 Petrobras 4,600 Brazil - 690 1,610 2,300 - -

Moho Nord 25/03/2013 Total 4,900 Congo - 1,960 2,940 - - -

Subsea Frame agreement 27/02/2013 Statoil 5,500 Norway/ Norwegian

Continental Shelf230 1,100 1,100 1,100 1,100 1,100

Aasta Hansteen (luva) 01/02/2013 Statoil 2,000 Norway/ North Sea - 400 500 600 500 -

Alvheim contract 27/12/2012 Marathon 300 Norway/ North Sea - 150 150 - - -

Visund field 02/10/2012 Statoil 300 Norway/North Sea 30 180 60 - - -

Troll extension 28/09/2012 Statoil 250 Norway 25 100 125 - - -

Dalia field 04/05/2012 Total 470 Angola/ Offshore 47 212 212 - - -

Edvard Grieg platform (formerly Luno). 03/05/2012 Kvaerner 1,500 Norway/ North Sea 150 675 675 - - -

Siakap North - Petai deepwater development 02/05/2012 Murphy 500 Malaysia/ offhsore 75 250 175 - - -

Awali Oilfield 30/03/2012 Enerserv $17m Bahrain 102 - - - - -

Draugen field 27/03/2012 Shell 105 Norway/ Norwegian Sea 53 53 - - - -

Troll 16/02/2012 Statoil 350 Noway/ NCS 53 105 105 88 - -

Bøyla project 05/01/2012 Marathon 210 Noway/ NCS 116 95 - - - -

Svalin project 29/12/2011 Statoil 400 Noway/ NCS 120 280 - - - -

Vilje South project 24/11/2011 Statoil 225 Norway/ North Sea 101 124 - - - -

Subsea control modules and topside power units 17/11/2011 Dana Petroleum 80 UK 24 47 - - - -

Brynhild project 11/11/2011 Lundin 700 Noway/ NCS 231 455 - - - -

Kikeh subsea expansion project 11/07/2011 Murphy Sabah 500 Malaysia/ offshore 350 - - - - -

3 subsea work-over systems 19/03/2011 Statoil 1,250 Noway/ NCS 625 250 - - - -

Fossekall-Dompap project 30/03/2011 Statoil 1,000 Norway/ North Sea 500 300 - - - -

Eldfisk 2/7 S 18/03/2011 ConocoPhillips 5,500 Norway/ North Sea 1,925 1,925 550 - - -

Vigdis North East development 11/02/2011 Statoil 500 Noway/ NCS 50 - - - - -

Goliat flowlines and risers 21/12/2010 Technip 65 Norway/ Barents sea 29 36 - - - -

Åsgard subsea compression system 01/12/2010 Statoil 3,400 Norway 1,530 1,020 - - - -

Goliat field 24/11/2010 Technip 80 Norway/ Barents Sea 32 16 - - - -

Gudrun tie-in to Sleipner 29/09/2010 Statoil 900 North Sea 270 270 - - - -

Clair Ridge project 12/06/2010 BP 1,700 UK/ West of Shetlands 595 340 - - - -

3-yr contract extension for E&C work 29/06/2010 Nexen GBP60m North Sea 189 108 - - - -

Offshore Wind Farm Nordsee Ost project 17/06/2010 (fabrication starts in Jan'11)RWE Innogy €115m Germany/ North Sea 259 - - - - -

Iara and Guará fields 20/04/2010 Petrobras $300m Brazil 450 450 90 - - -

Ekofisk accommodation platform - Ekofisk 2/4L 17/03/2010 ConocoPhillips 2,100 Norway/ North Sea 945 - - - - -

Goliat field 16/09/2009 ENI 2,300 Norway/ Barents Sea 805 690 - - - -

SUBSEA 9,910 12,279 8,292 4,088 1,600 1,100


29

Umbilicals backlog maturity model


Drilling: The Drilling division has 16 contracts in the backlog which provides revenue visibility for the company until 2015. In 2012, the company won a number of contracts from Chinese yards, which are becoming increasingly assertive in the rig market and are developing expertise in deeper waters. Rig pricing has improved since 2010, especially high-end, which should sustain Aker’s top-line growth.

Drilling backlog maturity model



(NOK m)Location 2012 2013 2014 2015 2016 2017

Girassol Resources Initiative (GirRI) phase 2 16/04/2013 Technip 150.00 Angola - 53 98 - - -

Erha North phase 2 15/03/2013 Exxon 150.00 Nigeria - 60 90 - - -

Aasta Hansteen umblicals contract 25/01/2013 Statoil 280.00 Norway - 112 168 - - -

Ichthys LNG Project 20/12/2012 McDermott 500.00 Australia - 200 300 - - -

frame agreement 11/12/2012 Shell 300.00 Global - 360 360 360 360 360

Block 15\06 West Hub development project 17/10/2012 ENI 300.00 Angola 30 195 75 - - -

Dalmatian field 27/09/2012 Murphy 450.00 GoM 68 383 - - - -

Ichthys umbilicals contract 16/07/2012 McDermott 440.00 Australia 44 176 220 - - -

Greater Western Flank (GWF) Phase 1 project 25/04/2012 Woodside 300.00 Australia 90 210 - - - -

Svalin C project 23/04/2012 Statoil 200.00 Norway/ North Sea 60 140 - - - -

Eight steel tube umbilicals 12/01/2012 Anadarko 600.00 GoM 180 420 - - - -

Jette field development 27/11/2011 Det norske's 60.00 Noway/ NCS 57 - - - - -

East Rochelle development project 21/07/2011 Endeavour Energy 83.00 UK/ offshore 58 - - - - -

Jack & St. Malo field developments 31/05/2011 Chevron 600.00 GoM 360 - - - - -

Norne field 23/03/2011 Statoil 200.00 Norway/ North Sea 80 - - - - -

CLOV development project 01/02/2011 Framo Engineering 80.00 Angola/ offshore 32 32 - - - -

Gorgon Project 26/03/2010 Chevron 550.00 Australia 275 - - - - -

UMBILICALS 1,334 2,340 1,311 360 360 360


(NOK m)Location 2012 2013 2014 2015

deepwater drilling riser system 12/12/2012 Daewoo 450.00 South Korea - 225 180 -

jack-up drilling equipment 24/09/2012 Zhenhua 400.00 China 20 380 - -

Complete semi-submersible drilling equipment topside package 23/07/2012 Hyundai 900.00 South Korea 135 765 - -

deepwater drilling riser 19/07/2012 Atwood 550.00 Malaysia 138 413 - -

Jack-up drilling equipment package 16/04/2012 Yantai 900.00 China 180 720 - -

two drilling equipment packages for 'Category D' rigs 28/03/2012 Daewoo 1,100.00 Asia 165 330 385 220

Seven new onshore drilling rigs 13/03/2012 Honghua 365.00 China 164 201 - -

Snorre A platform 28/02/2012 Statoil 1,000.00 North Sea 150 400 450 -

Deepwater drilling riser system for Atwood Advantage rig 09/01/2012 Daewoo $48m Asia 29 115 144 -

2 drilling equipment packages for 'Cat D' drilling rigs 26/11/2011 Daewoo 1,100.00 South Korea 330 385 385 -

delivery of a deepwater drilling riser system 04/07/2011 Daewoo 300.00 South Korea 150 90 - -

Complete drilling equipment package for a new deepwater drill ship 17/06/2011 Daewoo 540.00 Asia 378 - - -

Supply complete drilling equipment packages 30/05/2011 Cosco $195m China 468 468 - -

Drilling equipment packages for 2 deepwater drillships 20/04/2011 Daewoo $230m South Korea 897 - - -

Ekofisk 2/4 Z platform 22/12/2010 ConocoPhillips 1,100.00 Norway 550 - - -

two drilling equipment packages 28/05/2010 Daewoo $180m South Korea - - - -

DRILLING 3,754 4,491 1,544 220


30

Process Systems and Mooring and Loading Systems: These two subdivisions contributed only 5% of the company’s top line in 2012. Currently, the company is executing three contracts, which will provide revenue visibility until 2014.

Backlog maturity model


Growth potential: future projects

Offshore E&C by region Subsea activity in Aker’s target markets such as the NCS, Asia-Pacific and Brazil is expected to remain strong over the next five years, with a number of projects in the planning and development phases. Aker is well positioned, considering its strong value chain and supporting assets in these regions. It is investing aggressively to enhance its manufacturing capacity in all three key geographies. This, in addition to likely improvement in execution capability, makes us confident that it will be able to successfully leverage on the new developments in these key regions.

NWECS: Aker has the highest market share in the NCS, bolstered by a strong asset base supporting its operations in Norway and the UK. This includes manufacturing plants for subsea equipment and umbilicals, as well as service yards for life-of-field services. This strong local content and technological edge gained as the leader in executing difficult projects in the NCS places the company in a good position to capitalise on the activity upturn in the region, especially in the drive to open up the Arctic region. It aims to be the preferred partner for Statoil, for which it is currently executing projects such as Dagny, Aasta Hansteen, Troll and Mariner. The work includes a range of contracts from front-end engineering and design (FEED) to facilities modification work.

Activity in the North Sea area has been high over the last two years, and we are bullish about the outlook in light of the projects already under or nearing execution there. Projects could include both tie-in work for smaller fields as well as increased platform activity at larger fields like Skrugard. The table below details important projects in the NWECS, which are all at different stages of development. Aker is investing to double manufacturing capacity at its Tranby yard to fulfil the subsea equipment demand in the region and the expansion would likely be complete by the end of the year.


(NOK m)Location 2012 2013 2014

Kristin platform 22/12/2010 Statoil 900.00 Noway/ NCS 293 293 135

PROCESS SYSTEMS 293 293 135

Pusnes offshore loading systems for ten shuttle tankers 13/10/2011 South Korean shipyards 150.00 Norway & Brazil 53 90 -

Pusnes offloading systems(TM) to two FPSOs 26/05/2011 CQG Oil & Gas 120.00 Brazil 72 - -

MOORING & LOADING SYSTEMS 125 90 -


31

NWECS project bid pipeline

Source: Norwegian Petroleum Directorate

Aker has a strong relationship with Statoil and its long and successful project execution track record in the NWECS. Statoil has aggressive growth plans in the region and is aiming to raise its total oil and gas production to 2.5mboed by 2020 (current level: 2mboed). This is despite an average decline rate of 5% for its current portfolio. Although a significant portion of this growth will be achieved from Statoil’s international operations, especially from the unconventional shale acreage in the US and from offshore fields in Brazil and East Africa, the NCS will continue to play an important part in the company’s growth strategy, especially considering that 80% of its developed reserves are in the region.

Statoil has a large project pipeline leading up to the end of the decade. Aker is already involved in FEED studies on important projects such as Ivar Aasen, Mariner and Aasta Hansteen. We believe this early-stage presence increases the likelihood that its production systems will be used in the field development stage of these projects. The following table shows the extensive project pipeline for Statoil which we believe presents a strong opportunity for Aker.

Country Project Dev. Phase Operators

UK Kraken Tendering EnQuest

UK Rosebank FEED Chevron

UKGreater Lancaster Area

(GLA)Conceptual Hurricane Exploration

UK Catcher Conceptual Premier Oil

UK Bressay FEED Statoil

UK Mariner FEED Statoil

UK Western Isles Under ConstructionDana Petroleum

(subsidiary of KNOC)

Norway 15/5-2 EirinPDO submited last

yearStatoil

Norway 16/1-8. PDO submited Lundin

Norway 16/1-9 PDO submited Det norske

oljeselskap ASA

Norway 17/12-1 Bream PDO submited BG Norge AS

Norway 24/6-1 Peik PDO submited Centrica Resources

(Norge)

Norway 24/9-9 S Bøyla PDO submited Marathon Oil Norge

AS

Norway 25/2-10 S PDO submited Statoil

Norway 25/11-16 Svalin PDO submited Statoil

Norway 31/2-N-11 H PDO submited Statoil

Norway 34/8-13 A PDO submited Statoil

Norway 6406/9-1 Linnorm PDO submited A/S Norske Shell


32

Statoil project pipeline

Source: Statoil investor presentation and industry publications

Asia-Pacific: Asia-Pacific is central to Aker’s growth strategy and the company is investing heavily to enhance its presence in the region, with Malaysia as its hub for expansion. It is doubling the subsea equipment manufacturing capacity of its Port Klang plant and is also constructing an umbilicals manufacturing plant in Malaysia which will come into operation by the end of the year. It also recently opened a new service centre in Malaysia for providing life-of-field services in the region. Aker is already executing subsea and drilling equipment contracts in the region and recently won its first life-of-field service contract for Shell’s offshore fields in Brunei.

Location StatusDetails (peak

capacity kboed)Startup

Filed development

estimateOperator

Martin Linge (Hild)Norway/ North

SeaDev. 80 2016 $4.2bn Total

Julia US/ GoM Pre FID under study 2016Statoil (50%) /

ExxonMobile (50%)

Dagny & Erin fieldNorway/ North

SeaFID 50 2017 $4.18-$5bn Statoil

Ivar Aasen (previously

called Draupne)

Norway/ North

SeaFID 40 2017 $4.5bn (NOK24.7bn) Det norske

Mariner field UK/ North Sea FID 40 2017 $7bn Statoil

Aasta Hansteen field (prev

called luva)

Norway/ North

SeaFID 100 2017 $5.7bn Statoil

Johan SverdrupNorway/ North

Sea

Pre FID (also pre

FEED)120-200 2017+ $28bn Lundin

KKD (Jai Kos Dehseh)

Future Phases (Oil Sands

proj)

Canada Pre FID 30-60 2017+ Statoil

Shah Deniz Stage 2 AzerbaijanPre FID (FID likley

by the end of 2013)95 2017+ $28bn

Skrugard/ HavisNorway/

Barents SeaPre FID 60-95 2018 Statoil

Bressay UKPre FID (FID likely

in 2013)under study 2017+ $5bn Statoil

Peregrino phase 2 Brazil Pre FID under study 2017+ Statoil

Rosebank UK Pre FID under study 2017+ $6-8bn Chevron

Kizomba Satellites Phase 1 Angola 100,000 bopd 2012 BP


33

Australia, China, Malaysia, Indonesia and Vietnam are Aker’s key Asia-Pacific markets. It is also active in frontier basins like India. The Asia-Pacific region has historically been a marginal shallow water subsea market. Deepwater opportunities are largely untapped as Asia-Pacific has a very low subsea installed base. However, this is set to change as there are a number of deepwater projects (see table below) which are at the evaluation or development phase in the region which could support strong growth for companies like Aker.


34

Project pipeline in Asia

Source: External consultancy Intsok, Berenberg estimates

Name Operator CountryWater

Depth(M)Status

Date On

Stream

West Linapacan B (SC-14C) The Philodrill Corporation Philippines 250 Possible 01/01/2016

Gendalo Chevron Indonesia Company Indonesia 1425 Firm Plan 01/10/2016

Kamunsu East

Upthrown/Canyon (SB-G)Sabah Shell Petroleum Co Ltd Malaysia 1000 Probable 01/10/2016

Senangin (SB-K)Murphy Sabah Oil Company

LtdMalaysia 1431 Probable 01/10/2015

Rong Tre (Young Dragon) (11-

2)KNOC Vietnam Vietnam 92 Possible 01/01/2014

Ubah (SB-G) Sabah Shell Petroleum Co Ltd Malaysia 1430 Possible 01/10/2015

Kerisi (SB-K)Murphy Sabah Oil Company


Mya South (Block A-3) Daewoo International Ltd Myanmar 600 Probable 01/10/2016

Jangas (SB-K)Murphy Sabah Oil Company


Rotan (SB-H)Murphy Sabah Oil Company

LtdMalaysia 1140 Firm Plan 01/10/2016

Aster Eni Indonesia Company Ltd Indonesia 600 Probable 01/10/2017

West Linapacan A (SC-14C)

(Phase 2)The Philodrill Corporation Philippines 350 Probable 01/07/2015

Jangkrik (Muara Bakau Block)

(Kutei Basin)Eni Indonesia Company Ltd Indonesia 425 Firm Plan 01/01/2016

Sirasun (TSB) (Kangean PSC) Kangean Energy Indonesia Ltd Indonesia 150 Firm Plan 01/01/2014

GeronggongBrunei Shell Petroleum Co Sdn

BhdBrunei 1000 Probable 01/10/2017

Liuhua LH 29-1 (Block 29/26) Husky Oil China Ltd China (PRC) 723 Firm Plan 01/01/2015

Ledong 22-1 (Phase 2)

Extension

China National Offshore Oil

Corp(CNOOC Ltd)CNOOCChina (PRC) 100 Probable 01/10/2015

Panyu 35-1China National Offshore Oil

Corp(CNOOC Ltd)CNOOCChina (PRC) 300 Firm Plan 01/09/2013

Liuhua 16-2China National Offshore Oil

Corp(CNOOC Ltd)CNOOCChina (PRC) 400 Firm Plan 01/07/2016

Krishna-Godavari KD-1-1Oil & Natural Gas Corporation

(ONGC)India 844 Possible 01/10/2015

Annapurna (KG-DWN-98/2

R-Cluster)

Oil & Natural Gas Corporation

(ONGC)India 1030 Probable 01/10/2016

P Field (KG-DWN-98/2)

(Kanaka Durga)


(ONGC)India 493 Possible 01/10/2016

Krishna-Godavari UD-1 (KG-

DWN-98/2) (D5)


(ONGC)India 2841 Probable 01/01/2017

Dhirubhai 34 (D6-R Series)

(KG-DWN-98/3)Reliance Petroleum Limited India 2010 Probable 01/10/2015

Dhirubhai (D6-G1) (KG-DWN-

98/3)Reliance Petroleum Limited India 1400 Probable 01/10/2016


35

Brazil: Aker already has a strong installed base in Brazil, including a large manufacturing and service base in Rio Das Ostras. After poor contract execution on high-end subsea tree contracts in 2011, Aker has adopted a cautious stance in the region as it looks improve coordination between its Brazil-based operation and its teams operating in Norway. Aker has already increased its manufacturing capacity in Brazil and we think it has adequate local content to provide for the strong demand for subsea equipment there over the next five years. The following charts show the Petrobras’s demand for wet trees and manifolds. This market will be split between FMC, Aker and Cameron, and we believe that Aker’s asset base in the region positions it well in this oligopolistic market.

Demand for subsea trees and manifolds over 2013-17

Source: Infield subsea market report 2016

The following table gives the project pipeline for Petrobras to help it achieve its 4.2mbd oil and gas production target by 2020 (current production: 2mbd). Apart from Petrobras, Shell, Chevron and Statoil are the other operators in the region. Despite production target cuts by Petrobras in its latest business plan, the region is still expected to see strong demand for subsea production systems as well as tie-in systems and drilling packages. If Aker can resolve the quality issues it has faced in recent years, we believe it could win a substantial share of the demand growth that we expect to see in the medium term.

0

50

100

150

200

250

2012 2013 2014 2015 2016 2017

Wet Christmas trees Manifolds


36

Brazil project pipeline

Source: External consultancy Intsok, Berenberg estimates

Name Operator Country Water Depth(M) StatusDate On

Stream

Area Do 1-RJS-424

(Espadarte Southeast)Petrobras Brazil 1056 Probable 01/01/2014

Area Do 1-RJS-485 Petrobras Brazil 115 Possible 01/10/2014

Area Do 1-RJS-493 Petrobras Brazil 200 Possible 01/10/2014

Maromba (BC-20) Petrobras Brazil 160 Probable 01/10/2015

Atlanta (BS-4) (1-SHEL-4-

RJS)Petrobras Brazil 1554 Possible 01/08/2017

Pirapitanga (Ex BS-500) Petrobras Brazil 1500 Probable 01/01/2015

Lula North (BM-S-11) Petrobras Brazil 2126 Probable 01/07/2017

Iara Horst (BM-S-11) Petrobras Brazil 2230 Firm Plan 01/10/2016

Iara Northwest (BM-S-11) Petrobras Brazil 2222 Probable 01/07/2017

Carioca Pilot (BM-S-9)

(Sugarloaf)Petrobras Brazil 2100 Probable 01/07/2016

Lula Sul (BM-S-11) Petrobras Brazil 2126 Firm Plan 01/07/2017

Tartaruga Verde (BM-C-

36) (Block C-M-401)Petrobras Brazil 976 Probable 01/10/2017

Franco (Phase 1) (2-ANP-

1-RJS)Petrobras Brazil 2189 Firm Plan 01/04/2016

Brigadeiro (Parque Dos

Doces) (BM-ES-23)Petrobras Brazil 1900 Possible 01/10/2017

Gavea (BM-C-33) (1-

REPF-11A-RJS)

Repsol Sinopec Brasil

JVBrazil 2708 Possible 01/10/2017

Franco (Phase 2) Petrobras Brazil 2189 Probable 01/10/2016

Franco (Phase 3) Petrobras Brazil 2189 Probable 01/10/2017

Tambuata (Golfinho East)

(4-GLF-31-ESS)Petrobras Brazil 1520 Probable 01/10/2014

Atlanta EWT Test (BS-4)

Queiroz Galvao

Exploracao e

Producao

(QGEP)Queiroz

Brazil 1554 Firm Plan 01/08/2014

Tupi Northeast (1-BRSA-

976-RJS) (1-RJS-691)Petrobras Brazil 2131 Probable 01/10/2017

Carimbe Petrobras Brazil 1027 Probable 01/10/2017

Mandarim (Marlim Sul 4-

MLS-105D-RJS)Petrobras Brazil 1874 Probable 01/10/2014

Argonauta O-South

(Parque das Conchas BC-

10)

Shell Oil Do Brasil

LtdaBrazil 1600 Probable 01/10/2015


37

Regional growth

Aker’s subsea focus has primarily been on the NCS, but the drilling division has concentrated mainly on the demand for equipment from deepwater rig manufacturers in South Korea and China. This is visible in the regional breakdown of the product solutions projects which have been won since 2009, as shown in the graph below, which plots the revenue streams from these projects on a regional basis over the next three years. As can be seen, the NCS and Asia are expected to be the main regional drivers for the company, at least in the short to medium term.

The NWECS and Asia are expected to be the primary revenue contributors for Product Solutions in 2013 and 2014 (NOKm)

Source: Aker’s 2011 capital markets day, Berenberg estimates

Outlook: profitability Profit margins in Aker’s Product Solutions division have been on an improving trend as a result of improved market pricing and company project execution over the last three years. The EBITDA margin for the division rose from 8.6% in 2010 to 9.2% in 2012. Although we do not believe that the company’s target to raise the overall company EBITDA margin to 15% by 2017 is achievable, some margin expansion is still likely especially, as the zero margin contracts in Brazil will be fully executed by 2014. At the same time, we see market pricing to be increasing, especially in the high-end subsea and drilling markets which are the core revenue drivers for the company. Within Product Solutions, Subsea and Drilling technologies EBITDA margins have risen from respective levels of 7.7% and 7.7% in 2010 to 8.3% and 12.1% respectively in 2012. A reduction in quality costs, which came down from NOK3bn in 2010 to NOK750m in 2012, has helped margin expansion, as has a tight equipment market.

Compared to its peers FMC and Cameron, Aker follows an aggressive profit recognition policy. While its peers only book profits once the products are successfully delivered, Aker books profits once 20% of the project is complete. We think that this has been one reason why Aker has booked provisions on lump sum contracts in the past. This profit recognition policy also means that the backlog contract mix by project stage, ie “project phasing”, will have a bearing on overall profit margins.

In the following section, we give our profit projections for Product Solutions based on the contract mix in the backlog as well as the pricing expectations for the contract intake in the coming years.

0

2000

4000

6000

8000

10000

12000

14000

16000

2012 2013 2014 2015 2016

NWEC shelf Middel East & Africa Asia Brazil GoM


38

Contract mix

For a typical EPC (engineering, procurement and construction) equipment contract, profit recognition is zero before 20% completion. The following table gives the project execution schedule over 2013 to 2016 and corresponding percentage of completion. In 2013, there are three projects in the engineering phase which are less than 20% complete. In addition, any further equipment supply contracts won in the second half of 2013 would not contribute to margins.

In 2013 and 2014, the NWECS and Asia are expected be the main revenue contributors for the company, with the share of higher-margin Asia increasing in 2014 in the revenue mix. This will have beneficial implications for overall divisional margins.


39

Backlog execution profile


Start date Client Location

Sapinhoá and Lula Nordeste pre-salt field 27/03/2013 Petrobras Brazil 0% 15% 35% 50% 0% 0%

Moho Nord 25/03/2013 Total Congo 0% 40% 60% 0% 0% 0%

Subsea Frame agreement 27/02/2013 StatoilNorway/ Norwegian

Continental Shelf4% 19% 19% 19% 19% 19%

Aasta Hansteen (luva) 01/02/2013 Statoil Norway/ North Sea 0% 20% 25% 30% 25% 0%

Alvheim contract 27/12/2012 Marathon Norway/ North Sea 0% 50% 50% 0% 0% 0%

Visund field 02/10/2012 Statoil Norway/North Sea 11% 67% 22% 0% 0% 0%

Troll extension 28/09/2012 Statoil Norway 10% 40% 50% 0% 0% 0%

Dalia field 04/05/2012 Total Angola/ Offshore 10% 45% 45% 0% 0% 0%

Edvard Grieg platform (formerly Luno). 03/05/2012 Kvaerner Norway/ North Sea 10% 45% 45% 0% 0% 0%

Siakap North - Petai deepwater development 02/05/2012 Murphy Malaysia/ offhsore 15% 50% 35% 0% 0% 0%

Awali Oilfield 30/03/2012 Enerserv Bahrain 100% 0% 0% 0% 0% 0%

Draugen field 27/03/2012 Shell Norway/ Norwegian Sea 50% 50% 0% 0% 0% 0%

Troll 16/02/2012 Statoil Noway/ NCS 15% 30% 30% 25% 0% 0%

Bøyla project 05/01/2012 Marathon Noway/ NCS 55% 45% 0% 0% 0% 0%

Svalin project 29/12/2011 Statoil Noway/ NCS 30% 70% 0% 0% 0% 0%

Vilje South project 24/11/2011 Statoil Norway/ North Sea 45% 55% 0% 0% 0% 0%

Subsea control modules and topside power units 17/11/2011 Dana Petroleum UK 33% 65% 0% 0% 0% 0%

Brynhild project 11/11/2011 Lundin Noway/ NCS 33% 65% 0% 0% 0% 0%

Kikeh subsea expansion project 11/07/2011 Murphy Sabah Malaysia/ offshore 70% 0% 0% 0% 0% 0%

3 subsea work-over systems 19/03/2011 Statoil Noway/ NCS 50% 20% 0% 0% 0% 0%

Fossekall-Dompap project 30/03/2011 Statoil Norway/ North Sea 50% 30% 0% 0% 0% 0%

Eldfisk 2/7 S 18/03/2011 ConocoPhillips Norway/ North Sea 35% 35% 10% 0% 0% 0%

Vigdis North East development 11/02/2011 Statoil Noway/ NCS 10% 0% 0% 0% 0% 0%

Goliat flowlines and risers 21/12/2010 Technip Norway/ Barents sea 45% 55% 0% 0% 0% 0%

Åsgard subsea compression system 01/12/2010 Statoil Norway 45% 30% 0% 0% 0% 0%

Goliat field 24/11/2010 Technip Norway/ Barents Sea 42% 21% 0% 0% 0% 0%

Gudrun tie-in to Sleipner 29/09/2010 Statoil North Sea 30% 30% 0% 0% 0% 0%

Clair Ridge project 12/06/2010 BP UK/ West of Shetlands 35% 20% 0% 0% 0% 0%

3-yr contract extension for E&C work 29/06/2010 Nexen North Sea 35% 20% 0% 0% 0% 0%

Offshore Wind Farm Nordsee Ost project 17/06/2010 (fabrication starts in Jan'11)RWE Innogy Germany/ North Sea 30% 0% 0% 0% 0% 0%

Iara and Guará fields 20/04/2010 Petrobras Brazil 25% 25% 5% 0% 0% 0%

Ekofisk accommodation platform - Ekofisk 2/4L 17/03/2010 ConocoPhillips Norway/ North Sea 45% 0% 0% 0% 0% 0%

Goliat field 16/09/2009 ENI Norway/ Barents Sea 35% 30% 0% 0% 0% 0%

SUBSEA

% of completion


40

Backlog execution profile – continued



Girassol Resources Initiative (GirRI) phase 2 16/04/2013 Technip Angola 0% 35% 65% 0% 0% 0%

Erha North phase 2 15/03/2013 Exxon Nigeria 0% 40% 60% 0% 0% 0%

Aasta Hansteen umblicals contract 25/01/2013 Statoil Norway 0% 40% 60% 0% 0% 0%

Ichthys LNG Project 20/12/2012 McDermott Australia 0% 40% 60% 0% 0% 0%

frame agreement 11/12/2012 Shell Global 0% 20% 20% 20% 20% 20%

Block 15\06 West Hub development project 17/10/2012 ENI Angola 10% 65% 25% 0% 0% 0%

Dalmatian field 27/09/2012 Murphy GoM 15% 85% 0% 0% 0% 0%

Ichthys umbilicals contract 16/07/2012 McDermott Australia 10% 40% 50% 0% 0% 0%

Greater Western Flank (GWF) Phase 1 project 25/04/2012 Woodside Australia 30% 70% 0% 0% 0% 0%

Svalin C project 23/04/2012 Statoil Norway/ North Sea 30% 70% 0% 0% 0% 0%

Eight steel tube umbilicals 12/01/2012 Anadarko GoM 30% 70% 0% 0% 0% 0%

Jette field development 27/11/2011 Det norske's Noway/ NCS 95% 0% 0% 0% 0% 0%

East Rochelle development project 21/07/2011 Endeavour Energy UK/ offshore 70% 0% 0% 0% 0% 0%

Jack & St. Malo field developments 31/05/2011 Chevron GoM 67% 0% 0% 0% 0% 0%

Norne field 23/03/2011 Statoil Norway/ North Sea 40% 0% 0% 0% 0% 0%

CLOV development project 01/02/2011 Framo Engineering Angola/ offshore 40% 40% 0% 0% 0% 0%

Gorgon Project 26/03/2010 Chevron Australia 50% 0% 0% 0% 0% 0%

UMBILICALS

deepwater drilling riser system 12/12/2012 Daewoo South Korea 0% 56% 44% 0% 0% 0%

jack-up drilling equipment 24/09/2012 Zhenhua China 5% 95% 0% 0% 0% 0%

Complete semi-submersible drilling equipment topside package 23/07/2012 Hyundai South Korea 15% 85% 0% 0% 0% 0%

deepwater drilling riser 19/07/2012 Atwood Malaysia 25% 75% 0% 0% 0% 0%

Jack-up drilling equipment package 16/04/2012 Yantai China 20% 80% 0% 0% 0% 0%

two drilling equipment packages for 'Category D' rigs 28/03/2012 Daewoo Asia 15% 30% 35% 20% 0% 0%

Seven new onshore drilling rigs 13/03/2012 Honghua China 45% 55% 0% 0% 0% 0%

Snorre A platform 28/02/2012 Statoil North Sea 15% 40% 45% 0% 0% 0%

Deepwater drilling riser system for Atwood Advantage rig 09/01/2012 Daewoo Asia 10% 40% 50% 0% 0% 0%

2 drilling equipment packages for 'Cat D' drilling rigs 26/11/2011 Daewoo South Korea 30% 35% 35% 0% 0% 0%

delivery of a deepwater drilling riser system 04/07/2011 Daewoo South Korea 50% 30% 0% 0% 0% 0%

Complete drilling equipment package for a new deepwater drill ship 17/06/2011 Daewoo Asia 70% 0% 0% 0% 0% 0%

Supply complete drilling equipment packages 30/05/2011 Cosco China 40% 40% 0% 0% 0% 0%

Drilling equipment packages for 2 deepwater drillships 20/04/2011 Daewoo South Korea 65% 0% 0% 0% 0% 0%

Ekofisk 2/4 Z platform 22/12/2010 ConocoPhillips Norway 50% 0% 0% 0% 0% 0%

two drilling equipment packages 28/05/2010 Daewoo South Korea 0% 0% 0% 0% 0% 0%

DRILLING

Kristin platform 22/12/2010 Statoil Noway/ NCS 33% 33% 15% 0% 0% 0%

PROCESS SYSTEMS

Pusnes offshore loading systems for ten shuttle tankers 13/10/2011 South Korean shipyards Norway & Brazil 35% 60% 0% 0% 0% 0%

Pusnes offloading systems(TM) to two FPSOs 26/05/2011 CQG Oil & Gas Brazil 60% 0% 0% 0% 0% 0%

MOORING & LOADING SYSTEMS

% of completion


41

Profitability by projects



2012 2013 2014 2015 2016 2017

Sapinhoá and Lula Nordeste pre-salt field 27/03/2013 Petrobras Brazil - - 219 219

Moho Nord 25/03/2013 Total Congo - 235 353

Subsea Frame agreement 27/02/2013 StatoilNorway/ Norwegian

Continental Shelf- 128 106 106 106 106

Aasta Hansteen (luva) 01/02/2013 Statoil Norway/ North Sea - - 90 60 50 -

Alvheim contract 27/12/2012 Marathon Norway/ North Sea - 16 16 - - -

Visund field 02/10/2012 Statoil Norway/North Sea 25 7 - - -

Troll extension 28/09/2012 Statoil Norway 13 13 - - -

Dalia field 04/05/2012 Total Angola/ Offshore 30 24 - - -

Edvard Grieg platform (formerly Luno). 03/05/2012 Kvaerner Norway/ North Sea 78 64 - - -

Siakap North - Petai deepwater development 02/05/2012 Murphy Malaysia/ offhsore 37 20 - - -

Awali Oilfield 30/03/2012 Enerserv Bahrain 9 - - - - -

Draugen field 27/03/2012 Shell Norway/ Norwegian Sea 5 5 - - - -

Troll 16/02/2012 Statoil Noway/ NCS 16 11 - - -

Bøyla project 05/01/2012 Marathon Noway/ NCS 12 9 - - - -

Svalin project 29/12/2011 Statoil Noway/ NCS 11 27 - - - -

Vilje South project 24/11/2011 Statoil Norway/ North Sea 10 12 - - - -

Subsea control modules and topside power units 17/11/2011 Dana Petroleum UK 3 5 - - - -

Brynhild project 11/11/2011 Lundin Noway/ NCS 23 46 - - - -

Kikeh subsea expansion project 11/07/2011 Murphy Sabah Malaysia/ offshore 30 - - - - -

3 subsea work-over systems 19/03/2011 Statoil Noway/ NCS 61 24 - - - -

Fossekall-Dompap project 30/03/2011 Statoil Norway/ North Sea 49 29 - - - -

Eldfisk 2/7 S 18/03/2011 ConocoPhillips Norway/ North Sea 135 135 39 - - -

Vigdis North East development 11/02/2011 Statoil Noway/ NCS 5 - - - - -

Goliat flowlines and risers 21/12/2010 Technip Norway/ Barents sea 3 3 - - - -

Åsgard subsea compression system 01/12/2010 Statoil Norway 92 61 - - - -

Goliat field 24/11/2010 Technip Norway/ Barents Sea 3 2 - - - -

Gudrun tie-in to Sleipner 29/09/2010 Statoil North Sea 23 23 - - - -

Clair Ridge project 12/06/2010 BP UK/ West of Shetlands 51 29 - - - -

3-yr contract extension for E&C work 29/06/2010 Nexen North Sea 16 9 - - - -

Offshore Wind Farm Nordsee Ost project 17/06/2010 (fabrication starts in Jan'11)RWE Innogy Germany/ North Sea 19 - - - - -

Iara and Guará fields 20/04/2010 Petrobras Brazil - - - - - -

Ekofisk accommodation platform - Ekofisk 2/4L 17/03/2010 ConocoPhillips Norway/ North Sea 73 - - - - -

Goliat field 16/09/2009 ENI Norway/ Barents Sea 64 55 - - - -

SUBSEA 695 1,052 960 384 156 106

7% 9% 12% 9% 10% 10%

Profit recognition


42

Profitability by projects – continued



2012 2013 2014 2015 2016 2017

Girassol Resources Initiative (GirRI) phase 2 16/04/2013 Technip Angola - 4 8 - - -

Erha North phase 2 15/03/2013 Exxon Nigeria - 5 8 - - -

Aasta Hansteen umblicals contract 25/01/2013 Statoil Norway - 8 13 - - -

Ichthys LNG Project 20/12/2012 McDermott Australia - 15 23 - - -

frame agreement 11/12/2012 Shell Global - 29 29 29 29 29

Block 15\06 West Hub development project 17/10/2012 ENI Angola 18 6 - - -

Dalmatian field 27/09/2012 Murphy GoM 2 - - - -

Ichthys umbilicals contract 16/07/2012 McDermott Australia 15 15 - - -

Greater Western Flank (GWF) Phase 1 project 25/04/2012 Woodside Australia 6 15 - - - -

Svalin C project 23/04/2012 Statoil Norway/ North Sea 4 9 - - - -

Eight steel tube umbilicals 12/01/2012 Anadarko GoM 1 2 - - - -

Jette field development 27/11/2011 Det norske's Noway/ NCS 4 - - - - -

East Rochelle development project 21/07/2011 Endeavour Energy UK/ offshore 4 - - - - -

Jack & St. Malo field developments 31/05/2011 Chevron GoM 2 - - - - -

Norne field 23/03/2011 Statoil Norway/ North Sea 5 - - - - -

CLOV development project 01/02/2011 Framo Engineering Angola/ offshore 2 2 - - - -

Gorgon Project 26/03/2010 Chevron Australia 15 - - - - -

UMBILICALS 43 116 85 29 29 29

3% 5% 7% 8% 8% 8%

deepwater drilling riser system 12/12/2012 Daewoo South Korea - 28 22 - - -

jack-up drilling equipment 24/09/2012 Zhenhua China 40 - - - -

Complete semi-submersible drilling equipment topside package 23/07/2012 Hyundai South Korea 108 - - - -

deepwater drilling riser 19/07/2012 Atwood Malaysia 17 52 - - - -

Jack-up drilling equipment package 16/04/2012 Yantai China 90 - - - -

two drilling equipment packages for 'Category D' rigs 28/03/2012 Daewoo Asia 63 49 28 - -

Seven new onshore drilling rigs 13/03/2012 Honghua China 21 25 - - - -

Snorre A platform 28/02/2012 Statoil North Sea 14 37 41 - - -

Deepwater drilling riser system for Atwood Advantage rig 09/01/2012 Daewoo Asia 17 17 - - -

2 drilling equipment packages for 'Cat D' drilling rigs 26/11/2011 Daewoo South Korea 40 46 46 - - -

delivery of a deepwater drilling riser system 04/07/2011 Daewoo South Korea 18 11 - - - -

Complete drilling equipment package for a new deepwater drill ship 17/06/2011 Daewoo Asia 43 - - - - -

Supply complete drilling equipment packages 30/05/2011 Cosco China 54 54 - - - -

Drilling equipment packages for 2 deepwater drillships 20/04/2011 Daewoo South Korea 103 - - - - -

Ekofisk 2/4 Z platform 22/12/2010 ConocoPhillips Norway 63 - - - - -

two drilling equipment packages 28/05/2010 Daewoo South Korea - - - - - -

DRILLING 373 570 176 28 - -

10% 13% 11% 13% #DIV/0! #DIV/0!

Kristin platform 22/12/2010 Statoil Noway/ NCS 15 15 7 - - -

PROCESS SYSTEMS 15 15 7 - - -

Pusnes offshore loading systems for ten shuttle tankers 13/10/2011 South Korean shipyards Norway & Brazil 8 14 - - - -

Pusnes offloading systems(TM) to two FPSOs 26/05/2011 CQG Oil & Gas Brazil 5 - - - - -

MOORING & LOADING SYSTEMS 13 14 - - - -

Profit recognition


43

Field-Life Solutions – margin compression likely


Field Life Solutions financial estimates


We expect Field-Life Solutions divisional sales will grow at a three-year CAGR of 11% over 2012-15. Within the division, we expect MMO to exhibit the fastest growth at 12% pa followed by WIS at 7%.

Considering the maturity profile of the divisional backlog, and based on our assessment of the market, Aker’s expansion plans and the potential bidding opportunities in its core market, we think that these growth forecasts are achievable. Our revenue forecast implies an order intake which will average NOK22bn pa. In Q1 2013, order intake stood at NOK4bn. Better fleet utilisation in OMA along with MMO expansion in Asia-Pacific will lead to increased orders, we anticipate.

We are less bullish about margins, however, and expect the divisional EBITDA margin to contract by 92bp over 2013-15. Increased competition in both MMO and WIS, along with expansion plans in Asia (a low-margin region) would in our view result in this contraction. In 2013, quality costs in the Ekofisk Zulu platform contract would result in the divisional margin dropping to 8%, which would be followed by a partial improvement as these one-off impacts are absorbed and management is successful in improving execution and quality controls.

In the following section, we elaborate on our divisional forecasts based on our assessment of demand and supply dynamics, Aker’s growth strategy and upcoming bidding opportunities. This forms the core of our bottom-up modelling on which our divisional top line and EBITDA estimates are based.

NOK mn 2010 2011 2012 2013E 2014E 2015E

3 yr growth

cagr 2012-

15E

Sales 11,096 12,178 14,320 15,880 18,134 19,759 11%

As % group 33% 33% 32% 31% 32% 31% n.a.

Sales growth 10% 18% 11% 14% 9% n.a.

EBITDA 1,234 1,025 1,544 1,307 1,883 1,948 8%

As % group 37% 30% 33% 28% 30% 27% n.a.

EBITDA margin (%) 11% 8% 11% 8% 10% 10% n.a.


44

We expect order intake to average NOK24bn over 2013-15


Demand dynamics: Demand for field-life services is strong in mature offshore regions such as the North Sea, the GoM and the shallow water Asia-Pacific region. In these mature territories, offshore facilities are ageing and hence require a large amount of maintenance and modification work. Similarly in the NCS, there is a general trend to tie-in production from new discoveries to existing infrastructure rather than develop new processing platforms. This has improved project economics of marginal fields. This is generating strong demand for modification work in the region. A similar trend would also support MMO demand growth in the long term in other regions such as Brazil.

Aker is exposed to the entire field-life services offering through its MMO, WIS and OMA services based on its vessel fleet. MMO is the most important subdivision for Aker and contributed a quarter to company’s top line in 2012.

MMO: Aker is a strong player in the MMO sector in the NCS where the market is duopolistic in nature. Aker has a 40% market share, similar to its rival Norwegian player Able. On the UK side of the North Sea, there are far more players fulfilling market demand, including Petrofac, Wood Group and Amec. It is a similar story in Asia-Pacific, where a number of local companies are active, in addition to Petrofac and Aker. Aker in 2010 tried to expand its MMO business in the GoM market but its offering did not find much traction with the local E&P companies due to strong offering by local incumbents. The business is capital light and hence the competitive pressures in most markets are strong. In the Norwegian market, however, Aker is more protected by strong regulatory safeguards: only the two biggest players are allowed to carry out work on hot platforms.

However, despite a highly concentrated market, competitive pressures are rising. Recently, Worley Parson acquired MMO player Rosenberg, which improves its position to compete for market share. These competitive pressures are visible in MMO’s financial performance: divisional EBITDA fell from 10.1% in 2010 to 8.8% in 2012.

Aker’s growth strategy within MMO will also likely have a negative impact on the divisional margins. The company last year opened a new service base in Malaysia to target the Asia-Pacific market. It also won its first large MMO contract outside the NCS to manage Shell shallow water fields in Brunei. However, this is a lower-margin region, as is evident from the low-margin profile of Petrofac’s Offshore

0%

10%

20%

30%

40%

50%

60%

0

5

10

15

20

25

30

35

40

2013E 2014E 2015E 2016E 2017E




45

Project and Operations (OPO) division (2012 EBITDA margin: 6.8%), which has high exposure to the lower-margin Asia-Pacific.

WIS: Well intervention work is less sensitive than the Product Solutions division to fluctuations in the oil price as it is driven by opex and hence is less exposed to the cyclical nature of E&P capex. In a tough operating environment where oil companies are finding it difficult to replace reserves, better reservoir management has become increasingly important. Well intervention along with MMO is being used to enhance field recovery rates. As offshore fields gradually mature throughout the world, demand for WIS will rise with it. Moreover, as fields are developed in harsher deep and ultra-deep waters, the need for technologically advanced WIS will rise.

In this segment, Aker’s core competitors are the much larger US players Halliburton, Schlumberger, Weatherford and Baker Hughes. Aker’s product offering is more focused and is limited to offshore, primarily in the NCS and West Africa. The well service industry is global in nature and manpower and equipment can be easily relocated, and this is partly the reason why Aker faces competition from the global supplier base. The divisional margin has been declining over the last three years, and in 2012 stood at 17.8%

Aker’s well intervention work is supported by a fleet of three vessels which carry out subsea construction and well intervention work in North Sea, Brazil and West Africa. In Q2 2012, Aker won an eight-year contract for a new well intervention Cat-B rig worth NOK11bn. The project has since been delayed due to technical challenges, and indeed may not go ahead if Aker and Statoil decide that it is not the best well intervention solution available.

Outlook: top line

Project mix

MMO: In terms of project mix within the MMO subdivision, Aker has a high proportion of pure modification contracts which are higher margin than maintenance contracts. Most of these modification contracts are with Statoil, which is investing heavily to modify existing infrastructure in order to boost recovery from existing fields and develop marginal fields in the peripheries of existing platforms. The division provides revenue visibility until 2017, and the long-term nature of its contracts lower the group’s top-line volatility.


46

MMO backlog maturity model


WIS: Aker is working on seven well intervention projects, five of which are in Norway and two of which are in West Africa (Angola and Ghana). The contracts are drawn up on a reimbursable basis, like those in MMO, and hence are stable and less risky compared to the revenues from the Product Solutions division.

WIS backlog maturity model


Regional growth

Aker’s Field-Life Services division is primarily concentrated in the NCS. With the opening of service bases in Malaysia and Brazil, the business is set to grow in these two regions. However, business in Malaysia and Brazil is a lot more competitive than in West Africa and the quality of growth will be one consideration that Aker will need to take into account.

In Asia-Pacific, Petrofac and a number of local players provide maintenance and modification and well intervention services, and in Brazil, the dominant NOC can dictate its terms on rates. At the same time, the infrastructure there is new and the reservoirs are undeveloped and hence the need for MMO services are limited at

Start date Client value (NOK m) 2012 2013 2014 2015 2016 2017 2018

50% 29% 12% 5% 4%

Tie-in from Dagny. 30/01/2013 Statoil 650.00 - 163 163 163 163 - -

Gullfaks South 28/12/2012 Statoil 180.00 - 63 117 - - - -

Ormen Lange/Nyhamna onshore facilities 19/04/2012 Kvaerner 900.00 270 630 - - - - -

Mongstad refinery 12/10/2011 Statoil 360.00 72 144 126 - - - -

Åsgard A and B platforms 20/05/2011 Statoil 650.00 130 195 260 - - - -

Eldfisk field 23/03/2011 ConocoPhillips 1,300.00 585 260 - - - - -

MMO (MOD) 1,057 1,455 666 163 163 - -

White Rose field 10/05/2013 Husky 900.00 - 126 180 180 180 180 54

Solan field development 11/04/2013 Premier Oil £30m - 108 162 - - - -

Frame agreement 14/01/2013 Talisman/ Sinopec - 200 200 200 200 200 -

Shell's offshore facilities in Brunei 27/09/2012 Shell 2,300.00 - 460 460 460 460 460 -

Shetland Gas Plant (SGP). 17/10/2012 Total NOK80 p.a. - 80 80 80 20 - -

Frame agreement 27/06/2012 Exxon NOK170m p.a. 85 170 170 170 170 85 -

Frame agreement 11/04/2012 Badr Petroleum 500.00 75 275 150 - - - -

Ula, Valhall, Skarv, Hod and Tambar fields 30/03/2012 BP 1,000.00 500 1,000 500 - - - -

Frame agreement 12/01/2012 Talisman 870.00 290 290 290 - - - -

Ula, Valhall, Hod and Tambar fields 31/03/2011 BP 250.00 88 - - - - - -

Draugen & Ormen Lange fields 15/12/2010 Shell 1,250.00 500 750 - - - - -

Frame agreement 01/07/2010 Statoil 730.00 183 183 91 - - - -

Snorre A/B, Gullfaks A/B/C, Visund and Åsgard A/B 30/06/2010 Statoil 4,400.00 1,100 1,100 550 - - - -

Subsea control systems 30/03/2010 Petrobras 100.00 33 8 - - - - -

MA-D6 and KG-D6 field developments 19/11/2009 Reliance $25m 50 - - - - - -

MMO (MAIN) 2,903 4,750 2,833 1,090 1,030 925 54

MMO 3,960 6,204 3,499 1,253 1,193 925 54

Start date Client value (NOK m) 2012 2013 2014 2015 2016 2017

Frame agreement 01/11/2012 Statoil NOK80 p.a. - 80 80 - - -

Tyrm and Oselvar fields 02/10/2012 Dong NOK40m p.a. - 40 40 - - -

Wireline tractor services 01/10/2012 Statoil NOK40m p.a. - 100 100 100 100 100

Subsea intervention services 25/07/2012 Total $250m - 750 750 - - -

Jubilee and Tano deepwater fields 03/02/2012 Tullow $4m p.a. 24 24 24 - - -

Frame agreement 12/10/2009 BP GBP10m p.a. 23 - - - - -

WIS 47 994 994 100 100 100


47

best. Hence, Asia-Pacific offers the best area for growth for Aker, although the quality of growth may be an issue. Aker has already tried to enter the after-life field services business in the GoM but did not find traction in the region because of the strong service offering already provided by the incumbents.

