European Oil Services Top Picks AMEC Plc (AMEC.L),GBP810.00 Buy Saipem (SPMI.MI),EUR22.19 Buy Chasing the Pendulum Seadrill Limited (SDRL.OL),NOK142.10 Buy

FITT Research

Company Company 7 December 2009 Fundamental, Industry, Thematic, Thought Leading DB's Company Research’s Research European Committee has deemed this work F.I.T.T for investors seeking differentiated ideas. Here our European team undertakes a '360' analysis on the global oil services Oil Services industry that leverages unique data sourced from Wood Mackenzie and DB's expansive contract database to reveal the winners and losers of oil service themes & names across 2010-11. Fundamental: ‘capex pendulum’ should Chasing the pendulum swing back in favour of some but not all Industry: topline momentum is key driver of company earnings mid-term Thematic: a unique analysis of appraisal drilling and license terms

Global Markets Research Thought leading: deepwater drilling most attractive; E&C winners & losers Playing the trends: Amec, SPMI & SDRL - top picks offer impressive growth

Christyan Malek Lucas Herrmann, ACA Jonathan Copus Research Analyst Research Analyst Research Analyst (+44) 20 754-58249 (+44) 20 754-73636 (+44) 20 754-51202 [email protected] [email protected] [email protected]

Deutsche Bank AG/London All prices are those current at the end of the previous trading session unless otherwise indicated. Prices are sourced from local exchanges via Reuters, Bloomberg and other vendors. Data is sourced from Deutsche Bank and subject companies. Deutsche Bank does and seeks to do business with companies covered in its research reports. Thus, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. Independent, third-party research (IR) on certain companies covered by DBSI's research is available to customers of DBSI in the United States at no cost. Customers can access IR at http://gm.db.com/IndependentResearch or by calling 1-877-208-6300. DISCLOSURES AND ANALYST CERTIFICATIONS ARE

LOCATED IN APPENDIX 1. MICA(P) 106/05/2009 Europe United Kingdom Oil & Gas

7 December 2009 FITT Research European Oil Services Top picks AMEC Plc (AMEC.L),GBP810.00 Buy Saipem (SPMI.MI),EUR22.19 Buy Chasing the pendulum Seadrill Limited (SDRL.OL),NOK142.10 Buy

Key changes Ratings/ PT changes From To Christyan Malek Lucas Herrmann, ACA Jonathan Copus Acergy PT NOK 50 NOK 85 Research Analyst Research Analyst Research Analyst Aker Solutions PT NOK 40 NOK 60 (+44) 20 754-58249 (+44) 20 754-73636 (+44) 20 754-51202 AMEC PT GBp 850 GBp 950 [email protected] [email protected] [email protected] Lamprell PT GBp 185 GBp 210 Petrofac PT GBp 680 GBp 970 Fundamental, Industry, Thematic, Thought Leading Saipem PT E 23 E 27 DB's Company Research’s Research Committee has deemed this work F.I.T.T for Seadrill PT NOK 120 NOK 190 investors seeking differentiated ideas. Here our European team undertakes a '360' Seadrill rating Hold Buy analysis on the global oil services industry that leverages unique data sourced Subsea 7 PT NOK 50 NOK 80 Technip PT E 42 E 53 from Wood Mackenzie and DB's expansive contract database to reveal the Tecnicas Reunidas E 41 E 44 winners and losers of oil service themes & names across 2010-11. Wood Group PT GBp 190 GBp 210 Wood Group rating Hold Sell Fundamental: ‘capex pendulum’ should swing back in favour of some but not all Our annual review of global capex conducted in partnership with Wood Mackenzie Deepwater appraisal and successful (WM) forecasts a moderate decline, in aggregate, across 2009-11 (-3%). The long exploration wells drilled globally run oil price implicit in WM’s bottom up analysis is $70/bbl. We kick the 120 8.0 foundations to reveal green shoots in both exploration and 100 7.0 6.0 engineering/construction (E&C) segments. While not immune to heightened 80 5.0 macro risks near term their secular characteristics should help drive out- 60 4.0

performance for those companies with appropriate exposure. drilledWells 40 3.0

20 Industry: topline momentum is key driver of company earnings mid-term 2.0 exploration successful Appraisal/ We place each company’s industry and regional ‘blueprint’ against our updated 0 1.0 outlook. Together with our unique framework that differentiates companies on a 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 number of metrics we forecast, on average, topline growth for the group (9%, Appraisal/ successful exploration ratio (RHS) Successful exploration Appraisal 2009-12E) against a relatively cautious view on margin (c. 75bps EBITDA Source: Wood Mackenzie, Deutsche Bank reduction). Our 2009-12E earnings outlook for the sector is 8%. Deepwater rig rate outlook (>2000m)

2000 700 hematic: a unique analysis of appraisal drilling and license terms 1800 T 600 1600 Our proprietary analysis, done in conjunction with WM, reveals a material increase 1400 500 1200 400 in deepwater licenses awarded relative to last year’s study. Between 2010 and 1000 2014 70% of the world’s deepwater exploration licenses (exc. GoM) are due to 800 300 600 200

expire with a sharp rise expected to occur in 2012. We argue that this should drive Day rate ('000$k/d)

WM drilling days drilling WM 400 100 an impressive increase in absolute levels of exploration activity. Going forward this 200 would also imply a higher intensity of appraisal drilling (for every successful 0 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 deepwater exploration well we show that four appraisal wells have been drilled, 2009E 2010E 2011E on average, across this decade with some regions posting double digit figures). Drilling days Day rate Together this forms the basis to our structural view that demand for deepwater Source: Wood Mackenzie, Deutsche Bank rigs (particularly in the ultra-deep) will accelerate across the near to medium term. Current expectations for E&C revenue and margin 2009-11E