The OMA subdivision is primarily based in the NCS and Brazil. Growth in general is dependent on the fleet utilisation rate and the fleet’s expansion.

Outlook: profitability

MMO: From a contract mix perspective, there is a healthy share of pure modification contracts in the MMO segments. These are higher margin contracts as compared to pure maintenance projects and hence provide a positive margin skew to the division. Most of these modification contracts are with Statoil, which has an aggressive production growth and enhanced recovery target. The following table details the EBITDA streams for the MMO contracts currently in the backlog. Our assumptions/estimate for the profit margin for each contract is a function of three factors: 1) contract award date, 2) type and 3) region. Recent contracts, pure modification and non-Asian projects are comparatively higher margin.

Based on this analysis, the intrinsic backlog EBITDA margins should average 6.5% over 2013-2017. We forecast margin compression of 130bp over 2012-15 in the MMO division.


48

MMO Backlog profitability model


WIS: Like MMO, WIS contracts are reimbursable in nature and are also of longer duration. The following table only gives EBITDA streams from the contracts present in the backlog. The intrinsic backlog margin profile is healthy and we estimate that organic margins would average 22% over 2013-15.

WIS backlog profitability model


Start date Client value (NOK m)

2012 2013 2014 2015 2016 2017

Tie-in from Dagny. 30/01/2013 Statoil 650.00 - 15 15 15 15 -

Gullfaks South 28/12/2012 Statoil 180.00 - 6 11 - - -

Ormen Lange/Nyhamna onshore

facilities 19/04/2012 Kvaerner 900.00 26 60 - - - -

Mongstad refinery 12/10/2011 Statoil 360.00 6 12 11 - - -

Åsgard A and B platforms 20/05/2011 Statoil 650.00 12 18 23 - - -

Eldfisk field 23/03/2011 ConocoPhillips 1,300.00 54 24 - - - -

MMO (MOD) 97 135 61 15 15 -

9% 9% 9% 10% 10%

White Rose field 10/05/2013 Husky 900.00

Solan field development 11/04/2013 Premier Oil £30m - 9 14 - - -

Frame agreement 14/01/2013 Talisman/ Sinopec - 17 17 17 17 17

Shell's offshore facilities in Brunei 27/09/2012 Shell 2,300.00 - 30 30 30 30 30

Shetland Gas Plant (SGP) 17/10/2012 Total NOK80 p.a. - 6 6 6 2 -

Frame agreement 27/06/2012 Exxon NOK170m p.a. 6 12 12 12 12 6

Frame agreement 11/04/2012 Badr Petroleum 500.00 5 20 11 - - -

Ula, Valhall, Skarv, Hod and Tambar

fields30/03/2012 BP 1,000.00 38 75 38 - - -

Frame agreement 12/01/2012 Talisman 870.00 21 21 21 - - -

Ula, Valhall, Hod and Tambar fields 31/03/2011 BP 250.00 6 - - - - -

Draugen & Ormen Lange fields 15/12/2010 Shell 1,250.00 35 53 - - - -

Frame agreement 01/07/2010 Statoil 730.00 13 13 6 - - -

Snorre A/B, Gullfaks A/B/C, Visund

and Åsgard A/B 30/06/2010 Statoil 4,400.00 77 77 39 - - -

Subsea control systems 30/03/2010 Petrobras 100.00 2 1 - - - -

MA-D6 and KG-D6 field developments 19/11/2009 Reliance $25m 3 - - - - -

MMO (MAIN) 207 324 179 65 60 53

7% 7% 6% 6% 6% 6%

MMO 304 459 240 80 76 53

8% 7% 7% 6% 6% 6%

Profit recognition

Start date Client value (NOK m)

2012 2013 2014 2015 2016 2017

Frame agreement 01/11/2012 Statoil NOK80 p.a. - 14 14 - - -

Tyrm and Oselvar fields 02/10/2012 Dong NOK40m p.a. - 8 8 - - -

Wireline tractor services 01/10/2012 Statoil NOK40m p.a. - 19 19 19 19 19

Subsea intervention services 25/07/2012 Total $250m - 180 180 - - -

Jubilee and Tano deepwater fields 03/02/2012 Tullow $4m p.a. 6 6 6 - - -

Frame agreement 12/10/2009 BP GBP10m p.a. 5 - - - - -

WIS 11 227 227 19 19 19

23% 23% 23% 19% 19% 19%

Profit recognition


49

Engineering Solutions – broadening of client base


Engineering financial estimates


Aker works as a subcontractor for other EPC companies. The engineering backlog contains a mix of design, FEED and detailed engineering work. The margins on contracts vary between 5-20%, with detailed engineering projects commanding a higher margin than design study and FEED. The division’s business is located in the North Sea (both the UK and Norway) and the company is now expanding into Brazil and the GoM. The division is supported by engineering centres in Malaysia, India, Oslo and Houston.

We expect Engineering Solutions divisional sales to grow at a three-year CAGR of 9% over 2012-15. This would require order intake to average NOK5.9bn pa over the period. In our view, there is significant room for the division to improve in terms of both growth and margins. It currently has a narrow client base and at present is executing contracts for four clients. We think that Aker can successfully replicate the strategy of competitors such as Technip, which has built a strong early engineering service platform.

We expect order intake to average NOK5.6bn pa

Source; Berenberg estimates

NOK mn 2010 2011 2012 2013E 2014E 2015E

3 yr growth

cagr 2012-

15E

Sales 3,514 3,253 4,508 4,822 5,304 5,887 9%

As % group 11% 9% 10% 10% 9% 9% n.a.

Sales growth -7% 39% 7% 10% 11% n.a.

EBITDA 292 374 499 467 636 706 12%

As % group 9% 11% 11% 10% 10% 10% n.a.

EBITDA margin (%) 8% 11% 11% 10% 12% 12% n.a.

0%

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14%

16%

0

2

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6

8

10

12

2013E 2014E 2015E 2016E 2017E


Implied Order Intake Revenue coverage (%, RHS)


50

Backlog maturity model


Intrinsic profitability model


Start date Client value (NOK m) Location 2012 2013 2014 2015 2016

Frame agreement 21/06/2011 ENI 220.00 Norway 80 80 20 - -

sub-surface consultancy services 07/04/2010 BP NOK15 p.a. Noway/ NCS 15 - - - -

sub-surface consultancy services 17/03/2010 Statoil NOK 20m p.a. Global 20 - - - -

Staatsolie refinery expansion project 09/09/2009 Staatsolie NOK 60m p.a. Suriname 60 30 - - -

Draupne field 22/03/2012 Det norske 300.00 Norway/ North Sea 300 - - - -

Mariner field 12/07/2011 Statoil 125.00 Uk/ North Sea 63 - - - -

Hild field 29/09/2011 Total 215.00 Noway/ NCS 118 - - - -

Kebabangan (KBB) Northern Hub

development06/05/2010 Kebabangan 170.00 Malaysia/ South China Sea 43 43 21 - -

Dagny platform 18/02/2013 Statoil 1,400.00 Norway/ North Sea - 210 280 350 560

ENGINEERING 698 363 321 350 560

Start date Client value (NOK m) Location

2012 2013 2014 2015 2016

Frame agreement 21/06/2011 ENI 220.00 Norway 5 5 1 - -

sub-surface consultancy services 07/04/2010 BP NOK15 p.a. Noway/ NCS 1 - - - -

sub-surface consultancy services 17/03/2010 Statoil NOK 20m p.a. Global 1 - - - -

Staatsolie refinery expansion project 09/09/2009 Staatsolie NOK 60m p.a. Suriname 4 2 - - -

Draupne field 22/03/2012 Det norske 300.00 Norway/ North Sea 24 - - - -

Mariner field 12/07/2011 Statoil 125.00 Uk/ North Sea 5 - - - -

Hild field 29/09/2011 Total 215.00 Noway/ NCS 13 - - - -

Kebabangan (KBB) Northern Hub

development06/05/2010 Kebabangan 170.00 Malaysia/ South China Sea 5 5 3 - -

Dagny platform 18/02/2013 Statoil 1,400.00 Norway/ North Sea - 25 34 42 67

ENGINEERING 58 37 37 42 67

8% 10% 12% 12% 12%

Profit recognition


51

Financial forecasts and segment analysis

Income statement

Revenue and earnings forecasts


Aker’s revenue growth is a function of the increase in installed manufacturing capacity for equipment and service bases for after-life field services as well as equipment pricing and contracting fees for services. Given the high level of demand due to the development of deepwater and complex projects in the NCS, Brazil and West Africa in recent years and the scarcity of available space, the pricing of subsea equipment such as high-pressure trees, manifolds and drilling packages for deepwater semisubmersible rigs has steadily increased. Although the company faces rising competition in after-market field services, MMO and WIS, the amount of work is also rising. Similarly, with oil prices showing weakness, oil companies are placing more emphasis and resources in early stage engineering to make sure of project economics.

Aker has exposure to all of these fast-growing product and service lines which should in our view lead to resilience in future earning streams. Aker has been following an aggressive capex and acquisition strategy to expand its geographical footprint. Management is doubling the size of its subsea equipment manufacturing capacity at its Malaysian and Norwegian plants, a project that is due to complete by the end of the year. Similarly it has set up a service base in Malaysia with a view to penetrating the lucrative Asian market. In the long term, it plans to set up its third umbilicals plant in Asia.

Based on the structural trends and Aker’s expansion plans and high backlog revenue visibility, we forecast sales growth at a three-year CAGR of 12.9% over 2013-15 with EBITDA margins averaging 10.4% during the period.

Balance sheet and cash flows

Since 2011, Aker has faced balance sheet stress similar to the rest of the sector, with rising working capital requirements. The net debt has risen from NOK5bn in 2011 to NOK10bn at end-Q1 2013 with a resultant increase in gearing (net debt to equity) to 81%. A tough operating environment, in which the level of prepayments on contracts is falling, is the main reason for the higher working capital levels. Management expects working capital to average 5-6% of sales in the long term. We are more conservative, and for modelling purposes we have assumed a cash conversion cycle to shorten further to -101 days in 2013 from -116 days in 2012 and we expect working capital to average 7% of sales over 2013-17.

2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Sales 33,365 36,474 44,922 50,558 57,415 64,602 72,109 79,427

Sales growth 9% 23% 13% 14% 13% 12% 10%

EBITDA 3,308 3,445 4,739 4,718 6,184 7,148 8,073 9,025

EBITDA margin 9.9% 9.4% 10.5% 9.3% 10.8% 11.1% 11.2% 11.4%

EBIT 2,491 2,569 3,573 3,363 4,733 5,647 6,352 7,141

EBIT margin 7% 7% 8% 7% 8% 9% 9% 9%

EPS 5.17 5.99 8.72 7.88 11.20 13.77 15.48 17.64


52

We expect Aker to maintain a higher capex commitment to meet the growth targets it has set for itself. In 2012, capex outlays stood at NOK3bn, which we expect to rise to NOK3.2bn by 2017. We expect investment to be tilted towards the higher-margin Product Solutions division and expect the return on average capital employed to rise to 17% by 2017 compared to 14% in 2012 after falling off to 10% in 2013 due to quality costs.

Aker has raised its dividend outlays in recent years with the payout rising to 48% in 2012 compared to 38% in 2010. We have assumed a 50% payout over 2013-17.

ROCE and gearing projections

Source; Berenberg estimates

0.0

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40.0

50.0

60.0

70.0

80.0

2012 2013E 2014E 2015E 2016E 2017E

ROACE Net debt to Equity


53

Valuation

Aker has underperformed both market and sector over the past five years. This has been due to recurrent execution problems as the company has implemented its growth strategy. Aker’s margins have trailed those of its competitors, resulting in a valuation discount versus peers. The sharp de-rating which has occurred recently is also due to similar quality issues in the MMO and engineering divisions.

Aker share price versus pan-European market And relative to European OFS sector

Source: Thomson Reuters DataStream, Berenberg estimates

This underperformance has been warranted by Aker’s earnings momentum, both in absolute and relative terms. The following charts highlight Aker’s relative performance both in terms of share price and earnings against broader European Oil Field Services and equipment sector respectively. As can be seen, its share price performance has marginally lagged its earnings performance relative to the sector. This has resulted in an earnings de-rating over the past five years.

Aker price performance and earnings momentum relative to sector


In terms of earnings cyclicality, consensus forecasts have been on a gradually rising trend over the past three years after falling markedly in 2009. A spike in quality costs in Q1 2013 has also caused a downward revision of earnings forecast for the stock. As such, Aker’s forward P/E is a good reflection of absolute value, in our view.


54

Aker share price and earnings rebased Earnings progression versus forward P/E multiple


The absolute forward P/E is therefore a reasonable indicator of value for the stock. On this basis, the current level (approaching 8.9x next year’s earnings) is lower than its 10-year range after excluding the sharp dip during the financial crisis in 2008. This is also true of Aker’s cash flow multiple, shown on the right-hand chart below.

Aker forward P/E multiple (x) Aker forward P/CF multiple (x)


Since 2004, Aker’s forward P/E has typically traded at a 10% premium relative to the sector P/E. Again, it is currently lower than the historical trading range.


55

Aker forward P/E relative to European market P/E versus the European OFS sector


Aker’s absolute dividend yield has been rising consistently since 2010 and is now approaching 5%. Against a backdrop of rising yields across a number of stocks in the sector, its yield relative has been steadily falling.

Aker dividend yield (%) Aker dividend yield versus sector (%)


DCF

Our DCF-based model values Aker at NOK115 per share with a target P/E ratio of 10.3x on 2014 EPS of NOK11.2. We have used a two-stage DCF model to value the company, which we think is suitable considering the high-growth phase of the company which is expected to continue over the next ten years. Our long-term WACC assumption of 10.6% is based on cost of debt at 6% (the current yield on Aker’s long-term bond), cost of equity of 13.5% (a risk-free rate of 3%, Beta of 1.5 and an equity risk premium of 7%) and target gearing of 30%. We have used a terminal growth rate of 1.5% for long-term free cash flow.


56

DCF


DCF Sensitivity analysis


NOK m 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E

Revenues 44922 50558 57415 64602 72109 79427 84987 90936 96392 101211 106272

% growth 23% 13% 14% 13% 12% 10% 7% 7% 6% 5% 5%Terminal growth

rate1.5%

Risk free rate 3.0%

EBIT 3573 3363 4733 5647 6352 7141 7819 8184 8386 8704 9033 Cost of debt 6.0%

EBIT margin 8.0% 6.7% 8.2% 8.7% 8.8% 9.0% 9.2% 9.0% 8.7% 8.6% 8.5% Corporate tax rate 28%

Less adjusted taxes -697 -595 -1015 -1247 -1402 -1597 -1798 -1882 -1929 -2002 -2078 Equity deduction 0%

adjusted Tax rate -20% -18% -21% -22% -22% -22% -23% -23% -23% -23% -23%Equity risk

premium7.0%

NOPLAT 2876 2768 3719 4400 4950 5544 6020 6302 6457 6702 6955 Beta 1.5

NOPLAT margin 6.4% 5.5% 6.5% 6.8% 6.9% 7.0% 7.1% 6.9% 6.7% 6.6% 6.5% Beta post-2022 1.5

Change in working

capital1924 1356 573 1172 892 914 203 559 428 448 471

Cost of equity

2013-2213.5%

Depreciation 1166 1356 1451 1502 1721 1884 1997 2182 2410 2631 2763 WACC 2013-22 11%

dep/sales 2.6% 2.7% 2.5% 2.3% 2.4% 2.4% 2.4% 2.4% 2.5% 2.6% 2.6%Cost of equity

>202213%

Capex 2961 2847 2871 3553 3245 3177 3,145 3,183 3,181 3,340 3,188 WACC > 2022 10.55%

Capex/sales 6.6% 5.6% 5.0% 5.5% 4.5% 4.0% 3.7% 3.5% 3.3% 3.3% 3.0%

FCF -843 -79 1725 1177 2535 3337 4670 4743 5258 5545 6060

Free cash flow valuation

Value 13-22 17,462

Continuing value (>2022) 24,489

Net debt (m | 2012)) 10,147

Unfunded pension liability (m

| 2012) 607

Equity valuation 31,198

Value per share (NOK) 115

Free cash flow to firm model:115 1.0% 1.3% 1.5% 1.8% 2.0%

6.6% 171 178 186 195 205

8.6% 132 136 141 145 150

10.6% 110 112 115 118 121

12.6% 95 97 99 101 103

14.6% 85 86 87 89 90

LT Asset Growth Rate

WA

CC


57

Financials

Profit and loss account

Aker (NOK m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Revenues

Product Solutions 18,398 19,706 25,291 29,856 33,978 38,955 44,212 49,639

Field Life Solutions 11,096 12,178 14,320 15,880 18,134 19,759 21,539 22,920

Engineering 3,514 3,253 4,508 4,822 5,304 5,887 6,358 6,867

Group 33,365 36,474 44,922 50,558 57,415 64,602 72,109 79,427

Cost of sales (14,589) (16,233) (19,910) (22,501) (25,553) (28,752) (32,093) (35,349)

Gross profit 18,776 20,241 25,012 28,057 31,862 35,850 40,016 44,077

SG&A (15,468) (16,796) (20,273) (23,338) (25,678) (28,702) (31,943) (35,052)

EBITDA 3,308 3,445 4,739 4,718 6,184 7,148 8,073 9,025

Depreciation, Amortization & impairment (817) (876) (1,166) (1,356) (1,451) (1,502) (1,721) (1,884)

EBIT 2,491 2,569 3,573 3,363 4,733 5,647 6,352 7,141

Net interest (423) (458) (503) (627) (674) (659) (745) (752)

Other gains & losses (100) (38) (113) (389) - - - -

PBT 1,968 2,073 2,957 2,346 4,059 4,987 5,607 6,390

Taxation (634) (482) (697) (595) (1,015) (1,247) (1,402) (1,597)

Tax rate 32% 23% 24% 25% 25% 25% 25% 25%

Post tax profit 1,334 1,591 2,260 1,751 3,044 3,741 4,205 4,792

Income from continuing operations 1,334 1,591 2,260 1,751 3,044 3,741 4,205 4,792

Income from discontinued operations 676 3,663 - - - - - -

Group net income 2,010 5,254 2,260 1,751 3,044 3,741 4,205 4,792

Minority interests 53 36 11 40 69 85 95 108

Shareholder funds 1,957 5,218 2,249 1,712 2,975 3,656 4,110 4,684



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Balance sheet

Aker (NOK m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Balance sheet (NOK m)

Intangible assets 6,783 6,310 6,884 6,884 6,884 6,884 6,884 6,884

PP&E 7,494 7,409 10,041 12,614 14,034 16,085 17,609 18,902

Interest in associates & JV 424 246 283 283 283 283 283 283

Advances & receivables and other non current assets1,090 1,847 1,979 1,979 1,979 1,979 1,979 1,979

Non Current Assets 15,791 15,812 19,187 21,760 23,180 25,231 26,755 28,048

Inventories 1,686 1,765 2,360 2,651 3,010 3,387 3,781 4,164

Receivables 14,870 12,117 16,524 18,838 21,393 24,248 27,263 30,247

Cash and CE 3,198 1,308 1,214 2,814 2,989 1,984 1,904 2,386

Other current assets 4,381 3,008 930 930 930 930 930 930

Current assets 24,135 18,198 21,028 25,233 28,322 30,549 33,878 37,728

Total assets 39,926 34,010 40,215 46,992 51,502 55,780 60,633 65,776

Liabilties

Debt > 1Yr 7,508 5,371 6,683 11,170 11,170 11,170 11,170 11,170

Provisions/ other 2,349 2,797 3,048 3,048 3,048 3,048 3,048 3,048

Non current liabilities 9,857 8,168 9,731 14,218 14,218 14,218 14,218 14,218

Account payables 16,278 12,934 16,012 17,261 19,602 21,662 24,179 26,633

Debt < 1Yr 716 629 1,008 1,008 1,008 1,008 1,008 1,008

Others 2,936 1,313 1,484 1,484 1,484 1,484 1,484 1,484

Current liabilities 19,930 14,876 18,504 19,753 22,094 24,154 26,671 29,125

Total liabilties 29,787 23,044 28,235 33,971 36,312 38,372 40,889 43,343

Net assets 10,139 10,966 11,980 13,021 15,190 17,408 19,743 22,433

Total Equity 10,139 10,966 11,980 12,646 14,815 17,033 19,368 22,058

Minority interest 189 169 157 166 194 223 254 289

Shareholder's funds 9,950 10,797 11,823 12,480 14,621 16,810 19,115 21,769

Total Liabilities & Equity 39,926 34,010 40,215 46,617 51,127 55,405 60,258 65,401

Net debt/(cash) 5,026 4,692 6,477 9,364 9,189 10,194 10,274 9,792

Capital Employed (reported) 17,171 15,934 20,777 22,617 24,611 27,834 30,250 32,457



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Cash flow statement

Aker (NOK m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Cash flow

EBITDA 4,185 7,445 4,626 4,329 6,184 7,148 8,073 9,025

Adjusted for:

Net interest paid (384) (86) (396) (627) (674) (659) (745) (752)

Share in income of associates & JVs 31 73 (12) - - - - -

(Profit)/loss on asset disposals (156) (4,248) (465) - - - - -

Others 84 (38) 125 375 - - - -

Cash flow from operating activities 3,760 3,146 3,878 4,077 5,510 6,489 7,328 8,274

Changes in working capital (632) 1,203 (1,853) (1,356) (573) (1,172) (892) (914)

Tax paid (997) (522) (242) (595) (1,015) (1,247) (1,402) (1,597)

Net cash generated from operating activities 2,131 3,827 1,783 2,126 3,922 4,070 5,035 5,762

Capex (2,467) (3,385) (2,961) (2,847) (2,871) (3,553) (3,245) (3,177)

Acquisitions (184) (772) 92 (1,046) - - - -

Disposals 766 4,193 1,283 12 - - - -

Others (224) (238) (417) (47) - - - -

Net cash from investing activities (2,109) (202) (2,003) (3,928) (2,871) (3,553) (3,245) (3,177)

Cash flow less capex 22 3,625 (220) (1,802) 1,051 517 1,790 2,585

Net capital increase 56 77 179 - - - - -

Share buyback (57) (79) (121) - - - - -

Net debt issuance 599 (2,106) 1,263 4,487 - - - -

Dividends paid (714) (747) (1,059) (1,085) (876) (1,522) (1,870) (2,103)

others (5) (23) (1) - - - - -

Net cash from financing (121) (2,878) 261 3,402 (876) (1,522) (1,870) (2,103)

FX adjustment and others 111 (432) (135) - - - - -

Change in Cash balance 12 315 (94) 1,600 175 (1,005) (80) 482



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Ratios

Aker (NOK m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Per share data

Diluted shares (m) 277 272 272 272 272 272 272 272

Clean EPS (NOK) diluted 5.17 5.99 8.72 7.88 11.20 13.77 15.48 17.64

Dividend per share (NOK) 2.8 3.9 4.0 3.3 5.7 7.0 7.8 8.9

Cash flow per share (NOK) 7.69 14.08 6.55 7.82 14.43 14.98 18.53 21.21

Debt-adjusted CFPS (NOK) 8.72 15.37 7.96 9.55 16.29 16.80 20.59 23.28

NAV/share (NOK) 35.9 39.7 43.4 45.9 53.8 61.9 70.3 80.1

Financial ratios (%)

Payout ratio (as % EPS) 53 65 46 50 50 50 50 50

ROACE 9.5 11.7 14.4 10.2 15.0 16.2 16.4 17.1

ROE 23 52 22 17 24 25 24 24

Net debt(cash)/equity 50 43 54 74 62 60 53 44

ND/(ND+E) 33 30 35 43 38 37 35 31

Capex/cash flow 116 88 166 134 73 87 64 55

Depreciation/capex 33 26 39 48 51 42 53 59

Valuation ratios

P/E (x) 14.6 14.1 10.8 10.4 7.3 6.0 5.3 4.6

P/CF (x) 9.8 6.0 14.4 10.5 5.7 5.5 4.4 3.9

EV/EBITDA (x) 8.0 8.2 6.9 6.8 5.1 4.6 4.1 3.6

EV/DACF (x) 11.0 6.8 15.1 12.3 7.2 7.2 5.9 5.1

Dividend yield (%) 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1

Price to book (x) 2.1 2.1 2.2 1.8 1.5 1.3 1.2 1.0

Free cash flow yield (%) (1.6) 1.9 (4.6) (3.3) 4.8 2.3 8.1 11.7


Technip SA Oil & Gas

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Quality earnings drive premium valuation

• We initiate coverage on Technip with a Buy recommendation and a price target of EUR106. Our price target is based on a DCF valuation (WACC: 9.3%; terminal growth: 1.5%) and implies 31% upside.

• Integrated player: Technip is one of the most well integrated players and has a diversified value chain with exposure to both onshore and offshore engineering and construction, as well as hardware. In contrast with peers, which have concentrated service portfolios, the company’s revenue streams are geographically well balanced. Technip’s diversification in terms of its services and geographies as well as its strong market positioning on the back of an extensive asset base of vessels, spoolbases and manufacturing plants drive its strong growth momentum.

• Exposure to mega-trends: Technip has a high-tech service/product portfolio in the onshore, offshore and hardware spaces. In onshore, it is strong in the high-tech spectrum of projects such as gas-to-liquid (GTL), LNG and petrochemicals and has exposure to the downstream opportunities that shale developments are likely to create in the US. In offshore it has the highest market share in spar technology, which is used extensively in deepwater areas of the GoM, and it also has exposure to the floating production storage and offloading (FPSO) and floating liquefied natural gas (FLNG) markets. In hardware, Technip is the leader in consolidated flexible pipe manufacturing, which is the system of choice in the key growth market of Brazil. It also has a high market share of 17% in umbilicals. The company’s exposure to these mega-trends, along with its high-tech service portfolio, adds to the resilience of its earnings in our view. We forecast a top-line CAGR of 14% and an EBITDA CAGR of 16% for 2012-15. We are 2% above consensus for the top line and in line with consensus over the period.

• Valuation deserves premium: Technip’s 12-month forward P/E has fallen to 10.8x from 16.7x in early 2012. We believe that the stock deserves a higher multiple based on the structural growth and the underlying quality of its earnings.


Current price

EUR 82.40

Absolute

Price target

EUR 106.00 09/07/2013 Paris Close Market cap EUR 11,551 m Reuters TECF.PA Bloomberg TEC FP Share data

Shares outstanding (m) 110 Enterprise value (EUR m) 11,473 Daily trading volume 400,000

Performance data

High 52 weeks (EUR) 92

Low 52 weeks (EUR) 75 Relative performance to SXXP CAC 40 1 month -1.8 % -3.3 % 3 months -0.2 % -2.8 % 12 months -20.6 % -22.8 %

Key data

Price/book value 2.0 Net gearing -4.4% CAGR sales 2012-2015 14.0% CAGR EPS 2012-2015 18.9%

Business activities: Technip is a global leader in oil field services. It has a strong market position in subsea with a large vessel fleet and flexible pipe exposure. In onshore, Technip provides engineering expertise for design and construction of petrochemical plants and refineries.

10 July 2013


Jaideep Pandya


Y/E 31.12., EUR m 2011 2012 2013E 2014E 2015E

Sales 6,813 8,204 9,540 10,831 12,139

EBITDA 884 1,027 1,158 1,462 1,611

EBIT 710 822 913 1,187 1,313

Clean net income 507 545 624 823 915

Clean EPS 4.69 4.96 5.00 6.66 7.33

DPS 1.58 1.68 1.82 2.40 2.67

EBITDA margin 13.0% 12.5% 12.1% 13.5% 13.3%

EBIT margin 10.4% 10.0% 9.6% 11.0% 10.8%

ROE 11.7% 14.4% 13.4% 13.7% 15.8%

ROACE 19.3% 16.7% 15.7% 18.5% 18.5%

P/E 14.9 16.7 14.2 10.8 9.7

EV/CF (x) 10.9 18.4 11.2 9.4 9.1

EV/EBITDA (x) 7.9 8.8 7.6 5.9 5.3

EV/EBIT (x) 9.8 11.0 9.7 7.3 6.5

EV/Sales(x) 1.0 1.1 0.9 0.8 0.7

Free Cash flow yield 3.9% -0.8% 2.2% 4.1% 4.3%

Dividend yield 2.3% 2.0% 2.2% 3.0% 3.3%



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Company profile

Founded in 1958, Technip is one of Europe’s leading oil services companies, with a focus on the engineering and construction of both onshore and offshore oil and gas facilities. It is also a leading player in the manufacture and installation of subsea umbilicals, risers and flowlines (SURF), which take fluids in both directions between the seabed and the surface. The company currently employs 28,000 people in 50 countries.

Technip is organised along three operating divisions: subsea, onshore and offshore. From 2012, onshore/offshore are now reported on a combined basis. The divisional split of revenues and operating income for 2012 is shown in the following charts.

Revenue split in 2012 (EUR8.2bn) EBIT split in 2012 (EUR822m)

Source: Company data, Berenberg estimates Source: Company data, Berenberg estimates

The asset intensity of each business varies. Subsea and offshore are involved in the manufacturing of flexible (ie steel/plastic composite) pipes and their installation, and require industrial assets (eg manufacturing plants, pipelay vessels and assembly yards). By contrast, Technip’s onshore segment is more involved in engineering, which is an asset-light activity. Construction activity is typically subcontracted with Technip acting as project manager from the drawing board to the delivery of an operational facility. Onshore/offshore activities are usually performed on a lump sum (fixed-price) basis.

Technip’s revenue streams are fairly diversified on a geographic basis, which is in contrast to its position in 2006 when the Middle East accounted for nearly half of revenues. Since then, it has taken a very selective bidding approach in onshore downstream projects in regions with mostly lump sum opportunities. In 2012, Technip’s top client accounted for 11% of sales, its top five nearly 31% and its top 10 were 45% of sales. By project, its top five projects contributed around 18% of revenues and its top 10 projects generated 35% of sales.

Subsea49%

Onshore/Offshore

combined51% Subsea

67%

Onshore/Offshore

combined33%


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Revenue progression by geography


0%

20%

40%

60%

80%

100%

2006 2007 2008 2009 2010 2011 2012 1Q13

Europe/Russia/Central Asia Africa Middle-East Asia-Pacific Americas


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Investment thesis

We initiate coverage on Technip with a Buy recommendation and a price target of EUR106. Our price target is based on a DCF valuation (WACC: 9.3%; terminal growth rate: 1.5%) and offers an upside of 31%.

Technip is a European OFS company listed on the Euronext Paris exchange. The company is involved in the engineering and construction of oil and gas facilities globally. In 2012, it generated EUR8.2bn in revenues, EUR822m in EBIT (10% margin) and EUR542m in net profit. In the past three years, Technip has maintained a revenue growth CAGR of 8.3% and an EBIT growth CAGR of 7%. It has a healthy balance sheet with net cash of EUR183m at end-2012.

Our investment thesis is based on the following four points.

1) Integrated player: Technip is one of the most well integrated players and has a diversified value chain with exposure to both onshore and offshore engineering and construction, as well as hardware. In contrast with peers, which have concentrated service portfolios, Technip’s revenue streams are geographically well balanced. Its diversification in terms of services and geographies as well as its strong market positioning on the back of an extensive asset base of vessels, spoolbases and manufacturing plants drive its strong growth momentum. Its vertical integration into SURF equipment such as umbilicals and flexible pipes partially insulate margins from the tightness in the subsupplier market, while providing it with a competitive edge. We believe the company’s margins are stable due to its market positioning; it has developed expertise in the high-end technology-intensive segments of onshore (such as GTL and LNG) and offshore (ultra-deepwater field development), which have high barriers to entry and strong demand.

2) Exposure to mega-trends: Technip has a high-tech service/product portfolio in the onshore, offshore and hardware spaces. In onshore it is strong in the high-tech spectrum of projects such as GTL, LNG, petrochemicals and refining. Its technology portfolio and downstream positioning in the US have been strengthened by the acquisition of Stone & Webster’s process technologies, which provides Technip exposure to the downstream opportunities that shale developments are likely to create. In offshore, it has the highest market share in spar technology, which is used extensively in deepwater areas of the GoM and it also has exposure to the FPSO and FLNG markets. In hardware, Technip is the leader in consolidated flexible pipe manufacturing, which is the system of choice in the key growth market of Brazil. It also has a high market share of 17% in umbilicals. The company’s exposure to these mega-trends, along with its high-tech service portfolio, add to the resilience of its earnings, in our view.

3) It is different from the past: Technip has undergone restructuring ever since 2006 and now offers structurally high-quality earnings given: 1) its early-cycle engineering focus, where engineering services demand is strong and contracts are cost reimbursable; 2) its lowered exposure to risky lump sum contracts and selective bidding approach in regions with high cost inflation; and 3) its vertical integration in equipment manufacturing which partially insulates margins from the tightness in the subsupplier market, while also providing it with a competitive edge. Moreover, Technip has a conservative profit recognition approach – the company recognises most profits on a project during the last installation phase, when the risky


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procurement work is done. All these factors point to earnings which are of high quality and are relatively less sensitive to oil price fluctuations.

4) Valuation deserves premium: We think that the stock deserves a higher price multiple given the structural growth and the quality of its earnings. Technip’s 12-month forward P/E has fallen to 10.8x from 16.7x in early 2012. At the same time its premium to the European Oil Services & Equipment Index has fallen from 21% at the start of the year to 9%. This is despite strong order intake and management’s consistency in meeting its targets. We also think Technip deserves a management premium considering the restructuring success it has led through identifying and gaining exposure to growth sectors, markets and geographies.

Reasons to buy

Reason #1: its vertical integration, broad service portfolio and capacity expansion in high growth geographies confer strong growth potential Of the three global oil services contractors, Technip is the most diversified and vertically integrated. Technip is unique because of its fully-integrated product offering within the SURF space. It is the leading manufacturer of flexible subsea pipelines and umbilicals along with a large vessel fleet for pipelay installation and subsea field construction. Its broad and diversified product offering has been especially useful in an environment where offshore projects are becoming increasingly complex and in deeper water and farther offshore. Clients are increasingly seeking to give business to integrated service companies which are able to take complete charge of the development of a field. Technip’s subsea installation as well as its hardware manufacturing capabilities contrast with the likes of Wellstream (now part of General Electric), which manufactures flexible pipes but does not install them, or Subsea 7, which focuses only on installation – it recently sold its 49% stake in NKT Flexibles, a Danish manufacturer, which lies a distant third behind Technip and Wellstream.

In future, activity levels are likely to be driven by the key basins for field development. As a result, Technip has been strengthening its local presence in high-potential regional markets such as Africa, the GoM, Brazil and Asia-Pacific. Moreover, the Global Industries deal has added to Technip’s S-lay and offshore heavy-lifting capabilities and, along with its vertically-integrated range of products and services, this will enable it to offer complex project execution from deep water to shore. This is useful in its expansion thrust in Asia-Pacific and West Africa. The company also recently struck a partnership with Heerema through which it will obtain access to its two high-end J-lay and heavy-lift vessels, which will improve its ultra-deepwater pipelay capabilities.

In addition to the acquisition-/partnership-led growth in service capability, since 2007 Technip has been upgrading its fleet of vessels and manufacturing capabilities for flexible pipelines and umbilicals. The number of installation vessels has increased from 18 to 33 (including two under construction), while the number of manufacturing plants for flexible pipes and umbilicals has risen from five to seven (and not including the expansion of existing plants), with the plant at Acu, Brazil currently under construction. Technip’s new vessel, the Deep Orient, will be dedicated to the Asia-Pacific region and will help the company expand its geographical footprint.

Technip’s onshore segment includes both upstream activities and downstream operations. On the upstream side, the company is involved in engineering, production and construction (EPC) and project management for the production and transport of oil and gas, including onshore pipelines, natural gas treatment and LNG plants. In downstream, it is a major player in the development of oil


66

refineries, petrochemical and fertiliser plants. Technip also has experience in GTLs and was involved in Sasol’s Oryx plant in Qatar. It is also a leading proponent of FLNG and is currently executing FEED work for a couple of FLNG projects such as Prelude for Shell in Australia. Through the acquisition of Stone & Webster’s process technologies, Technip has gained expertise in refining and GTL technology, which it earlier lacked, and enhanced its technological expertise in petrochemicals. With the shale developments in the US causing a glut of low-priced gas in the region, complementary downstream industries for transport like LNG and value addition like GTL, fertilisers and petrochemicals are likely to experience substantial progress. With Stone & Webster, Technip is in a much stronger position to capitalise on this upcoming wave of projects.

Reason #2: exposure to mega-trends Technip has a high-tech service/product portfolio in the onshore, offshore and hardware spaces. The high barriers to entry (in the shape of propriety technologies, human expertise and track record/reputation) in this service space add resilience to margins. Moreover, the company has a strong impetus to grow due to the rising complexity of both offshore and onshore projects.

Technip’s onshore segment includes both upstream activities and downstream operations. On the upstream side, Technip is involved in EPC and project management for the production and transport of oil and gas, including onshore pipelines, natural gas treatment and LNG plants. In downstream, it is a major player in the development of oil refineries, petrochemical and fertiliser plants.

Offshore comprises the engineering, development and construction operations in relation to its oil and gas facilities in both shallow water and deep water. These include spars (constructed at its Pori yard in Finland), topsides for production platforms (tensioned leg platforms, or TLPs) and FPSOs. Technip has a strong track record in spars – building 15 out of the total 17 spars worldwide (mainly for use in the GoM). Moreover, Technip has experience in GTLs and was involved in Sasol’s Oryx plant in Qatar.

Its technology portfolio and downstream positioning in the US have been strengthened by the acquisition of Stone & Webster’s process technologies, which exposes Technip to the downstream opportunities that shale developments are likely to create.

In hardware, Technip is the leader in consolidated flexible pipe manufacturing, which is the system of choice in its key growth market of Brazil. It also has a high market share of 17% in umbilicals. The company’s exposure to these mega-trends along with its high-tech service portfolio add resilience to its earnings in our view.


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Reason #3: restructuring – diversified and less sensitive to the oil price Under new leadership, Technip has been rebalancing its portfolio in recent years with respect to the mix between subsea and onshore/offshore construction projects, its geographical exposure and the spread of clients (independents versus integrated majors versus NOCs). Recent acquisitions such as Global Industries and Stone & Webster have filled out its product offering.

Since 2006, Technip’s portfolio restructuring has meant a greater exposure to higher-margin subsea; the share of this in the backlog has risen markedly by 15% since then. Downstream’s (refining, petrochemicals, gas LNG) backlog contribution has shrunk by 25% during the same period (see charts below).

Exposure to higher-margin subsea has risen Downstream exposure has fallen to 40%


Technip has been through a process of lowering the risk in its project backlog. For example, it stopped bidding on a fixed-price basis in areas such as North America, Australia and the UK which have high cost inflation, and has adopted a highly selective approach in the Middle East where contracts are primarily on a lump sum basis. Its geographic realignment has been just as remarkable, with exposure to the Middle East declining by ~35% since 2006 to 13% in 2012.

Technip is playing to its strengths and taking projects which have high engineering and project management content while partnering with South Korean oil services companies which are strong in construction. It is also taking on more early-stage design work (FEED and pre-FEED) through its subsidiary, Genesis. This focus on early-stage engineering reduces any risks further down the line, when the project moves into the full development phase, and improves Technip’s chances of securing the larger EPC segments of projects in the execution phase.


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Reason #4: deserves a valuation premium Our price target of EUR106 is based on a DCF valuation (WACC: 9.3%; terminal growth rate: 1.5%) and implies 31% upside versus yesterday’s close. Our target P/E ratio of 16.1x on our 2014 EPS estimate of EUR6.6 is in line with the historical average trading range of 14-18x.

Technip’s historical P/E trading range

Source: DataStream

Technip has historically traded at a premium to the sector and versus its peer, Saipem, on P/E multiples. On a 12-month forward P/E multiple, its premium to the EU Oil Equipment & Services Index has contracted by 11% to 9% since the start of 2013. This has occurred on the back of oil price uncertainty and postponements of important projects in the GoM. We believe that the stock deserves a higher multiple based on the structural growth and the underlying quality of its earnings, which is the best among its peers. In our view, Technip’s consistency in meeting guidance and management’s targets along with backlog accretion will lead to an expansion of this premium. We think that the company also deserves a management premium considering the restructuring success it has led through identifying and gaining exposure to growth sectors, markets and geographies.

Technip’s premium to the EU Oil Equipment & Services Index has contracted by 11% to 9% on 12-month forward P/E since the start of 2013

Source: DataStream

0

2

4

6

8

10

12

14

16

18

20

2008 2009 2010 2011 2012 2013

12M Forward PE

5

7

9

11

13

15

17

19

2011 2012 2013

Technip EU oil equip & services index


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Technip is cheap versus its peers and its discount on 12-month forward P/E has increased

Source: DataStream

Key catalysts for our investment thesis

1) The translation of the bid pipeline into order intake, especially in areas where it is expanding capacity such as Asia and west Africa.

2) The uptake of flexible solutions outside of Brazil.

3) Any improvement in the fleet utilisation rate of ex-Global Industries vessels.

Main risks to our thesis

5) Further oil price weakness which would give oil companies an incentive to use less efficient but low-cost rigid pipelay systems for subsea field development especially in Brazil, its largest market, would adversely affect growth in Technip’s subsea division and lower capacity utilisation at its manufacturing plants for flexible pipes. In addition, project delays/cancellations in geographies important to Technip like the GoM, Brazil and Asia would have similar implications on revenue growth and margins.

6) A number of subsea contractors are increasing their investment in enhancing their deepwater vessel fleets. If this trend intensifies it would add substantial downward pressure on Technip’s subsea margins and lead to a more than 20bp margin compression, which we are modelling over 2013-17.

7) Recently, BP rejected the spar solution for the Mad Dog 2 project in the GoM. Poor utilisation at Technip’s Pori yard in the long term following this rejection (and if followed by other companies in the GoM) could harm the prospects for its energy and chemicals division.

8

10

12

14

16

18

20

22

2011 2012 2013

Technip Subsea 7 Saipem


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Technip: a well-integrated value chain player

Technip’s core strength lies in being a well-diversified product and service provider with strong market positioning in key geographies. This, in our view, improves the resilience of the company’s earnings and makes them less sensitive to variations in the oil price. In contrast to its closest competitor, Subsea 7, which is only involved in subsea field construction and pipelay, Technip’s service and product portfolio covers subsea, onshore, platform-based offshore construction as well as hardware (flexible pipes and umbilicals). From a geographic perspective, the company has exposure and high market share in large established markets such as Brazil, the GoM, the North Sea and West Africa and is expanding capacity in frontier regions like the underpenetrated deepwater areas of Asia.

On the onshore side, it caters to the high-tech spectrum of projects like GTL, LNG, refining and petrochemical projects. Technip has been strengthening its technology offering through bolt-on acquisitions. Its acquisition of Stone & Webster’s process technologies has strengthened its downstream technology offering as well giving it higher exposure to the downstream market in the US.

Technip’s strength in all these market segments is based on its engineering prowess. The company is very strong in early-stage engineering, which helps it to minimise the chances of cost overruns when a project is in the execution phase, while also improving its success in bidding for the larger EPC segments of the projects. In recent years, Technip has been increasing its early-cycle capex exposure by taking on a number of pre-FEED and FEED work through its subsidiary, Genesis.

Subsea/offshore value chain


Subsea: The subsea construction space is highly consolidated with the top three players, ie Technip, Subsea 7 and Saipem, being the only global subsea construction players. Of the three, Technip is the most diversified and vertically integrated. Once well completion is done and wellheads and blowout preventers have been installed, Technip is involved in the SURF segment of the project. This involves the engineering, manufacturing and installation of equipment connecting the oil and gas wells on the seabed to the surface platform. Technip is unique because of

Hardware

Installation

Pre-FEED & FEED

Key players

1. Technip (Genesis)

2. AMEC

Trunklay

Key players:

Saipem

Allseas

Field to share pipelay:

Key Players:

1. Saipem

2. Allseas

3. Technip

Heavylife Infiled and interfield Pipelay

Key players:

1. Saipem

2. Hreema

3. Subsea 7

4. Technip

Key players:

1. Subsea 7

2. Technip

3. Saipem7

4. McDermott

Subseas constrution,

divings support and ROVS

Key players:

1. Technip

2. Subsea 7

4. Saipem

Umbilicals Flexible pipes

Key player:

1. Technip

2. NKT Flexibles

3. Wellstream

Key players:

Aker Solutions

Technip

Nexans

Oceaneering


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its fully-integrated product offering within the SURF space. It is the leading manufacturer of flexible subsea pipelines, which have a number of advantages over the more conventional steel pipe, and is a major player in umbilicals.

Technip’s broad and diversified product offering has been especially useful in an environment where offshore projects are becoming increasingly complex and in deeper water and farther offshore. Clients are increasingly seeking to give business to integrated services companies, capable of taking complete charge of the development of a field. Technip’s subsea installation as well as its hardware manufacturing capability contrast with the likes of Wellstream (now part of General Electric), which manufactures flexible pipes but does not install them, or Subsea 7, which focuses only on installation – it recently sold its 49% stake in NKT Flexibles, a Danish manufacturer, which lies a distant third behind Technip and Wellstream.

Although Technip prefers to pursue a vertically-integrated approach, it has on occasion supplied the likes of Subsea 7 with flexible pipe products, while in Brazil, it sells pipe directly to Petrobras, which undertakes the installation itself (using vessels on a long-term charter from Technip). In addition to its expertise in flexible pipes, Technip also has a strong asset base to support rigid risers and flowlines systems. These include spooling bases for rigid pipeline manufacturing and rigid pipe installation (in-field, inter-field and field-to-shore). It is interesting to note that the company installs more rigid than flexible pipes. The broadness of its service portfolio adds relative financial stability in an otherwise highly cyclical sector.

In recent years, Technip has been leveraging its independent consulting arm, Genesis, to gain early-stage design exposure (FEED and pre-FEED). This helps to de-risk the portfolio especially further down the line, when the project moves into the full development phase. At the same time, it gives the company an early entry point into a project and improves its bidding position for the larger EPC segments of the overall project.

Onshore value chain


Onshore/offshore: Technip’s onshore segment includes both upstream activities and downstream operations. On the upstream side, Technip is involved in EPC and project management for the production and transport of oil and gas, including onshore pipelines, natural gas treatment and LNG plants. In downstream, it is a major player in the development of oil refineries, petrochemical and fertiliser plants.


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Offshore comprises engineering, development and construction operations in relation to oil and gas facilities in both shallow water and deep water. These include spars (constructed at its Pori yard in Finland), topsides for production platforms (TLPs) and FPSOs.

Technip also has experience in GTLs and was involved in Sasol’s Oryx plant in Qatar. It is also a leading proponent of FLNG and is currently executing FEED work for a couple of FLNG projects such as Prelude for Shell in Australia. It is the transferring of such onshore technology into an offshore environment that was behind Technip’s decision to merge the divisions.

It is worth emphasising that while Technip will assist the client in obtaining external financing (it does not co-invest), design the facility and procure the equipment, it subcontracts the actual construction work and acts as overseer of the project. This subcontracting approach gives Technip the flexibility to operate almost anywhere in the world, providing it is comfortable with its local subcontracting partners. Finally, if required by the client, it will undertake commissioning/start-up services.


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Restructuring – diversified and less sensitive to the oil price

Under new leadership, Technip has been rebalancing its portfolio in recent years, in terms of the mix between subsea and onshore/offshore construction projects, to its geographical exposure and the spread of clients (independents versus integrated majors versus NOCs). Recent acquisitions such as Global Industries and Stone & Webster have filled out its product offering.

Since 2006, portfolio restructuring has meant a greater exposure to higher-margin subsea, whose share in the backlog has risen markedly by 15% since then. Downstream’s (refining, petrochemicals, gas LNG) backlog contribution has shrunk by 25% during the same period (see charts below). Its geographic realignment has also been remarkable, with exposure to the Middle East declining by ~35% over the last five years to 13% in 2012.

Exposure to higher-margin subsea has risen Downstream exposure has fallen to 40%


Through these deep and swift structural changes, Technip’s “shrink-to-grow” strategy has been a success. This is evident from its financial performance and the quality of growth it has achieved over the last five years. At end-Q1 2013, Technip’s backlog was at a record level of EUR14.8bn and its book-to-bill ratio was healthy at 1.4x in 2012. This represents remarkable progress compared to its performance during the adjustment period of 2005-08, when a selective bidding approach led its backlog to fall to EUR7.2bn (a drop of EUR4bn!) at end-2008 and the book-to-bill ratio to average at 0.77x. What is even more interesting is that this growth has also come with an improvement in margins: the EBIT margin has averaged at 10.3% during 2009-2012, which is significantly higher than the 4.3% average over 2004-08. In our view, this reflects management’s correct identification of potential market opportunities and its efficient execution of expansion in tight (improving margins) service areas. In this report, we elaborate further on the strategic transformation Technip has achieved within the onshore and subsea spaces over the last eight years and the financial turnaround it has effected in its segmental performance.


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Sales (EURbn) and growth (%) Order backlog (EURbn) versus book-to-bill


Change in strategy – onshore/offshore

The portfolio reappraisal was triggered by a series of cost overruns and the resulting heavy contract losses in the 2005-06 period, in particular due to a number of large LNG trains in Qatar. Typically, procurement and construction each comprise around 40-50% of the overall value of a lump sum contract (the other components being engineering/design and commissioning/contingencies and profit margin). Technip was caught up in the very high industry cost inflation of the time and in a country where it was not completely familiar with its subcontractors. The fact that the projects were carried out as part of a joint venture (with Japanese player Chiyoda) perhaps added an extra layer of complexity in terms of management, and so the warning signs were perhaps not spotted at an earlier stage.

This highlights the risks of Technip’s asset-light strategy, by definition reliant upon outsourcing and a network of established subcontractors, combined with its lump sum (fixed price) contracting approach. This is particularly the case during an industry up-cycle – most of its international competitors rely more heavily on their own construction yards. While this brings a higher fixed cost base, it does mean that they are more in control of their own destiny when industry conditions are tight.

Nevertheless, Technip has been through a process of lowering the risk on its project backlog. For example, it stopped bidding on a fixed-price basis in countries such as US, Australia and the UK. Moreover, taking on more early-stage design work (FEED and pre-FEED) has served to reduce any risks further down the line, when the project moves into the full development phase.

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Backlog (€bn, LHS) Book-to-bill


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Onshore backlog split evolution


Regional diversification Offshore E&C has seen its historical presence in the North Sea and the GoM shift towards Brazil and Asia. But projects in developing countries are generally more price sensitive and are mainly for lump sum bids. This has necessitated a greater selectivity when it comes to bidding.

While opportunities in the downstream space have increasingly been in the Asia-Pacific region, the low natural gas price in North America is now creating downstream opportunities in that continent, including LNG, GTL, petrochemicals and fertilisers; areas in which Technip has a strong reputation. The recent acquisition of Stone & Webster’s process technologies should enhance its ability to leverage on these opportunities. Meanwhile in Asia, the high gas price and sustained long-term demand are strong drivers for traditional or FLNG projects.

Technip has previously changed its contract strategy in North America and no longer undertakes lump sum contracts. The company sees its initial focus being on petrochemical projects, with particular attention being paid to East Africa following huge offshore natural gas discoveries by the likes of Anadarko and ENI.

Client mix Technip’s onshore client base is well diversified and this highlights its strong relationship with national oil companies such as Saudi Aramco, PetroVietnam and SABIC. It has successfully completed refining projects like the Gdańsk refinery (capacity: 1,500bpd) in Poland in 2010 and the Dung Quat refinery which was completed in 2010 in Vietnam. Technip won a won a refinery project in Vietnam this year, which highlights its growing presence in Asia. In the Middle East, it has executed large lump sum LNG train projects in Qatar and Yemen. The following table shows the downstream projects Technip has successfully completed since 2008.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2006 2007 2008 2009 2010 2011 2012

Gas LNG Refining/ Heavy oil Petrochem Other


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Previous projects by clients

Source: Company press releases

Subsea – the crown jewel

Technip’s strategy in subsea has been to increase its manufacturing capacity and fleet of installation vessels in a more vertically-integrated fashion – very much an asset-heavy approach. Since 2007, it has been upgrading its fleet of vessels and manufacturing capabilities for flexible pipelines and umbilicals. The number of installation vessels has increased from 18 to 33 (including two under construction), while the number of manufacturing plants for flexible pipes and umbilicals has risen from five to seven (not including the expansion of existing plants), with the plant in Acu, Brazil currently under construction.

Activity levels in the future are likely to be driven by the key basins for field development. As a result, Technip has been strengthening its local presence in high-potential regional markets such as Africa, the GoM, Brazil and Asia-Pacific.

The Global Industries deal has also added to Technip’s S-lay and offshore heavy-lifting capabilities. Along with its vertically-integrated range of products and services, this will enable it to offer complex project execution from deep water to shore.

Nevertheless, the installation of larger-diameter trunk lines (mainly for natural gas) is still absent from Technip’s portfolio and will likely require buying the business from one of the two incumbents (Saipem and Allseas), which seems unlikely.

Regional exposure Technip is strong in three key regions: the North Sea, Brazil and the GoM. In the North Sea and the GoM, Technip’s competitive edge is underpinned by: 1) its strong links with Statoil and other international oil companies; 2) an extensive construction and engineering infrastructure comprising of fabrication yards, spoolbases, engineering centres; and 3) the strong commitment of its vessels to these regions. In Brazil, its solid relations with Petrobras along with its pioneering position in flexible pipe manufacturing mean it has a dominant position.

The following chart gives the geographic split of the subsea backlog and how it has changed over the last two years.

Project Country Year Completed

Qatar Gas

LNG trains in Qatar Qatar 2010

Saidi Aramco

Khursaniyah gas plant Saudi Arabia 2010

First train of Khursaniyah Saudi Arabia 2009

SABIC

Yansab ethylene and propylene plant Saudi Arabia 2009

TKOC (JV between Dow & PIC)

Ethylene plant in Shuaiba Kuwait 2008

Yemen LNG

First train of Yemen LNG Yemen 2009

Neste

Neste Oil biodiesel plant Netherlands 2011

Biodiesel plant Singapore 2010

Abu Dhabi Marine Operating Company

(ADMA-OPCO)

lower Zakum gas processing platform UAE 2010

Vietnam Oil & Gas Corp. (Petrovietnam)

Dung Quat refinery Vietnam 2010

Grupa Lotos

Gdansk refinery Poland 2010



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Technip is strengthening its position in Asia-Pacific and in 2011 it inaugurated its Asiaflex plant in Malaysia, which is the only flexible pipe manufacturing facility in the region. At the same time, the company will soon be inducting the Deep Orient into its fleet, a vessel which will be dedicated to projects in Asia-Pacific. This, in combination with its new Asiaflex manufacturing plant in Malaysia and enhanced heavy-lift capabilities, is likely to help Technip gain market share in the region and potentially alter the geographic mix.

Subsea backlog split


In West Africa, Technip is a relatively smaller player. This can be explained by its inability to fully carry out the EPIC project due to its lack of heavy-lifting capabilities and the local content (ie local infrastructure and construction capability), especially in Nigeria. The recent partnership agreement with Heerema and its acquisition of Global Industries should ameliorate this weakness and potentially help Technip gain traction there. These partnerships and acquisitions have enhanced its conventional shallow water field development capabilities.

Based on the “current” backlog for the subsea segment, our bottom-up top-line model based on 47 key projects estimates the following backlog maturity/revenue streams by geography for the subsea division. As can be seen in the chart below, the biggest “intrinsic” revenue contributors will likely remain the North Sea and the GoM, with the North Sea region being the more stable of the two.


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Technip’s subsea segment backlog schedule by geography


In our view, the backlog revenue contributions from Brazil will be relatively stable over the next five years. This is due to Technip’s long-term frame agreements with Petrobras for SURF equipment and vessels. Currently, seven of Technip’s pipelay vessels are on a long-term charter with Petrobras (see table below). Technip has partnered with Norskan, a subsidiary of Norwegian company DOF, in bidding for the USD5bn contract to supply Petrobras with seven pipe-laying support vessels (PLSVs) on a long-term charter. The partnership is in a leading position to win the contract for two of the seven PLSVs. In our view this, along with any additional equipment supply contracts, would support decent top-line growth for Technip in the Brazilian market.

Technip has four vessels on long-term charter with Petrobras

Source: Upstream

Client mix The following table shows the projects successfully executed by Technip over the last six years arranged by major clients. This analysis underscores the company’s competitive positioning based on: 1) its track record; 2) client relationships; and 3) local content in different geographic markets. As can clearly be seen, Technip has done a lot of work for Petrobras and also for Statoil, ENI, BP and Total. It has

-

500

1,000

1,500

2,000

2,500

2012 2013 2014 2015 2016

West Africa North Sea & Canada

GOM and North America Middlle East & Asia pacific

Brazil


79

also done decent work for E&P companies Tullow, Talisman, Murphy and Husky. The company’s track record highlights its strengths in Brazil, the GoM and the North Sea.

Client history highlights strong relationship with Petrobras, Total, BP and ENI


Project Country Year Completed

Petrobras

Normand Progress Long term charter Brazil 2012

Deep Capixaba Brazil 2012

Cascade GoM 2010

Chinook GoM 2010

Tupi gas export pipeline Brazil 2010

PDET Brazil 2007

Statoil

Hyme Norway 2012

Marulk Norway 2011

Sonangol

Gimboa Angola 2008

Total

GirRi Angola 2012

Pazflor Angola 2011

BP

Skarv Norway 2011

Block 31 Angola 2011

ENI

Kitan Australia 2011

ABO Nigeria 2009

Oyo Nigeria 2009

Chevron

Agbami Nigeria 2007

Tullow

Jubilee Ghana 2011

Jubilee FEED Ghana 2010

Talisman

Auk UK North Sea 2010

Burghley UK North Sea 2010

Murphy

Azurite Congo 2008

Husky

White rose North Amethyst Canada 2009


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Subsea E&C

Subsea divisional financial projections

Subsea estimates


Technip’s subsea segment has seen strong growth over the last two years, with its backlog growing to EUR3.2bn in 2012 compared with EUR2.2bn in 2010. Operating margins have declined sequentially since 2008, falling to 14.9% in 2012 compared with 19.5% in 2008. We believe the erosion in margins resulted from the tough contracting environment in Brazil, the Macondo-induced slowdown in the GoM and the low fleet utilisation following the Global Industries acquisition.

Based on our backlog profitability model, which takes into account project phasing and mix, we forecast that the subsea intrinsic backlog margin will remain stable in 2013 and spike in 2014. This bodes well for the company’s overall margin position in the medium term and, in our view, will soften the impact on margins that the more competitive environment is likely to create.

We project a revenue growth CAGR of 16% over 2013-15. This would require an implied order intake of EUR7.7bn a year over this period. With cumulative subsea bid opportunities exceeding USD6bn in Technip’s key geographies, ie the North Sea, the GoM, Brazil and Asia-Pacific, we think that Technip will be able to sustain decent growth in the division. We project a 16% top-line growth CAGR over 2013-15 and an average EBITDA margin of 19.6%.

Implied order intake of EUR7.7bn pa required to achieve a 17% top-line growth CAGR over 2013-15


€ m 2010 2011 2012 2013E 2014E 2015E

3 yr growth

cagr 2012-

15E

Sales 2,732 2,972 4,048 4,830 5,603 6,388 16%

As % group 45% 44% 49% 51% 52% 53% n.a.

Sales growth 9% 36% 19% 16% 14%

EBITDA 586 645 767 880 1,149 1,278 19%

As % group 75% 73% 75% 76% 79% 79% n.a.

EBITDA margin (%) 21.4% 21.7% 19.0% 18.2% 20.5% 20.0% n.a.

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Sales Backlog schedule



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Demand dynamics – global subsea capex expected to grow strongly at a 15.6% CAGR over 2013-15

As the oil industry moves into ever deeper waters and harsher environments, subsea installation is now one of the fastest-growing segments in the oil services industry. Technip is well placed to leverage this growth on the back of its leading market share of around one-third (just ahead of Subsea 7). The company, in our view, has a technological advantage based on its backward integration into flexible pipe manufacturing, in which it has nearly half of the market share. It has been one of the pioneers in flexible pipe technology and entered the market segment via its acquisition of Coflexip in the 1990s. It now has a leading position in the Brazilian market, where Petrobras is a strong proponent of using flexible systems to develop the country’s huge pre-salt oil and gas resources. Technip also has the only flexible pipe manufacturing facility in the Asia-Pacific region, which means it is well positioned to tap the offshore demand in the region.

The long-term subsea picture looks healthy. Despite the Macondo accident, the industry now has the capability (and opportunity) to drill in deeper waters and harsher environments. One lead indicator is the number of offshore rigs operating globally – the more wells drilled, the greater the reserves found that lead to offshore development contracts. Global subsea expenditures have risen by 40% a year over the last two years. Provided that international oil prices remain stable in the medium term, in the absence of any exogenous shocks we expect the subsea oil and gas segment to grow at a five-year CAGR of 15.6% over 2013-17. This will be supported by the west African projects starting to come in and Asia-Pacific experiencing strong growth in the under-penetrated deepwater segment. In the long term, demand for subsea field development will also emanate from gas projects in east Africa.

International offshore rig count has been rising in recent years (ex-North America)

The GoM drilling permits have recovered to post-Macondo levels


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82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12

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Historical performance – financial performance better than peers

As can be seen in the following charts, the subsea division’s order book, operating result and margin have generally risen in recent years. Unsurprisingly, this has coincided with the quantum leap in oil prices and the rising capital intensity of the producing companies. This stalled in 2009-10 in the aftermath of the oil price collapse that accompanied the financial crisis. However, with the backlog reaching a record level at the end of 2011 (and jumping again in Q1 2012), the division should enjoy both rising revenues and margins over the forecast period.

Technip’s subsea divisional backlog has grown at a strong five-year CAGR of 12% over 2007-2011. Growth has picked up sharply since 2010, a trend which has continued into 2013; the Q1 2013 backlog grew at a substantial 13% qoq. This growth in the backlog and top line has occurred on the back of a number of major contract wins in excess of USD1bn over the last three years. These mega-contracts span all the four main offshore oil and gas basins and some of these are given in the table below.

Mega-contract awards in excess of USD1bn

Source: Company press release

Subsea – sales (EURbn) and growth (%) Subsea – order backlog (EURbn) versus book-

to-bill


Subsea – EBIT (EURbn) and margin (%)


Project Country Client Value Award date

Quad 204 UK/ Europe BP 600 Mar'12

Supply of around 1,400 kilometers of

flexible pipes

Brazil/ South

AmericaPetrobas 2100 08/02/12

Contract for the Jack & St-Malo fields GoM Chevron 800 14/01/11

Walker Ridge development GoM Enbridge 600 06/01/11

Aseng field developmentEquitorial Guinea/

West AfricaNoble Energy 560 20/01/10


Mega contract awards in access of $0.5bn

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EBIT (€ bn) EBIT margin (%, RHS)


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Technip’s subsea margins have gradually declined since 2008, a trend in line with the industry. Vessel supply overhang in the low-end space and fleet expansion by Technip and Subsea 7 as well as by second-tier players like McDermott and EMAS have all played a role in margin de-rating for Technip and for the sector. We see this trend persisting in future, especially as oil and gas E&P companies have limited flexibility to stomach cost inflation in the current oil price environment. What is positive is that Technip’s subsea EBIT margins have on average been higher versus its quoted competitors. Technip has generally performed well versus its peers, helped by its backward integration into flexible pipes as well as its good project execution.

Technip’s subsea EBIT margins (%) compare well with peers


Top line – high revenue visibility

Outlook: current projects/backlog analysis In this section we take a closer look at key projects that are in the backlog from the stage of execution and complexity. At the same time, based on the duration and the project stage, we estimate the revenue streams from each individual contract. Our revenue projections for the subsea division are built on this bottom-up approach along without our assessment of key opportunities in core regions (to be discussed in the next section).

Our backlog schedule model highlights that the North Sea and the GoM will be the main contributors to the top line over 2013-15, with the North Sea being the more stable of the two. In the GoM, fewer but larger contracts will be in procurement and installation phase during this period. This includes a EUR800m Jack and St Malo field development and a EUR600m Walker Ridge project. The bulk of revenues from GoM contracts will be recognised in 2013, with a decline next year likely. On the other hand, the projects which are to be executed in the North Sea are smaller but more numerous in nature. They are also installation-focused, which provides overall stability to the revenue stream.

In Brazil, Technip sells flexible pipes directly to Petrobras, which undertakes the installation itself using vessels on long-term charter from Technip and other contractors. This contractual structure explains why subsea revenues from Brazilian contracts will be both sizable and stable until 2016. Technip currently has two further PLSVs under construction which will be on a long-term charter with

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Technip Subsea-7 Acergy Wellstream


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Petrobras once they come in service. This should add further weight and stability to its Brazilian revenues.

The current backlog of EUR14.8bn gives revenue visibility until 2016. We estimate that 41% of the subsea backlog will be recognised in 2013, 33% in 2014, 13% in 2015 and 12% in 2016.


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Backlog maturity revenue model

Source: Berenberg

Major ongoing projects Region Key CustomersValue

(€ m)Start date 2012 2013 2014 2015 2016 2017

SubseaPazflor Angola/ West Africa Total, Statoil, Esso, BP 1100 2009 - - - - - -

Jubilee Ghana/ West Africa Tullow 100 Feb'12 50 50 - - - -

Woodside GWFAustralia/ Asia

Pacific

BHP Billiton Petroleum, BP,

Chevron, Japan Australia LNG,

Shell

25 Feb'12 25 - - - - -

West Delta Deep Marine Phase 7 & 8A Egypt BG Group, Petronas 65 Dec'10 65 - - - - -

Quad 204 UK/ Europe BP 600 Mar'12 70 250 285 - - -

Islay, ETH-PIP1; UK/ Europe Total 70 Sep'10 - - - - - -

Åsgard subsea compression Norway/ Europe Statoil 150 22/02/2012 15 60 75 - - -

Reel-lay tie-backs Mexico/ Americas Shell 0 0 - - - - - -

Brynhild field development Norway/ North Sea Lundin 100 14/11/2011 30 70 - - - -

Gryphon Area Reinstatement Programme (GARP) UK/ North Sea Maersk Oil 40 06/09/2011 25 - - - - -

East Rochele development UK/ North Sea Endeavour Energy 70 27/05/2011 50 - - - - -

Vigdis NE projectNorway/ Norwegian

SeaStatoil 55 09/05/2011 35 - - - - -

EPIC of umbilicals, subsea equipment, flowlines, tie ins etc. Scotland/ North Sea Nexen Petroleum 135 11/01/2012 25 80 20 - - -

Subsea equipment installation and tie-ins, production flowlines, umbilicals Norway/ North Sea Statoil 55 13/01/2012 33 22 - - - -

Supply of around 1,400 kilometers of flexible pipes Brazil/ South America Petrobas 2100 08/02/2012 350 400 425 425 500 -

Two subsea contracts under the Diving Frame Contract Norway/ North Sea Statoil 45 29/02/2012 5 18 23 - - -

Bøyla field development. Norway/ North Sea Marathon Oil Norge 300 20/06/2012 15 80 130 75 - -

Subsea installation contractAustralia/ Asia

PacificApache 50 10/07/2012 8 43 - - - -

Supply & installation of pipelines & umbilicals China/ Asia Pacific CNOOC 110 15/10/2012 - 28 83 - - -

Cardamom field development GoM Shell 25 09/11/2012 - 25 - - - -

Girassol development proj. Phase 2 Angola/ West Africa Total 175 13/11/2012 - 53 123 - - -

Two subsea contracts Mexico PEMEX 105 23/05/2012 50 30 - - - -

development of the Auk North and Burghley fields UK/ North Sea Talisman 40 23/02/2010 20 - - - - -

Nord stream projectBaltic sea (connecting

Russia and germany)Nord Stream 35 18/03/2010 18 - - - - -

Marulk field development Norway/ North Sea Statoil 30 19/05/2010 14 8 - - - -

3 year repair and management agreement UK/ North Sea BP 120 01/07/2010 54 30 - - - -

Umbilical contract UK/ North Sea BP 14 16/07/2010 6 4 - - - -

Snorre project Norway/ North Sea Statoil 23 10/08/2010 10 6 - - - -

Statoil Pipeline Repair Service (PRS) Norway/ North Sea Statoil 19.5 09/11/2011 8 10 - - - -

Causeway development UK/ North Sea Valient 33 24/10/2011 33 - - - - -

Installation contract for development of the Conwy field East Irish Sea EOG 20 10/03/2011 14 - - - - -

EPIC subsea contract for the Gygrid project Norway/ Norwegian

SeaStatoil 90 23/02/2011 63 - - - - -

Aseng field developmentEquitorial Guinea/

West AfricaNoble Energy 560 20/01/2010 100 - - - - -

augmentation pipeline contract at the broom field UK/ North Sea Lundin 21 27/01/2010 - - - - - -

3-yr framework contract for design, fabrication & supply of flexible pipe

products.Norway/ North Sea Statoil 100 22/04/2010 40 10 - - - -

flexible pipe supply contract for the Tupi field Brazil/ Santos basin Petrobras 100 28/04/2010 50 - - - - -

4 year term agreement of pre FEED, FEED, Full EPIC and IRM servicesUK and Norwegian

Continental ShelfBG 250 22/06/2010 90 75 - - - -

Devenick field development UK/ North Sea BP 120 01/07/2010 60 - - - - -

Papa Terra filed development Brazil/ Santos basin Papa Terra 50 21/10/2010 - - - - - -

Umbilicals manufacturing contract GoM Shell 160 10/10/2011 60 20 - - - -

Satah Full Field Development Project UAE ZADCO 175 08/09/2011 13 39 57 66 - -


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Backlog maturity revenue model – continued

Source: Berenberg


(€ m)Start date 2012 2013 2014 2015 2016 2017

SubseaGjøa, Smoothbore Norway/ Europe GDF SUEZ 45 Mar'11 - - - - - -

Contract for the Jack & St-Malo fields GoM Chevron 800 14/01/2011 200 300 200 - - -

Umbilical contract for CLOV field development Angola Acergy 75 12/01/2011 - 75 - - - -

Walker Ridge development GoM Enbridge 600 06/01/2011 100 300 150 - - -

Last option for the Statoil frame contract for diving, pipeline repair,

contingency and modification servicesNorway/ North Sea Statoil 50-80p.a. 06/01/2012 65 65 65 - - -

SURF, Engineering and Project Management Services Global contract Shell 240 23/02/2012 40 50 50 50 50 -

Guara & Lula Nordeste pre-salt field development Brazil/ South America Petrobas 60 27/02/2012 40 - - - - -

Subsea equipment installation at Hadrian South Development GoM Exxon 75 01/03/2012 20 40 - - - -

Development of the Cheviot field Scotland/ North Sea Bluewater Industries 20 29/03/2012 - 20 - - - -

Development of the Lucius fieldGulf of Mexico/ South

AmericaAnadarko 700 05/04/2012 50 300 350 - - -

Flexible pipe supply lump sum contract Australia/ Asia

PacificINPEX 10 11/04/2012 - 10 - - - -

Development of fields: tie back to FPSO Scotland/ North Sea EnQuest 100 25/06/2012 20 50 30 - - -

EPIC contract UAE/ Persian Gulf Dubai Petroleum 100 02/07/2012 60 - - - - -

Aasta Hansteen filed devlopment. Norway/ North Sea Statoil 522.4 11/07/2012 100 250 172 - - -

Greater Stella Area (GSA) development UK/ North Sea Ithaca 184 30/07/2012 50 90 30 - - -

Upper Zakum 750K FEEDUAE/ Middle East &

North Africa Zakum Development Company 87.5 Aug'12 10 78 - - - -

Flexible pipe supply contract Brunei/ Asia Pacific Swiber Offshore Construction 25 23/08/2012 - 25 - - - -

Starfish field Trinidad and Tobago BG 75 06/12/2012 - 25 50 - - -

Balder Phase III development Norway Exxon 50 14/12/2012 - 25 25 - - -

Pipeline installation contract for Discovery’s South Timbalier Block 283

Junction Platform projectGoM Discovery System 50 18/12/2012 - 50 - - - -

EPIC contract for the Juliet project UK/ North Sea GDF SUEZ 25 08/01/2013 - 25 - - - -

EPIC contract for the Gannet F Reinstatement project UK/North Sea Shell 30 06/02/2013 - 30 - - - -

Pipelines stretch from the Malikai tension leg platform site to the Kebabangan

platform.Malaysia Shell 90 15/02/2013 - - 36 54 - -

EPIC contract for two new gas-export lines at the Laila and D12 fields Malaysia Shell 30 18/02/2013 - 15 15 - - -

EPSCI and pre-commissioning for the Moho Nord development project Congo Total 1500 08/04/2013 - 225 300 450 525 -

Gullfaks field: removal and replacement of the two oil-loading systems Norway/ North Sea Statoil 40 07/05/2013 - 12 28 - - -

Subsea tieback of the South White Rose Extension field Canada Husky 200 08/05/2013 - 50 120 30 - -

Norne Field developmentNorway/ Norwegian

SeaStatoil 40 14/05/2013 - 12 28 - - -

Subsea Revenues 2,258 3,530 2,868 1,150 1,075 -


87

Project pipeline by region

Brazil Since the discovery of pre-salt reserves in 2007, Petrobras has implemented an aggressive growth plan with a focus on ramping up production sharply. Currently, a number of FPSO-based field developments are either in the FEED or tendering stage for the eight major fields in the Santos basin, ie Lara, Cernambi, Guara, Parati, Bem-Te-Vi, Carioca and Jupiter. These fields together are estimated to potentially hold more than 50bn boe of oil and gas.

Petrobras’ business plan for the 2013-17 period cuts its medium-term (2016) and long-term (2020) production targets for Brazilian production. The new output goals, Petrobras’ new CEO insists, have been formulated on a more conservative basis. Nevertheless, they still imply a doubling of oil and gas production by the end of the decade. This suggests that activity levels are set to remain high despite concerns over the time taken by Petrobras to formalise the contracting of equipment deemed crucial for the development of its pre-salt assets in the Santos basin. Under the latest business plan announced by Petrobras, investment outlays to developing Brazil’s pre-salt oil and gas resources have been raised to USD236.7bn over the five-year period (2013-17).

Over 2013-17, these projects will require around 6,000km of umbilicals and 5,200km of flexible pipes. Technip’s Brazilian flexible pipe manufacturing plant, Flexibras, currently has a capacity of 450km/per year. It is also constructing a second flexible pipe plant in the country. At the same time Technip’s subsidiary, Duco, which manufactures umbilicals, is set to construct an umbilicals plant in Brazil. In our view, Technip’s strong local content and its long track record in working with Petrobras puts it at an advantage to capitalise on the high demand for equipment and installation vessels to develop these pre-salt resources.

Petrobras’ demand for umbilicals and flexible pipes over 2012-17


The table below lists the upcoming big projects in Brazil which are in the initial development stage or have a firm commitment. It represents a strong bid pipeline for Technip in the medium to long term.

0

200

400

600

800

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1200

1400

1600

1800

2012 2013 2014 2015 2016 2017

Umbilicals (km) Flexible pipes (km)


88

Brazilian project pipeline

Source: Instok

Next big projects

The North Sea Around one-third of Technip’s fleet has been operating in the North Sea region over the last 12 months, executing SURF and tie-back projects. There has been strong demand for these types of work in both the UK and Norwegian areas of the North Sea. The UK North Sea saw a record USD11.4bn of development capex in 2012, which is widely expected to rise to more than USD13bn this year. In Norway, the rise in demand for greenfield development and the need to reverse high decline rates at mature fields is being led by Statoil, which has an aggressive production target of 2.5mbd by 2020. This includes greenfield developments in the Norwegian Sea and the Barents Sea like Aasta Hansteen, Goliat and Skrugard and brownfield projects like Asgard.

The following table has a comprehensive list of projects which will be executed by Technip over the next 5-10 years in the western European continental shelf. Although we do see competitors rising on the fringes, most of the SURF work will be shared between Technip and Subsea 7 considering the fleet’s scale, the supporting resources and their experience in the region.

Project Dev. Phase Operators

Eight Pre-salt FPSOs (Lula, Iara, Carcara fields) Tendering/Under Construction Petrobras

Atlanta TenderingQueiroz Galvao

Exploration &

Transfer of Rights Area Phase I (Franco, Nordeste de Tupi)Four converted 150,000 b/d FPSOs

connected to subsea wellsPetrobras

Peregrino Phase II FEED Statoil

Carioca FEED Petrobras

Cernambi (formerly Iracema) Tendering/Under Construction Petrobras


89

Project pipeline

Source: Instok

The GoM What sets Technip apart is its strong position in the GoM, where it has executed projects like Perdido and Galapagos; we estimate that the region forms around 20% of its subsea backlog. Its work has included supplying spar and subsea installation services. The company’s important vessels, like Deep Blue, serve the North Sea, the GoM and Brazil at different times of the year and based on weather conditions. Technip faces local, relatively smaller and less experienced competitors like McDermott in the region. The GoM is the main market for Technip’s spar platform.

Similar to the surge in activity in the North Sea region, the GoM has seen a rise in exploration and development. The following table gives the projects near and after final investment decision (FID). Looking at the field development details and Technip’s contracting position in these projects, we estimate that the region represents a strong bidding opportunity for the company over 2013-17.


Kraken Tendering EnQuest

Rosebank FEED Chevron

Greater Lancaster Area (GLA) Conceptual Hurricane Exploration

Catcher Conceptual Premier Oil

Bressay FEED Statoil

Mariner FEED Statoil

Western Isles Under ConstructionDana Petroleum


15/5-2 Eirin PDO submited last year Statoil

16/1-8. PDO submited Lundin

16/1-9 PDO submited Det norske

oljeselskap ASA

17/12-1 Bream PDO submited BG Norge AS

24/6-1 Peik PDO submited Centrica Resources

(Norge)

24/9-9 S Bøyla PDO submited Marathon Oil Norge

AS

25/2-10 S PDO submited Statoil

25/11-16 Svalin PDO submited Statoil

31/2-N-11 H PDO submited Statoil

34/8-13 A PDO submited Statoil

6406/9-1 Linnorm PDO submited A/S Norske Shell


90

GoM project pipeline

Source: Instok, Berenberg

Profitability

Since 2008, a weaker contracting position has led to a deterioration in Technip’s operating profits from the subsea division. Operating margins further deteriorated in 2012 compared to 2011 due to the low utilisation rate of the former Global Industries vessels. However, on a quarterly basis, there is an improvement with margins increasing from 14.7% in Q1 2012 to 14.9% in Q4 2012. Greater activity in the North Sea and an improvement in the GoM is helping Technip find more work for its vessels and its manufacturing facilities. In addition, despite lower operating margins in 2012 over 2011, EBIT grew by 21% yoy due to the positive volume impact. We anticipate this trend will gradually continue in 2013 due to a positive offshore E&C outlook, which should boost overall fleet utilisation rates. The contract mix and our outlook for the subsea developments in Technip’s core markets underpin our estimates. In this section, we elaborate on our earning estimates for the division in greater detail.

Timing of profitability Technip follows the percentage of completion method to recognise revenues. However, unlike Saipem, profit recognition is delayed as the bulk of the profits are recognised in the last installation phase of a typical EPIC contract. Therefore, the contractual stage mix as well as the profitability profile of its projects in any given year are the key determinants of the overall divisional margin. The second graph on the following page gives the evolution of Technip’s subsea contracts currently in the backlog based the stage of work – ie engineering, procurement and installation/construction.

In 2013, a number of contracts, especially those in the North Sea, will be in procurement and engineering phase. These contracts were awarded in the early part of 2012 and will be in the low profitability phase in the current year. However, in 2014 the divisional marginal profile will be supported by the installation work on large USD500m+ contracts like the Lucius field development, Walker Ridge, and the Jack and St Malo field developments in the GoM.


Tiber Conseptual BP

Vito Shell

Vicksburg Shell

Cascade/Chinook Phase II & III Petrobras

Stones FEED Shell

Appomattox Conceptual, Pre-FEED Shell

Gunflint/ Freedom Conceptual Noble Energy

Deep Blue N/A Noble Energy

Pony /Knotty Head FEED HESS/Nexen

Julia Feed ExxonMobil

Hadrian North Conceptual ExxonMobil

Kaskida Conceptual BP

Buckskin/Moccasin Chevron


91

The following chart show the intrinsic backlog margin for the subsea division. As can be seen, the intrinsic margin spikes up in 2014 as a greater number of projects reach the installation phase. However, the margin profile will naturally stabilise as the company wins more contracts over the next 24 months. Based on the backlog analysis and the subsea bidding opportunities available to Technip over 2013-17, we estimate EBITDA margins to average at 19.2% and expect an 18% EBITDA growth CAGR for the division.

Organic backlog margin


Offshore Backlog revenue maturity by project stage (EURm)


0%

5%

10%

15%

20%

25%

30%

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2012 2013 2014 2015

0

500

1,000

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CY13 CY14 CY15

Engineering Procurement Installation


92

Onshore/offshore E&C

Onshore/offshore divisional financial projections

Onshore/offshore estimates


Since 2008, the combined backlog in onshore/offshore has grown strongly, rising to EUR7.8bn at the end of Q1 2013 from EUR3.7bn at the end of 2008. During this period, the company won large (EUR0.5bn+) offshore platform projects like the Mariscal Sucre development (PDVSA, Venezuela), Lucius Spar (Anadarko, Mexico) and the Malikai Tension Leg Platform. On the downstream side, refining and gas LNG formed the bulk of the order intake. Technip’s enhanced technology portfolio through its Stone & Webster acquisition should also help it capture opportunities within the petrochemicals and fertilisers space. The company also recently won the Yamal LNG plant contract which is estimated to cost around USD4bn, while the overall project could cost ~USD20bn. This contract, along with Technip’s long track record within LNG and the two FLNG FEED contracts it is executing for the Shell Prelude project and another one for Petronas, highlight its strength in the segment. The potential onshore and FLNG opportunities to tap the gas resources in east Africa could be possible growth catalysts for the onshore/offshore division in the medium term.

We project onshore/offshore divisional sales growing at a three-year CAGR of 11% over 2013-15. With a backlog revenue contribution of EUR3.8bn in 2013 and EUR1.68bn in 2014, this implies high revenue coverage of 82% and 54%, respectively. The implied order intake required in 2013 is EUR3.5bn with an average of EUR5.8bn per year needed over 2013-17. In Q1 2013, the order intake stood at EUR980m and considering the large Yamal LNG contract award since then, we are confident that in 2013 the company will achieve the required order intake.

€ m 2010 2011 2012 2013E 2014E 2015E

3 yr growth

cagr 2012-

15E

Sales 3,350 3,841 4,156 4,710 5,228 5,751 11%

As % group 55% 56% 51% 49% 48% 47% n.a.

Sales growth 15% 8% 13% 11% 10%

EBITDA 235 301 321 353 392 417 9%

As % group 30% 34% 31% 31% 27% 26% n.a.

EBITDA margin (%) 7.0% 7.8% 7.7% 7.5% 7.5% 7.3% n.a.


93

Implied order intake would need to average at EUR5.8bn per year to generate a 15% top-line growth CAGR over 2013-17


Historical performance – performing well despite the South Korean competitors

Since the cost overruns on major onshore projects in the Middle East, Technip has followed an aggressive portfolio realignment with less attention on countries with a lump sum focus. It has shifted its focus to the least-risky engineering part of onshore contracts, which are usually on a cost-plus basis. With this preference for quality over growth, Technip has been able to raise its onshore/offshore EBITDA margin from negative levels in 2007 to ~7.5% in 2012.

This portfolio realignment both in terms of project type and geography has helped Technip to achieve a strong order intake in 2012. This is in contrast to poor performance by peers such as Saipem and Petrofac, which have high exposure to the Middle East. Technip’s excellence in engineering has helped it win projects by partnering with service contractors that specialise in construction.

Onshore/offshore – sales (EURbn) and growth (%)

Onshore/offshore – order backlog (EURbn) versus book-to-bill


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90%

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7,000

8,000

2013E 2014E 2015E 2016E 2017E


Implied order intake Coverage (%, RHS)

-30%

-20%

-10%

0%

10%

20%

30%

40%

0

1

2

3

4

5

6

2004 2005 2006 2007 2008 2009 2010 2011 2012

Sales (€ bn) Sales growth (%, RHS)

0.0

0.5

1.0

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2.0

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0.0

2.0

4.0

6.0

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2004 2005 2006 2007 2008 2009 2010 2011 2012

Backlog (€ bn) Book-to-bill (RHS)


94

Onshore/offshore – EBIT (EURbn) and margin (%)


Demand dynamics

Over the last five years, the downstream oil and gas sector has exhibited strong growth in high-demand regions such Asia, the Middle East and Latin America. However, the structural adjustment has continued in Europe and the US with the closure of refineries across the region. However, shale developments in the US and the resulting low gas feed stock prices are likely to create opportunities for petrochemical, LNG, GTL and fertiliser production in the North American region. In Brazil, Petrobras has budgeted USD51.7bn for the downstream projects that are currently being implemented, which includes expansions at the Abreu and Lima refinery (to be partially ready by 2014).

Major OPEC countries are ramping up onshore E&C spending in the Middle East to boost their oil and gas production and refining capacity, as well as diversifying their petrochemical activities. Within downstream, refining will likely be the area with the fastest influx of capex. This trend is being encouraged by the rising domestic demand for refined oil products in these OPEC countries and the lack of export constraints on refined products in contrast to crude oil. A number of major refining projects are likely to be tendered in Saudi Arabia, Iraq and Kuwait in 2013.

Petrochemical projects in the Middle East, on the other hand, are facing medium-term bottlenecks from a shortage of new gas supplies. This has pushed back the development of important new chemical projects. A number of OPEC countries including Oman are set to invest strongly to enhance their gas production, but at least in 2013 gas constraints will likely limit capex on new petrochemical plants and extensions of existing ones. MEED estimates that only USD9.9bn worth of chemical projects are currently in the FEED, design and tendering phase in the Middle East and North Africa. This is sharply lower than the awards in 2012.

Top-line outlook

The following table shows our revenue estimates for the onshore/offshore projects currently in the backlog on a sequential basis. The current project backlog of EUR8bn provides revenue visibility until 2016. 45%, 29% and 18% of the backlog will be recognised as revenues in 2013, 2014 and 2015 respectively.

Given that 45% of the backlog will be maturing this year, Technip will need to win EUR3.5bn of new projects. In Q1 2013, it had already won EUR900m of orders and given the strong bid pipeline, we think that the order intake will likely be enough to meet our top-line estimates.

In the next section, we look at potential downstream awards in the four key regions of Brazil, Asia, the Middle East and the US, and assess Technip’s chances of

-4%

-2%

0%

2%

4%

6%

8%

-0.2

-0.1

0.0

0.1

0.2

0.3

0.4

2004 2005 2006 2007 2008 2009 2010 2011 2012

EBIT (€ bn) EBIT margin (%, RHS)


95

chances in successfully bidding for them. This would close the loop and help us give a holistic picture on revenue growth.


96

Backlog maturity revenue model

Source: Berenberg


(€ m)Start date 2012 2013 2014 2015 2016

OffshoreMartin Linge project Norway Total 591 21/12/2012 - 59 177 236 118

Akpo FPSO Nigeria/ West Africa Total 422 May'12 21 105 190 105 -

Prelude FLNG Australia/ Asia Pacific Shell 750 Jun'12 38 188 338 188 -

FLNG FEED Malaysia/ Asia Pacific Petronas 350 05/06/2012 50 200 100 - -

Khafji Crude Related Offshore, Saudi Arabia/ Middle

East & North Africa

Aramco Gulf Operations, Kuwait

Gulf Oil Company; 312.5 3Q10 100 120 - - -

KGOC Export PipelineSaudi Arabia/ Middle

East & North Africa Kuwait Gulf Oil Company (KOGAS) 25 Feb'12 3 10 13 - -

Design Wheatstone offshore gas processing platform Australia/ Asia PacificDaewoo Shipbuilding and Marine

Engineering90 26/01/2012 90 - - - -

Marsical Sucre development Venezuela PDVSA 1000 17/11/2010 300 300 - - -

Lucius Development project Spar Mexico Anadarko 1200 19/12/2011 350 650 - - -

Gendalo and Gehem fields Indonesia Chevron 100 23/03/2011 100 - - - -

HEJRE project development Denmark/ North Sea Dong E&P, Bayerngas 240 28/02/2012 100 60 - - -

Total EPIC - spar Norway/ North Sea Statoil 50 08/03/2012 50 - - - -

FEED contractGulf of Mexico/ South

AmericaBP 100 30/04/2012 20 80 - - -

Services contract for engineering, procurement, construction, installation and

commissioning for FLNG facilityMalaysia/ Asia Pacific Petronas 350 05/06/2012 50 100 150 100 -

Service contract for Ichthys FPSO unit Australia/ Asia PacificDaewoo Shipbuilding & Marine

Engineering210 22/06/2012 30 80 100 - -

Heera Redevelopment (HRD) process platform project India ONGC 50 04/02/2013 - 13 23 15 -

EPC of a tension leg platform (TLP) for the TLP Malikai Deepwater Project Malaysia Shell 400 08/02/2013 - 100 200 100 -

Engineering & modification services for the existing Greater Plutonio and Plutao,

Saturno, Venus and Marte (PSVM) floating production storage and offloading

(FPSO) units, located in Blocks 18 and 31

Angola BP 175 20/02/2013 - 35 35 35 35

P-76 FPSO Brazil Petrobras 375 17/04/2013 - 38 75 94 113

Offshore Revenues 1,301 2,137 1,400 873 266


97

Backlog maturity revenue model – continued

Source: Berenberg


(€ m)Start date 2012 2013 2014 2015 2016

Onshore

Fertilizer FEED Gabon/ West AfricaOlam International, TATA

Chemicals50 Sep'11 50 - - - -

ASAB 3 project, UAE/ Middle East &

North Africa Abu Dhabi Gas Industries 324 20th Nov'09 105 122 - - -

Horizon Oil Sands facility CanadaCanadian Natural Resources

Limited100 02/05/2011 25 45 25 - -

Phase 1 of a heavy residue hydrocracking complex Bulgaria/ Europe Lukoil Neftochim Burgas 600 25/01/2012 45 135 195 225 -

FPSO unit & central processing unit Australia/ Asia Pacific INPEX Corporation 210 18/09/2012 4 12 47 68 79

FEED services for two refineriesKazakhstan/ Asia

Pacific

Pavlodar Oil Chemistry Refinery,

Petrokazakhstan Oil Product50 26/09/2012 4 46 - - -

EPC of a petrochemical complex Mexico/ South America Braksem Idesa 840 04/10/2012 17 67 336 420 -

hydrotreater project in the Visakh refinery India Hindustan Petroleum 50 01/04/2010 15 - - - -

hydrotreater project in the Visakh refinery India Hindustan Petroleum 65 01/04/2010 20 - - - -

Hydrocracker of the Normandy refinery France Total 20 01/12/2010 8 10 - - -

Refurbishment & revamping of the Algiers refinery Algeria Sonatrach 709 02/12/2010 284 355 - - -

Phase 1 of heavy residue hydrocracking complex BulgariaBurgasnefteproekt EOOD (a Lukoil

engineering subsidiary) 70 21/01/2011 36 21 - - -

PMP onshore facilities Qatar Qatar gas 160 26/02/2010 50 60 - - -

3 contracts for refinery units IndiaMangalore Refinery &

Petrochemicals Ltd. (MRPL)25 08/06/2010 - - - - -

two hydrogen plants at their refineries in Memphis, Tennessee and McKee, Texas US Valero 20 30/09/2010 20 - - - -

Kharir Power Plant Project Yemen Total 1000 10/10/2010 550 - - - -

Uzbekistan GTL Uzbekistan Uzbekistan GTL LLC 250 13/12/2012 250 - - - -

Michelin elastomer composite plant Thailand Michelin Siam 20 15/11/2011 20 - - - -

Marsical Sucre Field development Venezuela PDVSA 800 28/09/2011 300 400 - - -

Petrobras grassroot fertilizer complex Brazil Petrobras 50 19/09/2011 50 - - - -

Amonia Urea fertilizer facility Gabon Gabon Fertilizer Company 75 15/09/2011 - - 75 - -

Macedon Gas proj Australia BHP 200 04/05/2011 100 100 - - -

Ethylene XXI project Mexico Braskem-Idesa 150 31/03/2011 - - - - -

FEED contract Malaysia/ Asia Pacific Petronas 50 13/03/2012 15 35 - - -

Front-end engineering design and the first phase of project management

consultancy services

Venezuela/ South

AmericaPetrocarabobo 50 02/04/2012 15 35 - - -

Two front end engineering and design contracts for plants Russia JSC Sibur Holding 150 27/06/2012 60 90 - - -

Supply of basic engineering package and an engineering and procurement services

contract for the ROGC plantIndia/ Asia Pacific Reliance Industries 150 04/07/2012 - 130 20 - -

Engineering, procurement and construction of an Halobutyl facilitySaudi Arabia/ Middle

EastAl-Jubail Petrochemical Company 500 23/07/2012 30 200 200 120 -

FEED for new ammonia plant US The Mosaic Company 25 03/01/2013 - 25 - - -

25 million tons per year latest-generation purified terephthalic acid (PTA) unit India JBF Petrochemicals Ltd. 175 24/01/2013 50 80 45 - -

Westlake Chemical's ethylene plant expansion in Kentucky US Westlake Chemical Corporation 50 29/01/2013 - 20 30 - -

contract for revamp of one of the conversion unit of the Ing. Héctor R. Lara Sosa

refineryMexico PEMEX $40m 13/02/2013 - 9 21 - -

Yamal LNG project Russia NOVATEK (80%) and TOTAL (20%), 2400 02/04/2013 - 240 720 720 720

EPC, pre-commissioning as well as commissioning & start-up assistance for

modification of the #3 sulfur recovery unit (SRU) of Bahrain refineryBahrain BAPCO 20 15/04/2013 - 6 14 - -

Onshore Revenues 2,123 2,242 1,728 1,553 799


98

Future growth

BRIC The BRIC region, due to the cumulative size of its economy, growth prospects and policy incentives, will likely see strong development in the downstream sector with the sanctioning of major refining and petrochemicals projects over the next five years.

In contrast, overcapacity and weak margins mean both Brazil and China have yet to achieve self-sufficiency in refined products. Chinese NOCs CNOOC and Sinopec are leading the charge in achieving the country’s aim of raising domestic oil and gas production to 15mbd by 2015 from 12mbd in 2011. In Russia, the administration is encouraging upgrades at its refineries through the implementation of a “60-65%” tax regime (in late 2011), which gives a tax advantage to the production of highly refined distillates. India is aiming to expand its refining capacity to 240m tonnes per year from 12mbd in 2011, in order to meet the growing domestic demand while maintaining its strong export capacity. This trend across the BRIC region is visible in the number of refining projects under construction and those in the evaluation phase (see the table on page 50).

The Middle East and North Africa The table on page 50 shows the petrochemical and refining projects which are currently in the pre-FID stage and will likely be sanctioned in the current year to start up by 2017. Technip’s major refining projects worth over USD10bn include the Nasriya refinery in Iraq and the Al Zour refinery in Kuwait. On the petrochemicals side, apart from the Al Gharbia refinery in the UAE with a total budget of USD20bn, smaller aromatic projects are likely to be approved in 2013.