Decrease in Thought leading: deepwater drilling most attractive; E&C winners & losers Deepwater 30% capex subsea 25% momentum vs. Based on our analysis of deepwater rig supply/demand we believe that day rates 20% 2008 study Deepwater Facilities 15% here should reach $600k/day by 2011 (currently c. $500k/day). Across the E&C Shallow water LNG 10% (opex) complex we carve out our most & least favored themes/regions and show how Refining & 5% Petrochem. 0% Frontier our appraisal drilling outlook has positive implications for contractors’ backlog. -5% Developments Regas Middle -10% Playing the trends: Amec, SPMI & SDRL - top picks offer impressive growth East -15% Shallow water Oil Sands Onshore -20% (capex) Upstream Average capex growth 2009-11E Amec, Saipem & Seadrill (upgraded to Buy) each possess excellent diversification GTL -25% and exposure to our highest conviction themes and regions. In contrast, WG -30% Negative margin outlook vs. 2008 study -35% (downgraded to Sell) appears at the weaker end of the industry spectrum given its -40% relatively poor positioning & business model. We have raised our target sector -350 -300 -250 -200 -150 -100 -50 - multiple, which in part drives our PT revisions (pg. 54). Key downside risks include Absolute margin downside 2009-11E(bps) oil prices sinking below $70/bbl for a sustained period and poor execution. Source: Wood Mackenzie, Deutsche Bank

Table of Contents

Executive summary...... 3 Exploration and appraisal drilling trends ...... 7 Exploration industry dynamics and relative profitability...... 20 Global engineering and construction outlook...... 28 Kicking the foundations reveals some green shoots...... 31 E&C industry dynamics and relative profitability ...... 39 Implications for companies’ earnings outlook 2010 and beyond...... 45 Sector valuation and company winners and losers...... 52 Top picks and key recommendation changes ...... 55 Appendix A: Valuation matrices ...... 57 Appendix B: Exploration, appraisal and development capex split...... 61 Deepwater drilling activity vs. oil price ...... 62 Appendix C: Snapshot of each company’s financing ...... 63 Appendix D: Shallow water drilling duration...... 66 Appendix E: Regional spread of contracted newbuild rigs...... 67 Appendix F: NOC/IOC/Independents investment in drilling ...... 68 Appendix G: Calculations behind backlog cover analysis...... 70 Appendix H: Regional split of shallow water capex ...... 72 Appendix I: Detailed overview of companies’ fleet ...... 73 Appendix J: ‘Backlog longevity’ calculation explained ...... 78 Appendix K: Asset utilisations ...... 80 Appendix L: Gearing analysis...... 89 Appendix M: Contract strategy analysis...... 90 Appendix N: NOC/IOC exposure ...... 92 Appendix O: Licenses awarded by depth (onshore and offshore) ...... 93 Appendix P: Wind power capacity ...... 94 Appendix Q: Strategic analysis of the E&C themes...... 96 Appendix R: Porter’s 5 forces on key service segments ...... 98 Appendix S: The CAPEX/OPEX ‘life cycle’ explained ...... 104 Appendix T: Global oil service spectrum explained ...... 107 Appendix U: Glossary of terms and simplifications ...... 110

Page 2 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Executive summary

Global outlook Our annual study of global capex conducted in partnership with Wood Mackenzie sees a moderate decline, in aggregate, across 2009-11 (-3% compounded from 2008 levels). Exploration, appraisal and development activity (wellhead operations, drilling and seismic) represents c. 40% of global capex in 2009E with the balance comprising engineering and The long run oil price construction (E&C) spend. In this note we kick the foundations to reveal green shoots in both implicit in our bottom up of these segments which while not immune to heightened macro risks near term, possess secular characteristics that should drive impressive growth in 2010-11 for those companies Wood Mack forecast is with appropriate exposure. $70/bbl. This is below DB’s commodities team estimate Figure 1: Global exploration* and E&C capex outlook of $80/bbl long run

700,000

600,000

500,000

400,000

Capex ($bn) Capex 300,000

200,000

100,000

- 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E

Exploration, appraisal and development capex E& C capex

Source: Deutsche Bank, Wood Mackenzie; *Appendix B shows exploration, appraisal and development capex split by seismic, wellhead operations and drilling; we estimate that IOC/NOC leasing of drilling rigs (onshore, shallow water and deepwater) represents c.12% of global capex E&C outlook Cost deflation across the supply chain and delays in Final Investment Decisions (FIDs) has driven a c. 10% drop vs. last year’s outlook (2008-10E). Despite this relatively muted Our analysis shows that backdrop we reveal a number of ‘sweet spots’ that include deepwater offshore construction NOCs will become a key (SURF and FPSO/facilities), LNG and OPEX spend (shallow/mid waters). By region, Middle constituent of oil services’ East (Saudi, Kuwait and UAE), SE Asia (Australia and India), Africa (Ghana, Egypt, Angola and backlog longer term making Nigeria) and Brazil should emerge as primary drivers of capex. We believe the majority of them potentially a ‘price FIDs here should begin to materialise across H2 2010 and continue through 2011. setter’ in the context of a global capex recovery (NOCs Performing strategic analysis of the subsets within this segment drives our absolute and relative outlook of profitability across the E&C complex. The themes we believe will provide are expected to represent out-performance (in terms of capex and margin) across the near to medium term are frontier 40% of global capex and developments, Middle East, LNG (and associated infrastructure) and ‘high-value’ (defined as 20% of all contracts signed highly technical) engineering and project management. Shallow water/conventional OPEX and across the OFS sector by deepwater facilities/FPSOs/subsea both share impressive capex outlooks but against the 2011) potential of excessive margin decline near term this leaves us with a broadly neutral view. Themes we expect will under-perform are shallow water/conventional CAPEX, oil sands and refining and petrochemicals.