99

Major projects to be tendered and awarded in 2013

Source: MEED

Project Region Client Status Completion dateBudget

($m)

Trans Saharan Gas pipeline Algeria Sonatrach Study 2016 2100

LNG Import Terminal Bahrain Bahrain Petroleum Company Main Contract prequalification 2017 1000

Nasiriya Integrated Project Iraq Iraq Oil Ministry Main Contract prequalification 2017 12000

Karbala Refinery Iraq South Refineries Company Feed completed 2017 7800

Kirkuk Refinery Iraq North Refinery Company Feed completed 2017 6000

Missan Refinery Iraq Missan Refinery Company Feed completed 2017 2500

Mosul Refinery Iraq Iraq Oil Ministry Feed completed 2017 2000

Clean Fuel project KuwaitKuwait National Petroleum

Company (KNPC)Main Contract prequalification 2018 18500

New refinery Project at Al Zour Kuwait KNPC Main Contract prequalification 2018 15000

Fifth Gas Processing Train Kuwait KNPC Feed completed 2017 1000

Gathering centre 29 Kuwait Kuwait Oil Company Study 2016 500

Khazzan tight gas

developmentOman BP Main Contract prequalification 2017 15000

Duqm Refinery Petrochemicals

projectOman

JV b/w Oman Oil Company &

Abu Dhabi International

Petroleum Investment Company

Study end-2017 8000

Rub al Khali development: Gas

treatment plantSaudi Arabia Saudi Aramco Study 2017 4000

Ras Tanura clean Fuels

ProjectSaudi Arabia South Rub al-Khali Company Main Contract prequalification 2016 500

Fujairah Refinery UAEInternational Petroleum

Investment CompanyFEED 2017 3500

Nasr Field Development UAEAbu Dhabi Marine Operating

Company (Adma-Opco)FEED 2018 2000

Fujairah LNG regasification

facilityUAE Emirates LNG Study 2017 350

Khor al Zubair fertilizer

complexIraq State Company for Fertilisers Main contract bid 01/02/2015 150

East Baghdad acid plant Iraq Midland Oil Company Main contract bid 01/06/2015 30

Ethyl benzene & Styrene

monomer plantEgypt E-Styrenics FEED 01/10/2015 250

Jubail MethylMethaacrylate

and Polymethacrylate plantsSaudi Arabia Sabic/ Lucite FEED 01/10/2016 500

Ras Laffan Olefins complex Qatar Qatar Petroleum/ Shell Main contract PQ 01/10/2017 6400

Al Gharbia chemicals industrial UAE Tacaamol Study 01/10/2017 20000

Source: MEED

Major Projects to be tendered and awarded in 2013


100

Profitability

After facing execution issues in LNG projects in the Middle East in 2007, Technip successfully altered its geographic mix and project profile. This meant playing more to its strengths and focusing on the early stages of a project to leverage on its strong engineering and technology portfolio. The company has also sharply lowered its exposure to the Middle East, where strong NOCs coupled with South Korean and local players have largely commoditised the onshore E&C space. Instead, Technip has positioned itself well in the US and in Asia-Pacific countries like Australia. The acquisition of major downstream technology player Stone & Webster has strengthened its technology portfolio.

This restructuring has had a positive impact on onshore margins. This is in contrast to other onshore European players like Saipem and Tecnicas Reunidas which have faced margin pressure over the last two years due to their high exposure to the Middle East.

In this section we discuss margin progression for the onshore/offshore division based on the mix of project stages and project types for the backlog over the next four years to estimate the intrinsic margin for the backlog. We then analyse the margin profile of the bidding opportunities available to Technip in the onshore space and use this to give our margin and earning growth estimates for the next three years.

The timing of profitability The graph on the next page shows the mix of backlog contracts for the onshore and offshore divisions in terms of their stage of completion. As can be seen in the table, both 2013 and 214 will not be great in terms of their project stage mix. This is because in 2013, a number of projects will be in the engineering and procurement phase and the same is true for 2014.

Based on a project-by-project earnings stream analysis of the backlog, we estimate the intrinsic backlog margin will average at 12% over 2013-17. The chart on page 53 shows the intrinsic margin evolution. The end margins will become subdued as Technip wins further contracts over the next 24 months. Based on the bidding opportunity over 2013-17 and the margin profile of these projects, we estimate the onshore/offshore operating margins will average at 7.4% during this period.

Onshore/offshore combined EBIT margins


0%

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4%

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10%

12%

14%

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18%

2013 2014 2015 2016


101

Onshore/offshore backlog


0

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102

Financial estimates

Income statement

Over 2012-15, we are expecting the company to report a revenue growth CAGR of 14% from EUR8.2bn to EUR12.1, EBITDA margins to rise from 12.5% in 2012 to 13.3% in 2015 and for net earnings to grow by a 19% CAGR over this period. Our EBITDA estimates are lower than consensus by 2% in 2013, 2% higher in 2014 and 1% higher in 2015, respectively. We are more bullish on backlog and revenue accretion, while expecting pressure on margins as a result of the likely increase in competition in the subsea segment.

Financial estimates



Technip operates a healthy balance sheet with a net cash position of EUR183m at end-2012. We note that there was a rise in working capital requirements for service contractors with a reduction in the level of prepayments in 2012. Technip’s experience has been similar, with a high working capital requirement of EUR439m in 2012 and EUR355m in Q1 2013. This has eaten into the company’s cash balances. Technip expects working capital requirements to normalise. For modelling purposes, we forecast its working capital requirement to average at EUR186m over 2013-17.

Technip has implemented an aggressive capex plan over the last three years to enlarge its fleet, expand its infrastructure and strengthen its local operations in countries such as Brazil. Its annual capex has averaged at EUR422m during 2010-12 and we forecast its capex will average at EUR494m over 2013-17.

€ m 2012 2013E 2014E 2015E 3 year cagr

Sales (Beren.) 8,204 9,540 10,831 12,139 14%

Consensus 8,204 9435 10659 11595 12%

EBITDA (Beren.) 1,027 1,158 1,462 1,611 16%

Consensus 1,027 1,180 1,433 1,592 16%

EBITDA margin (Beren.) 12.5% 12.1% 13.5% 13.3%

Consensus 12.5% 12.5% 13.4% 13.7%

Net Income 545 624 823 915 19%

Consensus 545 653 822 941 20%

EPS 4.32 5.0 6.6 7.3 19%

Consensus 4.32 5.4 6.7 7.7 21%


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Capex to be financed by operating cash flows


-60.0%

-40.0%

-20.0%

0.0%

20.0%

40.0%

60.0%

-1000

-600

-200

200

600

1000

1400

2010 2011 2012 2013E 2014E 2015E

Operating cash flow Capex Dividends Leverage


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Performance and valuation

Just like Saipem, the other sector heavyweight, Technip has fairly consistently outperformed versus both the market and sector over the past five years. The construction problems in Qatar have faded into the past as Technip has successfully rebalanced its portfolio risk, both in terms of projects and geographies. Its recent acquisitions such as Global Industries and Stone & Webster have filled out its product offering, while contract awards have been coming thick and fast.

Technip’s share price versus the pan-European market

Technip’s share price relative to the European OFS sector

Source: Thomson Reuters DataStream, Berenberg estimates Source: Thomson Reuters DataStream, Berenberg estimates

This outperformance has been warranted by Technip’s earnings momentum, both in absolute and relative terms. The following charts highlight Technip’s relative performance both in terms of share price and earnings against the market and OFS sector, respectively.

As can be seen, its share price performance has marginally lagged its earnings performance relative to both the market and sector. This has resulted in an earnings de-rating over the past five years (discussed in more detail below).

Technip’s price performance and earnings momentum relative to the market

Technip’s price performance and earnings momentum relative to sector



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In terms of earnings cyclicality, save for a brief interregnum in 2009, consensus forecasts have been on a gradually rising trend over the past 10 years. As such, Technip’s forward P/E is a good reflection of its absolute value, in our view.

Technip’s share price and earnings rebased Earnings progression versus forward P/E multiple


The absolute forward P/E is therefore a reasonable indicator of value for the stock. On this basis, the current level (approaching 14x next year’s earnings) is broadly in the middle of its 10-year range (excluding the financial crash in 2008). This is also true of Technip’s cash flow multiple, shown on the right-hand chart below.

Technip’s forward P/E multiple (x) Technip’s forward P/CF multiple (x)


DCF

Our DCF-based model values Technip at EUR106 per share and a target P/E ratio of 16.1x. We have used a two-stage DCF model to value the company which we think is suitable considering the company is in a high growth phase which we expect to continue over the next 10 years. In the initial high growth phase over 2013-22, we expect its free cash flow to average at EUR503m. We have used a WACC of 10% in the initial phase based on a cost of debt of 5%. In the long-term steady state we assume a respective WACC of 9.3%. In the tables below, we give a detailed view of the modelling and valuation sensitivities to different WACC and terminal growth scenarios.


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DCF valuation

Source: Berenberg

DCF Sensitivity

Source: Berenberg

Euro m 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E Free cash flow valuation

Revenues 8,204 9,540 10,831 12,139 13,123 13,989 14,689 15,277 15,811 16,286 16,693 ROE (2022) 14.3%

sales growth 16% 14% 12% 8% 7% 5% 4% 4% 3% 3% ROACE (2022) 17.7%

EBIT 822 913 1,187 1,313 1,375 1,434 1,425 1,451 1,470 1,482 1,486 Retention 0%

EBIT margin 10.0% 9.6% 11.0% 10.8% 10.5% 10.3% 9.7% 9.5% 9.3% 9.1% 8.9% Growth post 2022 (Assets) 1.5%

less: adjusted tax 205- 257- 331- 368- 393- 414- 413- 421- 426- 430- 431- Risk free rate 3.0%

adjusted tax rate -25% -28% -28% -28% -29% -29% -29% -29% -29% -29% -29% Cost of debt 6.0%

NOPLAT 617 656 856 945 982 1,021 1,012 1,030 1,044 1,052 1,055 Corporate tax rate 29%

Working capital requirement 439- 106- 198- 296- 55- 277- 20 245- 41- 146- 55-

Depreciation 195 244 275 299 315 326 338 367 379 407 417 Equity risk premium 7.0%

dep/sales 2.4% 2.6% 2.5% 2.5% 2.4% 2.3% 2.3% 2.4% 2.4% 2.5% 2.5% Beta 1.1

Net capex 723- 572- 542- 546- 394- 420- 441- 412- 395- 407- 417- Beta post-2022 1.2

capex/sales -8.8% -6.0% -5.0% -4.5% -3.0% -3.0% -3.0% -2.7% -2.5% -2.5% -2.5%

Free cash flow to the firm 351- 222 391 401 848 651 928 739 987 906 1,000 Cost of equity 2013-22 10.7%

WACC 2013-22 10.4%

Cost of equity >2022 11.4%

WACC > 2022 9.3%

Free cash flow to firm model:

Value 13-17 3,866


Net debt (m | 2012) 91

Unfunded Pension Liability (m | 2012) 134


Value per share (Euro) 106

FCFF

106 -1% 1% 2% 3% 4%

7% 104 116 131 153 186

8% 96 105 117 132 154

9% 90 97 106 117 133

10% 84 90 97 106 118

11% 80 85 91 98 107


LT

WA

CC


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Financials


Technip (€ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Revenues

Subsea 2,732 2,972 4,048 4,830 5,603 6,388 7,026 7,589

Onshore- offshore combined 3,350 3,841 4,156 4,710 5,228 5,751 6,096 6,401

Group 6,082 6,813 8,204 9,540 10,831 12,139 13,123 13,989

% change -6% 12% 20% 16% 14% 12% 8% 7%

EBITDA 777 884 1,027 1,158 1,462 1,611 1,690 1,760

Depreciation 157 174 195 244 275 299 315 326

Recurring EBIT 620 710 822 913 1,187 1,313 1,375 1,434

Non-recurring items -6 -16 -10 0 0 0 0 0

Stated EBIT 615 694 812 913 1,187 1,313 1,375 1,434

Net interest -20 17 -65 -27 -27 -23 -21 -8

Other income/(expense) 0 0 0 0 0 0 0 0

Affiliates 0 0 0 0 0 0 0 0

PBT 595 711 747 886 1,160 1,290 1,354 1,426

Income tax -179 -209 -205 -257 -331 -368 -393 -414

Tax rate (%) 30% 29% 27% 29% 29% 29% 29% 29%

Post-tax profit 415 503 542 629 829 922 961 1,012

Minority interests 2 5 -4 -5 -6 -7 -7 -7

Income from continuing

operations 418 507 538 624 823 915 954 1,005

Discontinued operations 0 0 0 0 0 0 0 0

Group net income 418 507 538 624 823 915 954 1,005

Clean net income 418 507 545 624 823 915 954 1,005



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Balance sheet

Technip (€ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Balance sheet (€ bn)

Fixed assets 4,146 5,662 6,022 6,350 6,617 6,865 6,944 7,038

Deferred tax/other 325 319 330 330 330 330 330 330

Total non-current 4,471 5,981 6,353 6,681 6,948 7,195 7,274 7,368

Current assets

Construction contracts - due from clients379 588 454 454 454 454 454 454

Inventories/receivables 2,267 2,393 2,505 3,790 4,600 5,487 5,932 6,516

Cash and cash equivalents 3,106 2,809 2,289 2,300 2,464 2,579 3,115 3,452

Total current 5,751 5,789 5,248 6,544 7,518 8,521 9,501 10,422

Assets held for sale 0 0 10 10 10 10 10 10

Total assets 10,222 11,771 11,611 13,235 14,476 15,726 16,785 17,799

Current liabilities

Current financial debt 681 598 400 400 400 400 400 400

Construction contracts - due to clients 695 724 873 873 873 873 873 873

A/c payables/advances 4,060 4,503 3,809 5,407 6,018 6,609 6,999 7,306

Current provisions 237 347 361 361 361 361 361 361

Total current liabilities 5,673 6,172 5,443 7,041 7,652 8,244 8,633 8,940

Non-current liabilities

Other non-current financial debts 1,092 1,553 1,706 1,706 1,706 1,706 1,706 1,706

Provisions 110 140 229 229 229 229 229 229

Deferred tax liabilities 145 231 271 271 271 271 271 271

Total non-current liabilities 1,347 1,925 2,206 2,206 2,206 2,206 2,206 2,206

Liabilities associated with assets held for sale0 0 0 0 0 0 0 0

Total liabilities 7,020 8,097 7,649 9,246 9,858 10,449 10,839 11,146

Total equity 3,202 3,673 3,962 4,407 5,037 5,696 6,365 7,072


Shareholders' funds 3,180 3,652 3,949 4,392 5,020 5,677 6,344 7,049

Total liabilities & equity 10,222 11,771 11,611 13,654 14,895 16,145 17,204 18,218

Net debt/(cash) (1,332) (657) (183) (194) (358) (473) (1,009) (1,346)

Capital Employed 1,965 3,126 3,913 4,347 4,812 5,357 5,490 5,860



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Cash flow statement

Technip (€ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Cash flow (€ m)

Net income 418 507 538 624 823 915 954 1,005

Depreciation & amortization 146 174 195 244 275 299 315 326

Provision for convertible bond redemption

premium 0 0 0 0 0 0 0 0

Split accounting of convertible bonds 0 0 0 0 0 0 0 0

Stock option charge/employee benefits 27 64 71 0 0 0 0 0

Capital (gain) loss on asset sales 3 1 (6) 0 0 0 0 0

Deferred income tax (51) 28 53 0 0 0 0 0

Minority interests/other (2) 9 31 5 6 7 7 7

Cash from operations 539 783 882 873 1,104 1,221 1,276 1,338

Change in working capital (501) (131) (439) (106) (198) (296) (55) (277)

Net cash provided by (used in) operating

activities 38 652 443 767 906 924 1,221 1,062

Capex (389) (357) (519) (572) (542) (546) (394) (420)

Acquisitions (141) (604) (248) 0 0 0 0 0

Disposals 22 4 44 0 0 0 0 0

Net cash provided by (used in) investment

activities (508) (958) (723) (572) (542) (546) (394) (420)

Cash flow less capex (470) (306) (280) 195 364 378 828 642

Net Capital increase 40 34 116 0 0 0 0 0

Share repurchases (2) 0 (108) 0 0 0 0 0

Dividends paid (144) (156) (173) (185) (200) (263) (293) (305)

Other 0 0 0 0 0 0 0 0

Net cash provided by (used in) equity

financing (105) (121) (165) (184) (199) (263) (292) (305)

Net debt issuance 894 133 (40) 0 0 0 0 0

FX adjustment 131 (3) (36) 0 0 0 0 0

Change in net debt 451 (297) (521) 11 165 115 535 337



110

Ratios

Technip (€ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Per share data

Diluted shares (m) 110 117 124 125 125 125 125 125

Clean EPS (€) (diluted) 3.92 4.69 4.32 4.99 6.58 7.32 7.63 8.03

Dividend per share (€) 1.45 1.58 1.68 1.82 2.40 2.67 2.78 2.93

Cash flow per share (€) 0.35 5.55 3.56 6.13 7.24 7.39 9.76 8.49

Debt-adjusted CFPS (€) 0.48 5.44 3.94 6.20 7.06 7.23 9.63 8.42

NAV/share (€) 28.9 31.1 31.7 35.1 40.1 45.4 50.7 56.3



ROACE 28.7 19.3 16.9 15.4 17.6 17.8 17.4 17.7

ROE 13.1 13.9 13.8 14.2 16.4 16.1 15.0 14.3

Net debt(cash)/equity -42 -18 -5 -4 -7 -8 -16 -19

ND/(ND+E) -71 -22 -5 -5 -8 -9 -19 -23

Capex/cash flow 1015 55 117 75 60 59 32 40


Valuation ratios

P/E (x) 14.4 14.9 19.2 16.2 12.3 11.1 10.6 10.1

P/CF (x) 161.9 12.6 23.3 13.2 11.2 10.9 8.3 9.5

EV/EBITDA (x) 6.1 7.9 8.8 7.6 5.9 5.3 4.7 4.4

EV/DACF (x) 91.3 10.9 18.5 11.4 9.8 9.4 6.7 7.3

Dividend yield (%) 2.6% 2.3% 2.0% 2.2% 3.0% 3.3% 3.4% 3.6%

Price to book (x) 1.9 2.1 2.3 2.0 1.8 1.6 1.4 1.3

Free cash flow yield (%) -5.8 3.9 -0.8 2.2 4.1 4.3 9.3 7.2


Subsea 7 SA Oil & Gas

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Headed towards earnings recovery

• We initiate on Subsea 7 with a Buy rating and a price target of NOK146, implying upside of 36%. We have used a WACC of 9.8% and a terminal growth rate of 1%.

• Subsea 7 is a global leader in subsea field development with a particular expertise in subsea, umbilicals, risers and flowlines (SURF). Its vessel fleet is the largest and most modern in the sector. The company is a pure installer. Its revenue streams are concentrated in the North Sea, West Africa and Brazil. Based on Subsea 7’s strong market positioning, cutting-edge technology portfolio, extensive asset base and aggressive capex plan, we think it is well positioned to grow, although earnings are relatively cyclical.

• Subsea space offers high growth and sticky margins due to sector consolidation: Subsea field development, especially in deepwater and ultra-deepwater areas, is projected to grow strongly over the next five years, with external consultant Infield forecasting a subsea capex CAGR of 15.4%. This, in our view would, generate positive pricing pressure considering the consolidated nature of the market space, which is dominated by Subsea 7 and Technip.

• Project phasing to augment earnings momentum: Subsea 7 is likely to experience margins and earnings recovery from 2014 onwards on the back of the phasing out of low-margin contracts won in Brazil in 2010. The risky installation phase on the problematic Guara Lula project in Brazil will be completed by end-2013. From 2014, the impact of these contracts will lessen considerably and hence result in margin improvement.

• Valuation: Subsea 7 is trading at a forward P/E of ~8.3x (2014 Berenberg EPS estimates), which is at the lower end of its historical range. Its historical premium to Technip has turned into a discount and we think that the company’s valuation has been overly penalised mainly on one-off problems. We expect a re-rating (on 12-month P/E) back to 2012 levels on the back of an earnings recovery from 2014 onwards.


Current price

NOK 107.10

Absolute

Price target

NOK 146.00 09/07/2013 Oslo Close Market cap NOK 7,102 m Reuters SUBC.OL Bloomberg SUBC NO Share data

Shares outstanding (m) 332 Enterprise value (USD m) 7,101 Daily trading volume 872,000

Performance data

High 52 weeks (NOK) 147

Low 52 weeks (NOK) 105 Relative performance to SXXP OBX 1 month -15.6 % -18.5 % 3 months -20.2 % -18.7 % 12 months -29.4 % -22.2 %

Key data

Price/book value 1.1 Net gearing 0.0% CAGR sales 2012-2015 9.8% CAGR EPS 2012-2015 19.2%

Business activities: Subsea 7 is an oil services company providing services such as designs, fabrication and installation of equipment for offshore industry

Non-institutional shareholders: SIEM Industries 19.81%

10 July 2013


Jaideep Pandya


Y/E 31.12., USD m 2011 2012 2013E 2014E 2015E

Sales 5,477 6,297 6,790 7,536 8,328

EBITDA 1,000 1,139 1,017 1,731 1,905

EBIT 641 808 625 1,295 1,431

Clean net income 451 847 423 872 975

Clean EPS 1.14 1.42 1.05 2.16 2.41

DPS 0.61 0.60 0.31 0.64 0.72

EBITDA margin 18.3% 18.1% 15.0% 23.0% 22.9%

EBIT margin 11.7% 12.8% 9.2% 17.2% 17.2%

ROE 8.0% 13.8% 6.9% 12.2% 12.3%

ROACE 12.9% 13.4% 6.1% 13.1% 14.8%

P/E 19.4 15.5 17.1 8.3 7.4

EV/CF (x) 14.6 17.6 8.9 6.2 4.0

EV/EBITDA (x) 8.2 7.6 7.0 3.7 2.9

EV/EBIT (x) 12.8 10.7 11.4 5.0 3.9

EV/Sales(x) 1.5 1.4 1.0 0.9 0.7

Free Cash flow yield -1.2% -2.9% 0.3% 3.8% 8.4%

Dividend yield 2.8% 2.7% 1.7% 3.6% 4.0%



112

Company profile

Subsea 7’s positioning in the oil and gas value chain


Subsea 7 is a leading global subsea installation player which, along with Technip, dominates the segment. The company operates a fleet of 40 vessels comprising heavy-lift, pipelay and diving support vessels along with 175 remote operating vehicles (ROVs). Using this fleet as well as supporting spool bases and yards, Subsea is involved in the installation of SURF and platforms as well as providing after-life field services for inspection and maintenance. These services are split between the four operating divisions: 1) SURF; 2) Conventional (platform installation in shallow waters); 3) Life of Field (after-life field services, inspection and maintenance); and 4) I-Tech (inspection and intervention work through ROVs). The revenue split by divisions is given in the left-hand pie chart below.

From a geographic perspective, Subsea 7’s main markets are the North Sea, West Africa and Brazil. The company operates in Asia through its joint venture with Sapura. The left-hand pie chart below highlights the importance of the North Sea and West Africa for the company.

Revenue split by work type Backlog split by geography


After selling its 50% stake in NKT Flexibles last year to NOV, Subsea 7 is no longer vertically integrated in hardware. Nevertheless, it has a leading technology

SURF, 67%

Life of Field, 12%

I Tech Veripos,

4%

Conventional,17%

Africa & GoM, 35%

Asia Pac & Middle East, 4%

Brazil, 16%

North Sea, Mediterranean& Canada, 45%


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portfolio, especially in pipes used for risers and flowlines used in deepwater/ultra-deepwater field development. This gives it an edge in developing fields in harsh environments such as Brazil and the NCS.


114

Investment thesis

We initiate on Subsea 7 with a Buy rating and price target of NOK146, implying upside of 36%. We have used a WACC of 9.8% and a terminal growth rate of 1%. Based on Subsea 7’s strong market positioning, cutting-edge asset base, strong technological portfolio and aggressive capex plan, we think that the company will be able to sustain strong top-line growth in the medium term.

Our investment thesis on Subsea 7 is based on the following.

1) Strong market positioning: Subsea 7 is well positioned in the high-end deepwater subsea installation space, an area which commands high margins. Along with Technip, Subsea 7 dominates this market segment. Its vessel base is the best of its peer group with regard to average age and breadth of services: it can provide services ranging from heavy-lift to rigid and flexible pipelay. This along with high local content in important hydrocarbon regions such as West Africa, North Sea and Brazil make us confident that the company will be able to sustain top-line growth of 10% CAGR over 2012-15.

2) Subsea space offers high growth and sticky margins due to sector consolidation: Subsea field development, especially in deepwater and ultra-deepwater areas, is projected to grow strongly over the next five years, with Infield forecasting a subsea capex CAGR of 15.4%. This in our view would generate positive pricing pressure, considering the consolidated nature of the market space, which is dominated by Subsea 7 and Technip.

3) Project phasing to augment earnings momentum: Subsea 7 is likely to experience margins and earnings recovery from 2014 onwards on the back of the phasing out of low-margin contracts won in Brazil in 2010. The risky installation phase on the problematic Guara Lula project in Brazil is expected to finish by end-2013. From 2014, the impact of these contract will lessen considerably and hence result in margin improvement.

4) Valuation: Subsea 7 is trading at a forward P/E of ~8.3x (2014 Berenberg EPS estimates), which is at the lower end of its historical range. Its historical premium to Technip has turned into a discount and we think that the company’s valuation has been overly penalised (ie the problems were mainly one-off in nature). We expect a re-rating (on 12-month P/E) back to 2012 levels on the back of an earnings recovery from 2014 onwards.


115

Reasons to buy

Reason #1: Subsea 7 is well-positioned Subsea 7 is well-positioned in the high-end deepwater and subsea installation space, an area which will likely see high E&P capex and which commands high margins. Along with Technip, it dominates this market segment as it has the sector’s largest fleet of subsea construction vessels and the second-highest number of ROVs after Oceaneering. The company is well-positioned in areas including the North Sea, West Africa and Brazil and also has exposure to the potentially high-growth market of Asia-Pacific through a joint venture with Sapura.

Subsea 7 stands out not only for the scale and global reach of its vessel base, but also for the quality of the fleet. Subsea 7’s vessel fleet is “latest generation”, with a low average age of 12 years, and is capable of carrying out the entire gamut of subsea and surface work in deep and shallow basins. This ranges from heavy-lift services to rigid and flexible pipelay. This, along with strong local content in important hydrocarbon regions such as West Africa, North Sea and Brazil, make us confident that the company will be able to sustain top-line growth at a 10% CAGR over 2013-15.

At the same time, Subsea 7 has a leading technology portfolio especially in pipes used for risers and flowlines used in deepwater/ultra-deepwater field development. The following table shows the depth of its technological portfolio. In our view, this gives it an edge in developing fields in harsh environments such as Brazil and NCS. With deepwater capex rising, we think that Subsea 7 is well-positioned to capitalise on the wave of new developments being planned.

Subsea 7’s strong technology portfolio

Source: Company presentation

Reason #2: The subsea market has high growth potential and the market segment is highly consolidated The subsea field development market space, especially in deepwater and ultra-deepwater fields, is set for strong growth over the next five years. Technological advances are making subsea field development in deeper and harsh environments increasingly viable. Mature shallow water basins, on the other hand, are suffering from high production decline rates and the level of competition between


116

contractors is intense. In onshore, resource nationalism as well as dominant NOCs are limiting both growth and margins for oil services contractors. Infield projects capex in deepwater and ultra-deepwater field development to grow at a CAGR of 16% over 2012-17. This would subsequently entail strong demand for both subsea installation and associated hardware.

In addition to the strong demand, subsea installation is also highly consolidated and is dominated by Subsea 7 and Technip. This consolidation is the result of high entry barriers in the shape of 1) a deepwater vessel fleet which is expensive to acquire and maintain, 2) technical expertise for the large lump sum EPIC projects and 3) associated infrastructure and local content such as spool-bases, manufacturing yards and plants. Because of these entry barriers we think that top tier players Subsea 7 and Tech will successfully be able to counter the vessel additions by smaller players such as Emas, McDermott and Petrofac. Market consolidation means that if demand continues to grow, pricing and margins would expand.

Reason #3: Project phasing to augment earnings momentum Subsea 7 is likely to experience margins and earnings recovery 2014 onwards on the back of phasing out of low-margin contracts won in Brazil in 2010. The risky installation phase on the problematic Guara Lula project in Brazil will be completed by the end of 2013. From 2014, the impact of these contracts will lessen considerably and hence result in margin improvement.

The company has now refocused its growth strategy away from Brazil where it lacks a strong local infrastructure base. We think that the phasing out of poor margin contracts along with a contract mix skewed towards high-margin regions such as West Africa will result in margin recovery.

Project phasing will also provide a margin lift. This is because better margin contracts will reach the late execution phase from 2014 onwards. The chart below details the revenue schedule of the current backlog according to project stage.

Backlog revenue schedule by project stage split


0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2013E 2014E 2015E



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Reason #4: Valuation

Subsea 7 is trading at a forward P/E of 8.3x, substantially lower than its five-year historical average of 14.7x. The stock is down by 19% ytd due to additional losses on its Brazilian contract. We think that these losses are primarily one-off and consequently believe that the stock has thus been overly penalised.


Source: DataStream

Historically, Subsea 7 has traded at a premium to the EU OFS index. This premium has largely eroded since the start of the year. The same is true in terms of its performance versus its closest peer Technip, against which it is currently trading at a discount versus the historical premium. We expect the company to re-rate (based on 12-month forward P/E) back to the levels seen in 2012 on the back of an earnings recovery from 2014 onwards.


118

Subsea 7 is trading in line with the EU Oil Equipment & Services Index, compared to average historical premium of 1.5% on 12-month forward P/E

Source: DataStream

Subsea 7’s is trading a discount to Technip on 12-month forward P/E as compared to a historical premium

Source: DataStream

5

7

9

11

13

15

17

19

21

2011 2012 2013

Subsea 7 EU oil equip & services index


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Demand dynamics

Against the backdrop of strong growth in deepwater exploration and development projects from both international oil companies and NOCs, the subsea segment (among the offshore subsector) is experiencing strong growth. Strong expansion plans from NOCs such as Petrobras (USD147bn in E&P capex over 2013-17) and big international oil company projects in West Africa (Angola, Nigeria) along with a possible revival in demand in the GoM following the Macondo accident imply that capex growth for this subsegment of offshore capex will remain robust for the next five years.

When Subsea 7 was formed by the merger of Acergy and Subsea Inc in 2011, the subsea field development market became duopolistic with Subsea 7 and Technip the two dominant players. With an improved vessel fleet and a stronger local content base, Subsea 7 is in a good position to bid for SURF opportunities – especially in the deepwater and ultra-deepwater fields. Before we examine further the growth outlook for the company, we take a closer look at historical growth rates (on a regional/client basis) and the contract mix of Subsea 7.

Regional growth Subsea 7 grew at a CAGR of 6% (on a combined basis for Subsea Inc and Acergy) over 2008-12. Backlog growth since the merger has been impressive: the order book has risen to USD10bn as of end-Q1 2013 from USD8.5bn at year-end 2011. Through the merger, Subsea 7 has not only broadened its vessel fleet but it has also managed to improve its regional profile – significantly strengthening its market position in West Africa, Asia and Brazil.

Subsea 7 has a very strong market share in key regions such as North Sea. Historically, Acergy was a strong EPIC player in North Sea and it has significantly bolstered its position through the merger with Subsea Inc, which was strong in life of field services in the regions through its diving support vessels and ROVs. In West Africa, while Acergy had a strong position in countries such as Angola, Subsea Inc was a relatively small player. Nevertheless, the combined entity that is Subsea 7 is a strong player in this region along with Saipem and Technip. In Brazil, the combination of Acergy and Subsea Inc has clearly improved the competitive strength of the new entity but it lags market leader Technip, which benefits from vertical integration in flexible pipes and umbilicals. In regions such as the GoM, Asia and Australia, Subsea 7 is a relatively weak player as neither Acergy nor Subsea Inc had a strong footprint in these markets.

Prior to the merger, the strongest growth region for Acergy was North Africa and the Mediterranean, which grew at a CAGR of 7% in 2006-10. Growth in South America was fairly robust at a 27% CAGR over 2006-10, albeit from a low base of USD82.6m in 2006. Growth in Asia has been fairly steady. However, a clear disappointment in terms of growth between 2006 and 2010 was the North Sea, where Acergy saw top-line contraction of 9% as the company lost market share to competitors such as Technip. From the point of view of Subsea Inc, the North Sea accounted for almost half its revenues and saw a sharp pick-up in growth between 2006 and 2007 followed by a period of stagnation (between 2007 and 2010, sales remained in the range of USD950m-1,100m). Meanwhile, Brazil was an area of strong growth (at a CAGR of 27% between 2006 and 2010), as the company managed to secure some long-term contracts from Petrobras.


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Since the merger, the clear regional growth areas for Subsea 7 have been the North Sea, Brazil and West Africa. This is underscored by the current backlog, ~90% of which relates to these three regions. Moreover, given that all three regions have a strong growth outlook in terms of offshore capex, it is highly likely that they will continue to dominate Subsea 7’s revenues over the next five years.

Clients Given that winning a contract in OFS mainly depends upon the bid price, availability of assets and track record, it is hard to forecast if a particular company will have an edge when it comes to winning business from a particular oil major. Nevertheless, we have looked at the project track record for both Acergy and Subsea Inc between 2006 and 2010, as presented in the table below.


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Major clients – Subsea Inc


Life-of-field services: deepwater Shetland area Scotland/ North

Sea02/11/10 BP

Andrew Area Development Project: bundle contract Scotland/ North

Sea11/06/10 BP

Galapagos and Nakika Phase 3 developments: installation Gulf of Mexico 13/04/10 BP

Greater Plutonio Development: GEL project Angola 19/08/09 BP

Valhall Flank Gas Lift Pipelines & Wellhead Platform Riser

Caisson

Norway/ North

Sea02/07/09 BP

Skarv and Idun fields Norway/ North

Sea29/11/07 BP

Installation works in the Skarv & Idun fields Norway/ North

Sea03/10/07 BP

Block 18 Greater Plutonio development Angola 14/08/07 BP

Valhall field: pipelineNorway/ North

Sea14/07/06 BP

Deepwater construction vessel & Hercules deepwater ROV Scotland/ North

Sea23/03/06 BP

Deepwater construction vessel & Hercules deepwater ROV Scotland/ North

Sea09/01/06 BP

ROV services GoM Gulf of Mexico 11/11/10 Petrobras

Deepwater Cascade & Chinook fields Gulf of Mexico 08/01/08 Petrobras

2 contracts - (1) ROV services, (2) supply of ROV and tooling

services

(1) Brazil, (2) West

Africa,

Mediterranean

17/12/07(1) Petrobras,

(2) Larsen

Extension to the "Hybrid Vessel" contract - deepwater

Campos BasinBrazil 23/07/07 Petrobras

ROVs onboard three drilling units Brazil 16/07/07 Petrobras

Exclusive use of the Kommandor 3000 Brazil 20/10/06 Petrobras

Drilling support contracts: ROVBrazil &

Equatorial Guinea24/08/06

Petrobras,

Exxon

Snorre B Riser Replacement project Norway/ North

Sea04/03/09 Statoil

Frame Contract for reeled pipe installation services Norway/ North

Sea17/07/06 Statoil

Frame Agreement Contract: Yttergryta development project

etc.

Norway/ North

Sea30/06/06 Statoil

Framework Agreement Contract for Shell's European AssetsUK & Norway/

North Sea27/09/10 Shell

Draugen field: Tanker Loading System Norway/ North

Sea03/09/08 Shell, BP

Campos Basin: provision of two Centurion QX ROVs Brazil 28/03/07 Shell

Development of the BC10 fields Brazil 28/12/06 Shell

Design, build and operation of ROVSV & DSV Europe 03/07/06 Shell

Contracts by major clients for Subsea Inc


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Major clients – Acergy


It is clear that Subsea Inc had a strong relationship with BP in terms of projects in the North Sea and the UK continental shelf (UKCS). Acergy, given its strong market position in Angola, has worked with every big oil major in West Africa. Moreover, it maintained solid relations with Petrobras, helping the merged company to win projects in Brazil.

Project mix Acergy and Subsea Inc had very different project mixes: Subsea Inc had a significant proportion of contracts on a day-rate basis while Acergy concentrated on lump sum contracts.

In our view, the merger between the two companies has resulted in a more balanced contract mix. Although having a large proportion of contracts on a day- rate basis can be useful, it increases the cyclicality of earnings/profitability and is a more commoditised way of pricing than full lump sum EPIC contracts – where the service provider has much more room to influence profitability.

Current projects Playing to its strengths, Subsea 7 has about 60% of current outstanding projects in two regions – the North Sea and West Africa. In this section, we take a closer look at key projects that are already in the backlog from the stage-of-execution and complexity point of view (we discuss the profitability of these projects in the profitability section).

For the purpose of modelling revenue recognition through the life of the project, it is important to determine the percentage split for each stage of execution of the project. While revenue recognition for each project will vary depending upon its complexity, having spoken to several industry experts, we have put together a revenue recognition model that provides a general overview of revenue recognition. Based on this model and the project start date, we estimate the progress of each of the key projects in Subsea 7’s current backlog.

Acergy contracts by main clients Country Date won Client Value ($m)

PRA1 Brazil 13/02/2006 Petrobras 300

Mexilhão gas export trunkline Brazil 03/04/2007 Petrobras 400

three year contract for the Acergy Harrier Brazil 30/10/2007 Petrobras 140

four year contract for the Polar Queen by

Petrobras in Brazil, with an option for an

additional four years

Brazil 14/06/2009 Petrobras 260

new four year contract for the Acergy

CondorBrazil 30/09/2010 Petrobras 220

Sul-Norte Capixaba Project Brazil 01/12/2010 Petrobras 190

5 year survey frame contract North Sea 30/01/2007 Statoil 120

Alve field North Sea 27/07/2007 Statoil 120

Gjøa and Morvin licenses North Sea 28/03/2008 Statoil 60

Tombua Landana development offshore

Cabinda,Angola/ Offshore 04/09/2006 Chevron 150

Escravos Nigeria 19/10/2009 Chevron 500


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Project pipeline Having discussed the stage of execution by individual project, we now try to ascertain the level of technicality and complexity of each project based on the nature of the work involved. We have also tried to estimate the amount of vessel days for the project, in order to calculate the vessel’s day rate. Subsea 7 is not backward-integrated in terms of procurement of flexible pipes or umbilicals, so the company must secure an attractive day rate for its vessels as this is where the profit margin for the project lies.


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Backlog revenue maturity model


Projects Client CountryContract value

($ m)Start date 2012 2013 2014 2015 2016

Block 17/18 BP Angola 110 0

ALNG

JV of Sonangol,

Chevron, BP,

Total, ENI

Angola 250 0

Deep Panuke Encana Canada 200 0

Skarv flowline BP North Sea 200 0

Skarv GSI BP North Sea 200 48

Fosse Dompap Statoil North Sea 170 153

Oso Re Exxon Nigeria 120 12

EGP3B Chevron Nigeria 500 160

P55 Export PetrobrasBrazil/ Campos

basin200 Oct'09 40

Block 18 Gas Export Line (GEL) BP Angola 150 Jun'09 5

Andrew Bundle BP UK 135 Jun'10 38

Jasmine Conocco UK/ North Sea 150 Aug'10 47

Gas Sul North Capixaba (GSNC) PetrobtrasBrazil/ Santos

basin200 Apr'08 136

MPN Satellite MOBIL Nigeria 190 May'09 175

Block 31 PSVM BP Angola 460 Jul'08 156 100

Tordis StatoilNorway/ North

Sea70 Apr'11 62 15

Skuld Statoil Norway 250 May'11 215 40

Ormen Lange Shel Norway 70 Apr'11 64 10

Laggan Tormore Total UK/ North Sea 250 May'10 50 70 60

Gumusut Shell Malaysia 825 Feb'10 200 200

Siri Caisson Dong Energy UK/ North Sea 220 Jun'11 62 100

CLOV development proj TotalAngola/ West

Africa1300 Jul'10 300 500 520

West Franklin field development Elf exploration UK/ North Sea 190 Dec'11 105 120

Terra Nova Suncor EnergyCanada,

Newfoundland100 Mar'12 93 44

Guara Lula PetrobrasBrazil/ Santos

basin1000 Nov-11 400 600

Martin Linge Development StatoilNorway/ North

Sea800 Nov-12 0 100 200 300 200

UOTE Petrobras Brazil 200 Dec'11 64 50 100 50

Ofon 2 Total Nigeria 467 Oct'11 61 100 200 130

Subsea Construction, Inspection, Repair

and Maintenance servicesBP

Scotland/ North

Sea300 2013 0 60 80 80 80

Angola/ West Africa Chevron Chevron 150 04 December 2012 0 15 60 75


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Backlog revenue maturity model - continued


Projects Client CountryContract value

($ m)Start date 2012 2013 2014 2015 2016

Julimar Development Project ApacheAustralia/ Asia

Pacific100 2013 0 25 50 50

Lianzi field offshore: EPIC SURF ChevronAngola/ West

Africa600 2014 0 100 200 300

Knarr field: SURF contract BGNorway/ North

Sea400 2H 2013 38 175 225

Cheviot Field: SURF contract ATPScotland/ North

Sea175 02/07/2012 0 75 100

Terra Nova Field: SURF contract SuncorCanada/ North

America100 Mar'12 0 50 50

Clair Ridge Project: pipeline BPNorway/ North

Sea100 Summer 2012 9 25 75

Subsea construction project SapuraAcergyVietnam/ Asia

Pacific100 2013 0 50 50

LoF contract BP GoM 125 mid 2012 0 30 30 35

Cardamom and West Boreas Projects Shell GoM 100 2011 50 50

Gorgon project ChevronAustralia/ Asia

Pacific500 12 December 2011 25 125 200 175

G1 Project ONGC India 200 29 July 2011 50 50

Kumang Project Petronas Malaysia 0 2011` 0 100 200

Montara PTTEPAustralia/ Asia

Pacific80 2011` 0 40 40

LTC of PLSVs and DSVs Petrobras Brazil 0 24 January 2011 0 100 100 100 100

Long-term charter contract for a new PLSV Petrobras Brazil 500 2011 100 100 100 100

IMR project Petrobras Brazil 0 2011 0 100 100 100 100

B11, Ekofisk WI and Eldfisk Projects ConocoPhillipsNorway/

Norwegian sea150 2011 135 15

5 yr IMR contract StatoilNorway/

Norwegian sea250 2011 50 50 50 50

Medway Development Project DanaDenmark/

North Sea50 2010 10 10

Underwater Services Contracts (USC) Shell 360 27/11/2012 120 120 120

2910 3294 3010 1565 900


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Future growth Due to a slowdown in project wins in 2012, Subsea 7 did not expand its backlog last year. Given that several of its projects will be in the mid-to-late stages of execution in 2013/2014, it is imperative for the company to win new projects in 2013. At its Q3 2012 results, the company provided a brief outlook on potential project wins for 2013, with a relatively positive view on West Africa (where several project awards have been delayed) while noting that supply-chain bottlenecks in the North Sea have also delayed some projects. In the following section, we a) take a look at three key regions of growth for Subsea 7 – Angola, Brazil and the North Sea; and b) highlight the key upcoming projects in these regions.

Regional growth analysis

Angola December 2009 marked the 10th anniversary of deepwater production in Angola. Since 1999, deepwater oil production has risen to around 1.5mbd, more than the output of the GoM and Nigeria combined, placing Angola behind only Brazil on this measure. Hence, despite only having a 2% market share in terms of global production, Angola holds significant importance not just for IOCs but also for oil services companies.

Angola’s oil production saw very strong growth from c750boed in 2000 to 2,000boed in 2008. Although output dropped marginally due to the oil price crash in 1999, based on the current outlook for exploration projects, Angolan oil production could rise to almost 2,500boed by 2015. Some experts believe that the output limits from OPEC membership are curtailing Angolan oil production by 10-15%. As of 2010, reserves in producing assets amounted to 6,700boed, with c90% represented by oil and c10% by gas.

Current producing assets Angolan offshore is divided into 50 concession blocks, of which 24 are licensed (eight are deepwater, four are ultra-deepwater and 12 are shallow water) while 27 blocks are still open. The lower Congo basin and Kwanza basins have been developed so far with regard to oil production/identified reserves. The blocks that produce virtually all of Angola’s deepwater oil today are those awarded in the 1993 licence round (also known as golden blocks), namely Block 14 (Chevron), Block 15 (Exxon), Block 17 (Total) and Block 18 (BP). While Blocks 31/32/33/34 were licensed in 1999, the average discovery in these was much smaller than from earlier blocks. Moreover, the licence round of 2005/06 that offered the expired portion of 1993’s golden blocks – namely, 15/06, 17/06 and 18/06 – saw a winning signing bonus of USD900m-1.1bn, underscoring the level of commitment and interest among major international oil companies.

Offshore market The surge in Angolan crude production over the past few years has been driven by technologically complex deepwater projects. With the next few years expected to bring another significant wave of deepwater projects, the outlook for capex for the offshore market is very positive. Over the past 10 years, oil companies have poured USD46bn in capex into deepwater developments and over the next decade this number is expected to exceed USD100bn – mainly due to the material shift to deepwater/ultra-deepwater developments (which are significantly more expensive than shallow water developments) and increasing local content.

Sanctioned projects slated for start-up before the end of 2012 include Pazflor (Total) in deepwater Block 17, PSVM (BP) in ultra-deepwater Block 31, and Kizomba Satellites Phase I (ExxonMobil) in deepwater Block 15. Moreover, Block


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17 is expected to start production under the CLOV project (Total) during 2014. The subsea sector is expected to see a tripling in capex allocation from oil majors in the next 10 years compared to the past decade, mainly because five of Angola’s 11 largest projects that are planned or already under way are in ultra-deepwater areas (three from BP in Block 31 and two from Total in Block 32) – implying total capex of USD20bn.

Forthcoming big projects

Block 31 – operated by BP Block 31 includes 20 discoveries and is located in water depths of 1,500m-2,450m. BP is applying the strategy of linking multiple hubs developed via subsea tie-backs to one floating production storage and offloading (FPSO) unit. There are estimated to be 150 wells in this field, which is being developed in three phases. The first phase of the development includes discoveries in Plutoa, Saturn, Venus and Marte, known as PSVM. This is a 48-well development linked by a network of 170km of flowlines, 95km of umbilicals and 15 manifolds. The first phase of this project saw awards of USD594m for Technip while Subsea 7 won a contract for USD460m. The next phases of this project are expected to mirror the first phase. According to a recent presentation from BP, the company is trying to further develop Block 31 from a south-east point of view. Development capex of USD1bn-1.5bn may be spent on the next phase of this project.

Block 32 – operated by Total Having successfully developed Pazflor and Clov (under construction – oil is to be produced by 2015), Total is very keen to continue development in the Kwana basin in Angola with big plans for developing Block 32. The Kaombo development project, which Total estimates holds 300m barrels of recoverable reserves, will deploy two FPSOs. This project is expected to have 32 production subsea wells and 26 water injection wells with 16 manifolds and 70km of production flowlines. While Modec, SBM offshore and Saipem are bidding for two FPSOs, Saipem has joined forces with Subsea 7 to bid for the EPIC of subsea equipment – competing with the Technip-Heerema JV. The total contract value of this project (from an EPIC point of view) will be USD1.5bn-2bn on our estimates.

Block 14 – operated by Chevron This block has seen significant development activity in recent years, including the BBLT complex with the Benguela-Belize compliant-piled tower and the Lobito and Tomboco subsea tieback to the Benguela-Belize compliant-piled tower with first oil production expected in 2006. Since then, Chevron has contemplated several smaller tiebacks with the Lianzi discovery, which was the contract won by Subsea 7 (worth USD600m with further new contracts for USD150m). The second opportunity in Block 14 is the Lucapa field, located at a depth of 1,200m. This project, currently in the FEED stage, is expected to have one or two FPSOs. We estimate that this project could be in the range of USD0.7bn-1bn and should be awarded this year.

Chissonga – operated by Maersk The Chissonga field is located in the Lower Congo basin with a water depth of 1500m in Block 16, where Maersk Oil acquired a 15% interest from Devon Energy for an initial payment of USD70m. After initial appraisal, Maersk has decided to build an FPSO similar to Total’s in Block 17, with 150,000bpd and 40 subsea wells. Having drilled an appraisal well and conducted a pre-FEED study, Maersk should issue FPSO/subsea work on this project in the next year; this project could also be in the range USD0.7bn-1bn.


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North Sea

New projects Based on the key projects discussed in the section above along with the track-record of Subsea 7 with regard to regions/clients, we have formulated the project pipeline for the company for the next 3-4 years.

North Sea project pipeline

Source: Berenberg

While we have weighted the projects based on the probability of success for Subsea 7, note that the timing of revenues from a project depends on when the projects are awarded.