Deutsche Bank AG/London Page 3 7 December 2009 Oil & Gas European Oil Services

Key risk to our forecast is if FIDs are delayed beyond 2010. Whilst this would place downside pressure on our 2011 estimates we believe the impact should be limited based on our view that IOCs looking to adhere to mid to longer term targets of production would have to invest across 2011/2012. Critical to their reserve replacement will be the need to offset production decline on maturing fields with incrementally new barrels. Having delayed FIDs across 2009- 10, we believe IOCs would be under renewed pressure to sustain production at their current levels provided was profitable. The upward structural shift in the number of deepwater Exploration outlook wells appraised coupled Demand: rising in deepwater. Proprietary analysis done in conjunction with Wood with a general rise in Mackenzie reveals a threefold increase in the number of deepwater appraisal wells drilled complexity in and around across this decade. We believe this trend is structural based on or analysis that shows a the wellhead suggests that steady rise (since 1995) in: i) deep and ultra-deep appraisal activity (South America and South appraisal activity will be East Asia appear to be emerging as primary drivers) as IOCs and NOCs place greater focus sustained at current levels on developing deepwater acreage. Discoveries in frontier regions across 1996-2000 created a backlog of wells requiring appraisal and triggered a material uplift in appraisal activity relative to exploration. ii) The proportion of wells drilled by independents and NOCs (that arguably possess a different set of criteria to IOCs). iii) The time taken to appraise deepwater wells (in part linked to their increasing depths and complexity). We have also tracked all exploration licenses awarded since 2000 with a focus on when they are due to expire. We note a material increase in deepwater licenses awarded relative to last Overall, whilst there is year’s study and reveal that between 2010 and 2014 70% of the world’s deepwater downside risk to drill given exploration licenses (exc. GoM) are due to expire with a sharp rise expected to occur in 2012. a potentially worsening We argue that this should drive an impressive increase in absolute levels of exploration macro environment activity. Going forward this would also imply a higher intensity of appraisal drilling (for every (particularly in the event successful deepwater exploration well we show that four appraisal wells have been drilled, that license expiries are on average, across this decade with some regions posting double digit figures). Together this extended), we believe that forms the basis to our structural view that demand for deepwater rigs (particularly in the ultra- near to medium-term deep >2000m) will accelerate across the near to medium term. Our analysis also reveals a exploration and appraisal robust outlook for shallow water exploration and appraisal drilling based on a material increase in licenses awarded across 2008/09. Onshore activity continues to appear lacklustre. drilling programs, The implications of the above are renewed investment in refurbishment and upgrading of particularly those in South deepwater rig fleet. America, West Africa and South East Asia should be Overall, whilst there is downside risk to drill given a potentially worsening macro environment least impacted (particularly in the event that license expiries are extended), we believe that near to medium- term exploration and appraisal drilling programs, particularly those in South America, West Africa and South East Asia should be least impacted. This is based, in part, on: i) IOC’s longer-term production targets that are weighted heavily to these regions leaving them with relatively less flexibility to relinquish their license and ii) our analysis in this note that presents a structural case for appraisal drilling that should be sustained at current levels. Incremental demand for best in class assets Rig supply: tight for the best of them. Our analysis shows that deepwater global rig (younger, latest generation liquidity (defined as % rigs that are currently un-contracted) has increased from 26% (2008- of rigs) will re-shape the 12E) to 40% (2009-12E) and from 70% to 90% in the shallow water segment (current newbuild schedules suggests a 19% increase in global rig capacity vs. current levels). We deepwater market as new believe the ultra deepwater market will demonstrate the best performance as supply/demand rig owners gradually fundamentals are expected to tighten again beyond 2010. Having fallen from a record level of displace market share $700k/day in 2008 and stabilised around $500k/day, we expect rig rates to rise from 2010 traditionally held by more (we forecast $600k/day by 2011) as license expiries loom and exploration/appraisal drilling mature drillers accelerates. With this in mind, we believe incremental demand for best in class assets (predominantly US based) (younger, latest generation of rigs) will re-shape the deepwater market as new rig owners gradually displace market share traditionally held by more mature drillers (predominantly US based). We expect downward pressure on rig day rates operating in depths lower than 2000m given the greater availability of (older generation) mid-water fleet partly offset by a robust demand outlook. Shallower water day rates should continue to fall but stabilise

Page 4 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

towards structurally higher levels than mid-cycle. Elsewhere in the exploration complex, rig construction services emerge as an attractive niche particularly in the Middle East.

Key 2010 trends for the companies We leverage our exhaustive database of contracts to show that since 2004, 70% of all contracts awarded across the E&C sector have comprised of sprint to market projects (STM We expect 2010 revenue characterised as brownfield developments that may be monetised relatively quickly and at a cover for oil service lower marginal cost of production than a greenfield project/FID). Whilst STMs are not companies exposed to immune to the volatility in commodity prices, we show that awards of this nature have been shallow and deepwater of instrumental in sustaining the group’s revenue cover for 2009 around historic levels. We investment (asset light and argue that the upward shift in shallow and deepwater appraisal drilling highlighted above asset intensive companies should spur a proportionate increase in spend directed towards related FEED work and sprint alike) to remain robust to market projects. As a result we expect 2010 revenue cover for oil service companies despite the risk of further exposed to this type of investment (asset light and asset intensive companies alike) to remain potential delays in FIDs robust despite the risk of further potential delays in FIDs across 2010. across 2010 Given company management’s general lack of guidance regarding the level of pricing that has been achieved on more recently signed contracts and the apparent lag on company profitability (our analysis reveals it can be anything up to three years) we believe this places downside risk on our renewed margin forecasts for the E&C group (which, on aggregate, assumes some contraction across 2009-11). Variations to this trend will clearly depend on each company’s ability to differentiate both within the respective industry and through the operational efficiencies, strategy and business model underpinning it.