Required growth to meet expectations Given the attractive fundamental growth profile of the capex linked to offshore oil field development, it is not surprising that analyst estimates for growth (top-line and bottom-line) had been very aggressive. However, more recently, the problems faced by Subsea 7 have led to sharply lower consensus estimates which should be easily met given the strong demand for subsea services over the next three years. The chart below details the order intake required to meet consensus estimates over 2014-15 after accounting for the profits contributed by the current backlog.


Kraken Tendering EnQuest

Rosebank FEED Chevron

Greater Lancaster Area (GLA) Conceptual Hurricane Exploration

Catcher Conceptual Premier Oil

Bressay FEED Statoil

Mariner FEED Statoil

Western Isles Under ConstructionDana Petroleum


15/5-2 Eirin PDO submited last year Statoil

16/1-8. PDO submited Lundin

16/1-9 PDO submited Det norske

oljeselskap ASA

17/12-1 Bream PDO submited BG Norge AS

24/6-1 Peik PDO submited Centrica Resources

(Norge)

24/9-9 S Bøyla PDO submited Marathon Oil Norge

AS

25/2-10 S PDO submited Statoil

25/11-16 Svalin PDO submited Statoil

31/2-N-11 H PDO submited Statoil

34/8-13 A PDO submited Statoil

6406/9-1 Linnorm PDO submited A/S Norske Shell


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Subdued consensus earnings expectations should be easily met

Source: Berenberg

0

1

1

2

2

3

3

4

2014 2015

US

D b

n

EBIT consensus Backlog profitability Order intake required


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Assets

Vessels Subsea 7 operates a highly specialised fleet comprising nine heavy-lift and rigid pipelay, 16 flexlay, eight diving and 12 light construction vessels. The merger in 2011 saw Acergy augment Subsea 7’s reeled pipelay and diving capability by bringing in J-lay, S-lay and heavy-lift vessels. The enhanced fleet has allowed Subsea 7 to offer subsea services including conventional rigid platform installation, subsea inspection and life of field services in shallow water as well as SURF installation in deepwater projects.

The company has an edge over both Technip and Saipem in terms of fleet size and age. The average age of Subsea 7 vessels is just 12 years, which compares to 17 and 30 years for Technip and Saipem respectively. Subsea 7 has invested heavily over the last five years in fleet upgrading, with capex averaging USD631m pa. Having the latest generation of vessels should translate into low maintenance capex requirements and therefore gear future capex towards growth.

Subsea 7 capex (Subsea 7 and Acergy prior to 2011) averaged USD610m over 2006-11


More than 70% of the fleet is now capable of operating in water depths in excess of 1,000m. This operational capacity and a young fleet have positioned Subsea 7 well to take advantage of the structural shift in E&P spending towards field development in deep and ultra-deep waters. Today it is strongly positioned in high-growth frontier regions such as Angola and Brazil. The following chart gives the fleet split by geography and highlights the importance of the North Sea, West Africa and Brazil, where the primary enabler vessels are committed.

Fleet excluding DSV and survey Rigid pipelay and heavy-lift


0

200

400

600

800

2006 2007 2008 2009 2010 2011 2012

US$ m

Subsea7 Inc Capex Acergy SA Capex

0

100

200

300

400

500

600

700

800

2006 2007 2008 2009 2010 2011 2012

Subsea 7 combined capex Average annual spend

North Sea, 45%

North America,

9%

Brazil, 32%

Asia Pacific, 5%

West Africa, 9%

North Sea, 45%

North America,

0%

Brazil, 22%

Asia Pacific,

11%

West Africa,

22%


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Heavy-lift: Unlike Technip, Subsea 7 possesses an impressive portfolio of vessels that are able to carry out heavy-lift work. Its Seaway Heavy Lifting JV operates vessels Oleg Strashnov and Stanislav Yudin in the North Sea while JV SapuraAcergy operates Sapura3000 in Asia-Pacific. Subsea 7’s heavy-lift capability has been further strengthened by the introduction of Seven Borealis with 5,000 tonnes of uplift power. Excluding Acergy Polaris, Subsea 7’s crane vessels can raise structures with weight in access of 2,500 tonnes. This fulfils the lift requirements of 90% of the offshore projects.

These vessels provide Subsea 7 with an edge, especially in the North Sea where there are only a few vessels with the ability to pick up equipment weighing more than 400 tonnes. The need for heavy lifting is rising in the North Sea as operators such as Statoil are moving towards greater hydrocarbon processing on the seabed for enhanced field recovery. Subsea 7 is well placed to tap this growing demand to place ever heavier equipment on the seabed.

Technip, on the other hand, is pursuing a collaborative approach to counter its weakness in this segment rather than developing its own dedicated heavy-lift vessel fleet. In October 2012, it struck an alliance with heavy-lift specialist Hereema to share capabilities in the ultra-deepwater SURF market. The question is, how value-accretive will this strategy be? Hereema only has three active crane vessels, with an additional one likely to enter service in 2014. Considering that its vessels will also be committed to executing its own backlog, Hereema in our view will have limited spare capacity for joint projects with Technip. Moreover, Hereema’s crane vessels have an average age of 30 years and hence Subsea 7’s latest generation Seven Borealis and Oleg Strahanov will likely have the upper hand. In poorly resourced regions such as West Africa, where operators require full-service contractors, Subsea 7’s in-house lift expertise has long-term benefits.

From a geographical perspective, Subsea 7’s large crane vessels have the three main regions covered. Seven Borealis and Acergy Polaris are executing projects in West Africa (Angola and Nigeria) while JV Seaway’s heavy-lifting vessels are operating in North Sea and Sapura 3000 is working on projects in Asia-Pacific.

Heavy-lift fleet

Source: Berenberg

Rigid pipelay: Subsea 7 has six rigid pipelay vessels able to work in reeled, J- and S-lay mode. These vessels cover the market segment comprising infield pipes and export lines installation. Its primary reel lay vessels are Seven Borealis, Seven Oceans and Seven Navica. These cover pipes of up to 16 inches in diameter. Seven Borealis, along with Sapura 3000, Acergy Anatres and Acergy Polaris, can lay larger diameter pipes of up to 60 inches in S-lay and J-lay mode. Considering that a

Vessel Type ROV Capability Lift capability Speed (knots) Pipeline Capability Pipe diameter Water depth Regional focus

Sapura 3000Rigid pipelay &

heavy lift

2 work class

ROVs3000 8

240t S Lay

400t J Lay

6 to 60 (S lay), 4

to 20 inch (J lay)3000 Asia Pacific

Seven BorealisRigid pipelay &

heavy lift

2 work class

ROVs5000 12

Reeled lay

600t S Lay

1000t J Lay

46 (S lay), 24 (J

lay)3000 West Africa

Acergy PolarisRigid pipelay &

heavy lift

2 work class

ROVs1440 7.5 136t S Lay 6 to 60 Deepwater West Africa

Oleg Strashnov Heavy lift none 5000 14 n.a. na. North Sea

Stanislav Yudin Heavy lift none 2500 12 n.a. na. North Sea


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number of these vessels have heavy-lift capability (as discussed in the previous section), they are able to execute large EPIC projects in combination with smaller support vessels.

Apart from Acergy Antres, Subsea 7’s rigid pipelay vessels are able to operate in water depths in excess of 2,000m and are therefore capable of taking on ultra-deepwater field developments in Angola and in Norwegian deep water. From a geographic perspective, the rigid pipelay fleet is split between West Africa, the Norwegian Sea and Asia-Pacific (in decreasing order of importance).

In West Africa, Borealis, Polaris and Antares have work schedules which run into 2013. In the past three quarters, pipelay vessel Acergy Antares has laid 130km in pipelines at Escravos Gas Projects Phase 3B in Nigeria. It will soon be joined by Acergy Polaris at the shallow-water Ofon 2 development. Borealis will be working at the Clov project in Angola for around nine months. The fleet in West Africa can execute similar projects in Brazil as transit times are short and the projects similar.

Seven Oceans and Seven Navica are currently in the North Sea region and will initiate offshore installation work on Laggan Tormore and Clair Ridge developments in 2014. The remaining rigid pipelay vessel, Sapura 3000, is committed to Asia-Pacific and is carrying out 28km in pipelay work at the subsea construction project in Vietnam.

Rigid pipelay fleet


Flexibles pipelay: Subsea 7 has around 16 subsea flexlay vessels able to carry out flexible pipelay in vertical (deepwater) and horizontal mode (shallow water). These vessels also have medium-lift capability along with ROV equipment (both observation and work class) and therefore can carry out subsea installation and inspection services. The latest flexlay vessels include Skandi Acergy, Skandi Seven and Seven Pacific. The fleet is broadly split between Brazil and the North Sea. The vertical flexlay vessels are concentrated in Brazil while the horizontal lays are based primarily in the North Sea.

The fleet is actively used both on a day-rate basis and on large EPIC projects. In the SURF projects, they work alongside larger rigid pipelay and heavy-lift vessels and carry out an array of work that includes installation of infield flowlines, jumpers, risers, flying leads, umbilicals and tieback services.

With the current collection of pipelay vessels – both rigid and flexibles – Subsea 7

Vessel Type ROV Capability Lift capability Speed (knots) Pipeline Capability Pipe diameter Water depth Regional focus

Sapura 3000Rigid pipelay &

heavy lift

2 work class

ROVs3000 8

240t S Lay

400t J Lay

6 to 60 (S lay), 4

to 20 inch (J lay)3000 Asia Pacific

Seven Oceans Pipelay2 work class

ROVs350-400t 13

Reeled pipelay for

rigid and flexible

pipes

6 to 16 3000Norwegian Sea /

Norway

Seven BorealisRigid pipelay &

heavy lift

2 work class

ROVs5000 12

Reeled lay

600t S Lay

1000t J Lay

46 (S lay), 24 (J

lay)3000 West Africa

Acergy PolarisRigid pipelay &

heavy lift

2 work class

ROVs1440 7.5 136t S Lay 6 to 60 Deepwater West Africa

Acergy Antares Pipelay none 300 120t S Lay 4 to 60 Shallow water West Africa

Seven PacificContruction and

Verical Flexlay

2 work class

ROVs250 13+ 260t vertical lay 3000 Canada

Seven SeasContruction and

Verical Flexlay

2 work class

ROVs400 13+

400t J Lay

430t flexlay3000


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can fulfil nearly 90% of the pipelay market. The only part missing in its service range is the trunkline business. The trunkline market is duopolistic in nature, being served by AllSeas and to a lesser extent Saipem. Following the merger, Subsea 7 decided to exit its small but high-margin trunkline business by selling its only trunklay barge. Considering the high barriers to entry for the large diameter pipelay segment, with an average trunklay vessel costing in excess of USD1bn, it seems unlikely that Subsea 7 will venture into an area dominated by niche specialist AllSeas and heavyweight Saipem.

Flexible pipelay fleet


Utilisation of vessels Subsea 7 was able to achieve high fleet utilisation in 2012 of 86%, up from 80% in 2011. Strong activity in the North Sea and the Norwegian Sea, where the bulk of Subsea 7’s fleet is committed, was a strong contributing factor to the healthy vessel utilisation rate. A number of large EPIC SURF projects were in the installation phase in January-September 2012; these include projects such as the Jasmine, Tordis and Andrew field development.

In 2013, a considerable amount of installation work will need to be done, utilising Subsea 7’s key vessels. For instance, Acergy Polaris will carry out platform installation at Ofon 2 in Nigeria, Seven Borealis will lay export lines at the Clov development in Angola, Seven Oceans will carry out tieback work at the Laggan

Vessel ROV Capability

Lift capability

(tons)

Speed

(knots) Pipeline Capability

Water depth

(m) Regional focus

Seven Mar2 work class

ROVs300 12

340t flexible lay

system3000 Brazil

Phoenix2 work class

ROVs60 12

340t flexible lay

system2300 Brazil

Acergy Condor2 work class

ROVs70 10.5

230t flexible lay

system2000 Brazil

Normand Seven2 work class

ROVs250 16.5

300t flexible lay

system2000 Brazil

Lochnagar2 work class

ROVs30 11

255t flexible lay

system2000 Brazil

Skandi Neptune2 work class

ROVs250 15 Flexible lay 3000 GoM

Seven Eagle2 work class

ROVs250 12.5

90t flexible lay

system3000

Atlantic North

Sea

Skandi Acergy2 work class

ROVs400 15 125t flexible lay 3000 Norwegian Sea

Skandi Seven2 work class

ROVs250 300t reel flexible lay 3000 Norwegian Sea

Normand

Oceanic

2 work class

ROVs400 17.6 Flexlay 3000 Norwegian Sea

Subsea Viking2 work class

ROVs100 10 flexible lay system 3000 North Sea/ UK

Seven Seas2 work class

ROVs400 13+

400t J Lay

430t flexlay3000

Kommandor

3000

2 work class

ROVs200 10

150t flexible lay

system1000 Brazil


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Tormore project in the UK North Sea and Seven Navica will lay oil and gas export lines at the Claire Ridge project in the Norwegian North Sea. This in our view will support decent fleet utilisation this year. However, compared to 2012, the utilisation rate will likely be lower.

Management has already highlighted emerging supply bottlenecks in the North Sea. An unseasonal spike in NSC vessel utilisation in Q1 2012 will have translated into relatively low fleet utilisation in Q1 2013. Our bottom-up project-by-project vessel schedule supports this view.

Fleet utilisation rate


Spool base The following table gives the details for the spoolbases and yards which Subsea 7 has globally. The company has strong infrastructure bases in West Africa, North Sea and Brazil.

50%

55%

60%

65%

70%

75%

80%

85%

90%

2Q10 4Q10 1Q11 3Q11 2011 2Q12 4Q12 1Q13


135

Spool base

Source: Berenberg

Yards TypeCountry/

Region

Target

marketFacilities

Luanda Spoolbase

Angola/

West

Africa

Offshore

(1) Single joint fabrication

(2) 17 station fabrication line

(3) Intermediate tie-in station

(4) 300m pipe storage berms

Port Isabel Spoolbase USA Offshore


(2) 40,000 sq ft pipe fabrication building

(3) 4,000ft long pipe stalk rack with capacity to

hold approximately 18,000 tons of pipe

(4) 6 stations at 80ft intervals for welding

(5) Equipped to fabricate pipe-in-pipe stalks

Ubu Spoolbase Brazil Offshore

(1) Single joint fabrication

(2) Firing line 1 - 15 work stations

(3) Firing line 2 - 17 work stations

(4) Designed to service deepwater market

Vigra SpoolbaseNorway/

North SeaOffshore

(1) 4000ft long pipe stalk rack

(2) 1000ft fabrication building


(4) Single and double joint fabrication

(5) Fully automatic pipe handling system

Sonamet

Lobito YardYard

Angola/

West

Africa

(1) 2,000m² workshops

(2) 200m quay, 10m draft, 3,000t capacity

(3) Fabrication line for riser tower, suction

anchors, piles, spoolbase

(4) 3 x Super duplex workshops of 3,000m²

(5) 3 x 400t crawler cranes

Warri

Globestar

Yard

Yard

Nigeria/

West

Africa

(1) 2000t Quay

(2) 2 smaller Quays rated at 1000t and 500t

capacity

(3) Super duplex workshops of 1,200m²

(4) Total covered working area: 10,150m²

(5) Outdoor lifting capacity: 6 Manitowoc cranes

(6) Welding capabilities: SAW, SMAW, TGAW,

FCAW, etc

Wick

Fabrication

Site

YardScotland/

North Sea

(1) Site area – over 300,000m²

(2) Longest pipeline bundle length – 7.7km

(3) Heaviest structure/manifold assembly -

approx. 600te

(4) Site/track bearing capacity - 25te/m²

(5) Four construction tracks providing a total

capacity of almost 28km for pipeline bundles and

associated work


136

Profitability

Despite having significantly different business models, Acergy (high on lump sum contracts) and Subsea 7 (high on day-rate contracts) managed to sustain very similar profitability margins of 16% EBIT over the three years prior to merger in 2011. While margins were very high in 2006-07 due to strong pricing coupled with a high utilisation rate, we are still in the recovery phase following the oil price crash in 2009. Pricing in regions such as West Africa and the North Sea is not yet where it was in 2007, but due to strong utilisation rates since the start of 2012, Subsea 7’s margins have trended upwards.

The merger between Acergy and Subsea Inc to form Subsea 7 has not only ensured significant consolidation in the subsea market but has also allowed the new company to diversify the services provided by its vessel fleet.

Profitability for Subsea 7 in the coming years will largely depend on a) pricing and b) vessel utilisation. But in our view it is imperative that the company wins larger projects – preferably in West Africa and Brazil, as these would allow it to fully utilise the potential of its key enabler vessels. Before we dig deeper into the profitability outlook for 2013-14, we take a closer look at some of the key factors linked to the company’s profitability.

Contract mix We have identified two main types of contracts in the backlog of Subsea 7, as follows:

a) full EPIC contracts, where the company bids on a lump sum basis for a project that mainly involves installation of flowlines/umbilicals/risers and subsea platforms; and

b) day-rate contracts, under which Subsea 7 mainly charters its vessels on a day-rate basis. Historically, a significant proportion of Subsea Inc’s business in the North Sea used this contract structure. Furthermore, Subsea 7 is currently carrying out (and planning to increase) its charter business with Petrobras in Brazil on such contracts.

Theoretically, there is more scope for profitability in full EPIC contracts as long as all the risks have been correctly assessed and the contract finishes on schedule – simply because pricing in these contracts is less transparent than in day-rate contracts. However, given the stark similarity in profitability of Subsea 7 and Acergy in the past, it is hard to argue that contract structure makes any difference as long as key enabler vessels are utilised to the right extent and priced appropriately. Other than these two contract structures, we have also encountered a unique contract structure with regard to Subsea 7 – the bundling approach.

Bundling technology The Subsea 7 pipeline bundle product integrates the required flowlines, water injection, gas lift, chemical injection and control system necessary for any subsea development and assembles them within a steel carrier pipe. At each end of the pipeline, the towhead structures, incorporating equipment and valves designed specifically for the field, are attached. The system, which has been fully function-tested onshore, is then launched and transported to its offshore location using the controlled depth tow method (CDTM). CDTM, which was pioneered and developed by Subsea 7, involves the transportation of pre-fabricated and fully tested pipelines, control lines and umbilicals in a bundle configuration suspended between two tugs. Once launched from the onshore site, the bundle is transported


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to its offshore location at a controlled depth below the surface. On arrival at the field, the bundle is lowered to the seabed and manoeuvred into location, and the carrier pipe is flooded to stabilise the bundle in its final position.

This concept is a major product offering of Subsea 7 and provides an economical, reliable and timely solution for its clients in our view. This approach is mainly used in areas with congested sea beds in deepwater, diverless operations. The current bundle product offering can be used in water up to a depth of 700m and the Wick site in Scotland can make pipes up to 7.8km in length. The site has received significant capex from Subsea 7, mainly due to the strong order book of the last few years.

In our view, Subsea 7 can make almost 35% EBITDA margins on these projects because a) it has a very strong position in this market; b) bundled technology enables projects to be completed faster than normal, especially in congested/diverless environments; c) in normal cases (such as in the North Sea), operators have to trench the pipe after the laying job is finished, adding to the cost of the project. But in this case trenching can be avoided because the pipe is coated with a layer of protective paint; and d) even though Subsea 7 may price the project as a normal EPIC contract, the usage of vessels with this approach is much less than in a normal EPIC project.

Current projects Subsea 7 has been using this technology for the past 30 years and has completed 60 or more projects based on this technology. As of now, there are five projects using this technology – details of which we have provided in the table below.

Projects using bundling technology


In our view, the Knarr project will be highly profitable for the company as it is one of the highest-value projects for the company using this approach. Moreover, given that the project finishes in 2014, we think it will be a key contributor to the company’s profitability next year.

Profitability by projects Given the level of disclosure on individual projects, it is very difficult to assess profitability on a project-by-project basis for Subsea 7, but we have tried to do so by looking at the nature of the contract (full EPIC, day-rate or bundled). In the following table, we have provided estimates for individual projects in terms of EBITDA margin and absolute level of profit.

Project Country Date won Client Value ($m)

Montrose Area Redevelopment Project UK 27/02/2013Talisman/

Sinopec285

Fram oil and gas development North Sea 21/01/2013 Shell 136

Western Isles development project UK 04/01/2013Dana

Petroleum300

Knarr field: SURF contractNorway/ North

Sea02/07/2012 BG 400

North Sea: Pipeline systemNorway/ North

Sea19/06/2012 95


138

We have attempted to understand the nature of each project along with the level of involvement. We have split the project into E (engineering), P (procurement & transportation), I (installation) and C (construction). Given that a) each of these stages of a project involves different level of profitability and b) each project has a different split in terms of nature of work, we have provided a breakdown of the nature of the work by project in the following table.

Backlog profitability model

Source: Berenberg

Timing of profitability Given the material differences in profit margin for the different stages of an EPIC, it is imperative to analyse the timing and stage of completion of individual projects to arrive at a yearly outlook for profitability. In general, projects in their final stage have disproportionately high profitability simply because a) margins are generally very high on the installation part, which is usually the final part; and b) it is very likely that companies have built several contingency provisions into a project which they tend to release towards the end of the project. Given the current backlog, we estimate that 2014 will see a significant portion of revenues from the late stages of projects, implying higher profitability for the year compared to 2013. In the following chart, we compare the split of projects for 2012-14 by stage.

Client

Contract

value

Total

profit

Project profit

margin 2012 2013 2014 2015 2016

Laggan Tormore Total 250 39 15.5% 12 20

Gumusut Shell 825 140 17.0% 20 45 50

Siri Caisson Dong Energy 220 40 18.3% 10 30

CLOV development proj Total 1300 134 10.3% 20 55 60

West Franklin field development Elf exploration 190 38 20.0% 10 28

Terra Nova Suncor Energy 100 16 15.5% 8 8

Guara Lula Petrobras 1000 - 0.0% - -

Martin Linge Development Statoil 800 151 18.9% - 12 40 50 55

UOTE Petrobras 200 35 17.6% 2 5 15 15

Ofon 2 Total 467 76 16.4% - 12 29 35

Subsea Construction, IMR services BP 300 61 20.2% 12 12 15 15

Julimar Development Project Apache 100 14 13.5% - 1 6 7

Lianzi field offshore: EPIC SURF Chevron 600 114 19.0% - 14 40 60

Knarr field: SURF contract BG 400 87 21.8% 25 62

Cheviot Field: SURF contract ATP 175 44 25.0% 15 30

Terra Nova Field: SURF contract Suncor 100 18 18.3% 5 13

Clair Ridge Project: pipeline BP 100 15 15.4% 5 10

Subsea construction project SapuraAcergy 100 15 15.4% 5 10

LoF contract BP 125 25 20.0% 12 12 12 12

Cardamom and West Boreas Projects Shell 100 18 18.0% 5 13

Gorgon project Chevron 500 75 15.0% 10 20 45

G1 Project ONGC 200 37 18.3% 10 20 28

Kumang Project Petronas 0 - 10 20 28

Montara PTTEP 80 20 25.0% 5 15

LTC of PLSVs and DSVs Petrobras 400 100 25.0% 20 20 20 20 20

Long-term charter contract for a new PLSV Petrobras 500 100 20.0% 20 20 20 20 20

IMR project Petrobras 400 80 20.0% 20 20 20 20

B11, Ekofisk WI and Eldfisk Projects ConocoPhillips 150 30 20.0% 25 5

5 yr IMR contract Statoil 250 50 20.0% 10 10 20 10 10

Acergy Condor charter Petrobras 220 44 20.0% 10 20 10 10

DSV contract DSVi Collective 250 50 20.0% 10 20 10 10

Medway Development Project Dana 50 - 0.0% 5.00 5.00

181 449 605 385 145

6% 9% 21% 27% 19%

Profit estimates


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Projects by stage

Source: Berenberg

From the chart, it is apparent that 2013 will be a year of transition, in which Subsea 7 may see a marginal drop in EBITDA margins simply due to the mix of projects and stage of completion. We think 2014 EBITDA margins will be materially higher than in 2012, despite both years having a high proportion of contracts in a late stage of completion, due to factors such as:

a) better pricing for projects in 2010/2011 (late stage in 2014) compared to 2009 (late stage in 2012);

b) a higher proportion of bundled contracts (which in our view have the best profitability) in 2014 than in 2012;

c) the size and magnitude of projects to be completed in 2014 being larger than in 2012; and

d) 2014 will not have the burden of Guara Lula, a zero-profitability contract that was a material drag on profitability in 2012.

Stage1 Stage2 Stage3 Stage2&3

Client

Project profit

margin 2012 2013 2014 2015 2016

Laggan Tormore Total 15.5%

Gumusut Shell 17.0%

Siri Caisson Dong Energy 18.3%

CLOV development proj Total 10.3%

West Franklin field development Elf exploration 20.0%

Terra Nova Suncor Energy 15.5%

Guara Lula Petrobras 0.0%

Martin Linge Development Statoil 18.9%

UOTE Petrobras 17.6%

Ofon 2 Total 16.4%

Subsea Construction, IMR services BP 20.2%

Julimar Development Project Apache 13.5%

Lianzi field offshore: EPIC SURF Chevron 19.0%

Knarr field: SURF contract BG 21.8%

Cheviot Field: SURF contract ATP 25.0%

Terra Nova Field: SURF contract Suncor 18.3%

Clair Ridge Project: pipeline BP 15.4%

Subsea construction project SapuraAcergy 15.4%

LoF contract BP 20.0%

Cardamom and West Boreas Projects Shell 18.0%

Gorgon project Chevron 15.0%

G1 Project ONGC 18.3%

Kumang Project Petronas

Montara PTTEP 25.0%

LTC of PLSVs and DSVs Petrobras 25.0%

Long-term charter contract for a new PLSV Petrobras20.0%

IMR project Petrobras 20.0%

B11, Ekofisk WI and Eldfisk Projects ConocoPhillips 20.0%

5 yr IMR contract Statoil 20.0%

Acergy Condor charter Petrobras 20.0%

DSV contract DSVi Collective 20.0%

Medway Development Project Dana 0.0%


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Performance

Since showing consistent outperformance versus both the sector and the market following the recovery in oil prices during 2008-11, Subsea 7 has de-rated sharply on the back of losses on its large SURF contract in Brazil. The stock has underperformed compared to the sector and the broader market. This is despite strong order intake, which will likely sustain top-line growth. The stock’s relatively high sensitivity to oil prices stems from high operational gearing, lack of diversification and primary exposure to the capex cycle.

Subsea 7’s share price versus the pan-European market…

…and the European OFS sector


The recent underperformance can be explained by earnings momentum. The following charts highlight Subsea 7’s performance both in terms of share price and earnings relative to the OFS sector. It highlights the narrowing of the gap between the two.

Price performance and earnings momentum relative to sector


The absolute forward P/E is a reasonable indicator of value for the stock. On this basis, the current level (approaching 14x next year’s earnings) is lower than the


141

middle of its 10-year range (excluding the financial crash in 2008). This is also true of Subsea 7’s cash flow multiple, shown on the right-hand chart below

Subsea 7 forward P/E multiple (x) Subsea 7 forward P/CF multiple (x)


Since 2008, Subsea 7’s forward P/E has typically traded at a 40-60% premium to the pan-European market P/E. It is now trading at a discount to the market, highlighting the cyclical nature of the stock and the negative earnings momentum it is facing.

Against the sector, the company has historically traded at a premium of 20-40%. It is currently trading below this range with the premium having largely disappeared.

Subsea 7’s forward P/E relative to European market

Subsea 7’s P/E versus European OFS sector



142

DCF

Our DCF-based model values Subsea 7 at NOK146 per share with a target P/E ratio of 11.3x based on our 2014 EPS forecast of USD2.16. We have used a two-stage DCF model to value the company, which we think is appropriate considering the high-growth phase of the company; this is expected to continue for the next 10 years. In the high-growth phase of 2013-17, free cash flow is expected to average USD642m. We have used a WACC of 12.3% for this phase based on a cost of debt of 5%. In the long-term steady state, we assume a WACC of 9.8% based on a target debt ratio of 20%. The detailed modelling and valuation sensitivities to different WACC and terminal growth scenarios are given in the table below.

Discounted cash flow

Source: Berenberg

FCF FCF sensitivity



$ m 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E Free cash flow valuation

Revenues 6297 6790 7536 8328 9119 9940 10685 11219 11668 12076 12439

Revenue growth 7.8% 11.0% 10.5% 9.5% 9.0% 7.5% 5.0% 4.0% 3.5% 3.0% Growth post 2017 (Assets) 1.0%

Risk free rate 3.0%

EBIT 808 625 1295 1431 1521 1608 1697 1748 1783 1809 1826 Cost of debt 5.0%

EBIT margin 13% 9.2% 17.2% 17.2% 16.7% 16.2% 15.9% 15.6% 15.3% 15.0% 14.7%

Corporate tax rate 28%

Less adjusted taxes -222 -166 -392 -438 -472 -506 -517 -533 -544 -552 -557

Tax rate -27% -27% -30% -31% -31% -31% -31% -31% -31% -31% -31% Equity risk premium 7.0%

Beta 1.2

NOPLAT 587 459 903 992 1049 1102 1179 1215 1239 1257 1269 Beta post-2015 1.4

margin 9.3% 6.8% 12.0% 11.9% 11.5% 11.1% 11.0% 10.8% 10.6% 10.4% 10.2%

Cost of equity 2012-17 11.7%

Working capital -356 11 -249 -61 -63 -74 -38 -65 -74 -72 -72 WACC 2012-17 11%


Depreciation 331 392 437 474 507 535 566 595 607 604 622 WACC > 2017 9.8%

Dep/sales 5.3% 5.8% 5.8% 5.7% 5.6% 5.4% 5.3% 5.3% 5.2% 5.0% 5.0%

Net capex -758 -805 -791 -791 -775 -596 -641 -673 -642 -664 -622

Capex/sales -12.0% -11.9% -10.5% -9.5% -8.5% -6.0% -6.0% -6.0% -5.5% -5.5% -5.0%

Free cash flow to the firm -196 58 299 614 719 967 1067 1071 1130 1125 1197


Value 13-22 4,252


Net debt (m | 2012) 185

Unfunded pendion liability (m | 2012) 23


Value per share ($) 24.4

NOK/$ 6

Value per share (NOK) 146.2

FCFF

0% 1% 3% 2% 2%

8% 156 156 170 178 189

9% 189 151 156 163 163

10% 137 142 146 146 157

11% 131 134 134 142 147

12% 125 125 131 135 139


LT

WA

CC


143

Financial estimates

Income statement

Financial estimates


Considering the bidding opportunities available to Subsea 7 in its main geographies, we forecast company sales will grow at a CAGR of 10% over 2012-15. This would require average order intake of USD7bn pa, only marginally higher than the USD6.8bn order intake achieved in 2012. Our revenue growth projections are higher than consensus.

On margins, we are relatively bullish and we expect operating income to grow at a CAGR of 19% over 2013-15; consensus is for 15%. Our more positive view is based on the bottom-up modelling of revenues and profitability for each contract. The phasing out of the low-margin Brazilian contracts in 2014 should result in margin expansion, in our view.

Order intake of USD7bn pa is required to generate top-line growth of 10% CAGR over 2012-15


USD m 2010 2011 2012 2013F 2014F 2015F 3 year cagr

Sales (Beren.) 2,369 5,477 6,297 6,790 7,536 8,328 10%

Consensus 2,369 5,477 6,297 6,648 7,313 7,940 8%

EBITDA (Beren.) 558 1,000 1,139 1,017 1,731 1,905 19%

Consenus 558 1,000 1,139 1,042 1,497 1,710 15%

EBIT (Beren.) 436 641 808 625 1,295 1,431 21%

Consensus 436 641 808 659 1,048 1,275 16%

Net income (Beren.) 313 451 847 423 872 975 5%

Consensus 313 451 847 565 712 847 0%

EBITDA margin (Beren.) 24% 18% 18% 15% 23% 23%

Consensus 24% 18% 18% 16% 20% 22%

EPS (Beren.) 1.42 1.05 2.16 2.41 19%

Consensus 1.42 1.09 1.92 2.31 18%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2013E 2014E 2015E 2016E 2017E




144

Balance sheet and cash flow

Subsea 7 has maintained a healthy balance sheet despite an aggressive capex programme over the last few years. Net debt at the end of Q1 2013 stood at just EUR185m with leverage (net debt to equity) at 3%. We expect capex to average USD751m pa over the next five years; this should be covered by the operating cash flows the company is likely to generate, which we see averaging USD1.3bn pa over the period.

ROACE to rise to 19% by 2017


0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

-1000

-500

0

500

1000

1500

2012 2013E 2014E 2015E 2016E 2017E

NOPLAT Working capital Net capex ROACE (%, RHS)


145

Financials


Subsea 7 ($ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Income Statement ( $ m)

Revenues 2,369 5,477 6,297 6,790 7,536 8,328 9,119 9,940

Cost of sales 1,747- 4,530- 5,202- 5,850- 5,878- 6,496- 7,158- 7,852-

Gross profit 622 946 1,095 940 1,658 1,832 1,961 2,087

SG&A 260- 410- 373- 395- 452- 500- 547- 596-

Depreciation, Amortization &

impairment 122 359 331 392 437 474 507 535

EBITDA 558 1,000 1,139 1,017 1,731 1,905 2,028 2,144

Share in affiliates and JVs 75 104 86 80 89 98 107 117

EBIT 436 641 808 625 1,295 1,431 1,521 1,608

Net interest 19- 20- 29- 36- 30- 17- 1 23

Other gains & losses 18- 7 290 - - - - -

PBT 399 627 1,069 589 1,264 1,413 1,522 1,631

Taxation 131- 176- 222- 166- 392- 438- 472- 506-

Post tax profit 268 451 847 423 872 975 1,050 1,125

Income from continuing

operations 268 451 847 423 872 975 1,050 1,125

Discontinued operations 45 - - - - - - -

Group net income 313 451 847 423 872 975 1,050 1,125


Equity holder 265 424 830 415 855 956 1,030 1,103



146

Balance sheet

Subsea 7 ($ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Balance sheet ($ bn)

Intangible assets 6 2,602 2,599 2,599 2,599 2,599 2,599 2,599

PP&E 1,279 3,352 3,748 4,161 4,515 4,832 5,100 5,161

Interest in associates & JV 215 264 223 223 223 223 223 223

Other 86 116 104 104 104 104 104 104

Non Current assets 1,586 6,334 6,674 7,087 7,441 7,758 8,026 8,087

Construction contracts, accrued income & prepaid expenses242 898 1,012 1,012 1,012 1,012 1,012 1,012

Inventories 24 57 59 80 85 98 113 129

Receivables 382 773 1,090 1,209 1,445 1,643 1,849 2,070

Cash and CE 484 803 1,288 1,560 2,215 3,140 4,213 5,592

Other current assets 271 382 371 371 371 371 371 371

Current assets 1,403 2,914 3,821 4,232 5,128 6,264 7,558 9,174

Total assets 2,990 9,248 10,495 11,319 12,569 14,022 15,584 17,261

Debt > 1Yr 435 881 1,041 1,041 1,041 1,041 1,041 1,041

Provisions/ other 104 263 217 217 217 217 217 217

Non current liabilities 540 1,143 1,258 1,258 1,258 1,258 1,258 1,258

Account payables 673 1,219 1,452 1,603 1,594 1,744 1,902 2,065

Debt < 1Yr 0 13 495 495 495 495 495 495

Construction contracts- due to clients218 594 511 511 511 511 511 511

Others 299 446 412 412 412 412 412 412

Current liabilities 1,191 2,272 2,869 3,020 3,012 3,161 3,320 3,482

Net assets 1,259 5,833 6,368 7,041 8,300 9,603 11,007 12,521Minorities 57 52 44 58 65 72 79 87Shareholders' funds 1,203 5,781 6,325 6,533 7,295 8,050 8,854 9,714Net debt/(cash) (49) 90 248 (24) (679) (1,604) (2,678) (4,057)

Capital employed 1,239 5,952 6,639 6,590 6,704 6,540 6,278 5,767



147

Cash flow statement

Subsea 7 ($ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Cash flow ($ m)

Net income 313 451 847 423 872 975 1,050 1,125

DD&A 118 334 328 392 437 474 507 535

(Profit)/loss on disposals 0 3 0 0 0 0 0 0

Other (81) (94) (304) (0) 0 (0) 0 0

Cash flow before w/cap 350 694 871 816 1,309 1,449 1,558 1,661

Working capital (202) (114) (356) 11 (249) (61) (63) (74)

Cash flow from operations 148 579 515 827 1,060 1,388 1,495 1,587

Capex (524) (677) (758) (805) (791) (791) (775) (596)

Acquisitions 0 458 (6) 0 0 0 0 0

Disposals 3 10 345 0 0 0 0 0

Net investment (484) (125) (354) (355) (301) (250) (182) 50

Dividends paid (62) (14) (199) (200) (104) (214) (239) (257)

Cash flow after capex + divs (398) 441 (38) 272 655 925 1,074 1,379

Capital increase 5 8 7 0 0 0 0 0

Share buybacks 0 (60) (200) 0 0 0 0 0

Net debt issuance -11.1 9.2 686.7 0 0 0 0 0

Other (16) (38) (37) 0 0 0 0 0

Forex (4) (41) 65 0 0 0 0 0

Change in Net Debt (424) 319 485 272 655 925 1,074 1,379



148

Ratios

Subsea 7 ($ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Per share data

Diluted shares (m) 206.7 366.3 380.2 396.4 396.4 396.4 396.4 396.4

Clean diluted EPS ($) 1.4 1.1 1.4 1.0 2.16 2.4 2.6 2.8

Dividend per share ($) 0.0 0.6 0.6 0.3 0.6 0.7 0.8 0.8

Cash flow per share ($) 0.72 1.58 1.35 2.09 2.67 3.50 3.77 4.00

Debt-adjusted CFPS ($) 0.8 1.6 1.4 2.2 2.7 3.5 3.8 4.0

NAV/share ($) 5.82 15.78 16.64 16.48 18.40 20.31 22.33 24.51


Payout ratio (as % EPS) 0% 54% 42% 30% 30% 30% 30% 30%

ROACE 19% 13% 13% 6% 13% 15% 17% 19%

ROE 23% 8% 14% 7% 12% 12% 12% 11%

Net debt(cash)/equity -4% 2% 4% 0% -9% -20% -30% -41%

ND/(ND+E) -4% 2% 4% 0% -10% -25% -43% -71%

Capex/cash flow 355% 117% 147% 97% 75% 57% 52% 38%

Depreciation/capex 22% 49% 43% 49% 55% 60% 65% 90%

Valuation ratios

P/E (x) 12.6 19.4 15.5 17.1 8.3 7.4 6.9 6.4

P/CF (x) 24.2 14.0 16.3 8.6 6.7 5.1 4.8 4.5

EV/EBITDA (x) 6.4 8.2 7.6 7.0 3.7 2.9 2.2 1.4

EV/DACF (x) 26.3 14.6 17.6 8.9 6.2 4.0 3.0 1.9

Dividend yield (%) - 2.8 2.7 1.7 3.6 4.0 4.3 4.6

Price to book (x) 3.0 1.4 1.3 1.1 1.0 0.9 0.8 0.7

Free cash flow yield (%) 19% 16% 15% 23% 26% 31% 32% 31%


Petrofac Ltd Oil & Gas

149

Risk reward trade-off deteriorating

• We initiate coverage on Petrofac with a Hold rating and a price target of GBp1,370. Our price target is based on a DCF (WACC: 10%; terminal growth: 1%) and implies 9% upside from the current share price. Petrofac is the largest UK-listed oilfield services company and offers engineering, construction and maintenance of oil and gas facilities, both upstream and downstream. The company has three business lines: Engineering & Construction (E&C), Offshore Projects & Operations (OPO) and Integrated Engineering Services (IES).

• Risky SURF strategy: We think that its capex-heavy growth strategy to enter the SURF market, in which it has no evident competitive advantage, pose a risk to its earnings quality and sustainability. Given the entry of several new players (EMAS, McDermott), we think profitability in the SURF market (current EBITDA margin: 20%) will come under pressure.

• E&C battling the storm: E&C has excessive exposure to the Middle East where margins are structurally moving down due to competition. This makes margin contraction likely over the medium term if Petrofac is to reverse backlog erosion on a sustainable basis.

• IES is a cash drain: The higher capex commitment for offshore fleet build-up and the resultant cash flow and balance sheet stress could compromise growth at the high-margin IES division, which we also expect will be in a heavy capex phase over the next three years.

• Financial estimates: We forecast Petrofac’s ROCE will decline from 30% in 2012 to 16% by 2015 as a result of margin compression in onshore E&C and high start-up investment to enter the SURF segment over the next five years. As a result of the high capex, we expect the company’s net cash position of USD265m at end 2012 to change into a net debt position of USD1.3bn by 2015. We forecast a sales CAGR of 10% and an EPS CAGR of -0.1% for 2012-15.

Hold (initiation) Rating system

Current price

GBp 1,284

Absolute

Price target

GBp 1,370 09/07/2013 London Close Market cap GBP 4,257 m Reuters PFC.L Bloomberg PFC LN Share data

Shares outstanding (m) 340 Enterprise value (USD m) 6,873 Daily trading volume 1,005,000

Performance data

High 52 weeks (GBp) 1,737

Low 52 weeks (GBp) 1,194 Relative performance to SXXP FTSE 100 1 month 0.9 % -1.9 % 3 months -10.3 % -11.2 % 12 months -30.8 % -25.8 %

Key data

Price/book value 3.2 Net gearing 0.2% CAGR sales 2012-2015 10.3% CAGR EPS 2012-2015 -0.1%

Business activities: Petrofac is an international provider of facilities solutions to oil and gas production and processing industry

10 July 2013


Jaideep Pandya


Y/E 31.12., USD m 2011 2012 2013E 2014E 2015E

Sales 5,801 6,324 7,206 7,852 8,478

EBITDA 759 896 1,000 1,074 1,133

EBIT 679 766 846 899 889

Clean net income 543 640 664 672 638

Clean EPS 1.57 1.87 1.94 1.96 1.86

DPS 0.55 0.64 0.68 0.69 0.66

EBITDA margin 13.1% 14.2% 13.9% 13.7% 13.4%

EBIT margin 11.7% 12.1% 11.7% 11.4% 10.5%

ROE 48.5% 40.4% 34.0% 29.6% 25.1%

ROACE 49.2% 37.5% 25.7% 19.7% 16.4%

P/E 14.7 13.4 9.7 9.6 10.1

EV/CF (x) 5.0 -20.7 12.4 10.7 11.5

EV/EBITDA (x) 8.4 9.3 6.9 6.8 6.9

EV/EBIT (x) 9.4 10.9 8.1 8.1 8.7

EV/Sales(x) 1.1 1.3 1.0 0.9 0.9

Free Cash flow yield 10.3% -11.4% -7.1% -3.4% -3.2%

Dividend yield 2.4% 2.6% 3.7% 3.7% 3.5%



150

Company profile

Petrofac is the UK’s largest listed oilfield services company. Based in both the UK and UAE, it offers engineering, construction and maintenance of oil and gas facilities, both upstream and downstream. It was first listed in October 2005.

In early 2012, Petrofac unveiled a new two-divisional structure. The first is ECOM (Engineering, Construction and Operations & Maintenance), which combines its onshore and offshore engineering, procurement and construction capabilities with its operations management and consulting services. Within ECOM, there are four reporting segments: Onshore E&C, OPO, Engineering & Consulting Services (ECS) and IES.

Petrofac revenue split (2012, USD6.3bn) Net income split 2012 (USD0.63bn)


• E&C: This division carries out E&C work, mainly for onshore oil and gas projects and mainly on a lump sum (fixed price) basis. Its geographical focus is mainly in the Middle East, North Africa and the Caspian Sea region.

• The OPO division undertakes E&C work for offshore oil and gas projects. Moreover, it provides operational support (maintenance) as well as management activities for both onshore and offshore installations, the latter mainly in the North Sea.

• ECS: This small division provides engineering services both internally and to external clients.

• IES: Previously called Energy Developments, this unit participates in upstream projects, where there is no exploration risk (ie the oil and gas resources have already been discovered). It offers potential customers and partners a variety of upstream contract types and typically does not take entitlement (ownership) to either reserves or production of oil and gas.

Backlog evolution (USDbn) Revenue geographical split (2012)


E&C65%

OPO21%

ECS3%

IES11%

E&C73%

OPO9%

ECS4%

IES14%

0

2

4

6

8

10

12

14

2007 2008 2009 2010 2011 2012

Onshore E&C OPO IES

Middle East & Africa,

39%

CIS & Asia, 36%

Europe, 20%

Other, 5%


151

Investment thesis

Our investment thesis is based on our bearishness on Petrofac’s growth strategy which, in our view, puts at risk its earnings quality and capital efficiency. We project that its ROCE will decline from 30% in 2012 to 15% in 2015. This is based on our forecasts for EBITDA and sales growing by 7% and 10% during the period. Our EBITDA growth projections are 9% lower on average compared to consensus over 2013-15. The core reasons why we have a Hold rating on the stock are as follows.

1. Offshore: In a broader macro-environment where oil price weakness and cost inflation are encouraging oil companies to reassess, and in some cases cancel, large projects, Petrofac’s growth path will increase its exposure to the oil and gas capex cycle and raise its risk profile. We think Petrofac lacks the strong differentiating features to compete effectively with entrenched players like Technip and Subsea 7. It will likely have to compromise on margins as it lacks expertise, local content and associated infrastructure (spool bases, fabrication yards). The divisional ROCE, in our view, would not justify the undertaken risks.

2. Onshore: We think that Petrofac would also have to choose between margins and growth in its onshore E&C and maintenance and modification (MMO) business. Competitive pressures are high in its key geographies, MENA (E&C) and the North Sea and Asia (MMO). While we think Petrofac will be able to reverse backlog attrition in E&C, we forecast divisional margin compression of 181bp over 2012-15.

3. IES: The Petrofac IES division would require capex of USD0.5bn-1bn over 2013-15 and would remain free cash flow negative. Higher working capital requirements in onshore E&C and capex commitments for fleet build-up will likely create balance sheet stress and potentially compromise growth in high-margin IES division.

4. Valuation: We initiate coverage on Petrofac with a Hold rating and a target price of GBP13.7 which is based on a DCF model (WACC: 10%, terminal growth: 1%). Our target P/E on 2014 EPS of 10.4x is lower than the historical trading range of 12-16x. We think that the stock justifies a discount compared to the historical multiples at which it has traded due to uncertainty regarding the success of its growth strategy and increasing balance sheet stress.


152

Reasons to Hold

Reason #1: SURF growth strategy puts earnings quality at risk Petrofac has been taking more offshore capital projects to develop greenfields in the North Sea and Asia-Pacific, revenues for which are included in the OPO and IES divisions at the moment. Recent contracts include the FPSO-based Brentai development in Malaysia, where Petrofac is developing the field for Petronas on a risk service contract basis. Petrofac recently announced plans to enhance its offshore field construction capability and over 2013-17 will invest USD1bn to gain SURF installation capability.

This capex would entail developing a fleet of supporting vessels around a top-end vessel which would have heavy-lift and deepwater pipelay capability. According to Petrofac’s management, these vessels would target the deepwater golden triangle, ie Brazil, the GoM and West Africa. It believes that, post-consolidation, in the subsea space (Acergy/Subsea 7 merger, Technip/Heerema alliance), this is a good point for a new player. The fleet build-up will take around four to five years and Petrofac will start bidding for projects for 2016 onwards.

We think that Petrofac’s timing and market assessment is completely off, and that this might not the best use of the firm’s capital – especially when its high-margin IES business is in a heavy capex phase. We do not foresee tightness at the high-end subsea installation space, and the margins which Petrofac is aiming at will prove difficult to achieve.

There is already an oversupply of vessels in the low-end installation space. At the same time, a number of large high-end enabler vessels will be joining the market over the coming years (see table below). Second-tier players are in the mid- to late capex stages in order to enhance SURF capabilities. These include McDermott, which has invested USD1bn over the last five years. Companies like EMAS and Heerema are introducing vessels with revolutionary lifted-reel pipelay technology which will give them the competitive advantage against larger players Technip, Subsea 7 and Saipem. The rising competitive pressures are evident from the fact that subsea margin for most of the contractors has gradually fallen since 2011. We also observe that oil companies are either postponing or cancelling large projects (the recent examples being Mad Dog 2 and Hadrian), and the tendering process is taking much longer than anticipated. Demand-side weakness could even exacerbate this downward margin trend.

In our view, Petrofac has limited – if any – competitive advantage in the SURF segment. It has no experience, relationships or local content in the golden triangle region that it targets. Yves Inbona, who joined Petrofac last year and is leading the company’s offshore thrust, should learn from the poor experience of Saipem (his former employer) in expanding into Brazil. Weak local content, high competition from existing players and a dominant client has resulted in it taking projects at zero margins. If a global offshore contractor like Saipem is finding it difficult to enter new geographies, we do not foresee the Petrofac experience being any better – especially when oil companies prefer contractors with full EPIC capability and resource nations demand local content.

Apart from its onshore presence in Mexico, these are all virgin territories in which the company has no experience, relationships and associated infrastructure. We also doubt how Petrofac would be able to use the strengths it has in the low- to medium-tech end of onshore E&C.


153

We observe that the SURF operating margins for the leading SURF players like Technip and Subsea 7 have been facing downward pressure. However, EBITDA margins are still high, at around ~20%. We forecast margin expansion for Petrofac’s OPO division, which currently includes revenues from capital projects along with that from traditional maintenance and modification work. We expect the EBITDA margins for the OPO division to double from 6.8% in 2012 to 13% in 2020. Revenues are expected to grow at an average rate of 20% pa over the next 10 years. However, despite the higher margin contribution from the SURF projects, the asset-heavy growth strategy would, on our forecasts, lead to an ROCE contraction from 30% in 2012 to 16% in 2015.

A number of new high-end vessels will enter the market by 2016

Source: Berenberg and company data

Vessel Contractor Type Delivery year

Lift

capability

(tons)

Speed

(knots)

Water

depth (m)

Castorone Saipem Pipelaying vessel 2013 600 14 3000

Seven Waves Subsea 7Contruction and Verical

Flexlay2014 0 3000

Deep Orient TechnipFlexible-Lay &

Construction2013 250 13 3000

2*550t PLSV TechnipFlexible-Lay &

Constructionn.a. 2500

ST 261 TechnipFlexible-Lay &

Construction2014 400 13 3000

Deep Energy Technip Rigid Reel lay & J lay 2013 150 20 3000

Lay Vessel 108 McDermot Rigid and flexible lay 2014 0 3048

DLV 2000 McDermot Heavy lift and S lay 2015 2000 13.5 3000

Aegir HeeremaDeep water construction

vessel2013 4000 3500

Pieter Schelte Allseas Heavy lift & trunklay early 2014 48000 14 3000

Lewak Constellation EMAS Reel and flexible lay 41852 3000 0 3000

DLV 5000 PetrofacHeavy lift & Rigid

pipelay2016 5000 0 2000


154

Reason #2: Onshore E&C and MMO to face margin attrition Onshore E&C and traditional offshore MMO work forms the bulk (more than 80%) of Petrofac’s top line. The two divisions have faced a structural shift in operating environment with the level of competition adversely affecting margins. Petrofac, in our view, will have to choose between margin compression and backlog attrition.

Onshore E&C: Petrofac has high exposure to the MENA region, which formed 40% of its overall backlog in 2012. The region has seen market entry and rising competition from Asian players in recent years and commoditising of onshore E&C business. Onshore E&C, being asset-light, has only a few barriers to entry – technology and human capital being the main ones – and, as a result, has become increasingly fragmented. Petrofac is a midstream player and involved in low-end work such as gas processing, tank farms and onshore pipelines. Margins in this division can be volatile, a function of the lumpy nature of larger turnkey contracts which have a typical duration of two to four years.

Onshore E&C revenue split by geography: has high exposure to the MENA region which we estimate contributed 62% to divisional revenues


Despite this low-end exposure and tough operating environment, Petrofac’s track record has been more consistent versus its European peers. From June 2012 to May 2013, Petrofac won USD7.15bn of contracts in the Middle East which placed it first among the list of top 10 contractors in the regions and well ahead of its European peers Saipem and Tecnicas Reunidas.

Middle East39%

North Africa23%

CIS38%


155

Petrofac has gained market share in MENA, but the competitive landscape has deteriorated


However, despite the strong relative performance and gain in market share, all is not good for Petrofac. The company’s E&C backlog has eroded significantly due to slippage in contract awards in the Middle East – Petrofac’s core market. Since 2010, the backlog has nearly halved. The major contracts won by Petrofac in H1 2013 and the strong bid pipeline for downstream project in the MENA region should help Petrofac reverse backlog attrition in 2013. However, we think that margins will likely take a hit. A number of large and high-margin projects like South Yolatan (USD3.4bn), Ruwais (USD1bn) and Laggan Tormore (USD800m) will be completed this year.

Onshore E&C remains Petrofac’s largest reporting segment, responsible for nearly two-thirds of its revenues, and more than 70% of net profits. Therefore, any weakness in this segment will be difficult to negate.

In addition, Petrofac’s E&C division also has high project risk, where only five projects contributed over three-quarters of the revenues in 2012. Although it has never lost money on lump sum E&C projects, a highly aggressive bidding environment and the quest to reverse backlog erosion creates the risk of potential slippage for the company. Another cause of concern is the deteriorating contractual terms for E&C projects which are experiencing rising working capital requirements with an increasing number of new projects coming with low or no prepayments. The negative working capital nature of the onshore E&C business was one cash source for the capex-hungry IES division. High working capital requirements are creating cash flow stress for Petrofac, whose cash position fell by USD960m to only USD614m in 2012. The company would have to tap the equity and debt markets to finance growth in IES and offshore capital projects if this trend continues.

We forecast Onshore E&C will grow at a low five-year CAGR of 2% by 2013-15, while margins will compress by 181bp during the period.

Contracts won during June 2012- May 2013

$ bn

Petrofac 7.15

Samsung Engineering 5.1

Tecnicas Reunidas 3.81

Daelim industrial 2.68

SK Engineering and Construction 2.41

Hyundai E&C 1.88

JGC Corporation 1.65

Hanwha E&C 1.05

Technip 1.01

Saipem 0.8

$ bn

Samsung Engineering 12.4

Daelim 10.1

GS E&C 8.6

JGC Corporation 8.3

SK E&C 7.8

Saipem 7.8

Petrofac 5.1

Hyundai E&C 4.7

Tecnicas Reunidas 4.6

Technip 4.4

Tecnimont 3.7

CTCI Corporation 2.5

McDermott 2.3

NPCC 2.2

Daewoo E&C 2.1

Projects under execution by contractor as Sep'12


156

OPO: Given the general trend towards outsourcing across the industry, Petrofac has expanded its OPO business internationally in the Middle East and has won contracts in countries such as Iraq (it has a one-year maintenance contract with BP at the giant Rumaila oil field), Thailand (Jasmine), Malaysia (Bekok-C platform and Sepat projects), as well as contracts to provide onshore and offshore engineering and construction services to all of Apache’s North Sea assets. These contract wins have helped bring the divisional backlog up to the record level of USD3.5bn in 2012. Strong cash flows generated by OPO have been one of the main financing sources for the capex-heavy IES (see chart below). With the company’s capex commitments likely to rise further to fund its market entry into offshore field construction, the importance of the less risky oil and gas infrastructure maintenance and modification business for Petrofac will only increase.

Cash flows (EBITDA less tax and capex) generated by OPO is financing IES growth

Growth capex (capex less DDA)


Macro-economic trends point to the operating environment for OPO becoming tougher. Increased competition from the likes of Wood Group and Amec, the recent expansion of Aker in Asia and the entry of big players like Worley Parson, which acquired Rosenberg, all point to increasing industry fragmentation. This has led to a move towards KPI-linked contracts which are inherently more risky while, at the same time, margins have deteriorated for the sector. Clients are also now seeking to re-tender expiring contracts, rather than roll them over, in order to obtain lower costs and test new supplier models. This can be seen as both an opportunity (winning contracts) and a threat (losing them) for Petrofac. While the contracting environment is becoming tough in the OPO space, Petrofac has been able to raise margins through lowering costs and expanding into offshore capital projects like the Don field development (the UK) and Berentai and Cendor fields (Malaysia).

In our view, there is a plausible risk that Petrofac is taking its focus off the stable maintenance and modification business for offshore capital projects. In a tough operating environment, this could result in its lunch being eaten by more nimble players. Already, we can see that, stripping out capital projects, Petrofac’s growth capex, ie capex less DDA, has been marginal in the segment in recent years. In our view, Petrofac needs a more balanced growth strategy which gives emphasis on protecting and growing market share in the more stable and defensive parts of its service portfolio when its own risk profile is set to rise.

-400.0

-300.0

-200.0

-100.0

0.0

100.0

200.0

2008 2009 2010 2011 2012

OPO IES-10

0

10

20

30

40

50

60

2005 2006 2007 2008 2009 2010 2011 2012


157

Reason #3: BS stress and offshore thrust could compromise IES growth Over the past decade, Petrofac’s growth strategy has been based on leveraging its strong balance sheet and cash flows from its stable cash-generative OPO business and negative working capital onshore E&C division to take upstream exposure. So while offshore E&C contractors have invested heavily in fleet and associated infrastructure (yards, manufacturing plants and spool bases), Petrofac has used the asset-light nature of the rest of its business and has invested heavily in the emerging IES business. Over the last three years, 72% of its overall capex has been spent on the IES division. This has led to strong backlog growth for the division during the period. IES high-margin order intake has, to date, been able to neutralise the poor E&C project intake.

Until 2011, Petrofac has been able to maintain this high capex commitment while keeping balance sheet in a net cash position. However, we doubt that this trend will be sustainable in the long term as a result of structural changes occurring in both E&C and OPO space – both onshore and offshore – which are putting pressure on margins and growth while raising working capital requirements. The initial effects were already visible in 2012, where the net cash position fell by USD1.2bn to just USD265m. Net working capital increased by USD918m in 2012, and we expect the working capital requirement to average out at USD228m over 2013-17 compared to the negative working capital position historically. This would be an additional strain on the cash position.

Despite its worsening cash profile and high capex commitments over the next five years – which are expected to average USD510m pa for the IES division – Petrofac will now be investing USD1bn over the five-year period to enter the subsea E&C market. Because of the high capex commitments, we estimate that its net cash position will convert to a net debt of USD412m this year and that leverage (net debt to equity) will rise to 48% by 2016. Rising balance sheet stress along with high capex commitment for fleet build-up could compromise growth in high-margin IES, in our view.


158

Reason #4: Valuation We initiate coverage on Petrofac with a Hold rating and a target price of GBP13.7, based on a DCF (WACC 10%; terminal growth: 1%) model. Our target P/E on 2014 EPS of 10.4x is lower than the historical trading range of 12-16x, but is in line with the current price multiple. We think that the stock justifies a discount compared to historical multiples due to uncertainty regarding the success of the company’s growth strategy and rising balance sheet stress.

Petrofac has historically traded in line with the EU Oil Equipment & Services Index. However, on a 12-month forward P/E, it has moved to a discount of 27%. We think that the market has priced in the changed risk profile of the company. Further price movement will effectively depend on whether Petrofac is able to execute its market entry into the SURF segment along with reversing backlog attrition in Onshore E&C.


Source: DataStream

Petrofac’s discount to the EU Oil Equipment & Services Index has risen to 24% on a 12-month forward P/E since the start of 2013

Source: DataStream

0

5

10

15

20

25

2008 2009 2010 2011 2012 2013

12M Forward PE

0

2

4

6

8

10

12

14

16

18

20

2011 2012 2013

Petrofac EU oil equip & services index


159

Catalysts in the short to medium term

1) Uptake of low margin (less than 7%) contracts in the Middle East.

2) Clarity on SURF capex for market entry which points to a larger-than-expected scale of fleet and associated infrastructure.

3) A compromise on margins as the company bids on contracts to enter the SURF market.

Risks to thesis

1) Sharp and sustainable increase in oil prices which cause an across-the-board increase in vessel day rates.

2) A toning down of SURF ambitions with a downward reassessment and delay in capex.

3) Successful diversification of onshore backlog away from the Middle East.

Where do we stand versus consensus?

We are bullish compared to consensus about the top line and bearish on margins for Petrofac. The reason we differ from consensus is because we think that the company will opt for growth over quality, especially in the onshore E&C division for which we expect EBITDA margin contraction of 181bp over 2013-17. This will be offset by growing revenue streams from the high-margin but much smaller IES division. Overall, we expect 1.1% EBITDA margin contraction for the company versus a 3.6% margin expansion expected by consensus.

We acknowledge Petrofac’s strengths in MENA based on its tax advantage of being locally based and its local NOC linkages through its JV with Mubadala (named Petrofac Emirates). This gives it the ability to compete and hold ground against Asian peers, and compete it will. However, contract wins will be at the expense of margins.

We expect top-line growth to come in at a 10% CAGR over 2012-15 versus consensus expectations of 8%. Revenue growth will be driven by the strong bid pipeline for downstream E&C projects in the MENA region, where consultant MEED expects USD175.5bn in projects to be awarded in the region between June 2013 and May 2014.

Financial estimates: Berenberg versus consensus

Source: DataStream

2012 2013E 2014E 2015E

3Yr cagr

2012-15

Sales (Beren.) 6,324 7,206 7,852 8,478 10%

Consensus 6,324 6460 7236 7883 8%

EBITDA (Beren.) 915 1,000 1,074 1,133 7%

Consensus 915 1020 1216 1404 15%

EPS (Beren.) 1.87 1.94 1.96 1.86 -0.1%

Consensus 1.87 1.90 2.23 2.52 11%

Petrofac Ltd Oil and gas

160

Onshore E&C – increasing headwinds

Divisional background: Petrofac’s Onshore E&C is not involved in some of the more high profile technologies, such as LNG liquefaction plants and GTL – it is more “mid-tech” (eg gas processing plants) compared with the more advanced technologies deployed by Technip. However, by sticking to its core markets of MENA and central Asia, it has established a leading presence with a strong track record and reputation, as well as strong links with local NOCs. As a result, it has been able to compete in the Middle East where Asian activity has been rife. This has particularly been the case for downstream projects (eg refining, petrochemicals), which Petrofac has tended to side-step. Although it could provide E&C capability for utility services on-site, it would typically seek to partner with a more established player for the central processing units.

Onshore E&C Revenue split by geography: high exposure to the MENA region which we estimate contributed 62% to divisional revenues in 2012

Source: DataStream

Onshore E&C financial projections

Low single-digit top-line growth and gradual margin erosion expected


After achieving strong backlog growth in onshore E&C up to 2010, Petrofac has literally fallen over the fiscal cliff, with the order book declining from USD9bn in 2010 to USD5.1bn in 2012. During this period, revenues have held up as a result of the back-end-loaded nature of these contracts. However, Petrofac has already

Middle East39%

North Africa23%

CIS38%

$ m 2012 2013E 2014E 2015E

3r CAGR

2013-15

Sales 4,358 4,314 4,401 4,621 2%

As % group 69% 60% 56% 55%

growth 5% -1% 2% 5%

EBITDA 580 561 528 531 -3%

As % group 65% 56% 50% 48%

EBITDA margin (%) 13.3% 13.0% 12.0% 11.5%


161

exhausted this flexibility, and would need to generate order intake of USD5.2bn pa over the next five years just to keep revenues at around the same level. As per management guidance, divisional backlog would likely grow this year, which we think is highly probable considering the contracts wins ytd and the bid pipeline for the remainder of the year. In nominal terms, this would require an order intake of at least USD3.2bn, which is the quantum of the backlog which expires in 2013.

Order intake needs to average USD5.2bn pa over 2013-17 to generate low top-line growth averaging at 2% during the period


0%

10%

20%

30%

40%

50%

60%

70%

80%

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

2013E 2014E 2015E 2016E 2017E

Revenue Backlog schedule



162

Key themes for onshore E&C

Theme # 1: strong bid pipeline to support top line-growth The Middle East, the hub of the onshore oil and gas E&C market, has experienced subdued contract awards since 2009. The slump in global demand, political instability from Arab Spring and bureaucratic bottlenecks in countries such as Iraq have led to delayed project awards. MEED estimates that there were USD170bn of unawarded projects in GCC countries at end-Q3 2012 (see chart below). This trend continued into 2012 with project awards at par with 2011 (USD25bn). Project sanctioning picked up in 2013, where USD43bn of contracts were awarded between June 2012 and May 2013. Between June 2013 and May 2014, MEED expects USD175bn of upstream and downstream contracts awards, a level which is markedly higher than the last few years.

Oil and gas project awards in the GCC

Source: MEED

On the upstream side, the main drivers for higher capital outlays include: 1) attempts to neutralise the natural depletion rate of mature fields; and 2) the higher production targets of OPEC countries, particularly Iraq. On the downstream side, rising local demand for refined products and stronger employment generation efforts underpin attempts by the Gulf countries to increase the refining capacity of heavy oils and to move lower down the petrochemical value chain.

We expect gas developments on the upstream side and refining in downstream to exhibit the strongest growth in the Middle East. Strong gas demand from the power, industrial and petrochemical sector in the region, along with the limits on associated gas production due to OPEC quotas, is shifting focus on developing non-associated gas fields. Similarly, key OPEC members like Saudi Arabia, the UAE and Kuwait have ramped up targets for refining capacity. Considering that export of refined products falls outside OPEC quotas, member countries are being tempted to raise exports of refined products in the face of crude oil capacity additions in countries like Iraq.

In our view, Petrofac is well placed to benefit from these structural trends. Its low cost base and strong local linkages with the NOCs as well as local subcontractors give it an edge over its European peers. In addition, it is good at executing gas developments and associated midstream infrastructure comprising gas processing plants, onshore pipelines and tank farms.

http://www.meed.com/attachments.aspx?js=yes&height=auto&width=572&storycode=3156558&attype=P&atcode=36729

http://www.meed.com/attachments.aspx?js=yes&height=auto&width=572&storycode=3156558&attype=P&atcode=36730


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Strong bid pipeline: USD175.5bn worth of projects to be sanctioned June 2013-May 2014


Future growth: E&C by theme MEED estimates that it currently has USD170bn worth of projects in the study, planning, engineering and tendering phase in the GCC region. In 2013, oil and gas project awards are expected to grow on the back of attempts by OPEC members to raise production capacity. Iraq is aiming to lift production capacity to 12mbd by 2017 from the current level of 3mbd. Strong onshore upstream investment, along with strong motivation among OPEC members, especially Saudi Arabia, in order to spur employment generation, should result in development of the downstream value chain. In this section, we discuss the key themes in onshore E&C and key developments to take place in primary GCC countries – and outline what opportunities this would entail for Petrofac.

Gas developments: Demand for gas in the GCC countries is growing at a brisk pace, which is prompting an influx of investment in gas developments. Growing demand from the power, industrial and petrochemical sectors is driving capex in gas projects. In an attempt to maintain oil export capacity, countries like Saudi Arabia want to shift electricity generation to gas from oil. Outside of Qatar, new power and petrochemical projects are having difficulty obtaining long-term gas supplies which highlights the tightness of the gas market in the Middle East. A number of LNG import terminals are being planned in countries such as Bahrain and Kuwait. Focus is also shifting to non-associated sour gas developments because of OPEC quota restrictions on associated gas.

MEED estimates that Saudi Arabia and Oman will invest USD5.1bn each in new gas projects, with the UAE likely to spend USD1.8bn in raising gas production capacity.

Projects Country Sector

Budget ($

bn)

Iraq strategic crude oil export pipeline: Haditha-Aquaba Iraq Oil 11.2

Iraq strategic crude oil export pipeline: Basra Haditha Iraq Oil 10.2

Karbala refinery expansion Iraq Oil 7.8

Kirkuk refinery expansion Iraq Oil 6

Clean fuel project: Mina Abdullah - package 1 Kuwait Oil 6

Clean fuel project: Mina Abdullah - package 2 Kuwait Oil 6

Duqm refinery Oman Oil 6

Clean fuel project : Mina al-Ahmadi package Kuwait Oil 5.8

New refinery project: package 1 (process plant) Kuwait Oil 3.7

Fujairah refinery (phase 1) UAE Oil 3.5

Kuwait environmental remediation project Kuwait Oil 3.5

Petrochemicals complex Iraq Chemicals 3.2

New refinery project: package 3 (utilities and offsites) Kuwait Oil 3

New refinery project package 2 (process plant) Kuwait Oil 3

Khazzan and Makarem fields: early field development Oman Gas 3

Al-Karaana Petrochemical package 2: MEG, olefins, alcohol units Qatar Chemicals 3

The North Reggane project Algeria Gas 3

Dorra gas field development offshore Saudi Arabia Gas 3

Halfaya project surface facility: phase 2 Iraq Oil 2.5

New refinery Project: package 4 (tankage) Kuwait Oil 2.5

Malaysian oil refinery Iraq Oil 2.5


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Key upcoming gas developments include the following.

1) A USD15bn BP tight gas project in Oman, where FID is expected in 2013: BP expects full field development to cost around USD15bn. Reserve size is huge, at 30tcf gas, and the first phase of development would be targeting 1.2bcfd in production.

2) The North Reggane project: The state-run national oil company in Algeria, Sonatrach, has upped the tempo of its four-year USD68bn investment programme by signing a deal with a consortium led by Spanish oil firm Repsol for the development of six new gas fields in the country’s North Reggane project, according to the Oxford Business Group (OBG). The USD3bn venture in the Sahara desert will include the construction of a pipeline from Algeria to Spain which should begin operations in mid-2016, while production from the gas wells is expected to reach a stable 8m cubic metres of gas per day in the first 12 years of the project. Production from the gas wells will be instrumental in meeting Spanish demand, estimated at 36bn cubic metres.

Refining: A number of mega refining projects are being planned in the MENA region. Several countries are planning to raise refining capacity. The thrust comes from an attempt by key OPEC countries, such as Saudi Arabia, to boost the export of refined products which are not restricted by OPEC quotas. With conventional oil production sharply ramping up in countries like Iraq, and unconventional oil production growing in North America, this shift towards refined oil products seems timely.

Saudi Arabia is planning to double its refining capacity by 2015. Refineries currently in execution include Yanbu and Jubail. These are aiming to refine bottom-of-the-barrel heavy oil for exporting refined products to Asia and Europe. The UAE is targeting refining capacity of 0.62mbd and are currently executing the USD10.1bn Ruwais refinery expansion project which is expected to be completed by Q1 2014. Oman is focusing on integrated refining and petrochemical plants to the lack of additional supplies of gas feedstock for new petrochemical plants.

Key upcoming refining projects in the MENA region include the following.

1) UAE: A USD3.5bn 0.2mbd second refinery at Fujarah. Technip is executing the FEED design project. The EPIC award is expected to be announced by 2013.

2) Oman: A USD1.5bn-1.8bn expansion of the Sohar refinery is planned, for which nine international contractors have been shortlisted. These include Technip, Tecnicas Reunidas, Hyundai and GS Engineering. The contract is to be announced by mid-2013.

3) Oman: The USD5bn 0.23mbd Duqm refinery is also at the study stage, with FEED expected by the end of 2012 and the EPIC award anticipated for 2014.

4) Bahrain: A USD8bn expansion of the Sitra refinery is at the planning stage.

5) Kuwait: The USD14bn Al Zour refinery is at the planning stage, with the project tender likely in 2013.

Petrochemicals: Saudi Arabia is leading the push in greater diversification by developing a plastics conversion sector. This thrust to move down the petrochemicals value chain is being backed by the aim to spur greater employment generation. Saudi Arabia is linking the development of the plastics industry in an


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attempt to develop the automobile production sector in the country. The new speciality chemicals industry would use the base chemicals (polyethylene and ethylene glycol) that it currently produces. Oman is moving along in its strategy to integrate refining and petrochemicals hubs to use ethylene out of the refining plant as feedstock in petrochemical plants.

Key upcoming petrochemical projects include the following.

1) Oman: USD800m capex for the Sohar plastics plant.

2) Oman: The Duqm petrochemicals plant.

3) Saudi Arabia: A number of projects which are estimated to cost over USD28bn from 2013-20 (see table below).

Sabic future projects, 2011-2020

Source: MEED

Theme #2: Petrofac to sacrifice margins for growth Despite healthy demand trends in the onshore E&C space, we think that margins are headed downwards for the onshore E&C sector. This is because the operating environment has become difficult in the MENA region due to a fragmented contractor market and cut-throat competition from South Korean companies. Being based in Sharjah, which has a zero corporate tax rate and access to a local value chain, has given Petrofac the ability to maintain market share in a highly competitive market. Over the last 12 months, it has won the most contracts (estimated at ~USD7bn) in the MENA region. This aggressive posturing, though good for the top line, would translate in lower overall margins in our view.

Petrofac needs to reverse backlog attrition We think that over the next 12 months, Petrofac will continue to bid aggressively for projects. This is because it needs to re-build its onshore E&C backlog, which has eroded significantly over the last three years due to slippage in contract awards in the Middle East. Since 2010, the backlog has nearly halved to reach USD5.1bn at end-2012. With 63% of the remaining backlog maturing in 2013, revenue visibility for 2014 onwards has diminished. We think that the need to reverse backlog attrition would tempt Petrofac to maintain an aggressive bidding stance in the region.


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Onshore E&C – sales (USDbn) and growth (%)

Onshore E&C – order backlog (USDbn) versus book-to-bill


Theme #3: project phasing to negatively impact margins in 2014 In this section, we look at Petrofac’s profitability profile based on a comprehensive bottom-up analysis of its ongoing E&C projects. The profit margin on any project is dependent on three factors: 1) the project stage; 2) the project type and location; and 3) the contracting environment at the time of project award. The following graph shows Petrofac’s profit recognition schedule for a typical EPC project which highlights that greater profits are booked as the risk profile of the project improves.

Profit recognition profile


Petrofac does not recognise any profit at the engineering stage and there is a spike in profit recognition when procurement begins. As the project moves further down the execution phase, the built-in contingencies are released, which further boost profit margins. So margins are higher in the later stage of the project and near zero at the engineering stage. For modelling purposes, we have assumed zero margins at the engineering stage and 3% in procurement.

The following graph plots the revenue contribution of the contracts in the backlog by project stage. As can be seen, in 2014 most of the contracts will be in the zero margin procurement phase. In contrast in 2013, a number of major ~USD1bn projects like the Yoloton gas field development, Ruwain NGL and Laggan

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Tormore will be at the construction phase. This clearly highlights that margins in 2014 will experience a dip because of project phasing of the contracts currently in the backlog. In addition, the contracts it will win in 2013 will only reach profit recognition in 2015.

Backlog revenue conversion by project stage (USDm)


Another major determinant of profitability is the regional mix of the projects. Petrofac targets a higher profit margin on more risky EPC projects, particularly those in new territories – eg areas outside the MENA region. Since 2006, Petrofac has executed major EPC projects in various new regions, including the Kashagan and Karachaganak projects in Kazakhstan, the South Yoloton Project in Turkmenistan and the Salam gas plant in Egypt. Standard lump sum projects, in particular gas developments in the Middle East, command much lower margins.

At the same time, the strong presence of South Korean competitors also makes achievement of the 11% margin target difficult in the Middle East. From a regional perspective, Petrofac’s projects in Algeria and Turkmenistan command higher margins compared to the Middle East, while projects in Iraq lie somewhere in the middle in terms of profitability. In 2013, the main non-MENA projects would have been completed, which will have a negative impact overall profitability in 2014. The following graph plots the profit stream from the contracts currently in the backlog and the associated overall EBITDA margins. As can be seen, there would be a dip in margins in 2014.

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Profit stream (USDm) from the current backlog and associated backlog margin


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IES

Divisional background: Petrofac’s IES division leverages on the company’s E&C skills, along with a healthy balance sheet, in order to co-invest alongside its clients in upstream oil and gas projects (as Petrofac puts it, “the provision of financial capital in addition to our intellectual capital”). In contrast with the E&C business, this activity requires upfront investment of capital, and so acts as an offset. The hiring last year of Andy Inglis, BP’s former head of upstream, signalled Petrofac’s intention to capitalise on what it sees as a niche in the market and expand the business aggressively. In 2011, it struck a partnership with Schlumberger, the world’s biggest and (arguably) best oil services company, to complement Schlumberger’s down-hole expertise with the above-ground project management and execution skills of Petrofac. Recently, the JV has bid successfully in the latest bid round for service contracts in Mexico, winning the re-development of the mature Panuco field.

Petrofac’s IES division is currently working on 10 upstream projects which have been undertaken under different types of contracting models. The division is purposely avoiding exploration risk and concentrating on fields which are already in production, or are ready to be developed. The division has done well over the last three years; the order book has expanded to USD3bn at end-2012, from USD1.5bn in 2010, and sales growth averaged 18% over the period. The revenue contribution from the division can be expected to grow significantly as the fields it is currently developing start ramping up. However, higher capex requirements would mean that, in net terms, the division would remain cash flow negative.

IES financial estimates

Primary growth contributor to group revenues


The IES division has exhibited the strongest growth within Petrofac’s service portfolio. The divisional backlog has grown by USD2bn pa over the last two years. These field development and rehabilitation projects have high initial capex requirements, so, initially, cash flow is negative. In 2012, total capex for the division was around half a billion dollars. In 2013, management expects a capex requirement of USD600m-700m on the projects in the backlog. Capex commitments for the ongoing projects are likely come off as these projects reach development targets and move into a net cash generative phase.

We estimate a three-year revenue CAGR of 25% over 2012-15, with implied order intake of USD1.1bn pa over this period. In our view, this would entail a capex commitment of USD566m per year over the next three years. Petrofac has

$ m 2012 2013E 2014E 2015E

3r CAGR

2013-15

Sales 719 935 1,215 1,397 25%

As % group 11% 13% 15% 16%

growth 39% 30% 30% 15%

EBITDA 204 280 365 391 24%

As % group 23% 28% 34% 35%

EBIT margin (%) 28.4% 30.0% 30.0% 28.0%


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identified 2,200 potential fields globally which could be a target market. Considering the brownfield work required in mature basins and Petrofac’s strong NOC relationships, we think it will be able to achieve order intake to meet our estimates.

Order intake would have to average at USD1.1bn pa over 2013-15 to meet our revenue growth estimate


Key themes for IES

Theme #1: IES gives Petrofac exposure to NOC capex and opex Compared to E&C contractors in the oil services sector, Petrofac is pursuing a unique service portfolio. Its IES division leverages on its E&C capabilities to co-invest alongside its clients to develop small greenfields or redevelop larger brownfield projects facing production declines. The company’s strong balance sheet allows it to take on the capital commitments which come in developing an upstream project.

Petrofac undertakes three types of contracting models: production enhancement contracts (PECs), risk service contracts (RSCs) and pure production-sharing contracts (PSCs). It purposely avoids exploration risk and concentrates on fields which are already in production or are ready to be developed. PECs typically involve deploying capital to redevelop mature fields on a pre-agreed tariff per barrel for incremental production after taking into account a fix field decline rate. RSCs and PSCs are for developing greenfield projects. In RSC, Petrofac does not book reserves; instead, the return on the project is determined on agreed targets such as project costs, and timing to first gas and production levels post-completion. Petrofac has indicated its preference for PECs and RSCs over PSCs, which lowers the sensitivity to the oil price for the overall division.

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Key IES projects


Petrofac’s main focus is on NOCs, whose giant fields are in decline and which need help to maintain them. Alternatively, they may have new, smaller discoveries but lack the resources (both financial and human capital) to handle them. These types of projects – lower complexity and lower field size – are typically off limits for the oil majors, and fall below the size and scale preferred by NOCs. Petrofac’s willingness to forego the booking of production or reserves on its balance sheet and to undertake fixed-margin contracts is a further attraction for the NOCs and a deterrent for the majors. This should play out well with certain governments (eg Mexico, Kuwait), where foreign ownership of hydrocarbon reserves is politically difficult. Petrofac should therefore see less political risk in the countries in which it operates.

Demand for brownfield remediation and production enhancement is likely to be strong in the coming years in both onshore and offshore shallow water oil and gas basins. This includes operations in Mexico, Romania, the Middle East and Asia-Pacific. Through its OMO division, Petrofac has both the experience of managing mature fields in the North Sea and Asia-Pacific and the relationships to win production enhancement projects in these regions.

Theme #2: Projects are entering the production ramp-up phase A number of upstream projects which Petrofac has been developing over the past two years will be in production ramp-up phase over 2013-15. This would translate into stronger earnings contribution by the division for Petrofac and help it to partially neutralise margin attrition in its onshore E&C division.

PEC: Petrofac is executing four PECs, one in Romania and the others in Mexico. It is currently working on a PEC for Petrom (OMV: 51%) in Romania in an effort to offset the production decline of the mature Ticleni oil field. It was also awarded two PEC contracts (Magallanes and Santuario) in Mexico’s first licensing round. Combined production from these contracts is expected to rise from 27,000boed to


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42,000boed over the 2013-2015 period, with a concomitant rise in the unit tariff, from USD3.50/bbl to USD4.25/bl.

Production enhancement contracts


The following table gives the incremental production from these fields along with the associated revenues. These have been estimated by taking into account the agreed tariff structure for base production and incremental production. We estimate that the overall revenues from the current PEC will rise to USD417m by 2017.

Production enhancement contract revenue model


RSC: Under this model, Petrofac will help develop, operate and maintain a field, while the resource holder retains ownership and control of its reserves. Petrofac is currently working on two RSC contracts. It has a 50% share in the Berantai development offshore Malaysia where the project partners will receive a rate of return linked to their performance against an agreed incentive structure. The latter is linked to project costs, timing to first gas and production levels post-completion.

In the Etinde shallow water project in Cameroon, Petrofac has entered at an early stage and will initially provide engineering support to Euroil (Bowleven’s subsidiary) for the field development plan for the project. Conditional on FID on

Project Country LicensorContract

start

Duration

(y)

PFC stake

(%)

incremental

tariff ($/bbl)

Baseline tariff

($/bbl)

Cost

recovery

Prodn

(k

boe/d)

Initial backlog

for first 5 yrs

$bn (PFC

share)

capex (PFC share)

Ticleni RomaniaOMV

PetromNov-10 15+10 100% 35 0% 3.3 0.27

Magallanes Mexico Pemex Feb-12 25 90% 5.01 1.05 75%

Santuario Mexico Pemex Feb-12 25 90% 5.01 1.05 75%

Panuco Mexico Pemex 19/06/2012 30 year 7 1.6 75% 15 0.4

US$17.5m for first 2 years;

thereafter c. 50% x

US$1.5m of 2P remaining

reserves (50mmboe at

1/1/11)

ArenqueOffshore

MexicoPemex 28/08/2012 30 year 7.9 0.79 75% 5 0.5

US$50m in the first 2

years; thereafter c. US$1m

of 2P remaining reserves

(93mmboe at 1/1/11)

$500m over contract life;

$200m in first 2 years0.714

Project 2010 2011 2012 2013 2014 2015 2016 2017 2010 2011 2012 2013 2014 2015 2016 2017

Ticleni 0.00 0.35 0.97 1.67 2.46 3.77 3.52 3.29 0.00 4 12 21 31 48 45 42

Magallanes 8.54 16.31 24.16 24.10 23.65 0.00 0 5 19 32 46 45 44

Santuario

Panuco 2.32 4.86 7.65 10.73 14.12 0.00 0 9 14 21 28 35 44

Arenque 1.30 2.68 4.16 5.77 7.55 0.00 0 1 5 9 13 18 23

28 60 93 134 143 152 4.24 3.65 4.78 5.77 5.93 6.06

Revenues ($ mn)Incremental production (kboed)


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the project, Petrofac will invest USD500m to develop the field and generate revenues based on Bowleven’s production revenues. Appraisal drilling is continuing on the field, and gross reserve estimates are 60m boe oil and condensate and 400bcf gas. First production is estimated to be in 2016 if the project goes ahead. For the RSC contracts, Petrofac aims to generate a net profit of USD45m by 2015.

PSC: This mirrors the approach taken by the majors where upstream investment can come in the form of a PSC or a more straightforward tax and royalty model. Petrofac currently has exposure to three projects, two PSC and one tax/royalty. These are: a 30% stake in the PSC for the Cendor oil field expansion offshore Malaysia (Block PM304); a 45% stake in the PSC for the Chergui gas field in Tunisia; and a 20% equity stake in the Greater Stella project in the North Sea. The cumulative production from these fields will rise to 15,100boed from 8,000boed in 2013 on the back of the Phase 2 Greater Stella development.

Theme #3: potential opportunities with require high capex to tap Armed with a strong balance sheet, and with the former head of upstream at BP now running the business, Petrofac might be tempted to try to bite off more than it can chew. This does not seem to be the case hitherto. While capex in the business will likely increase (the company is talking of annual investment of USD0.5bn-1.0bn), it has carried out a careful analysis worldwide of the potential opportunities which fit its skills set. It has identified 4,500 fields controlled by the NOCs, of which around 2,400 would represent the target market for Petrofac – being too low priority for the NOCs or too small for the IOCs. This also helps its competitive position. While some of its upstream projects are awarded via competitive tender (eg Mexico), we would also expect it to win further contracts on a directly negotiated basis.

Petrofac has identified 2,400 fields controlled by NOCs which would represent its target market



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Offshore OPO

Divisional background: Petrofac is a leading provider of operations and maintenance (O&M) support to existing, producing fields, both on- and offshore, in order to improve recovery and extend field life. Around two-thirds of the divisional top line is generated in the UK/North Sea where Petrofac, Amec and Wood Group dominate. Contracts are typically long-term (three to five years) and cost-reimbursable in nature. This lends stability to divisional cash flow, but also means that both pre- and post-tax margins in this division are the lowest in the group. In 2012, the division contributed 21% to group sales and 9% to net income. Competitive pressure in the offshore MMO market has been rising. Petrofac has been able to sustain margin and top-line growth by undertaking high-margin and high-risk offshore capital projects to supplement earnings streams. Over the next five years, it plans to enter the SURF segment, and would have an expensive capex programme to finance this portfolio expansion. The company plans to split Offshore Capital Projects from OPO eventually. For modelling purposes, we have kept offshore capital projects within the division.

OPO financial estimates

Stable margins and sales five-year CAGR of 15% over 2012-17


Petrofac has generated strong growth in the OPO division with order intake of USD2.05bn in 2012, double that of 2011. USD1.5bn of this backlog will be recognised as revenue in 2013, which is higher than divisional revenues of USD1.4bn in 2012. Even in the absence of new contract awards, this would translate into revenue growth of 7%. We project revenue growth of 20% for the division in 2013, which would imply an order intake of USD2.2bn and a stable backlog in the year.

Investment in Maintenance & Modification (MMO) is less sensitive to the changes in oil price, and global MMO opex exhibited healthy growth during the turbulent period of 2007-2009. In 2012, the global MMO market grew in all mature oil and gas basins. We expect this trend to continue, as a natural result of the ageing of the oil and gas infrastructure. Brazil and Asia-Pacific, although small, will be important contributors to growth in this segment. Petrofac has a strong position in Asia-Pacific, and enjoys a solid relationship with players like Petronas in the region. It aims to grow its presence in West Africa, and has gained experience operating in the region through its partnership with Sevan Energy in Nigeria (it plans to open an office in Lagos this year). It has also established a partnership with Bowleven to develop the Etinde permit offshore Cameroon.

$ m 2012 2013E 2014E 2015E

3r CAGR

2013-15

Sales 1,403 1,684 1,936 2,130 15%

As % group 22% 23% 25% 25%

growth 12% 20% 15% 10%

EBITDA 95 118 145 170 21%

As % group 11% 12% 14% 15%

EBITDA margin (%) 6.77% 7.00% 7.50% 8.00%


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However, despite healthy global demand, the operating environment for Maintenance & Modification (MMO) has toughened, with increased competition from the likes of Wood Group and Amec. This has led to a move towards KPI-linked contracts, which are inherently more risky, while, at the same time, margins have deteriorated. Clients are also now seeking to re-tender expiring contracts, rather than roll them over, in order to obtain lower costs and test new supplier models. This can be seen as both an opportunity (winning contracts) and a threat (losing them) for Petrofac. While the contracting environment has been becoming tough in the OMO space, Petrofac has been able to raise margins through lowering costs and expanding into higher-margin capital projects.

The company is taking on more capital projects to develop offshore fields and will now be spending USD1bn to develop a SURF installation fleet over the next five years. This would have a positive impact on group revenues and margin profile. We estimate that the OPO division will grow at a three-year CAGR of 15% over 2013-15, while we expect EBITDA margins to expand by 223bp during the period. Our growth estimates would require order intake of USD2.9bn pa during this period.

Implied order intake to average at USD2.9bn pa over 2013-17


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Financials

Income Statement

Sales projections


We forecast that group sales will grow at an 10% CAGR over 2013-15. This is substantially lower than the growth achieved in prior years. We expect this slowdown on the back of weakness in the Onshore E&C division, which contributes 70% of group revenues and has experienced sharp backlog attrition. The IES and OPO divisions will be the strongest growth drivers for the company, in our view, and we expect them to grow at a 25% and 15% CAGR over the next three years. This would neutralise the weakness in onshore E&C, which we anticipate would grow by only a 2% CAGR.

We expect group EBITDA margin to drop by 1.1% over 2012-15, despite an increased contribution from the high-margin IES division. We expect this division’s margins to average out at around 29% over the period, and its revenue contribution to increase to 16% by 2015 from the current 11%. This bearishness on group margins is due to expected margin compression by 181bp in onshore E&C.

$ m 2012 2013E 2014E 2015E

3Yr cagr

2012-15

Group 6,324 7,206 7,852 8,478 10%

YoY growth 3% 14% 9% 8%

Onshore E&C 4,358 4,314 4,401 4,621 2%

YoY growth 5% -1% 2% 5%

% of group 69% 60% 56% 55%

Offshore Project & Operations 1,403 1,684 1,936 2,130 15%

YoY growth 12% 20% 15% 10%

% of group 22% 23% 25% 25%

Engineering and Consulting Services 248 273 300 330 10%

YoY growth 19% 10% 10% 10%

% of group 4% 4% 4% 4%

ECOM 6,009 6,271 6,637 7,081 6%

YoY growth 7% 4% 6% 7%

% of group 95% 87% 85% 84%

Integrated Energy Services 719 935 1,215 1,397 25%

YoY growth 39% 30% 30% 15%

% of group 11% 13% 15% 16%


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EBITDA projections



Petrofac has a strong balance sheet, and is in a net cash position. This has made it possible to implement its unique growth strategy which involves taking on relatively risky upstream IES projects – production sharing contracts, in particular, as well as lump sum E&C contracts in the Middle East. The company’s gross debt at the end of 2012 was USD349m, and its gross debt/equity ratio of 23% (7% at end-2011). Despite this increase in leverage, Petrofac still maintains a net cash position of USD365m. In September 2012, the company gained access to a five-year USD1.2bn revolving credit facility at a floating Libor rate of +1.5%. Drawdown from this facility formed the bulk of its debt at end-2012.

In the medium term, higher capex commitments to grow its IES portfolio and develop the Offshore Capital Projects division will result in a net debt position for the company. We estimate that the leverage ratio (net debt to equity) will rise to 44% by the end of 2017. This would translate into a net debt to EBITDA ratio of 1.16x by 2017.

$ m 2012 2013E 2014E 2015E

3Yr cagr

2012-15

Group 915 1,000 1,074 1,133 7%

YoY growth 31% 9% 7% 5%

EBITDA margin 14.5% 13.9% 13.7% 13.4%

Onshore E&C 580 561 528 531 -3%

YoY growth 5% -3% -6% 1%

EBITDA margin 13.3% 13.0% 12.0% 11.5%

Offshore Project & Operations 95 118 145 170 21%

YoY growth 67% 24% 23% 17%

EBITDA margin 6.8% 7.0% 7.5% 8.0%

Engineering and Consulting Services 36 41 36 40 3%

YoY growth 9% 14% -12% 10%

EBITDA margin 14.5% 15.0% 12.0% 12.0%

ECOM 711 720 709 741 1%

YoY growth 10% 1% -1% 5%

EBITDA margin 11.8% 11.5% 10.7% 10.5%

Integrated Energy Services 204 280 365 391 24%

YoY growth 258% 37% 30% 7%

EBITDA margin 28.4% 30.0% 30.0% 28.0%


178

Petrofac leverage to rise to finance growth


We expect Petrofac’s capex outlays to increase over the next three years as it develops the necessary capability to enter the SURF segment as well as fulfil the capex requirements of its upstream projects. We project that capex will average USD830m pa over the next five years. Based on these outflows, we estimate Petrofac’s free cash flows will remain negative until 2015. Following this, cash flow stress will likely decrease as the company comes out of its high capex phase and the IES portfolio starts generating higher production and cash.

Leverage to rise markedly due to higher capex commitments


-160%-140%-120%

-100%-80%-60%

-40%-20%0%20%40%60%

0

200

400

600

800

1,000

1,200

2010 2011 2012 2013E 2014E 2015ECapex Leverage (%, RHS)

-150%

-100%

-50%

0%

50%

100%

-500

0

500

1,000

1,500

2010 2011 2012 2013 2014 2015

Operating cash flow Capex Dividend Leverage (%, RHS)


179


Since listing in 2005, Petrofac has been one of the best performing stocks in the sector thanks to rapid growth in its order backlog. However, to some extent, Petrofac has become a victim of its own success. Its performance has rolled over in 2012-13 versus both the market and the sector as a falling backlog is perhaps the result of perhaps the unrealistic expectation that this rate of rapid growth was sustainable. The stock has de-rated on the back of weakness in onshore E&C and capital intensive growth strategy to enter the SURF installation segment.

Petrofac share price versus pan-European market

Petrofac share price relative to European OFS sector

Source: DataStream, Berenberg estimates

Like its peers, Petrofac’s absolute and relative share price performance is driven by its earnings momentum. Against both the market and the sector, its share price has lagged its earnings growth over the past five years.

Petrofac price performance and earnings momentum relative to market

Petrofac price performance and earnings momentum relative to sector



180

We believe the absolute forward P/E is therefore a reasonable indicator of value for the stock. On this basis, the current level (approaching 10x next year’s earnings) is towards the bottom end of its 10-year range (excluding the financial crash in 2008). This is also true of Petrofac’s cash flow multiple, shown on the right-hand chart below.

Petrofac forward P/E multiple (x) Petrofac forward P/CF multiple (x)


DCF

Our DCF-based valuation gives a target price of GBP13.7 for Petrofac. We use the two-stage DCF model to value the company. Our model assumes that it will go through two distinct phases – an initial 10-year (2013-22) high-growth phase followed by a long-term steady-state low growth phase. We think this is suitable, considering the negative free cash flows in the initial period. The detailed valuation model with our free cash flow projection and assumptions for the terminal growth rate and WACC and valuation sensitivity analysis is given in the table below.