Key recommendations for 2010 We place each company’s industry and regional ‘blueprint’ against our global exploration and E&C projections outlined above. Together with our unique framework that differentiates We believe Saipem, Amec companies on a number of metrics we model the company’s earnings outlook to 2012 and Seadrill are optimally (forecast horizon has been extended from 2011). We forecast, on average, topline growth for placed across the oil the group (9%, 2009-12E) against a more cautious view on margin (c. 75bps EBITDA services chain and reduction). Our 2009-12E earnings outlook for the sector is 8%. Our top picks are: demonstrate superior earnings growth. In contrast, Seadrill: upgraded to Buy, PT NOK 190 (previously 120). Sector leading exposure to deep Wood Group (downgraded and ultra-deepwater drilling fuels impressive earning growth (21% 2009-12E CAGR). We to Sell) appears at the other argue for an absolute and relative re-rating against the European and US oil services. This end of the industry should be driven, in part, by its imminent listing in the US (Q1’10) which should help improve investors’ perception of its superior asset quality and deepwater exposure (relative to its spectrum given its relatively most comparable US peers). weak positioning and business model Amec: Buy, PT raised to 950p (previously 850p). The company’s unique business model and impressive diversification beyond oil and gas (underpinned by its ‘high-value’ engineering and project management) should drive superior earnings visibility relative to its E&C peers (13% 2009-12 CAGR vs. sector average of 8%).

Saipem: Buy, PT raised to E27 (previously E23). High relative and absolute exposure to several of our preferred themes (including deepwater drilling) drives leading backlog cover and earnings growth across the E&C sector (10% 2009-12 CAGR).

In a scenario where the oil price could sit significantly below $70/bbl for a sustained period of time, we believe the earnings of E&C companies will be negatively impacted beyond 2011 as oil company capex gets pulled back. The reason why our earnings outlook should remain unchanged before then is that existing company backlog provides sufficient revenue cover and that the margins associated with the majority of these projects would have already been contracted (subject to execution performance, of course). Even so, share price sentiment will

Deutsche Bank AG/London Page 5 7 December 2009 Oil & Gas European Oil Services

be negative (in anticipation of a slowdown in earnings momentum beyond 2010 not to mention the sector’s strong correlation with oil price). Against this backdrop we believe Saipem and Amec would outperform on a relative basis (vs. their E&C peers); Wood Group and Aker Solutions should underperform (we have downgraded Wood Group to a Sell from Hold). On an absolute basis we prefer Seadrill from our entire coverage universe.

Valuation –sector target multiple moved from 2010 to 2011; we continue to argue for a discount against historical multiples Our 2011E EV/DACF for the sector is currently 7.0x (market cap-weighted) which represents c. 33% discount to the sector’s historical average (2000-08) of 10.5x. Given the decline in both exploration and E&C capex we expect over the near to medium term against what appears to be a slowing in earnings momentum, we believe that our target sector multiple (2011) should trade at a discount to historical multiples.

On balance, we argue that At the industry level, based on our analysis above we believe the risk (primarily execution and our sector target multiple margin compression)/reward (primarily revenue) trade off has shifted more into ‘equilibrium’. should trade at a 20% However, in light of the lack of visibility surrounding FIDs nearer term linked to the risk of discount (vs. -50% renewed deterioration at the macro level, on balance we argue that our sector target multiple previously) to the historical should trade at a 20% discount to the historical average (vs. -50% previously). Improved cashflow visibility to the end of the decade (fuelled by robust sector backlog) coupled with a average general improvement in execution and risk sharing between the contractor/client justifies why we believe this sector should not trade at a deeper discount to historical multiples.

Our implied PTs are supported by our DCF valuation in which we assume peak company earnings in 2012 with subsequent linear fade to our mid-cycle scenario in 2015. We have lowered our company WACCs to reflect the reduced market risk premium as well as the relatively lower cost of debt vs. last year’s study. We detail changes in company WACC in Appendix A. This in part drives our price target changes on our universe of stocks (summarised on page 54). We assume a long-term growth rate of 3% which is the average mid-cycle rate since 1990 for the Euro oil services.

Risks Oil price: whilst impossible to quantify, Wood Mackenzie estimates that 2010/11 E&C capex would be c. 20% lower if oil prices sink to $40/bbl. Russia, North America, Europe and Canada in particular could see an even more exaggerated decline. The Middle East will be the least impacted but nonetheless we would expect to see a slow down. Companies most at risk in this context are Acergy, Susbea 7, Wood Group and Aker Solutions (regional and Key risks are oil price, thematic exposures detailed on pages 46 and 47). In contrast, we believe this downside risk for companies exposed to deepwater drilling will be mitigated by the structural need for backlog cancellation and operators to drill (near and medium-term) and their longer contract lives that should drive execution earnings growth well into the next decade.

Backlog cancellation (e.g. due to lack of client/contractor funding): Our discussions with Wood Mackenzie and Pegasus Global (leading risk consultants) suggest there is very little probability contracted projects will be cancelled given the healthy state of IOC and NOC balance sheets. In the unlikely event that they do, contractors have the right to file for liquidated damages and take control of all cash pre-payments. Equally we show that the refinancing risk on debt maturities of the companies we cover is low (detailed in Appendix C) and as a result we do not expect them to have cashflow issues in executing their contracts.

Execution: Poor execution is another key industry risk. We believe the potential impact this risk can have on company earnings remains impossible to quantify ahead of any material announcement.