Free cash flow


$ m 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E

Net income 630 664 672 638 592 584 723 899 1,009 1,271 1,387

Interest * (1-tax rate) 6 -13 -47 -73 -76 -89 -90 -87 -84 -79 -73

Working capital -918 -274 -212 -280 -187 -210 -255 -295 -231 -145 -129

Depreciation 130 154 175 244 361 513 583 619 679 480 447

Net capex -615 -997 -852 -809 -766 -727 -570 -543 -521 -474 -540

Free cash flow to the firm -779 -440 -170 -134 76 249 570 767 1,020 1,211 1,238

EPS (Euro) 1.87 1.94 1.96 1.86 1.72 1.70 2.11 2.62 2.94 3.71 4.04

ROE 40.4% 34.0% 29.6% 25.1% 20.9% 18.8% 19.8% 20.8% 20.1% 21.2% 20.0%

ROACE 37.5% 25.7% 19.7% 16.4% 13.8% 12.6% 14.1% 15.5% 15.5% 17.2% 16.6%

Reinvestment 66% 65% 65% 65% 65% 65% 65% 65% 65% 65% 65%

Sustainable growth (equity) 26.5% 22.1% 19.2% 16.3% 13.6% 12.2% 12.9% 13.5% 13.1% 13.8% 13.0%

Sustainable growth (assets) n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

Interest bearing debt/capital 18% 33% 38% 35% 35% 33% 30% 27% 24% 22% 19%


181

DCF

Source : Berenberg estimates

Sensitivity


Free cash flow valuation NOSH (2012) 340

ROE (2022) 20.0%

ROACE (2022) 16.6% Free cash flow to firm model:

Retention 65% Value 13-22 1,648


Growth post 2022 (Assets) 1.0% Net debt ($m | 2012)) -265

Risk free rate 3.0% Unfunded pension liability ($m | 2012))100

Cost of debt 6.0% Equity valuation 6,934

Corporate tax rate 21% Value per share (USD) 20.4

GBP to USD exchange rate 1.49

Equity risk premium 7.0% Value per share (GBP) 13.7

Beta 1.3

Beta post-2022 1.4


WACC 2013-22 11%


WACC > 2022 10%

13.7 0.5% 1.0% 1.0% 2.0% 2.5%

8% 15.7 16.6 16.6 18.9 20.4

9% 14.2 14.9 14.9 16.7 17.8

10% 13.1 13.7 13.7 15.1 15.9

11% 12.2 12.7 12.7 13.8 14.4

12% 11.4 11.8 11.8 12.7 13.3


LT

WA

CC


182

Financials


PETROFAC ($ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Revenues

Onshore E&C 3,254 4,146 4,358 4,314 4,401 4,621 4,852 5,094

Offshore Project & Operations 722 1,251 1,403 1,684 1,936 2,130 2,449 3,184

Engineering & Consulting Services 173 208 248 273 300 330 363 399

Integrated Energy Services 384 519 719 935 1,215 1,397 1,607 1,768

Group 4,354 5,801 6,324 7,206 7,852 8,478 9,271 10,445

EBITDA

Onshore E&C 472 585 580 561 528 531 534 535

Offshore Project & Operations 27 61 95 118 145 170 220 334

Engineering & Consulting Services 26 40 36 41 36 40 40 44

Integrated Energy Services 128 90 204 280 365 391 402 442

Group 634 759 896 1,000 1,074 1,133 1,196 1,355

Depreciation & Amortization (96) (80) (130) (154) (175) (244) (361) (513)

EBIT 538 679 766 846 899 889 835 842

Net financials 5 1 7 -17 -59 -91 -95 -111

Others 0 4 0 0 0 0 0 0

Profit before tax 544 684 773 830 840 798 739 731

Tax (111) (141) (135) (166) (168) (160) (148) (146)

Tax rate (%) 17% 21% 18% 20% 20% 20% 20% 20%

Cont'd operations 558 540 630 664 672 638 592 584

Net profit 558 540 630 664 672 638 592 584

Underlying net profit 454 543 640 664 672 638 592 584

Equity holders 558 540 632 664 672 638 592 584

Minority interests 0 0 (2) 0 0 0 0 0



183

Balance sheet

PETROFAC ($ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Balance sheet ($ bn)

PPE 287 594 905 1753 2436 3008 3420 3641

Intangibles 192 229 432 427 421 414 407 400

Associates 16 164 177 177 177 177 177 177

Tax/Other 130 169 487 487 487 487 487 487

Total non-current 625 1156 2001 2844 3521 4086 4491 4705

Current assets

Inventories 7 11 27 27 27 27 27 27

Receivables 1057 1353 1915 2270 2474 2671 2921 3291

Work in progress 804 612 656 786 857 925 1012 1140

Due from related parties 0 99 22 24 27 29 32 35

Cash & bank balances 1063 1572 614 587 637 196 222 175

Other 45 89 97 97 97 97 97 97

Total current 2976 3736 3331 3792 4119 3945 4311 4765

Payables 1021 1744 1981 2376 2589 2699 2952 3325

Due to related parties 12 23 38 38 38 38 38 38

Interest bearing loans 47 61 57 57 57 57 57 57

Accrued contract expenses 1275 1269 743 594 476 380 304 243

Excess billings 178 389 328 295 266 239 215 194

Other 143 133 92 92 92 92 92 92

Total current liabilities 2677 3619 3239 3452 3517 3506 3658 3950


Interest bearing loans 40 16 292 942 1442 1442 1692 1692

Provisions 45 60 100 100 100 100 100 100

Tax/Other 60 83 151 151 151 151 151 151

Total non-current liabilities 145 159 543 1193 1693 1693 1943 1943

Total liabilities 2822 3778 3782 4645 5210 5199 5601 5893

Total equity 779 1114 1550 1990 2429 2833 3201 3578

Non-controlling interests 3 3 1 1 1 1 1 1

Shareholders' funds 776 1111 1549 1989 2428 2832 3200 3577

Net debt/(cash) -975 -1495 -265 412 862 1303 1527 1574

Capital employed 927 1276 2094 3184 4123 4527 5145 5522



184

Cash flow statement

PETROFAC ($ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Cash flow

PBT 668 681 765 830 840 798 739 731

Gain on discontinued operations (125) 0 0 0 0 0 0 0

DD&A 96 80 130 154 175 244 361 513

Net finance income (5) (1) (7) (17) (59) (91) (95) (111)

Gain/loss on disposal (tangible & intangible) (2) (0) (33) 0 0 0 0 0

Payment/Benefits related 21 33 37 0 0 0 0 0

Net Interest paid 8 5 2 (17) (59) (91) (95) (111)

Income taxes paid (99) (157) (83) (166) (168) (160) (148) (146)

Other 5 (127) (289) 0 0 0 0 0

Cash from operations 567 514 522 818 847 882 952 1,097

Change in working capital (451) 758 (918) (274) (212) (280) (187) (210)

Net cash from operating activities 117 1,271 (396) 543 635 602 766 888

Capex (tangible & intangibles) (131) (466) (569) (997) (852) (809) (766) (727)

Investment in associates (8) (50) (25) 0 0 0 0 0

Acquisitions (15) 0 (20) 0 0 0 0 0

Disposals (9) 1 66 0 0 0 0 0

Other (101) (16) (1) 0 0 0 0 0

Net cash provided by (used in) investment

activities (264) (531) (549) (997) (852) (809) (766) (727)

Cash flow less capex (148) 740 (945) (453) (217) (207) (1) 160

Shares repurchased (36) (49) (76) 0 0 0 0 0

Shares issued 0 0 0 0 0 0 0 0

Dividends (132) (159) (201) (224) (232) (235) (223) (207)

Other (32) (19) 241 0 0 0 0 0

Net cash provided by (used in) equity

financing (201) (228) (36) (224) (232) (235) (223) (207)

Debt issuance 0 0 0 650 500 0 250 0

Forex (8) (12) 3 0 0 0 0 0

Change in cash position (357) 501 (978) (27) 50 (442) 26 (47)

Cash at beginning of period 1,417 1,034 1,535 614 587 637 196 222

Cash at period end 1,061 1,535 557 587 637 196 222 175



185

Ratios

PETROFAC ($ m) 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Per share data

Diluted shares (m) 343 346 343 343 343 343 343 343

Clean EPS ($) (diluted) 1.32 1.57 1.87 1.94 1.96 1.86 1.72 1.70

Dividend per share ($) 0.44 0.55 0.64 0.68 0.69 0.66 0.61 0.60

Cash flow per share ($) (diluted) 0.34 3.68 (1.15) 1.58 1.85 1.76 2.23 2.59

Debt-adjusted CFPS ($) (diluted) 0.33 3.67 (1.17) 1.62 1.99 1.97 2.45 2.85

NAV/share ($) (diluted) 2.3 3.2 4.5 5.8 7.1 8.3 9.3 10.4



ROACE 44 49 38 26 20 16 14 13

ROE 71 48 40 34 30 25 21 19

Net debt(cash)/equity -125 -134 -17 21 35 46 48 44

ND/(ND+E) 497 392 -21 17 26 32 32 31

Capex/cash flow 113 37 -144 183 134 134 100 82


Valuation ratios

P/E (x) 14.6 14.7 13.4 9.7 9.6 10.1 10.8 11.0

P/CF (x) 55.9 6.1 -21.4 11.7 10.0 10.6 8.3 7.2

EV/EBITDA (x) 8.8 8.4 9.3 6.9 6.8 6.9 6.7 5.9

EV/DACF (x) 49.8 5.0 -20.7 12.4 10.7 11.5 9.5 8.2

Dividend yield (%) 0.02 0.02 0.03 0.04 0.04 0.04 0.03 0.03

Price to book (x) 8.4 7.0 5.5 3.2 2.6 2.2 2.0 1.8

Free cash flow yield (%) -0.2 10.3 -11.4 -7.1 -3.4 -3.2 0.0 2.5


Saipem SpA Oil & Gas

186

Structurally challenged

• We initiate coverage on Saipem with a Hold rating and a price target of EUR14.2. Our price target is based on a DCF (WACC: 9.2%; terminal growth: 1%) and implies -1% downside.

• Saipem is a diversified value chain player with exposure to both onshore and offshore engineering and construction (E&C) as well as drilling. The stock has de-rated 51% ytd on the back of sharp cuts in earnings guidance for its E&C business. Although we expect margin recovery, we believe Saipem’s margin is unlikely to reach prior levels because of its low-tech market positioning and adverse structural trends in its E&C business.

• Structurally challenged: While specialists like Technip and Petrofac have carved strong positions in relatively niche, uncontested markets – early-stage engineering and technology for Technip and upstream equity investment for Petrofac – Saipem has remained a one-stop shop offering a multitude of services at the low-tech end of the value chain. In onshore, it has lost market share and is struggling to compete with cost-efficient South Korean peers with access to the Asian value chain. This has led to sharp erosion in the backlog and margin compression. We think margin improvement will be at the expense of growth. In offshore, it has poor exposure to high-margin deepwater subsea installation, where an increasing proportion of future E&C capex is likely to be targeted, especially with the maturation of the subsea factory concept. It has stuck to shallow-water trunklay and platform installation work based on an ageing vessel fleet which demands high maintenance capex. It also lacks flexible pipelay installation capability, which is Petrobras’s preferred field development method in a region where Saipem intends to grow. While non-core, the drilling divisions have performed well, but growth will be limited as the capex programme is largely complete.

• Estimates: We expect sales and EBITDA to grow at a three-year CAGR of 0.7% and -5.3% respectively, which is lower versus consensus over 2012-15.

Hold (initiation) Rating system

Current price

EUR 14.40

Absolute

Price target

EUR 14.20 09/07/2013 Milan Close Market cap EUR 8,161 m Reuters SPMI.MI Bloomberg SPM IM Share data

Shares outstanding (m) 439 Enterprise value (EUR m) 15,498 Daily trading volume 2,257,000

Performance data

High 52 weeks (EUR) 39.90

Low 52 weeks (EUR) 12.50 Relative performance to SXXP FTSE MIB 1 month -28.7 % -26.1 % 3 months -35.7 % -34.8 % 12 months -78.0 % -73.1 %

Key data

Price/book value 1.3 Net gearing 108.9% CAGR sales 2012-2015 0.7% CAGR EPS 2012-2015 -9.5%

Business activities: Saipem provides offshore and onshore installation and drilling services.

Non-institutional shareholders: ENI SPA 42.93%

10 July 2013


Jaideep Pandya


Y/E 31.12., EUR m 2011 2012 2013E 2014E 2015E

Sales 12,631 13,386 13,458 13,456 13,671

EBITDA 2,135 2,207 725 1,595 1,875

EBIT 1,493 1,481 -19 854 1,155

Clean net income 921 902 -265 459 669

Clean EPS 2.09 2.05 -0.60 1.04 1.52

DPS 0.70 0.68 -0.20 0.34 0.50

EBITDA margin 16.9% 16.5% 5.4% 11.9% 13.7%

EBIT margin 11.8% 11.1% -0.1% 6.3% 8.4%

ROE 22.4% 19.1% -2.1% 11.3% 13.8%

ROACE 14.0% 11.9% -1.0% 5.9% 8.0%

P/E 16.2 17.3 -23.7 13.7 9.4

EV/CF (x) 11.1 61.2 32.0 8.9 6.0

EV/EBITDA (x) 8.6 9.1 16.4 7.2 5.6

EV/EBIT (x) 12.3 13.6 -619.3 13.4 9.1

EV/Sales(x) 1.4 1.5 0.9 0.8 0.8

Free Cash flow yield 2.6% -5.1% -12.1% 6.8% 16.1%

Dividend yield 2.1% 1.9% -1.4% 2.4% 3.5%



187

Company background

Saipem is one of Europe’s largest OFS companies, with a diversified product offering across exploration and the E&C phase. Its construction yards in key oil-producing countries and a large fleet consisting of field development vessels, pipelayers, rigs and FPSO units provide it with a global reach, local content capability and linkages to NOCs which few other players can match, in our view.

Saipem operates four divisions, splitting E&C and drilling capability along offshore and onshore lines. The four divisions are therefore Offshore E&C, Onshore E&C, Offshore Drilling and Onshore Drilling. The divisional split of revenue and EBIT for 2012 is given in the graph below, which highlights that Saipem’s core E&C divisions form the bulk (ie 86%) of the top line, but have significantly lower operating margins than the much smaller, non-core drilling divisions.

Revenue split 2012 (EUR13.4bn) EBIT split 2012 (EUR1.5bn)


Saipem’s client base is highly skewed towards NOCs and international oil companies, which lends resilience to the company’s earnings as the capex programmes of integrated majors are less dependent on short-term oil price trends. Over the last three years, Saipem’s exposure to Brazil and Asia-Pacific has risen on the back of capacity additions in the two regions. Meanwhile, its exposure to the Middle East has fallen as a result of greater market fragmentation.

Saipem’s client base is heavily skewed towards NOCs and IOCs

Backlog split by region (EURm)


Offshore E&C40%

Onshore E&C46%

Offshore drilling

8%

Onshore drilling

6%

Offshore E&C46%

Onshore E&C27%

Offshore drilling

20%

Onshore drilling

7%

0%

20%

40%

60%

80%

100%

2008 2009 2010 2011 2012

NOCs IOCs Independents Other

0

5,000

10,000

15,000

20,000

25,000

2010 2011 2012

Europe/Russia/Central Asia Africa

Middle-East Asia-Pacific

Americas


188

Investment thesis

We initiate coverage on Saipem with a Hold recommendation and a price target of EUR14.2. Our price target is based on a DCF (WACC: 9.2%, terminal growth: 1%) and implies -1% downside.

Saipem is one of the largest European OFS companies and is listed on the Milan Stock Exchange. The company is involved in the engineering and construction of oil and gas facilities globally and also runs a high-margin drilling business with both onshore and offshore capability.

The company has experienced severe attrition in its onshore backlog and margin compression in its overall E&C business. The completion of projects in high-margin regions in offshore as well as aggressive bidding in established MENA markets and in Brazil have been the primary reasons for Saipem’s poor financial performance. This has created legacy issues for the company and it is now booking losses for a number of these contracts, especially in Mexico and Canada where it is reliant on subsuppliers. These legacy issues along with the financial and reputational fallout from the corruption investigation on contracts in Algeria will affect the speed of restructuring the company is trying to implement. In addition, the company has just completed an expensive capex programme which left the balance sheet with net debt of EUR4.8bn (net debt to equity of 87%) at the end of Q1 2013.

Saipem is also structurally poorly-placed. While peers like Technip and Petrofac have restructured and carved out a strong position in relatively uncontested markets – early-stage engineering and technology for Technip and upstream equity investment for Petrofac – Saipem has failed to diversify from its mainly construction/execution expertise and gain exposure to new technologies (such as flexible pipes), or develop adequate engineering and construction capabilities in high-margin market segments such as SURF, GTL and FLNG.

The investment thesis underlying our Hold recommendation is based on the following three points.

1. Likely to fall off the backlog cliff: Saipem’s Onshore E&C division (which contributes 46% to group revenues) has high exposure to the MENA region, which is becoming structurally challenging. We think that Saipem will struggle to compete with low-cost Asian peers and with companies like Petrofac which have a tax advantage. Saipem’s onshore backlog is highly skewed towards low-tech gas processing plants and gas pipelines, which will subdue overall margins in the medium term. Saipem’s new management is adopting a more selective approach towards onshore projects to improve margins. Considering that market fragmentation and high completions are likely to persist, we think that Saipem will fail to regain its lost market share in MENA without compromising on margins. In addition, the sharp backlog erosion which has occurred since 2010 will hit the top line in 2014 in the absence of record order intake in 2013-14. We estimate that Saipem would need to win ~EUR7bn worth of new contracts over 2013-14 to keep the top line at the 2013 level during 2014, compared to order intake of ~EUR4bn achieved in 2012. We think that this is highly unlikely and hence expect top-line contraction over the next two years.

2. Legacy issues will blunt financial restructuring: Saipem’s previous management undertook a number of contracts especially in onshore E&C


189

at poor margins to sustain revenue growth. Because of its aggressive accounting policy where it books profits based on percentage of completion, it has had to reverse profits booked on a number of contracts which assumed unrealistic margin assumptions. As the company reassesses its remaining order book, there is a possibility that there might be similar contracts which need a reduction in profitability estimates and reversal of profits already booked. Other main legacy problems include the corruption investigations on its activities in Algeria. This has strained its relations with Sonatrach and in our view tarnishes its reputation in the country and in the broader MENA region in addition to the financial fallout in the shape of fines and payment delays on existing projects in Algeria. In addition, if these allegations are proved true, Saipem’s parent company ENI might reconsider its shareholding in the company. This would both create share overhang for the company as well as have financial implications as the company has access to low-cost financing through ENI.

3. Reliance on old technologies: In offshore, Saipem has low exposure to high-margin deepwater and subsea field E&C, where an increasing proportion of future E&C capex is likely to go. Instead its expertise lies in shallow water projects through its large fleet of ageing S-lay barges and heavy-lift vessels. In addition, it lacks expertise in new field development systems such as flexible pipes. Based on these weaknesses in offshore capability, Saipem’s expansion into new geographies such as Brazil and Asia-Pacific is proving difficult. It is currently undertaking nearly zero-margin projects in Brazil, which in our view highlights the company’s poor competitive standing versus the more established specialist subsea players, Technip and Subsea 7. In the absence of another expensive capex programme to move up the technology ladder, we believe Saipem will lack the differentiation needed to expand successfully in competitive offshore regions such as Brazil and Asia-Pacific.

4. Balance sheet weakness limits restructuring capability: Saipem has just completed an expensive capex programme of EUR16bn undertaken during 2007-12. This has weakened its balance sheet and reduced financial flexibility, with the company’s leverage (net debt to equity) rising to 87% at the end of Q1 2013. At the same time, Saipem’s working capital requirements have risen sharply and are eating into its operational cash flows. With Saipem planning to reduce net debt to EUR1bn from the current level of EUR4.8bn, we doubt the company has the financial flexibility to invest in order to restructure and grow.


190

Reasons to Hold

Reason #1: Saipem’s competitive advantage has weakened Saipem is an asset-heavy company and focuses on the ownership of offshore vessels and construction yards. It therefore performs well during an industry up-cycle and suffers during a down-cycle, when lower asset utilisation puts downward pressure on margins. This explains part of the margin and backlog attrition which the company has faced recently. Being asset-heavy, it has high operational gearing and hence needs a continuous stream of order intake to maintain earnings. This reduces Saipem’s flexibility when projects are delayed.

In the onshore space, in addition to delays in project announcements and tendering, the market has become increasingly fragmented. While Saipem benefited historically from its extensive global reach, strong local content and execution capability, these advantages have paled in comparison with the low cost base of South Korean peers. With the market entry of these Asian players, onshore downstream construction work has been commoditised away from Saipem. Meanwhile, in the face of these trends and its experience of cost overruns in LNG projects (Qatar) in 2006, Technip has diversified away from MENA (a lump sum market) and developed expertise as a downstream engineering and technology specialist. But Saipem has failed to adapt to the change and develop complementary specialist skills. In the absence of large project announcements, it now has to resort to low-end work which commands low margins. We estimate that low-end onshore pipelines and gas pipelines account for nearly half of the onshore contracts Saipem has won since 2010.

Onshore E&C contracts won since 2010 by project type


The financial performance of the Onshore E&C division has suffered as a result, with sharp erosion in the backlog and compression in margins. Considering that market fragmentation and high completions are likely to persist, we think that Saipem will fail to regain its lost market share in MENA without compromising on margins. In addition, the severe backlog erosion which has occurred since 2010 will hit the top line in 2014 in the absence of record order intake in 2013-14. We estimate that Saipem would need to win ~EUR7bn worth of new contracts over 2013-14 to keep the top line at the 2013 level during 2014, compared to order intake of ~EUR4bn achieved in 2012. We think that this is highly unlikely and hence expect top-line contraction over the next two years.

Refining and petrochems

11%

Oil sands

8% Fertilizers4%

Onshore pipeline17%

Gas processing30%

Field development

15%

Infrastructure13%

Power2%


191

Reason #2: Legacy issues Saipem’s previous management adopted an aggressive bidding approach to win downstream projects during the tough contracting environment in 2009-2010 (see chart below). Based on its aggressive accounting policy of booking profits based on the percentage of completion of the project rather than on an assessment of project risk, it booked profits on these contracts. The new management team is reassessing these contracts and is being forced to reserve profits and book losses on contracts which had unrealistic margin assumptions. In Q2 2013, it booked large losses on onshore contracts in Mexico and Canada. As the company reassesses its order book in other regions, there is a possibility that there might be similar contracts which might need a reduction in profitability estimates and reversal of profits already booked.

Onshore E&C order intake (EURm)


In addition, the company’s operations in Algeria are also stuck in a limbo amid investigation of corruption allegations on contracts it won in the country. This has strained its relations with Sonatrach and, in our view, has tarnished its reputation in the country and in the broader MENA region. In addition, there could be financial fallout in the shape of fines and cancelled payments on existing projects in Algeria.

Reason #3: Reliance on old technologies Saipem’s competitive edge has been in construction and projection execution on the back of its strong local content and infrastructure base. It has been weak compared to peers such as Technip in engineering, in our view. It has a relatively old fleet with an average age of 20 years. This adds to the maintenance capex, which runs at EUR400m (about 40% of the level of annual capex in the high-capex phase of development). This will be a drain on cash flows; we forecast operating cash flows to average EUR1.4bn pa over 2013-15.

In contrast, subsea specialists Technip and Subsea 7 both have a high-specification fleet which gives them a competitive edge in the fast-growing SURF market. Saipem, however, is strong in gas trunklay and fixed-platform installation work in shallow waters. We observe that the large and high-profile trunklay projects Galsi and TANAP (to connect the demand centres of Europe to gas supplies in North Africa and Central Asia) are experiencing long delays. Instead, tanker LNG trade seems to be a cost-effective solution and activity is picking up. This is negative for

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2007 2008 2009 2010 2011 2012

Record order intake in poor contracting environment


192

Saipem’s large fleet of S-lay vessels. Although Saipem has expertise in LNG, a fragmented market and low entry barriers mean that this has lower margins.

In addition, Saipem is weak in subsea installation, specialising instead in offshore fixed-platform installation work on the back of a large base of heavy-lift vessels. However, the subsea factory technology concept is fast reaching maturation which is limiting demand for new platforms. This is because longer tiebacks from subsea wells to existing infrastructure are a more cost-effective solution. In addition, if subsea oil and gas processing technology continues to evolve as it is currently doing, over the next 10-15 years newer developments will not require subsurface processing facilities in shallow waters. In our view, Saipem needs to understand the urgency of the need to develop subsea expertise, as technology discontinuity is testing existing business models.

Similarly, Saipem also lacks expertise in new field development systems such as flexible pipes. Based on these weaknesses in offshore capability, its expansion into new geographies such as Brazil and Asia-Pacific is proving difficult. It is currently undertaking nearly zero-margin projects in Brazil which highlight the company’s poor competitive standing versus the more established specialist subsea players, Technip and Subsea 7. In the absence of another expensive capex programme to move Saipem up the technology ladder, it will lack the differentiation to expand successfully in competitive offshore regions such as Brazil and Asia-Pacific, in our view.

Reason #4: Balance sheet weakness limits restructuring capability Saipem has just completed an expensive capex programme of EUR16bn undertaken during 2007-12. This has weakened its balance sheet and has reduced financial flexibility. The company’s leverage (net debt to equity) rose to 87% at the end of Q1 2013 from 70% in 2011.

Currently, Saipem benefits by being a subsidiary of ENI as it borrows through the parent company, leading to low financing costs. The recent profit downgrade by Saipem’s management has created fears that ENI could possibly exit its stake in the long term as Saipem’s activities are not core to its business. Although ENI management has since then denied having any plans to do so, the risk of higher borrowing costs should encourage Saipem to reduce its financial gearing. With the company planning to reduce its net debt to EUR1bn from the current level of EUR4.8bn, we doubt it has the financial flexibility to invest in order to restructure and grow.

At the same time, we observe that Saipem’s working capital requirements have risen sharply and are eating into its operational cash flows (see the year 2012 in the right-hand graph below). With a stressed balance sheet, Saipem thus has limited room to manoeuvre, in our view, at least over the next three to five years.


193

Leverage has risen as a result of an aggressive capex programme over the last five years

Capex outlays to decline over the next three years


Valuation

Saipem has historically traded at a 12-month forward P/E range of 13-17x. Following the recent sharp cut in earnings guidance for 2013, Saipem’s 12-month forward P/E has spiked. We think that this spike is essentially caused by sharply reduced 2013 consensus estimates and should therefore normalise once the 2014 numbers are accounted for. Our target P/E is based on our 2014 EPS estimate of EUR1.06 is 13.4x, which is at the lower end of the historical trading range.


Source: DataStream

Having a heavy weighting within its sector, Saipem has been treated as a defensive stock and has historically traded at a premium compared to the EU Oil Equipment & Services Index. Since 2011, this premium has averaged 13%. The premium has spiked recently, primarily because of the very low 2013 consensus estimates. This premium normalises once 2014 EPS estimates are taken in account. We think that the current concerns regarding Saipem’s operational gearing and structural weaknesses are priced in. However, there are risks to the downside if the strong bid pipeline communicated by Saipem’s management fails to translate into substantial order intake and if further legacy issues regarding corruption allegations in Algeria and losses on onshore E&C contract arise.

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Saipem 12-month forward P/E versus EU Oil Equipment & Services Index

Source: DataStream

Saipem 12-month forward P/E versus peers

Source: DataStream

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Value chain

Saipem has pursued quite a distinctive strategy over many years. It is unashamedly an asset-heavy company, possessing offshore construction vessels, fabrication yards and its own drilling fleet. As such, it tends to benefit relative to its peers during an industry upturn when capacity becomes tighter, and suffers during a down-cycle when lower asset utilisation puts downward pressure on margins.

With a diverse services portfolio, Saipem is more of a one-stop shop, rather than a niche player. Gas trunklay (large-diameter pipelay) is the only area in which Saipem has unmatched capability. Saipem’s competitive advantage instead lies in its execution/construction capability through its global reach and strong local content. This strategy has worked well for Saipem historically, but as projects become more complex (onshore and offshore), specialist demand has risen – which is where Saipem lags. In addition, the value of its execution expertise is coming under scrutiny as it has been unable to compete effectively against Korean services companies with access to low-cost Asian value chains. Hence, despite its diversified exposure to the value chain, we believe Saipem lacks the nimbleness to compete against the likes of Technip and Subsea 7.

Offshore E&C

Saipem’s key strength in its Offshore E&C division is its industry-leading fleet of more than 35 offshore construction vessels. Its activities generally include the EPIC of offshore oil and gas facilities. Saipem typically executes these on a lump sum turnkey (LSTK; ie fixed-price) basis. Around 85% of its E&C backlog is lump sum, the remainder being on a less risky, cost-plus basis.

Offshore E&C – EBIT (EURm) and margin (%)

Order backlog (EURm) versus book-to-bill


The division covers a wide range of offshore activities including installing and maintaining subsea architecture (in which Saipem is behind industry leaders, Technip and Subsea 7); laying long-distance, transmission (ie large-diameter) pipelines (mainly natural gas) in both shallow and deep water; and operating heavy-lift cranes and other offshore vessels, such as remotely operated vehicles (ROVs). It also has a small, leased FPSO business but, given the low returns, Saipem is cautious about expanding this business aggressively.

Its operations are bolstered by manufacturing sites across the globe, which are crucial in providing local content. The latter is of ever-increasing importance to

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resource-holding governments, keen that their economies should benefit from more than merely selling oil and gas production. This should leave Saipem well-placed to capitalise on such relationships, in our view.

Saipem has just emerged from a high-capex phase and has expanded its vessel fleet. Amassing this fleet does not come cheaply which, to some extent, raises barriers to entry and limits competition. For example, in deepwater pipelaying, Saipem’s principal competitor is Allseas, a privately-owned company, with a smaller fleet and more limited financial strength.

Recent additions to Saipem’s fleet were the ultra-deepwater pipelay vessel Castorone, along with FDS 2 (Field Development Ship) and Saipem 7000, both pipelay and/or heavy-lift vessels. These vessels cost around USD1bn each and have increased the company’s operational gearing.

As the industry’s offshore capabilities improve in deep water, this has increasingly become the domain of the international majors. To this extent, offshore activity should become more predictable, as few majors tend to cut spending materially during oil price downturns. That said, contract awards can be delayed in the hope of lower costs.

Given the division’s high fixed-cost base, project activity can become lumpy in nature, and pricing (and hence margin) development tends to be a function of industry utilisation. Over the 2010-12 period and into 2013, the offshore construction market has been relatively weak, with a relative dearth of large contract awards. This has resulted in declining backlogs for many players in the industry, so competition for new awards has been quite aggressive. Saipem’s recent profit downgrade for 2013 is a result of this competition.

Onshore E&C

Saipem’s Onshore E&C division carries out detailed engineering, procurement and construction (EPC) services for onshore upstream projects, midstream projects (eg gas processing) and downstream projects (ie refineries, LNG facilities, petrochemical and fertiliser plants). Again, most of the projects are carried out on a fixed-cost basis (lump sum). Saipem has a particular geographical focus on the Middle East (especially Saudi Arabia), North and West Africa and the Caspian Sea.

Since onshore activity tends to be less asset-intensive than offshore, margins are typically lower. Also, the client base tends to be different – clients are more often NOCs whose investment levels are typically steadier over time and less vulnerable to oil price volatility. NOCs also tend to value local content more highly, which plays to Saipem’s strengths in countries such as Algeria and Nigeria. Lower complexity results in project approvals being granted more quickly, although the timing of contract awards can be as unpredictable as for offshore projects.


197

Onshore E&C – EBIT (EURbn) and margin (%)

Order backlog (EURbn) versus book-to-bill


Onshore margins have fallen sharply since peaking in 2011 as a result of tough pricing competition, particularly in the Middle East (principally from the big South Korean chaebols – Samsung, Daewoo, Hyundai). Saipem is biting the bullet after a sharp drop in margins and is adopting a more selective approach, rather than bidding aggressively on price. Despite this, we only expect a modest margin improvement from here onwards, as we believe the competitive landscape in the MENA region (Saipem’s core market) has changed for the long term. We expect margins to eventually normalise in the range of 4-5%.

Offshore Drilling

Saipem operates a mid-sized fleet of drilling units, currently comprising two drillships, seven semi-submersibles, eight shallow-water jack-up units and one tender-assisted drilling unit. The latest additions to the fleet are the Scarabeo 9 ultra-deepwater and the Scarabeo 8 semi-sub. All the deepwater units are contracted on a long-term basis to 2015-17, a number of them to parent company, ENI. This gives a degree of stability to divisional earnings with little room to increase the backlog unless Saipem decides to expand the fleet further. We do not envisage this for the foreseeable future.

Onshore Drilling

The Onshore Drilling division owns and operates a fleet of 106 onshore rigs in 12 countries. Around two-thirds of the fleet operates in Latin America (Peru, Venezuela, Colombia, Brazil, Ecuador and Bolivia). Margins tend to be more volatile from quarter to quarter given the shorter duration of contracts compared with those for Saipem’s offshore activities, and are generally half the level of those in the more capital-intensive Offshore Drilling segment, as shown in the chart below.

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Saipem’s onshore versus offshore drilling margins (%)


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Offshore E&C – the “new normal”

Divisional background: Saipem’s key strength in this division is its industry-leading fleet of more than 35 offshore construction vessels. Its activities generally consist of the engineering, procurement, installation and construction (EPIC) of offshore oil and gas facilities. Saipem typically executes these on an LSTK (ie fixed-price) basis. Around 85% of its current E&C backlog is lump sum, the remainder being on a less risky, cost-plus basis. The division comprises a wide range of offshore activities including installing and maintaining subsea architecture (in which Saipem is behind the industry leaders, Technip and Subsea 7), laying long-distance transmission (ie large-diameter) pipelines (mainly natural gas) in both shallow and deep water, and operating heavy-lift cranes and other offshore vessels.

Offshore E&C financial estimates

Offshore E&C


Following its significant guidance downgrade for 2013, Saipem has given greater granularity on the bid pipeline over the medium term. With Saipem, the problem has not been growth per se but its “quality”. The company’s offshore backlog grew to EUR8.7bn in 2012 compared to EUR6.6bn at the end of 2011 and EUR5.5bn at the end of 2010. The share of high-margin regions like West Africa and central Asia (the Caspian Sea and the Black Sea) will fall in 2013 with the completion of large contracts like the Kizomba tieback, Nord Stream twin pipeline and Kashagan trunkline projects in 2012.

However, what is positive is that Saipem’s bid pipeline contains a number of mega-projects in high-margin West Africa, East Africa and central Asia. Short-term opportunities over 2013-14 include the Bonga South West Development (Nigeria, USD12bn FDC), Kaomba (Angola, USD3bn-4bn FDC), Moho Nord Democratic Republic of Congo, USD7bn FDC) and South Stream (Russia, USD2.3bn cost estimate). Medium- to long-term bidding opportunities include the Mamba field (Mozambique, USD50m FDC) and Shah Deniz Stage 2 (Azerbaijan, USD16m-20m FDC).

Based on this healthy bid pipeline, we project divisional revenues to grow at a 8% CAGR over 2012-15. We expect the EBIT margin to rise to 7% by 2015 after falling to -0.6% in 2013. Order intake would have to average EUR6.2bn pa to meet our estimates; we think this is achievable looking at the extensiveness of Saipem’s bid pipeline.

€ m 2010 2011 2012 2013E 2014E 2015E

Sales 4,486 5,075 5,356 5,793 6,256 6,694

As % group 40% 40% 40% 43% 46% 49%

Sales growth 13% 6% 8% 8% 7%

EBIT 613 686 690 -33 313 469

As % group 46% 46% 47% 172% 36% 40%

EBIT margin (%) 13.7% 13.5% 12.9% -0.6% 5.0% 7.0%


200

Offshore E&C – order intake to average EUR5.9bn pa to meet our top-line estimates over 2013-15


Demand dynamics

Over the next five years, the largest offshore E&C markets will remain the North Sea, the GoM, Brazil and West Africa. The impetus for large E&P spending in these four regions will be based on reversing production declines (Norway) or boosting oil export capacity (Brazil). Asia-Pacific and East Africa, on the other hand, will be areas of strong growth with high investment in large gas fields in Mozambique and Tanzania and the development of under-penetrated deepwater basins in Asia.

We believe Saipem is well-placed to tap a number of project opportunities which are likely to arise in these core geographies. Key factors supporting this view include Saipem’s links with ENI (which is developing the Mamba gas fields in Mozambique), its strong local content capability and its dominant position in large-diameter pipelay.

Saipem is exceptionally strong in shallow water basins such as the North Sea, the Caspian Sea, Asia-Pacific and Nigeria. In offshore E&C, Saipem’s core competency lies in developing fixed offshore platform facilities through its heavy-lift vessels and large-diameter pipelines through its S-lay vessels. Only six vessels in its 35-strong fleet have ultra-deepwater capability and it has a small fleet of five subsea construction vessels.

The offshore oil and gas sector is maturing and the number of discoveries in shallow water basins is coming down. This highlights that the thrust of future oil and gas exploration and development (and hence capex) will be in deep waters. Saipem’s lack of an asset base and expertise in this area will likely have implications for the type of growth it will be able to achieve. It currently has no plans for a major new capex programme. In our view, this will limit its ability to tap high-margin work in the golden triangle area (Africa, the GoM and Brazil) in the medium term.

Historical growth dynamics

Saipem has experienced strong growth in its project backlog – and subsequently its top line – since the slump in project awards in 2010. In 2012, it booked new contracts of ~EUR7.5bn, taking the backlog to EUR8.7bn for the division, compared to EUR6.6bn at the end of 2011. The strong growth has been

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underpinned by project wins, especially for gas export lines for the Ichthys LNG (Australia), Otumara Sighara Escravos (Nigeria) and Vladimir Filanovsky (Russia) projects. Saipem also won a large, USD1.1bn+ contract for the Sapinhoa North field (Brazil), for which it will supply riser and gas export systems. Although growth has been strong, the quality of growth has become a pressing issue for the company leading to significant earnings and margin revisions for 2013. Looking ahead, we believe any margin re-rating will depend on portfolio restructuring in terms of both geographical exposure and the type of work undertaken. We think that this will prove difficult for the company.

Regional growth

The following graph shows the geographical split of project awards for the Offshore E&C division by value since 2010. It shows that the awards have been quite diversified, with contract wins in all major oil regions. Low-margin regions such as MENA, Asia-Pacific and the GoM have collectively accounted for a high share of the contract wins. Saipem has been investing to improve its local presence in the Americas and opened a new fabrication yard in Canada in 2012, with another yard currently under construction in Brazil. However, despite this geographical diversity in its Offshore E&C backlog, the fact remains that Saipem (despite its scale) is primarily a shallow-water field infrastructure developer.

Geographical split of the contracts won since 2010 (by value)


The following chart shows the expected revenue contributions from the Offshore E&C backlog by geography between 2013 and 2015. The MENA and North Sea regions will be the primary revenue contributors for the company until next year. However, the Middle Eastern Al Wasit project will be in the installation phase in 2013 and will be executed by 2014. This explains the slump in MENA revenue contribution from next year. By comparison, the North Sea’s region’s revenue contributions will be more uniform, with only a marginal decline in 2014. This is explained by the smaller and more continuous nature of the contracts in the area.

Brazil & rest of South America

11%

North Sea & Europe

19%

Central Asia14%Middle East &

North Africa19%

West Africa15%

Asia Pacific15%

GoM7%


202

Offshore E&C divisional backlog schedule by geography (EURbn)


Project mix

The following table shows an important segment of our bottom-up revenue model for Saipem’s Offshore E&C division. It shows our revenue estimates for Saipem’s offshore E&C contracts which are currently in the divisional backlog. Our bottom-up model projects that 55% and 37% of the backlog will mature in 2013 and 2014, contributing revenues of EUR4.7bn and EUR3.2bn respectively. A number of contracts won in 2012 should move into their high revenue-generating phase over the next 24 months.

In the regional growth section above, we explained that the Middle East and North Sea regions would be the largest revenue contributors for the division in 2013. This will have negative implications for the quality of growth, which is evident in Saipem’s significant earnings downgrade for this year. We discuss the quality of growth in more detail in the Financial estimates section of this report.

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Offshore backlog revenue model


Country ClientContract value

($ m)Start date 2012 2013 2014 2015

Offshore E&C

Sapinhoa Norte & Cernambi Sul Brazil Petrobras 600 19/10/2012 - 150 210 240

Girassol and Dalia FPSOs Angola Total 100 19/10/2012 - 30 35 35

Vladimir FilanovskyRussia/ Caspian

SeaLukoil 250 19/10/2012 - 119 131 -

Congo River Crossing PipelineAngola/ DR of

CongoChevron 350 24/09/2012 44 236 70 -

URF & gas export line Angola Chevron 300 Q4 2013 - 38 143 120

Keppel FELS B Class rigKazahkstan/Caspia

n Sea

Teniz

Burgylau150 24/09/2012 - 45 53 53

UK sector of the North Sea UK/ North Sea 150 24/09/2012 - 45 53 53

Southern part of Mafumeira field Angola Chevron 200 29/06/2012 30 65 70 35

ASASA Pressure Maintenance project & Usari FA-FR Risers

and Edop Pipeline extensionNigeria

Mobil

Producing

Nigeria/

Aveon

100 29/06/2012 23 51 26 -

Vladimir Filanovsky: Northern Caspian SeaRussia/ Caspian

SeaLukoil 770 21/05/2012 116 250 270 135

Hejre fieldDenmark/ North

SeaDong E&P 330 21/05/2012 78 165 87 -

Lula field: Gas export trunkline Rota

CabiúnasBrazil Petrobras 490 29/03/2012 135 201 154 -

Marjan and Manifa fields Saudi ArabiaSaudi

Aramco210 29/03/2012 74 109 28 -

Ichthys LNG Project: Gas Export Pipeline Australia INPEX 1170 18/01/2012 351 410 410 -

US sector of the Gulf (400km New Orleans) GoM 630 18/01/2012 189 221 221 -

Gas export pipeline Lula NE - Cernambi Brazil Petrobras 150 16/12/2011 45 53 53 -


204

Offshore backlog revenue model – continued



($ m)Start date 2012 2013 2014 2015

Dragon – CIGMA Gas Export Pipeline Venezuela PDVSA 450 16/12/2011 214 236 - -

Basra Terminal - Iraq Crude Oil Export Expansion, Project – Phase 2 IraqSouth Oil

Company375 17/10/2011 113 131 131 -

OFON2 - D030 contract Nigeria Total 525 17/10/2011 158 184 184 -

Platforms & marine facilities: UK & Norwegian North SeaNorway & UK/ North

Sea, GoM600 17/10/2011 180 210 210 -

Kirinskoye Gas Condensate

FieldRussia/ Bering Sea Gazprom 350 30/09/2011 79 123 123 -

Ruby Field Development - Sebuku BlockBorneo/ Makassar

Strait

PearlOil

(Sebuku) Ltd150 30/09/2011 34 53 53 -

West Delta Deep Marine Concession EgyptBurullus Gas

Company350 13/06/2011 114 123 61 -

Norwegian and British sectors of the North SeaNorway & UK/ North

Sea450 13/06/2011 146 158 79 -

Expansion CPC marine export terminal Russia/ Black Sea

Caspian

Pipeline

Consortium

100 13/06/2011 51 26 - -

(1) Liwan 3-1 Field – Deepwater EPCI, (2) Guara & Lula-Northeast gas

export pipelinesChina & Brazil

(1) Husky Oil

China Ltd, (2)

Petrobras

1000 03/05/2011 325 350 175 -

Al Wasit Gas program Saudi Arabia Saudi Aramco 2200 09/03/2011 770 770 - -

Walker Ridge export pipeline GoMChevron &

Shell420 16/12/2010 105 110 110 -

2 platforms as part of the Greater Ekofisk Area Development project Norway/ North SeaConocoPhillip

s Petroleum280 31/03/2010 74 74

FPSO vessel Aquila field Italy Eni 1000 25/10/2009 210 210 210 -

Bonga North-West field Nigeria Shell 200 14/10/2009 53 53 - -

4,783 5,002 3,346 670


205

Offshore E&C bid pipeline by region

Saipem is very strong in the installation of large-diameter pipes, topsides and jackets. The scale, type and quality of its asset base are the key determinants of its success in winning contracts and of the geographical mix of its revenues. In this section we discuss the key opportunities for Saipem in its key geographical markets in light of its asset base.

West Africa Projects currently in the FEED stage will likely see EPIC awards for subsea construction, platforms, topsides and export pipelines over the next 24 months. The Saipem 3000 (heavy-lift and pipelay) and S-lay barge S355 have a West Africa focus, and along with vessels with high transit speeds (Castorone, Saipem FDS 2) could be used to bid for these projects.

We highlighted earlier that Saipem has previously carried out a considerable amount of work for ENI (Saipem’s parent company), Total, Conoco and Statoil. As can be seen in the table below, ENI has two projects currently in the FEED stage in West Africa, one in Angola and one in Nigeria. Block 15 East Hub and the Zabazaba/Etan field development projects will require the installation of subsea trees tied back to an FPSO. Zabazaba will also need the installation of 130km of gas export lines. Saipem would be ideally placed to execute the heavy-lift and export line installation work required for these projects, in our view.

Total is developing the Kaombo project in Angola; the project is already in the tendering phase for two converted FPSOs. Field development is estimated to cost USD3bn. Modec, SBM offshore and Saipem are bidding for the project, with Modec and SBM regarded as the main contenders. Total is expected to award the EPC contract for the conversion of two FPSOs by mid-2013 on a “design one and build two” concept. Field development will also require the installation of subsea equipment and flowlines, in which Saipem could use its FDS and Saipem 3000 vessels if it wins the subsequent contracts.

In 2012, Saipem successfully completed the first phase of the USD650m Kizomba satellite tieback project, which included the engineering, construction, transport and installation of pipelines, umbilicals, risers and subsea systems connecting the Mavacola and Clochas Fields to the existing FPSO units at Kizomba A and B. The second phase of the project is currently in the planning stages and we believe that Saipem, given its experience there, should benefit from a natural preference for additional development. The following table also shows large upcoming projects by BP, Maersk and Chevron.

North Sea

Saipem has two primary enablers – Saipem 7000 and Castoro Sei – which together can lay infield lines as well as large-diameter trunklines; they also have sizeable heavy-lift capability of 14,000 tonnes which can be used either to assist in subsea construction or for platform and topside installations.

In the previous section, we highlighted that Saipem has executed and is executing a number of pipeline and platform installation projects for Statoil in Norway. This includes the Gudrun Sigrun development project, the Gjoa export pipeline and platform, the Ekofisk jacket and the Valemon topsides and flare. The following table shows a number of projects in UK and Norway which are in various phases of development and should see project awards in the medium term. Statoil will be


206

the operator of a number of these projects. Considering Saipem’s strong relationship with the company, it is well placed in bidding for these new developments, in our view.

In the UK, Statoil has already taken a final investment decision on the Mariner project which is estimated to cost more than USD7bn and would be the largest development in the UK in more than a decade. Statoil is targeting 55,000bd between 2017 and 2020. Statoil has already won the heavy-lift operations for the project, and a contract for risers, pipeline, umbilicals and marine operations as well as a floating storage unit (FSU) is likely to be awarded in Q2 2013. Statoil’s second UK project, Bressay, is very similar to Mariner and the company is expected to take a final investment decision on the project this year. In both projects, the field will be linked to an FSU and the output will be transported via shuttle tankers. As in the case of Mariner, Saipem would therefore be ideally placed to supply the heavy-lift requirements for Bressay, in our view.

In Norway, Statoil has a number of projects for which it has already submitted the field development plans. While smaller discoveries will primarily be tied back to existing infrastructure, Statoil’s larger projects (or those further away from the existing facilities), like the 225m boe Dagny gas field, will require a development solution of separate platforms for processing and FSUs and shuttle tankers for oil and gas transportation. The development of the Dagny field is estimated to cost USD5.4bn.

Asia-Pacific

Saipem recently opened a fabrication yard in Indonesia, which along with dedicated S-lay vessels in the region enables the company to execute EPIC projects in Asia-Pacific. Saipem’s S-lay vessels Castoro Otto, Castoro 10 and Semac 1 are based in Asia-Pacific. The new pipelay vessel Castorone will also be executing a project in China during 2013.

On the back of its strong local presence, Saipem has worked and is working on a considerable number of projects in the Asia-Pacific region. Countries which stand out from a project perspective are Indonesia, Vietnam and Australia. The following table shows the large projects in the Asia-Pacific region which are currently in various stages of development. The strongest impetus in development is expected in offshore China, with CNOOC as the operator.


207

Saipem offshore bid pipeline


Location Status StartupFiled development

estimateOperator

SURF / Subsea

Bonga South West Nigeria ; South West field FEED 2020 $12 billion Shell

Burullus 9BEgypt; around 90 km offshore

the northwest Nile delta2013 Saipem

Carioca Brazil 2016 Petrobras

Egina Nigeria FEED 2017 $15bn Total

Jangkrik Indonesia, East Kalimantan FID given in Feb'13 2015 1.4$bn Eni ; GDF Suez holding

Kaombo - Block 32 Angola Feed 2017 3-4$ bn Total

Lula 2 fields BrazilTendering/Under

ConstructionPetrobras

Moho North Congo Dev. 2016 $7bn Total

Mozambique - Anadarko Mozambique pre FEED 2018 $50bnEni, Anadarko Petroleum

Corp

Mozambique - Eni Mozambique like 9 like 9 like 9 like 9

OPL 245 Nigeria FEED Eni

Rabicoes Brazil

Scarborough URF Australia


208

Saipem bid pipeline – continued


Location Status StartupFiled development

estimateOperator

Pipelines

Argo Cluster Italy

Browse Package 1 Australia FEED 2017 $30-$50bn Woodside Energy Ltd.

Kepodang Indonesia FEED 4Q 2014 Petronas

Rota 3 Brazil

Shah Deniz Stage 2 Azerbaijan Study 2017 $16-20 bn

South Stream South Russia in construction 2015 $2.3bn Gazprom

Floaters

Gendalo-Gehem FPU 2 units Indonesia pre FEED 2016 1 $bn Chevron

Kaombo (Block 32) FPSO Angola pre FEED 2016 Total

Masela FLNG Indonesia, Arafura Sea FEED 2014 - 2018 $19.6bn Inpex Masela

Moho FPUCongo, 70km of Congolese

CostFEED $8bn Total, Aker Solutions

Mozambique FLNG Mozambique

Scarborough FLNG Australia 2015 ExxonMobile

Fixed Facilitie

Dragon-Patao Venezuela FEED 2016 1.5$bn PDVSA

Lucapa Angola pre FEED 2014 Chevron

South Ndola Angola

Tangguh Indonesia 12 $bn BP


209

Profitability

Since peaking at 14.2% in 2009, Saipem’s Offshore E&C operating margins have deteriorated to an average of 12.9% in 2012. In its recent earnings guidance, Saipem reduced its 2013 EBIT forecast for the division sharply. The cut in the company’s guidance is based on the timing of project execution and contract awards as well as costs associated with the delayed commissioning of the Castorone vessel. Saipem contends that that many of the projects won in the highly competitive environment of 2009-11 will be in the execution phase in 2013, which will have a deleterious effect on overall margins. The share of higher-margin contracts in the Baltic Sea, West Africa and Caspian Sea in the overall backlog will dip in 2013, with project work in many of these regions having concluded in 2012. In addition, Saipem has compromised on margins in order to break into the Brazilian market.