Page 6 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Exploration and appraisal drilling trends

Proprietary analysis done in conjunction with Wood Mackenzie reveals a threefold increase in the number of deepwater appraisal wells drilled across this decade. We believe this trend is structural based on our analysis that shows a steady rise (since 1995) in: i) deep and ultra-deep appraisal activity (South America and South East Asia appear to be emerging as primary drivers) as IOCs and NOCs place greater focus on developing deepwater acreage. Discoveries in frontier regions across 1996-2000 created a backlog of wells requiring appraisal and triggered a material uplift in appraisal activity relative to exploration. ii) The proportion of wells drilled by independents and NOCs (that arguably possess a different set of criteria to IOCs). iii) The time taken to appraise deepwater wells (in part linked to their increasing depths and complexity).

We have also tracked all exploration licenses awarded since 2000 with a focus on when they are due to expire. We note a material increase in deepwater licenses awarded relative to last year’s study and reveal that between 2010 and 2014 70% of the world’s deepwater exploration licenses (exc. GoM) are due to expire with a sharp rise expected to occur in 2012. We argue that this should drive an impressive increase in absolute levels of exploration activity. Going forward this would also imply a higher intensity of appraisal drilling (for every successful deepwater exploration well we show that four appraisal wells have been drilled, on average, across this decade with some regions posting double digit figures). Together this forms the basis to our structural view that demand for deepwater rigs (particularly in the ultra-deep >c. 2000m) will accelerate across the near to medium term. Our analysis also reveals a robust outlook for shallow water exploration and appraisal drilling based on a material increase in licenses awarded across 2008/09. Onshore activity continues to appear lacklustre.

Finally, in this section we argue that the implications of the above are renewed investment in refurbishment and upgrading of deepwater rig fleet (and to a lesser degree shallow and onshore assets).

Appraisal activity represents a discrete yet material driver of drilling demand In our last FITT report titled ‘Reality Check’ (Oct 2008) we focused on the impact exploration drilling would have on the overall supply/demand outlook for rigs with a particularly emphasis on the deep and ultra-deepwater. We leveraged Wood Mackenzie’s global database of signature bonuses, licenses awarded and drilling days (measured as the time between spudding and completion of the well and a useful indicator of demand to drill) to analyse the Our focus to start with is the outlook for drilling by different depths and respective rig types. We also looked at these outlook for shallow water licenses with a focus on their expiry profiles. Whilst we revisit these trends and their and deepwater (defined as implications later on in this section our focus to start with is the outlook for shallow water >400m) appraisal drilling and deepwater (defined as >400m) appraisal drilling and the incremental impact this could have on demand for rig capacity and ultimately day rates.

Simply put, appraisal drilling occurs when the operator has had enough success on an exploration well to want to drill it further. Ultimately it will determine the operator’s decision on whether to develop the well and proceed with an FID (first oil).

Deutsche Bank AG/London Page 7 7 December 2009 Oil & Gas European Oil Services

For every deepwater exploration well, an average four appraisal wells are drilled Figure 2 below shows the number of deepwater appraisal wells vs. successful exploration wells drilled over time. The correlation between the two should not be surprising and we observe the relatively high proportion of appraisal wells drilled subsequent to oil and/or gas being found.

Figure 2: Deepwater appraisal and successful exploration wells drilled globally

120 8.0

7.0 100

6.0 80

5.0

Wells drilled Wells 4.0

40 Appraisal/ successful exploration 3.0

20 2.0

Our analysis reveals a 0 1.0 relatively high proportion of 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 appraisal wells drilled Appraisal/ successful exploration ratio (RHS) Successful exploration Appraisal Source: Wood Mackenzie, Deutsche Bank subsequent to oil and/or gas being found Figure 3 shows the relative number of appraisal wells vs. successful exploration wells drilled by region.

Figure 3: Ratio of deepwater appraisal wells drilled vs. successful exploration wells by region

10 Appraisal/ successful exploration ratio 5

0 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Africa N America S America South East Asia Australia Average

Source: Wood Mackenzie, Deutsche Bank We make the following observations from the above:

A structural increase in appraisal activity in relative and absolute terms driven by a greater focus on deepwater acreage by IOCs and NOCs. Discoveries in frontier regions

Page 8 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

across 1996-2000 created a backlog of wells requiring appraisal and helps explain the divergence between appraisal and exploration drilling during the same period.

The global historic average is around 4 appraisal wells drilled per successful exploration well.

South America and North America (primarily Gulf of Mexico) have both experienced relatively higher appraisal activity vs. other parts of the world. Large discoveries across this decade would have driven the spikes in appraisal drilling relative to exploration. Secular increase in appraisal drilling should place upside pressure on global demand for deepwater rigs Factors that will influence the degree of appraisal drilling going forward include:

The operator’s desire to establish the well’s commerciality particularly on acreage that is technical challenging (e.g. very deep, remote and/or harsh weather conditions),

An operator’s ambition to achieve first oil as quickly as possible in order to lower the payback period of investment (particularly when the development cycle is difficult to shorten and where there is greater ability to do so during the exploration and appraisal phase),

The well’s proximity to a nearby well(s) that would make it immediately commercial if tied back to existing subsea infrastructure and platform (s),

The fiscal terms set about by the host government which could allow within a certain time frame the participants to be reimbursed on some of the costs incurred during appraisal (vs. exploration which is more often than not fully expensed across the company’s P&L). No doubt commodity prices will drive operators’ appetite to explore and appraise more wells and a weaker macro environment could see a slowdown in activity. However, we believe the We believe the structural shift upward trend evidenced above in the number of deepwater wells appraised should stabilise evidenced above in the at current levels on an absolute and relative basis. This is supported by our analysis below number of deepwater wells which shows: appraised will be sustained at A structural shift in appraisal activity towards deeper waters (figure 4). We also depict current levels this by region (figure 5) and show that South America and South East Asia have emerged as swing players since the start of this decade

Figure 4: Appraisal drilling has gravitated towards mid Figure 5: …South America and South East Asia have and ultra-deep water… emerged as swing players across this decade

6,000 6000

5,000 5000

4,000 4000

3,000 3000 Drilling days Drilling days 2,000 2000

1,000 1000

- 0 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

400-799 800-1199 1200-1599 1600-1999 2000-2399 2400-2799 2800-3199 N America S America Africa E Hemisphere Europe Middle East Source: Wood Mackenzie, Deutsche Bank; drilling days is defined as the time drilled between spudding & Source: Wood Mackenzie, Deutsche Bank; drilling days is defined as the time drilled between spudding & completion of well. completion of well. A higher exploration success rate over time argues for more appraisal work per unit well explored (figure 6 shows the global success rate rising from an average of 15% on average across the first half of the decade to 25% since 2005),

Deutsche Bank AG/London Page 9 7 December 2009 Oil & Gas European Oil Services

An increase in the proportion of wells drilled by independents and NOCs since the mid- 90’s (figure 7). NOCs’ appetite to explore and appraise will be based on their own (strategic) ambitions for future production. Independents’ incentive to appraise will be linked to their respective drilling schedules (shareholders’ primary focus will be on the company’s exploration and appraisal success).

Figure 6: Exploration success rate (based on commercial Figure 7: …with a greater proportion of wells drilled by and technical success) has generally improved over independents and NOCs time…

31% 350 60% 29% 55% 27% 300

25% 50% 23% 250 s

21% 45% 200 19% 40% 17% 150 15% 35%

Exploration success rate success Exploration 13% % Independents NOC & 100 11% 30%

Total wellsdrilled (exploration and appraisal) 50 25% 7%

5% 0 20% 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 Independent E&P IOC NOC % Independents & NOCs (RHS) Source: Wood Mackenzie, Deutsche Bank Source: Wood Mackenzie, Deutsche Bank A gradual increase in the time spent (on aggregate) to drill an appraisal well (figure 8) arguably linked to a general rise in complexity in and around the wellhead,

Figure 8: Average drilling time per well has increased substantially across the decade

100% 75

90% 70

80% 65

70% 60

60% 55 50% 50 40%

45 30% well per days drilling Average

Proportion of wells drilled across water depths water across drilled of wells Proportion 40 20%

10% 35

0% 30 2000 2001 2002 2003 2004 2005 2006 2007 2008

2800-3199 2400-2799 2000-2399 1600-1999 1200-1599 800-1199 400-799 Exploration (RHS) Appraisal (RHS) Source: Wood Mackenzie, Deutsche Bank A counter-argument to our thesis above is that the cumulative experience built by the operator in drilling over the respective acreage could drive higher well flow rates and over time result in fewer wells drilled and within a shorter time frame. We have seen anecdotal evidence of this already in some basins such as Santos, Brazil where IOCs have expressed interest in reducing drilling times going forward. Whilst this dynamic places downside risk on the long run global demand to appraise, for now it appears to be limited to a few regions around the world and specific to only a handful of IOCs.

Shallow water and onshore appraisal drilling at parity with exploration Figures 9 and 10 below highlights the volatility in drilling activity for onshore and offshore appraisal drilling with the recent rise fuelled by the increase in commodity prices (we would expect the reverse to occur across 2009 given the sharp drop). Whilst this cyclicality is not surprising, we observe that in contrast to deepwater, the level of appraisal drilling relative to

Page 10 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

exploration has rarely moved beyond parity. Appendix D shows the aggregate time spent to drill an exploration/ appraisal well.

Figure 9: Shallow water appraisal and successful Figure 10: Onshore appraisal and successful exploration exploration wells drilled globally wells drilled globally

800 8.4 400 1.6

1.5 700 7.4 350 1.4 600 6.4 1.3

500 5.4 300 1.2

400 4.4 1.1 Wells drilled Wells Wells drilled Wells 250 1.0 300 3.4 0.9 Appraisal/ successful exploration

200 2.4 exploration successful Appraisal/ 200 0.8

100 1.4 0.7

150 0.6 0 0.4 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Successful exploration Appraisal Appraisal/ successful exploration ratio (RHS) Successful exploration Appraisal Appraisal/ successful exploration ratio (RHS) Source: Wood Mackenzie, Deutsche Bank Source: Wood Mackenzie, Deutsche Bank Deepwater license expiries should fuel structural demand to explore (and in turn appraise) across 2010-14 In conjunction with Wood Mackenzie we have tracked all exploration licenses awarded since 2000 with a focus on when they are due to expire.

Figure 11: Expiry profile of deepwater exploration licenses awarded* Our analysis argues for an increase in the number of 1200 25% exploration wells drilled as 1000 license expiries loom; this 20% should see a corresponding 800 number of appraisal wells 15% drilled 600 10% 400 % expiring Licenses expiring 5% 200

0 0% 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021-2039

Exploration % expiring October 2008 estimate

Source: Wood Mackenzie , Deutsche Bank; * note that even though the above depicts licenses awarded from 2000, the scale begins as of when they are due to expire i.e. 2006 onwards Figure 11 depicts how this profile has changed since we originally began the study a year ago. An increase in the absolute number of licenses awarded since October 2008 (we expand on this below) will see a higher ‘density’ of licenses collectively expiring across our forecast horizon. What is more telling, in our opinion, is which regions and depths are seeing their licenses enter into expiry near to medium term as this would arguably place concentrated demand on rigs in the local vicinity and by rig type respectively.