In this section, we analyse the profitability of individual projects currently in the backlog and of the high-margin contracts Saipem could potentially win in the medium term. This will help us project earnings from the backlog and those from new projects over the next three years. Our methodology for the Offshore E&C segment is the same as we adopted and explained in our report on Subsea 7.

Our bottom-up analysis corroborates management’s view of a dip in earnings in 2013. This is based on the assessment of projects by the type of work and their location. Saipem’s profit recognition policy is done on a “progressive progress basis”; ie booking profits based on the percentage of completion of the project.

Geographical split of projects – implications for profitability In an earlier section, we showed our revenue estimates split by geography. We repeat the following graph to illustrate the implications this geographical split will have on Saipem’s profitability. We estimate that 54% of total divisional backlog profits will be recognised in 2013, a figure which will fall to 37% in 2014.

To estimate the profits from the current Offshore E&C backlog, we classify the profits as high, medium and low margin. This is dependent on: 1) geography; 2) water depth; and 3) the date of project award.

Offshore E&C divisional backlog schedule by geography (EURbn)


0

1

2

3

4

5

6

7

2012 2013 2014 2015

GoM

Asia Pacific

West Africa


Central Asia

North Sea &Europe

Brazil & rest ofSouth America


210

The following table focuses on the final project stage and lists the projects according to timing, location, water depth and margin profile. The light orange cells represent high-margin installation phases and the dark cells represent low-margin installation phases. Typically, a high-margin installation phase is seen with deeper water projects, especially those in West Africa. Exceptions to this rule are the deepwater projects in Brazil, where Saipem is compromising on margins to gain market share. Shallow-water projects, especially in competitive regions like Asia-Pacific, are low-margin. Exceptions to this rule are the shallow water projects in the Caspian Sea and the Black Sea.

Based on this methodology, we create the following profitability profiles of the installation phase of the project backlog. As can be seen in the table, only one high-margin project (the CPC marine terminal expansion project) will be in the installation phase in 2013. At that time, the low-margin Al Wasit project will also be in the installation phase. In 2014, five high- and eight low-margin projects will be in the installation phase. This means that although earnings should rebound in 2014, the improvement in margin will not bring divisional margins back to the levels seen over the past two years.


211

Contracts by margin profile

Source: Berenberg

Country Client 2012 2013 2014 2015

Offshore E&C

Sapinhoa Norte & Cernambi Sul Brazil Petrobras Deep (low margin)

Girassol and Dalia FPSOs Angola Total Deep (high margin)

Vladimir Filanovsky Russia/ Caspian Sea LukoilShallow (high

margin)

Congo River Crossing Pipeline Angola/ DR of Congo ChevronShallow (high

margin)

URF & gas export line Angola ChevronShallow (high

margin)

Keppel FELS B Class rig Kazahkstan/Caspian Sea Teniz BurgylauShallow (high

margin)

UK sector of the North Sea UK/ North Sea Shallow

Southern part of Mafumeira field Angola Chevron Deep (high margin) Deep (high margin)

ASASA Pressure Maintenance project & Usari FA-FR Risers and Edop

Pipeline extensionNigeria

Mobil Producing Nigeria/

Aveon OffshoreDeep (high margin)

Vladimir Filanovsky: Northern Caspian Sea Russia/ Caspian Sea Lukoil Deep (high margin) Deep (high margin)

Hejre field Denmark/ North Sea Dong E&P Deep (high margin)

Kizomba Satellites Tiebacks Angola ESSO Deep (high margin)

Lula field: Gas export trunkline Rota

CabiúnasBrazil Petrobras Deep (low margin)

Marjan and Manifa fields Saudi Arabia Saudi AramcoShallow (low

margin)

Ichthys LNG Project: Gas Export Pipeline Australia INPEX Shalow

US sector of the Gulf (400km New Orleans) GoM 0 Deep

Gas export pipeline Lula NE - Cernambi Brazil Petrobras Deep (low margin)

Dragon – CIGMA Gas Export Pipeline Venezuela PDVSA Deep

Basra Terminal - Iraq Crude Oil Export Expansion, Project – Phase 2 Iraq South Oil CompanyShallow (low

margin)


212

Contracts by margin profile – continued

Source: Berenberg

Country Client 2012 2013 2014 2015

OFON2 - D030 contract Nigeria Total Shallow

Platforms & marine facilities: UK & Norwegian North SeaNorway & UK/ North Sea,

GoM0 Shallow

Kirinskoye Gas Condensate

FieldRussia/ Bering Sea Gazprom

Shallow (high

margin)

Ruby Field Development - Sebuku Block Borneo/ Makassar Strait PearlOil (Sebuku) Ltd Shallow

West Delta Deep Marine Concession Egypt Burullus Gas Company Deep

Norwegian and British sectors of the North Sea Norway & UK/ North Sea 0 Shallow

Expansion CPC marine export terminal Russia/ Black Sea Caspian Pipeline ConsortiumShalow (high

margin)

Shalow (high

margin)

(1) Liwan 3-1 Field – Deepwater EPCI, (2) Guara & Lula-Northeast gas

export pipelinesChina & Brazil

(1) Husky Oil China Ltd, (2)

PetrobrasDeep (low margin)

Al Wasit Gas program Saudi Arabia Saudi AramcoShallow (low

margin)

Walker Ridge export pipeline GoM Chevron & Shell Deep

Experimental phase of the Kashagan field development Kazahkstan Agip KCO Shallow

Critical Crude Pipeline Replacement Project Nigeria Shallow

Castor Underground Gas Storage Development Project: Construction

Gas PipelineSpain UTE ACS Cobra Castor Shallow Shallow

Nord Stream twin gas pipelines Baltic Sea Nord Stream AGShallow (high

margin)

Extension of the ‘Kashagan

Trunklines’Kazahkstan Agip KCO Shallow

P55-SCR project, Roncador field Brazil Petrobras Deep (low margin)

3 platforms for the Jasmine Development Project UK/ North Sea ConocoPhillips Petroleum Shallow

2 platforms as part of the Greater Ekofisk Area Development project Norway/ North Sea ConocoPhillips Petroleum Shallow

FPSO vessel Aquila field Italy Eni Deep

PNG LNG Offshore Pipeline Project EPC2 Papua New Guinea ExxonMobil company Shallow

Chim Sao Platform and Pipelines Project VietnamPTSC

Mechanical and ConstructionShallow


213

Onshore E&C – on the edge of a backlog cliff

Saipem’s Onshore E&C division carries out detailed EPC services for onshore upstream projects, midstream projects (eg gas processing) and downstream projects (ie refineries, LNG facilities, petrochemical and fertiliser plants). Saipem has high exposure to the MENA region and has suffered because of the aggressive bidding approach of its Asian peers.

Onshore E&C estimates

Onshore E&C


Saipem’s Onshore E&C division has not fared well since 2010. The backlog has fallen sharply as a result of the low order intake. Revenues have been supported by eating into the divisional backlog. The company has been losing market share to South Korean competitors in its core MENA market. In its earnings guidance, management expects an 80% slump in operating profits in 2013 versus 2012. This is based on the low-margin contracts Saipem has entered into since 2010 and delays in large contracts in Venezuela, Nigeria and Iraq.

We are less optimistic about the long-term growth and margin outlook for Saipem’s Onshore E&C division. Saipem’s strengths lie in project construction and execution rather than engineering. This advantage pales in comparison to Asian competitors with low-cost value chains. This explains the depletion in Saipem’s divisional backlog, which has fallen from EUR10.5bn at the end of 2010 to EUR6.7bn in 2012. This depletion has occurred alongside a reduction in backlog quality, with the divisional EBIT margin projected to fall to -8.5% in 2013 compared to 8.1% in 2011.

In recent months, Saipem has adopted an increasingly aggressive approach towards competing for business in the Middle East in order to regain market share, but in our view this will be at the expense of quality. We believe the MENA onshore market has changed structurally, especially with regards to the competitive landscape. Whereas peers like Technip have diversified away from the region and built up their capabilities in early-stage and higher-tech engineering, the MENA region accounts for a substantial 54% of Saipem’s backlog – and its key market (ie construction and execution) has been largely commoditised.

In its recent presentation, Saipem gave detailed guidance on the bidding opportunities in the onshore E&C space. Half of these opportunities are in the MENA region. We expect the company to sustain revenue growth beyond 2014 on the back of these opportunities, which will likely be in the high revenue recognition phase by then. However, any improvement in margins will be muted, in our view, because of the structural factors discussed earlier. We expect the division’s operating margin to decline to 4% in 2015 after falling to -8.7% in 2013.

€ m 2010 2011 2012 2013E 2014E 2015E

Sales 5,236 5,945 6,175 5,668 5,101 4,846

As % group 47% 47% 46% 42% 38% 35%

Sales growth 14% 4% -8% -10% -5%

EBIT 370 483 395 -484 51 194

As % group 28% 32% 27% n.a. 6% 17%

EBIT margin (%) 7.1% 8.1% 6.4% -8.5% 1.0% 4.0%


214

Onshore E&C (EURm)


Regional split

The following graph shows the regional split of the Onshore E&C contracts won since 2010. Low-margin areas like the Middle East, Nigeria and Algeria account for ~70% of the contracts won since then. In the MENA region, the bidding environment has remained extremely competitive, with South Korean OFS companies undercutting their European rivals on the back of their low Asian cost base. In this environment, Petrofac is one of the few European companies which have been able to hold their stead. It has been able to do this through the tax advantage it gains by being based in the UAE. Saipem has no such advantage and has therefore struggled both to win projects and to sustain divisional margins.

Onshore E&C geographic split of the contracts won since 2010 (EURm)


The following graph shows the revenue progression for the contracts in the divisional backlog, split by geography. The Middle East and Africa combined will account for 54% of the revenues in 2013. The divisional backlog supports revenues until 2014; hence Saipem will need to win projects to refill its backlog and maintain, if not grow, its top line.

0%

20%

40%

60%

80%

100%

0

2,000

4,000

6,000

8,000

10,000

2013E 2014E 2015E 2016E 2017E

Sales backlog schedule

Implied order intake Coverage (%, RHS)

€ m

Mexico & Suriname

10%Italy2%

Middle East & North Africa

54%

West Africa15%

Australia11%

Canada8%


215

Onshore E&C backlog revenue split by geography (EURbn)


Project mix Saipem currently has 26 projects in its Onshore E&C backlog. The following chart shows the breakdown by type of onshore project won since 2010 (based on project value). As can be seen, the largest segment is gas processing at 30%, followed by onshore pipeline at 17%. Similarly, Saipem is executing a number of infrastructure projects such as railway lines, port structures and drainage systems in various regions. These make up 13% of the projects won since 2010. These three onshore E&C segments – like the projects within them – command low margins. Saipem has traditionally been the leader in refining developments; however, since 2010, refining plants have accounted for only 11% of the total onshore orders won. This will have a negative influence on margins, in our view.

Onshore E&C revenue split by type of project


Saipem follows a revenue recognition policy based on “cost to cost”. For a typical full EPC contract, the cost breakdown is based on the cost incurred at each stage. Assuming that each stage takes an equal amount of time, 20% of the revenues are recognised in the engineering, 40% in the procurement and 40% in the construction phase. Based on this revenue recognition methodology, we have estimated the revenue progression for each contract in the Onshore E&C division.

0

1

2

3

4

5

6

2012 2013 2014 2015 2016

Canada

Australia

West Africa


Italy

Mexico &Suriname


14%

Oil sands8%

Fertilizers4%

Onshore pipeline14%

Gas processing29%

Field development

16%

Infrastructure14%

Power1%


216

Our analysis does not account for change orders for individual projects which can be up to 20% of the size of the original contract. We will use an average change order rate for the entire backlog to reach our final revenue estimates.

The following table shows our revenue projections on a contract-by-contract basis; we project revenues of EUR4.7bn in 2013 and EUR1.7bn from these contracts in 2014, which equates to 78% and 28% of our divisional revenue projections for the two years.

Onshore E&C backlog revenue model

Source: Berenberg


($ m)Start date 2012 2013 2014 2015 2016

EPC contract for a pipeline between El Encino, to Topolobampo MexicoTransportadora de Gas Natural

Norte-Noroeste400 22/11/2012 100 120 120 20

Additional scope for Santos GLNG Gas Transmission Pipeline Australia Santos GLNG 400 22/11/2012 180 220

Southern Swamp Associated Gas Solution Nigeria Shell 800 26/07/2012 144 488 168 - -

Naphtha & Aromatics Package of Rabigh II Saudi ArabiaSaudi Aramaco/ Sumitomo

Chemical 800 27/06/2012 180 205 210 105 -

Otumara-Saghara-Escravos Pipeline Nigeria Shell 200 27/06/2012 50 150 - - -

Package 8: Jeddah Stormwater Drainage Program Saudi Arabia Emarat 350 13/04/2012 88 263 - - -

Safco V Saudi Arabia SABIC 600 13/01/2012 222 252 126 - -

Railway tract linking Shah & Habshan UAE Etihad Rail Company 750 28/09/2011 169 263 263 - -

Two breakwaters and new quay Marroco Tangier Mediterranean 250 28/09/2011 56 88 88 - -

Horizon Oil Sands Project - Hydrotreater Phase 2 Canada Canadian Natural 390 21/09/2011 66 98 102 102 -

Independent Power Plant at Afam Nigeria Rivers State 260 21/09/2011 176 52 - - -

Expansion of the Tout

Lui Faut RefinerySuriname Staatsolie 640 25/07/2011 152 164 252 - -

Otumara-Saghara-Escravos gas pipeline Nigeria Shell 160 25/07/2011 120

Hi-speed/hi-capacity railway Italy Rete Ferroviaria Italiana 364 28/04/2011 118 127 64 - -

Gladstone LNG: Bowen and Surat Basins pipeline Australia Gladstone LNG Operations 1,000 14/01/2011 350 263 - - -

Early Production Facility Project for the

Jurassic fieldKuwait Kharafi National 480 17/12/2010 178 202 101 - -

Central Processing Facility Khurbet East oil field Syria Dijla Petroleum Company 720 17/12/2010 288

First phase Sunrise Oil Sands project Canada Husky Oil Company 850 03/12/2010 220 223 56 - -

LDHP project Algeria Sonatrach 350 20/09/2010 123 92 - - -

Olero Creek Restoration Project Nigeria NNPC/Chevron Nigeria Limited JV 50 20/09/2010 10

Reconstruction & extension of the Pointe Noire Container Quay Congo Port Autonome de Pointe Noire 100 20/09/2010 35 26 - - -

New booster station (BS-171) Kuwait Kuwait Oil Company 900 18/06/2010 293 315 158 - -

Gas process plant

and of the sulphur recovery unitUAE Abu Dhabi Gas Development 3,500 03/05/2010 897 919 459 - -

2 desulphurisation units & 2 amine regeneration units Mexico PEMEX 800 10/03/2010 210 105 - - -

Gorgon LNG jetty and marine structures project Australia Chevron 300 13/11/2009 79 79 - - -

Replacement of compressors systems at KOC’s Gathering Centres Kuwait Kuwait Oil Company 200 13/11/2009 42

4,264 4,651 2,386 327 20


217

Profitability

Since the start of 2012, Saipem’s Onshore E&C segment has suffered in terms of both growth and margins. The divisional EBIT margin averaged 6.4% during 2012, compared to 8.1% in 2011. This trend will be exacerbated in 2013 and we expect an operating loss of EUR527m for the division. This will be on the back of losses on projects in Mexico, Canada and Algeria.

Management has highlighted project delays in Venezuela. These are primarily heavy-crude projects to develop oil sands resources in the Orinico belt and therefore command a higher margin. In terms of geographical split, the Onshore E&C backlog is also skewed towards low-margin MENA and Nigeria.

In the previous section, we also showed the split of the project backlog by contract type and geography. We argued that most of the work to be executed is relatively low-margin gas processing, onshore pipeline and infrastructure projects, which collectively account for around 60% of the contracts won since 2010. Technologically complex refining projects accounted for only 11% of the contracts won during the same period. This explains the margin weakness the company is facing.

In addition, apart from one contract from 2009, the backlog consists entirely of work won since 2010, during which period the margin environment has been very tight.

Onshore E&C backlog split by project type

Geographical split



11%

Oil sands

8% Fertilizers4%

Onshore pipeline17%

Gas processing30%

Field development

15%

Infrastructure13%

Power2%

Mexico & Suriname

10%Italy2%

Middle East & North Africa

54%

West Africa15%

Australia11%

Canada8%


218

Drilling

Offshore Drilling

Offshore Drilling estimates

Offshore drilling


Saipem has experienced strong growth in the backlog and revenues on the drilling side of its business, as well as an improvement in margins. This has occurred on the back of robust exploration and development drilling demand, especially for deeper waters. Saipem has implemented a sizeable capex programme over the last five years, as part of which it recently inducted the deepwater semisubmersible rigs Scarabeo 8 and Scarabeo 9. Management stated that, for the medium term, its major capex phase has been completed. In light of the long lead times to build a deepwater drill rig, we expect top-line growth in offshore drilling over the next five years to be a function of the re-rating of rig rates, as contracts for rigs approach renewal. These include Scarabeo 4 (Q4 2013), Scarabeo 5 (Q2 2014) and Saipem 10000 (Q2 2014), as well as four jack-up rigs.

Based on potential re-rating of around 10% for these rigs, as well as our assumptions of the downtime for these rigs over next five years, we expect top-line growth at a 3% CAGR over 2012-17. Considering the tight nature of the high-end deepwater rig space and the long-term trend towards deepwater field development, we expect strong divisional operating margins averaging ~30% over 2013-17.

Demand dynamics Saipem is a small player in the offshore drilling market and operates a fleet consisting of six ultra-deepwater, six deepwater and seven shallow water rigs. Since 2011 it has made two additions to the fleet: ultra-deepwater semisubmersibles Scarabeo 8 and Scarabeo 9. Both are on long-term charter (until the end of 2016) with ENI and are drilling in various locations in West Africa and the North Sea. The induction of these two units has helped the division post strong revenue and profitability growth over the last two years.

Unlike large players such as Transocean, which are able to exploit changes in rig rates by having vessels operating in the spot market, Saipem’s drilling units are contracted on a long-term basis. The fleet is currently fully utilised, a trend which is likely to persist looking ahead. Saipem’s ultra-deepwater rigs are contracted on average until 2015-17, a number of them to parent company ENI. This results in a degree of stability in divisional earnings, with little room to expand the backlog unless Saipem decides to expand its fleet further. The company has just emerged from a significant capex phase and we do not envisage any major rig additions in the foreseeable future.

€ m 2010 2011 2012 2013E 2014E 2015E

Sales 750 833 1,088 1,234 1,295 1,284

As % group 7% 7% 8% 9% 10% 9%

Sales growth 11% 31% 13% 5% -1%

EBIT 258 222 293 388 388 385

As % group 20% 15% 20% n.a. 45% 33%

EBIT margin (%) 34.4% 26.7% 26.9% 31.4% 30.0% 30.0%


219

Saipem is unique within the E&C OFS space in its drilling capability. This full service capability from drilling to field development provides Saipem with an edge in poor infrastructure regions and with less technologically advanced NOCs, especially in places like West Africa. Therefore its drilling operations – both on/offshore – are concentrated in areas where it already has a strong local E&C presence. This helps the company to build stronger links with the NOCs and creates cross-selling opportunities.

In addition, the cycles of the two activities (E&C and drilling) tend to operate out of phase with one another, reducing earnings volatility. Onshore/shallow water drilling tends to suffer first during a downturn as the duration of contracts is shorter, so lower day rates feed through quickly to profits.

Historical growth Saipem’s offshore drilling division revenues have grown at a robust rate of 24%cagr over 2008-12. This has come on the back of an aggressive capex plan with the aim of gaining ultra-deepwater capability. During this period the company inducted three new ultra-deepwater rigs which have contributed towards both top-line growth and margin improvement for the division. With the vessels already fully contracted, the company currently lacks spare capacity to generate further growth. Management currently does not envisage another capex programme to boost drilling capacity; hence future growth will primarily be a function of pricing rather than volume.

Geographical split Most of the high-end offshore rigs operate offshore Norway/UK and West Africa. Shallow-water units, on the other hand, are contracted in Asia and the Middle East. The graph below shows the average day rates of Saipem’s vessels operating in these regions. The fleet rate corresponds with the type of vessel operating there.

Saipem fleet average fleet day rate by geography (USD000 per day)


In East Africa, Saipem’s ultra-deepwater rig, Saipem 10000, is operating for ENI drilling wells at the prolific Mamba basin in Mozambique. This explains the high average rig rate in the region. In West Africa, a number of rigs are operating in both deep and shallow waters in Angola and Nigeria. This explains the low average day rate of USD450,000 in the region. Most of Saipem’s jack-up rigs are located in the Middle East, as the NOCs in the region progress in their relatively nascent offshore thrust. Saipem’s drilling fleet has no direct exposure to the GoM and so

443

500

150

450

0

100

200

300

400

500

600

West Africa East Africa Middle East, NorthAfrica and Asia

North Sea


220

was not directly affected by the fallout from the Macondo oil spill. Saipem also has no exposure to Brazil.

The following graph shows our top-line estimates by region for the Offshore Drilling segment. These are simple estimates in which we assume that rigs continue working in the same region in the future. The largest contributor will be West Africa, followed by the North Sea region and MENA and Asia.

Offshore drilling revenue contributions by region (EURm)


Future growth As can be seen in the graph, from 2013 onwards the top line (and also profitability) is forecast to be stagnant. We anticipate marginal top-line growth over the next five years. This will essentially come from pricing improvements on a number of rigs for which there will be new marketing rounds as their contracts expire over 2013-15. In 2013 and 2014, Saipem will hold marketing rounds for the Saipem 10000 and Scarabeo 5 ultra-deepwater rigs. Most of the deepwater and shallow water vessels are contracted for relatively short periods and most will also have new marketing rounds during this period. The improvement in the fleet day rates will likely be in line with the overall market trend.

In their recent strategy presentations, a number of IOCs have indicated plans to raise their rig counts for the exploration of new acreage and the development of new fields. This trend will be more pronounced in deep and ultra-deepwater where the main drive for exploration and development will be.

The following table shows our revenue estimates for the offshore drilling division based on a bottom-up approach of modelling the revenues from each rig. Based on the day rate trend in the spot market, along with the structural shifts in oil and gas exploration and development, we have assumed a 10% pricing improvement for ultra-deepwater rigs, 2% for deepwater and 10% for shallow water jack-ups when the contracts are renewed.

Based on this estimation methodology, we forecast an offshore drilling top line of EUR1.2bn in 2013 and a three-year revenue growth CAGR of 5.7% over 2012-15.

0

500

1,000

1,500

2,000

2011E 2012E 2013E 2014E 2015E 2016E

West Africa East Africa MENA & Asia North Sea Others


221

Offshore drilling revenue model

Source: Berenberg

Offshore Drill Vessels TypeInduction

date

Max water

depth (feet)

Country/

RegionContractor

Contract

untilConstruction yard 2011 2012 2013 2014 2015 2016 2017

Saipem 100005th gen Ultra

deepwater drillship2000 10000

Mozambique

/ East AfricaENI Aug'14 S a msung 2000 153.0 153.42 153.0 160.7 168.3 124.50 168.30

Saipem 120006th gen Ultra

deepwater drillshipApr'10 12000

Angola/

West AfricaTotal Aug'17 S a msung 2010 148.8 147.13 148.8 148.8 146.7 146.71 128.90

Scarabeo 75th gen semi

submersible drill rig1999 4920

Angola/

West AfricaENI 1Q16 Tuzla sh ipwa rd 1977 122.4 122.74 112.0 122.4 122.4 131.58 110.66


submersible drill rigApr'12 10000

North Sea/

NorwayENI 2Q17

S e vma sh ya rd , Finc a n tie ri ya rd

a nd We stc on ya rd 2012 - 50.51 153.0 153.0 153.0 153.00 136.44


submersible drill rigAug'11 12000 West Africa ENI 4Q16 Ya n ta i S h ipya rd 2012 - 145.87 153.0 153.0 153.0 153.00 142.94



Norway/

North SeaStatoil 2Q14 Finc a n tie ri h ipya rd 1990 99.6 120.72 81.5 126.8 129.1 103.29 129.11

Scarabeo 63rd gen semi


Egypt/ North

Africa

Burullus

Gas1Q15 Ra uma Re o la S h ipya rd 1984 103.3 39.91 107.1 104.2 95.3 77.82 104.75

Scarabeo 42nd gen semi


Egypt/ North

AfricaIEOC 3Q13 Blohm & Voss sh ipya rd 1976 45.9 45.27 46.1 32.1 46.2 46.18 46.52

Scarabeo 32nd gen semi


Nigeria/

West AfricaAddax Feb'14 Blohm & Voss sh ipya rd 1975 64.6 32.78 70.4 70.8 49.2 70.80 70.80

Perro Negro 2 Jack-up rig 300 UAE NDC 3Q13 UIE S h ipya rd 1980 23.4 18.21 24.0 25.4 24.7 19.75 25.80

Perro Negro 3 Jack-up rig 300 India

Hindustan

Exploration

Company

4Q12 Ita lc a n tie ri 1983 28.8 19.33 26.6 29.5 30.4 24.58 31.76

Perro Negro 4 Jack-up rig 150Egypt/ North

AfricaPetrobel 4Q14 Brownsville 1977 19.8 19.85 14.9 19.8 21.8 21.78 21.48

Perro Negro 5 Jack-up rig 245 Saud ArabiaSaudi

Aramco3Q13 Le vings ton sh ipya rd 1981 21.6 21.66 20.3 22.8 16.9 23.04 23.82

Perro Negro 7 Jack-up rig Apr'08 375 Saudi ArabiaSaudi

Aramco4Q14 Jo rong sh ipya rd 2007 35.8 42.96 40.5 41.1 38.7 45.19 45.19

Perro Negro 8 Jack-up rig Sep'10 350 Italy ENI Nov'14 La broy sh ipya rd 2010 42.8 41.90 40.5 42.3 46.5 44.54 45.19

Total revenues ($ m) 909.8 1,022.3 1,191.6 1,252.5 1,242.1 1,185.7 1,231.7

Revenues


222

Profitability The operating margin of the offshore drilling division has declined since 2008, falling from 36.4% to 26.9% in 2012. This has tracked the fall in the market day rates for shallow water rigs. Saipem contracts its shallow water jack-ups for relatively short durations; the subsegment is therefore more exposed to changes in market conditions and hence the spot day rates. The fall in divisional margins essentially reflects this trend. The company’s push into the less-cyclical deepwater drilling business has helped partly offset this decline in margins.

Over 2013-17, we expect divisional operating margins to average 31%. This improvement reflects the cyclical improvement in the day rates for both shallow and ultra-deepwater rigs, which should start feeding into profitability with the expiry of the current contracts. Based on our revenue estimates for the division, along with our margin assumptions for the next three years, we project divisional operating profits to grow at a CAGR of 8.3% over 2012-15.

Onshore drilling

Onshore drilling estimates

Onshore drilling


In its onshore drilling division, Saipem owns and operates a fleet of around 100 onshore rigs in 12 countries. Around two-thirds of the fleet operates in Latin America (Peru, Venezuela, Colombia, Brazil, Ecuador and Bolivia). Margins tend to be more volatile from quarter to quarter given the shorter duration of contracts compared to those for Saipem’s offshore activities, and are generally half the level of those seen in the more capital-intensive offshore drilling segment, as shown in the chart below.

€ m 2010 2011 2012 2013E 2014E 2015E

Sales 688 740 750 806 846 888

As % group 6% 6% 6% 6% 6% 6%

Sales growth 8% 1% 7% 5% 5%

EBIT 78 102 103 110 114 120

As % group 6% 7% 7% n.a. 13% 10%

EBIT margin (%) 11.3% 13.8% 13.7% 13.7% 13.5% 13.5%


223

Saipem’s onshore versus offshore drilling margins (%)


In the onshore drilling space, Saipem’s focus is primarily the Latin American region where two-thirds of its onshore rigs are based. The market is saturated by local and international players. Operating margins have therefore historically been in the low teens. In the last four years, margins have improved from 10.6% to 13.7% on the back of strong exploration and development drilling in the region. We project stable top-line growth at a 5.8% CAGR over 2012-15 and that margins will gradually decline.

0%

5%

10%

15%

20%

25%

30%

35%

40%

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Offshore Onshore Group


224

Financials and valuation

The oil services sector has been one of the market success stories in recent years and until lately Saipem has been no exception. After consistent outperformance during 2009-12, it has underperformed the wider pan-European market after announcing sharp cuts in earnings guidance for 2013. Saipem’s performance has been largely in line with the European OFS sector, but being a heavyweight it was a defensive bet during the collapse in the oil price during 2008-09.

Saipem share price versus pan-European market…

…and relative to the European OFS sector


We noted earlier that the sector and its constituents tend to be driven by earnings momentum, both in absolute and relative terms. The following charts highlight Saipem’s relative performance in terms of both share price and earnings momentum against the market and the OFS sector, respectively.

As can be seen, its relative share price performance has historically lagged its earnings performance against both sector and market. This has resulted in an earnings de-rating over the past five years. Versus the sector, the reason for Saipem’s lacklustre share price performance more recently is readily apparent – earnings upgrades at Saipem have lagged those for the sector as a whole.

Saipem price performance and earnings momentum relative to market…

…and relative to the European OFS sector



225

The absolute forward P/E is therefore a reasonable indicator of value for the stock. On this basis, the current level is towards the upper end of its 10-year range (excluding the financial crash in 2008). This is also true of Saipem’s cash flow multiple, shown in the right-hand chart below.

Saipem forward P/E multiple (x) Saipem forward P/CF multiple (x)


Valuation

Our DCF-based approach yields a fair value for Saipem of EUR14.2 per share and a 2014 target P/E multiple of 13.6x. We have employed a two-stage DCF model, which we think is appropriate considering that Saipem has completed its capex programme and free cash flow should remain in positive territory over 2013-22. The initial ten-year growth phase is valued under our WACC estimate of 8.3%. In the long-term, low-growth steady-state after 2017, we have assumed a terminal growth rate of 1% and a higher WACC of 9.2%, which is based on a target debt to capital ratio of 30%. Our projections of primary cash flow drivers along with a sensitivity analysis of our valuation are given below.


226


Source: Berenberg

DCF


Euro m 2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E

Revenues 13,386 13,458 13,456 13,671 14,140 14,667 14,960 15,259 15,565 15,876 16,193

Growth % 0.5% 0.0% 1.6% 3.4% 3.7% 2.0% 2.0% 2.0% 2.0% 2.0%

EBIT 1481 -19 854 1155 1387 1443 1526 1495 1479 1429 1376

EBIT Margin 11% 0% 6% 8% 10% 10% 10% 10% 10% 9% 9%

Less: Provision for taxes 393- 100- 189- 276- 344- 364- 397- 389- 384- 371- 358-

tax rate -27% 521% -22% -24% -25% -25% -26% -26% -26% -26% -26%

NOPLAT 1,088 120- 665 879 1,042 1,080 1,129 1,107 1,094 1,057 1,019

Working capital -1086 -268 -91 205 7 -28 -16 -16 -16 -17 -17

Depreciation 726 744 741 720 696 671 643 641 623 635 648

Dep/sales 5.4% 5.5% 5.5% 5.3% 4.9% 4.6% 4.3% 4.2% 4.0% 4.0% 4.0%

Net capex -1012 -952 -709 -623 -576 -599 673- 687- 669- 635- 648-

as a % of sales -8% -7.1% -5.3% -4.6% -4.1% -4.1% -4.5% -4.5% -4.3% -4.0% -4.0%

Free cash flow to the firm -284 -595 606 1181 1169 1125 1084 1045 1031 1041 1002

Free cash flow valuation

ROE (2022) 14.1%

ROACE (2022) 10.3%

Retention 67%

Growth post 2022 (Assets) 1.0%

Risk free rate 3.0%

Cost of debt 3.5%

Corporate tax rate 28%

Equity risk premium 7.0%

Beta 1.3

Beta post-2022 1.3


WACC 2012-22 8.29%


WACC > 2022 9.2%


Value 13-22 5,280


Net debt (m | 2012) 4358

Unfunded pension liability (m | 2012) 229


Value per share (Euro) 14.2


227

Sensitivity


FCFF

14 -1.0% 0.0% 1.0% 2.0% 3.0%

7.2% 14.0 15.9 18.3 21.8 26.8

8.2% 12.6 14.1 16.0 18.5 21.9

9.2% 11.6 12.8 14.2 16.1 18.7

10.2% 10.7 11.7 12.9 14.4 16.3

11.2% 9.9 10.8 11.8 13.0 14.5

LT

WA

CC



228

Financial estimates

Income statement Over 2012-15, we expect Saipem to report revenue growth at a 0.7% CAGR from EUR13.4bn to EUR13.7bn. We expect EBITDA margins to decline from 16% in 2012 to 14% in 2015 and net earnings to decline at a three-year CAGR of 9.5%. Our EBITDA growth estimates are lower than consensus by 10% on average during 2013-15. We expect pressure on margins as a result of likely increased competition in the onshore space.

Financial estimates


Balance sheet and cash flow Saipem’s balance sheet has weakened over the last few years, with leverage (net debt to equity) rising from 68% in 2011 to 87% at the end of Q1 2013. Despite the high debt ratio, Saipem has benefited from being a subsidiary of ENI, which has an A (S&P) credit rating. Only 6% of Saipem’s long-term debt is directly from banks while the rest is from ENI.

Saipem’s cost of borrowing would rise in the absence of the lending facility from ENI. Although ENI’s chairman has reaffirmed his support for the company retaining its stake in Saipem, the outcome of the ongoing graft litigation concerning Algerian contracts will likely have a strong bearing on ENI’s long-term position in the company.

Saipem’s debt structure Debt maturity (EURm)


The pressure on operating margins in the E&C space will mean that despite the lower capex commitments over the medium term, Saipem’s leverage will remain high. We estimate capex to average EUR0.7bn pa over 2013-17 and leverage to decline to 66% by 2015. In the long term, we expect Saipem to maintain a target

€ m 2012 2013E 2014E 2015E 3 year cagr

Sales (Beren.) 13,386 13,458 13,456 13,671 0.7%

Consensus 13,386 13,318 13,327 13,811 1.0%

EBITDA (Beren) 2,207 725 1,595 1,875 -5.3%

Consensus 2,207 775 1,783 2,131 -1.2%

Net Income (Beren.) 902 265- 459 669 -9.5%

Consensus 902 329- 580 848 -2.0%

Banks6%

ENI SpA20%

ENI Finance

International74% 0.0

200.0

400.0

600.0

800.0

1,000.0

1,200.0

1,400.0

2013E 2014E 2015E 2016E 2017E


229

leverage ratio of 30% for an efficient capital structure.

Lower capex commitments (EURm) and deleveraging


0.0%

20.0%

40.0%

60.0%

80.0%

100.0%

120.0%

-500

0

500

1000

1500

2000

2010 2011 2012 2013E 2014E 2015E

Operating cash flow Capex

Dividends Leverage (%, RHS)


230

Financials


Saipem 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

$/€ (period-average) 1.33 1.39 1.29 1.29 1.29 1.29 1.29 1.29

Revenues (€ m)

Offshore 4,486 5,075 5,356 5,793 6,256 6,694 7,096 7,451

Onshore 5,236 5,945 6,175 5,668 5,101 4,846 4,943 5,042

Offshore drilling 750 833 1,088 1,192 1,252 1,242 1,186 1,232

Onshore drilling 688 740 750 806 846 888 915 943

Group 11,177 12,631 13,386 13,458 13,456 13,671 14,140 14,667

% change 8.3 13.0 6.0 0.5 (0.0) 1.6 3.4 3.7

EBITDA 1,836 2,135 2,207 725 1,595 1,875 2,082 2,115

DA&I 517 642 726 744 741 720 696 671

EBIT 1,319 1,493 1,481 -19 854 1,155 1,387 1,443

Net interest -110 -133 -148 -178 -195 -186 -173 -160

Affiliates 30 19 16 16 16 16 16 16

PBT 1,239 1,379 1,349 -181 675 985 1,230 1,300

Income tax -345 -392 -393 -100 -189 -276 -344 -364

Tax rate (%) 28% 28% 29% 0% 28% 28% 28% 28%

Post-tax profit 894 987 956 -281 486 709 886 936

Minority interests -50 -66 -54 16 -27 -40 -50 -53

Net income 844 921 902 -265 459 669 836 883

Post-tax non-recurring items 0 0 0 0 0 0 0 0

Clean net income 844 921 902 -265 459 669 836 883



231

Balance sheet

Saipem 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Balance sheet (€ m)

Fixed assets 7,403 8,024 8,254 8,461 8,429 8,332 8,211 8,138

Intangible assets 760 752 756 756 756 756 756 756

o/w goodwill 733 730 731 731 731 731 731 731

Financial investments 117 110 116 116 116 116 116 116

Other 132 248 263 263 263 263 263 263

Total non-current 8,412 9,134 9,389 9,596 9,564 9,467 9,346 9,273

Current assets

Inventories 791 1,353 2,332 2,323 2,323 2,360 2,441 2,532

Receivables 4,330 3,504 3,252 3,503 3,687 3,745 3,874 4,018

Cash and cash equivalents 930 1,029 1,325 268 783 1,643 2,435 3,140

Other 565 832 897 897 897 897 897 897

Total current 6,616 6,718 7,806 6,991 7,689 8,645 9,646 10,587

Total assets 15,028 15,852 17,195 16,587 17,253 18,112 18,993 19,860

Current liabilities

Current financial debt 1,329 1,722 2,140 2,140 2,140 2,140 2,140 2,140

A/c payables 5,814 5,341 4,982 4,956 5,048 5,349 5,565 5,772

Other current liabilities 422 900 472 472 472 472 472 472

Total current liabilities 7,565 7,963 7,594 7,568 7,660 7,961 8,177 8,384


Long-term debt 2,887 2,576 3,543 3,543 3,543 3,543 3,543 3,543

Provisions 357 409 380 380 380 380 380 380

Other/deferred tax liabs 65 81 125 125 125 125 125 125

Total non-current liabilities 3,309 3,066 4,048 4,048 4,048 4,048 4,048 4,048

Total liabilities 10,874 11,029 11,642 11,616 11,708 12,009 12,225 12,432

Total equity 4,154 4,823 5,553 4,972 5,545 6,103 6,768 7,428


Shareholders' funds 4,060 4,709 5,405 4,839 5,397 5,940 6,588 7,230

Net debt/(cash) 3,286 3,269 4,358 5,415 4,900 4,040 3,248 2,543

Capital employed 7,417 8,015 9,831 10,616 10,674 10,372 10,245 10,200



232

Cash flow statement

Saipem 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Cash flow (€ m)

Net income 844 921 902 (265) 459 669 836 883

Minorities 50 66 54 (16) 27 40 50 53

Depreciation & amortization 514 608 701 744 741 720 696 671

Provisions/writedowns 16 18 29 0 0 0 0 0

Capital (gain) loss on asset sales (17) 2 0 0 0 0 0 0

Other/timing differences 137 108 (28) 0 0 0 0 0

Cash from operations 1,544 1,723 1,658 463 1,228 1,429 1,581 1,607

Change in working capital (220) (174) (1,434) (268) (91) 205 7 (28)

Net cash provided by (used in) operating activities 1,324 1,549 224 195 1,136 1,634 1,588 1,579

Capex (1,593) (1,162) (1,021) (952) (709) (623) (576) (599)

Acquisitions 0 (93) 0 0 0 0 0 0

Disposals 138 71 9 0 0 0 0 0

Net cash provided by (used in) investment activities (1,455) (1,184) (1,012) (952) (709) (623) (576) (599)

Cash flow less capex (131) 365 (788) (757) 427 1,011 1,012 981

Capital increase 0 0 0 0 0 0 0 0

Share repurchases/Option Exercise 35 11 29 0 0 0 0 0

Dividends paid (263) (297) (352) (300) 87 (151) (220) (275)

Other 0 0 0 0 0 0 0 0

Net cash provided by (used in) equity financing (228) (286) (323) (300) 87 (151) (220) (275)

Net debt issuance (Long & Short) 259 20 1,419 0 0 0 0 0

Others 0 (5) 0 0 0 0 0 0

FX adjustment 44 5 (12) 0 0 0 0 0

Change in cash balance (56) 99 296 (1,057) 515 860 792 705



233

Ratios

Saipem 2010 2011 2012 2013E 2014E 2015E 2016E 2017E

Per share data

Diluted shares (m) 439.8 440.0 439.8 439.8 439.8 439.8 439.8 439.8

Clean EPS (€) (diluted) 1.92 2.09 2.05 (0.60) 1.04 1.52 1.90 2.01

Dividend per share (€) 0.63 0.70 0.68 (0.20) 0.34 0.50 0.63 0.66

Cash flow per share (€) 3.01 3.52 0.51 0.44 2.58 3.71 3.61 3.59

Debt-adjusted CFPS (€) 3.19 3.74 0.75 0.85 2.90 4.02 3.89 3.85

NAV/share (€) 9.23 10.70 12.29 11.00 12.27 13.51 14.98 16.44



ROACE 14.2 14.0 11.9 -1.0 5.9 8.0 9.8 10.3

ROE 23.4 22.4 19.1 -2.1 11.3 13.8 14.9 14.1

Net debt(cash)/equity 79 68 78 109 88 66 48 34

ND/(ND+E) 44 40 44 52 47 40 32 26

Capex/cash flow 120 75 456 488 62 38 36 38


Valuation ratios

P/E (x) 14.8 16.2 17.3 -23.4 13.5 9.3 7.4 7.0

P/CF (x) 9.4 9.6 69.4 31.8 5.5 3.8 3.9 3.9

EV/EBITDA (x) 1.8 1.5 2.0 7.5 3.1 2.2 1.6 1.2

EV/DACF (x) 11.2 11.0 60.5 31.2 8.7 5.8 5.5 5.2

Dividend yield (%) 2.2% 2.1% 1.9% -1.4% 2.4% 3.6% 4.4% 4.7%

Price to book (x) 3.1 3.2 2.9 1.3 1.1 1.0 0.9 0.9

Free cash flow yield (%) -4.4 6.3 -12.9 -12.2 6.9 16.3 16.3 15.8



234

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235

Please note that the use of this research report is subject to the conditions and restrictions set forth in the “General investment-related disclosures” and the “Legal disclaimer” at the end of this document.

For analyst certification and remarks regarding foreign investors and country-specific disclosures, please refer to the respective paragraph at the end of this document.

Disclosures in respect of section 34b of the German Securities Trading Act (Wertpapierhandelsgesetz – WpHG)

Company Disclosures Aker Solutions ASA no disclosures Petrofac Ltd no disclosures Saipem SpA no disclosures Subsea 7 SA no disclosures Technip SA 5 (1) Joh. Berenberg, Gossler & Co. KG (hereinafter referred to as “the Bank”) and/or its affiliate(s) was Lead

Manager or Co-Lead Manager over the previous 12 months of a public offering of this company. (2) The Bank acts as Designated Sponsor for this company. (3) Over the previous 12 months, the Bank and/or its affiliate(s) has effected an agreement with this company

for investment banking services or received compensation or a promise to pay from this company for investment banking services.

(4) The Bank and/or its affiliate(s) holds 5% or more of the share capital of this company. (5) The Bank holds a trading position in shares of this company. Historical price target and rating changes for Aker Solutions ASA in the last 12 months (full coverage)

Date Price target - NOK Rating Initiation of coverage

10 July 13 115.00 Buy 10 July 13

Historical price target and rating changes for Petrofac Ltd in the last 12 months (full coverage)

Date Price target - GBp Rating Initiation of coverage

10 July 13 1370.00 Hold 10 July 13

Historical price target and rating changes for Saipem SpA in the last 12 months (full coverage)

Date Price target - EUR Rating Initiation of coverage

10 July 13 14.20 Hold 10 July 13

Historical price target and rating changes for Subsea 7 SA in the last 12 months (full coverage)

Date Price target - NOK Rating Initiation of coverage

10 July 13 146.00 Buy 10 July 13

Historical price target and rating changes for Technip SA in the last 12 months (full coverage)

Date Price target - EUR Rating Initiation of coverage

10 July 13 106.00 Buy 10 July 13

Berenberg distribution of ratings and in proportion to investment banking services

Buy 41.65 % 51.43 % Sell 19.19 % 8.57 % Hold 39.16 % 40.00 %


236

Valuation basis/rating key

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http://www.berenberg.de/research.html?&L=1

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General investment-related disclosures Joh. Berenberg, Gossler & Co. KG (hereinafter referred to as „the Bank“) has made every effort to carefully research all information contained in this financial analysis. The information on which the financial analysis is based has been obtained from sources which we believe to be reliable such as, for example, Thomson Reuters, Bloomberg and the relevant specialised press as well as the company which is the subject of this financial analysis. Only that part of the research note is made available to the issuer (who is the subject of this analysis) which is necessary to properly reconcile with the facts. Should this result in considerable changes a reference is made in the research note.

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Analyst certification I, Asad Farid, CFA, hereby certify that all of the views expressed in this report accurately reflect my personal views about any and all of the subject securities or issuers discussed herein.

In addition, I hereby certify that no part of my compensation was, is, or will be, directly or indirectly related to the specific recommendations or views expressed in this research report, nor is it tied to any specific investment banking transaction performed by the Bank or its affiliates.

I, Jaideep Pandya, hereby certify that all of the views expressed in this report accurately reflect my personal views about any and all of the subject securities or issuers discussed herein.

In addition, I hereby certify that no part of my compensation was, is, or will be, directly or indirectly related to the specific recommendations or views expressed in this research report, nor is it tied to any specific investment banking transaction performed by the Bank or its affiliates.

Remarks regarding foreign investors The preparation of this document is subject to regulation by German law. The distribution of this document in other jurisdictions may be restricted by law, and persons into whose possession this document comes should inform themselves about, and observe, any such restrictions.

United Kingdom This document is meant exclusively for institutional investors and market professionals, but not for private customers. It is not for distribution to or the use of private investors or private customers.

United States of America This document has been prepared exclusively by the Bank. Although Berenberg Capital Markets LLC, an affiliate of the Bank and registered US broker-dealer, distributes this document to certain customers, Berenberg Capital Markets LLC does not provide input into its contents, nor does this document constitute research of Berenberg Capital Markets LLC. In addition, this document is meant exclusively for institutional investors and market professionals, but not for private customers. It is not for distribution to or the use of private investors or private customers.

This document is classified as objective for the purposes of FINRA rules. Please contact Berenberg Capital Markets LLC (+1 617.292.8200), if you require additional information.

Third-party research disclosures

Company Disclosures Aker Solutions ASA no disclosures Petrofac Ltd no disclosures Saipem SpA no disclosures Subsea 7 SA no disclosures Technip SA no disclosures (1) Berenberg Capital Markets LLC owned 1% or more of the outstanding shares of any class of the subject

company by the end of the prior month.* (2) Over the previous 12 months, Berenberg Capital Markets LLC has managed or co-managed any public

offering for the subject company.* (3) Berenberg Capital Markets LLC is making a market in the subject securities at the time of the report. (4) Berenberg Capital Markets LLC received compensation for investment banking services in the past 12

months, or expects to receive such compensation in the next 3 months.* (5) There is another potential conflict of interest of the analyst or Berenberg Capital Markets LLC, of which

the analyst knows or has reason to know at the time of publication of this research report.

* For disclosures regarding affiliates of Berenberg Capital Markets LLC please refer to the ‘Disclosures in respect of section 34b of the German Securities Trading Act (Wertpapierhandelsgesetz – WpHG)’ section above.


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Copyright The Bank reserves all the rights in this document. No part of the document or its content may be rewritten, copied, photocopied or duplicated in any form by any means or redistributed without the Bank’s prior written consent.

© May 2013 Joh. Berenberg, Gossler & Co. KG

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