Deutsche Bank AG/London Page 11 7 December 2009 Oil & Gas European Oil Services

Figure 12: Given that the majority of the world’s Figure 13: …we take a closer look at the expiry profile of deepwater rigs* operate outside of GoM… deepwater exploration licenses awarded exc. GoM

4% 4% 120 18% 6% 16% 100 14% 80 12% 10% 60 17% 46% 8%

40 6% % expiring

Licenses expiring 4% 20 2% 0 0% 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2020 23% 2021-2039 S America GOM E Hemisphere Africa Russia Europe Exploration % October 2008 estimate

Source: Deutsche Bank, ODS Petrodata; * refers to contracted newbuild deepwater rigs (represents c.17% of Source: Deutsche Bank, Wood Mackenzie all rigs (existing + new) Between 2010 and 2014, 70% of the world’s deepwater exploration licenses (excluding GoM) are due to expire with an acute rise expected to occur in 2012. We believe the absolute increase in licenses expiring (particularly in 2014) relative to last year’s outlook places additional strain on the world’s deepwater rigs given excess capacity has remained broadly unchanged across the same period.

Figure 14: Breakdown of deepwater exploration licenses expiring by depth excluding GoM*

120

The sharp rise in ultra- 100 deepwater (i.e. >c. 2000m) 80 license expiries should place additional strain on the demand 60 for these types of rigs (5th/6th generation) of which there are 40 far fewer of to the end of the expiring Licenses decade relative to shallow and 20 mid-water rigs

0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2020 2039 2021 - - 2021 400-799 (Peak 2014) 800-1199 (Peak 2009 & 2014) 1200-1599 (Peak 2009 & 2012) 1600-1999 (Peak 2010, 2012 & 2014) 2000-2399 (Peak 2012) 2400-2799 (Peak 2013) >2800 (Peak 2009, 2012 & 2015)

Source: Deutsche Bank, Wood Mackenzie, *Given the scale of GoM licenses awards (on average 400/year vs. 40/year elsewhere in the world) and the fact that two thirds of them are below 1500m, we have excluded this region from the chart in order to show clearly the trends occurring in ultra-deep i.e. >c. 2000m Figure 14 shows that the majority of licenses across all depth intervals are due for expiry over the next five years. The sharp rise in ultra-deepwater (i.e. >c. 2000m) license relinquishments should place additional strain on the demand for these types of rigs (fifth/sixth generation) of which there are far fewer of to relative to shallow and mid-water rigs. We expand on the supply/demand implications of this analysis on day rates in the next section (‘exploration dynamics’).

Page 12 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 15: Breakdown of deepwater exploration licenses expiring by region

100 1200

90 1000 80

70 800

60 Brazil and South East Asia 600 will emerge as swing 50 400 players in the global 40

demand for deepwater rigs Licenses expiring 30 200

20 0 10

0 -200 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021- 2039

Europe (Peak 2009 & 2014) South East Asia (Peak 2012 & 2015) Africa (Peak 2009 & 2013) S America (Peak 2010 & 2012) N America (Peak 2013 & 2017) GOM (Peak 2018) (RHS)

Source: Deutsche Bank , Wood Mackenzie We draw the following observations from the above:

South America licenses should relinquish between 2010 and 2013. This should see a hike in exploration and subsequent appraisal drilling activity that implies greater demand for rigs near term. Note that the increase in exploration activity triggered by the Tupi find Europe, Africa and GoM in 2007 de-stabilised the global market for rigs as existing ones gravitated towards South have all experienced a America and un-contracted global rig capacity reduced (mainly driven by new orders material increase in licenses placed by Petrobras). Our analysis of all recently built rigs operating globally shows that awarded over the last 12 27% have been contracted to work in the region over the next five years (detailed in months. Extensions to Appendix E). drilling programs have been The majority of the licenses awards in Africa across this decade will expire between most prominent in these 2010 and 2015 which should see operators continue to bid on un-contracted rigs to regions. Together this sees ensure that their drilling commitments are fulfilled. We note a large number of new renewed expiries across the licenses that have been awarded over the last 12 months and that broadly 20% of the mid term and more regular existing base has been renegotiated (drilling programs extended). Together this has peaks pushed out Africa’s expiry profile towards the middle of next decade (vs. last year’s outlook which showed the majority of licenses in this region expiring by 2012).

Europe (largely represented by the North Sea and Norwegian shelf) should witness a renewed surge in drilling mid to longer term as expiries continue into the next decade (vs. last year’s outlook that showed the majority of licenses relinquishing by 2010)

We show the Gulf of Mexico separately given its much larger scale of licenses awarded vs. the rest of the world (albeit that each license is far smaller in block size). We note that the pressure to drill in this region is less given the first ‘peak’ in expiry does not occur until broadly 2012/13. In addition, oil companies have arguably more flexibility in being able to extend drilling programs here relative to other parts of the world.

Deutsche Bank AG/London Page 13 7 December 2009 Oil & Gas European Oil Services

Following a hike in 2009, shallow water and onshore license relinquishments appear to be reducing mid term and with it the pressure to drill ahead of expiry Figure 16: Expiry profile of shallow water and onshore Figure 17: Breakdown of shallow water and onshore licenses awarded from 2000 exploration licenses expiring by region

3000 25% 1200 3000 1000 2500 2500 20% 800 2000 2000 600 1500 15% 1500 400 1000

10% Licenses expiring 200 500 1000 % expiring

0 0 N America licenses expiring 5%

Count of licenses expiring 500 2002 2005 2007 2009 2011 2013 2015 2017 2019

0 0% 2021-2040

GOM (Peak 2009 & 2013) E Hemisphere (Peak 2008, 2012 & 2015) 2002 2005 2007 2009 2011 2013 2015 2017 2019 S America (Peak 2009, 2012 & 2014) Africa (Peak 2010 & 2012)

2021-2040 Europe (Peak 2012) Middle East (Peak 2009 & 2011) Exploration % expiring Russia (Peak 2008, 2011 & 2033) N America (Peak 2022) (RHS)

Source: Deutsche Bank, Wood Mackenzie Source: Deutsche Bank, Wood Mackenzie Shallow water licenses appear to be generally less periodic in their expiry and having collectively reached a peak this year, the pressure to drill into the end of the decade is reducing. Looking at the regional splits, GoM not surprisingly represents one of the largest constituents of shallow water drilling and is to a large degree driving the downtick in license relinquishments to the end of the decade. To what extent will volatile macro conditions impact drilling programs being adhered to and the appetite to drill?

What is implicit in the above is that every operator be it oil company or independent will have …the risk to this assumption no choice but to drill in order to fulfil their commitments to the host government. High is that if macro conditions commodity prices will no doubt influence their appetite to explore and appraise more deteriorate, then we could actively. However, even if oil prices were to fall significantly below current levels the access see a reduced willingness to reserves (particularly those that offer high net margin barrels) should remain a priority over from governments to its near-term commerciality and development. The risk to this assumption is that if credit explore easing the pressure availability and macro conditions were to worsen, governments themselves (committed to on IOCs/NOCs and social programs and other fiscal pressures) could in turn pull funding and therefore become more accommodating to drilling programs. This would see license expiries extended easing independents to drill the pressure for oil companies to explore and appraise. This decision process would typically be initiated by the host government or National Oil Company. International oil companies that have left their licenses early or exited countries pre-maturely have in the past found it extremely difficult to return. Note it is not uncommon to see them negotiate with their partners including the host government on the grounds that Overall, whilst there is the block acreage yielded very little in the way of discoveries and should not continue to be downside pressure to drill drilled upon. This is clearly a sensitive discussion but nonetheless one that again removes given some uncertainty on some of the pressure to remain overly committed to drilling schedules and in particular those the macro environment that have not been successful. (particularly in the event that license expiries are Overall, whilst there is downside pressure to drill given some uncertainty on the macro environment (particularly in the event that license expiries are extended), we believe that near extended), we believe that to medium-term exploration and appraisal drilling programs particularly those in South near to medium-term America, West Africa and South East Asia should be least impacted. This is based on: drilling programs particularly those in South 1) Wood Mackenzie’s view that these host governments in particular have greater strategic America, West Africa and ambition to increase their country’s oil and gas production, South East Asia should be 2) IOC’s longer-term production targets are weighted heavily to these regions leaving them least impacted with relatively less flexibility to relinquish their licenses,

Page 14 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

3) Our analysis above that presents a structural case for appraisal drilling that should be sustained at current levels on an absolute basis. Drilling demand outlook In this section we model the various datasets provided by Wood Mackenzie’s global exploration database (licenses acreage, signature bonuses, drilling days) to derive an outlook of demand to drill split offshore vs. onshore and also across various depth intervals. The appetite to drill is not homogeneous across the spectrum of depths or indeed onshore and offshore. We combine this analysis with the conclusions derived from our earlier observations on license expiries and outlook for appraisal activity to renew our forecasts for rig day rates offering an alternative to the methodologies adopted by ODS Petrodata and consultancies alike. Figure 18 below shows the increase in deepwater signatures bonuses since the start of the decade. The uplift in shallow water signature bonuses in 2008 is primarily driven by Brazil (Campos and Santos basins) and the US (Alaska Chukchi Sea basin and GoM).

Figure 18: Signature bonuses accelerated across 2006-2008 with an increasing emphasis on deepwater

14,000

12,000

10,000

8,000

6,000

Signature bonus ($mn) bonus Signature 4,000

2,000

- 2000 2001 2002 2003 2004 2005 2006 2007 2008

Onshore Offshore <400m Deepwater >400m

Source: Deutsche Bank, Wood Mackenzie

Deutsche Bank AG/London Page 15 7 December 2009 Oil & Gas European Oil Services

Figure 19: Shift in licensees awarded (see Appendix O for detailed trends on licenses awarded) has historically been followed with a similar (directional) change in drilling days (exploration and appraisal)

200,000 3,500,000 180,000 3,000,000 160,000 140,000 2,500,000 120,000 2,000,000 100,000 80,000 1,500,000 drilling days drilling 60,000 1,000,000 40,000 500,000 km2) in (acreage licenses 20,000 0 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E

Onshore Shallow water (0-400m) Deepwater (>400m) licenses awarded (RHS)

Source: Deutsche Bank , Wood Mackenzie; * drilling days is defined as the time drilled between spudding & completion of well. Shallow water drilling outlook shows mixed signals Figure 20: Drilling activity in depths 0-199m* Figure 21: Drilling activity in depths 200-399m*

Increase in licenses Whilst outlook appears aw arded expected to lacklustre, activity is expected fuel drilling activity be driven from a higher base 129,000 300,000 7,000 90,000 80,000 109,000 250,000 6,000 70,000 5,000 89,000 200,000 60,000 4,000 50,000 69,000 150,000

days 3,000 40,000

drilling days drilling 49,000 100,000 30,000 2,000 20,000 29,000 50,000 1,000 licenses (acreage km2) in licenses (acreage km2) in 10,000 9,000 0 0 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E 2009E 2010E 2011E

drilling days licenses awarded drilling days licenses awarded

Source: Wood Mackenzie and Deutsche Bank estimates; *2009 license acreage has yet to be fully updated by Source: Wood Mackenzie and Deutsche Bank estimates; *2009 license acreage has yet to be fully updated by WM WM Mid deepwater outlook robust, ultra-deepwater continues to accelerate Figure 22: Drilling activity in depths 800-1199m* Figure 23: Drilling activity >2000m*

Ramp up in licenses awarded across 2007-08 should see an Ultra-deepwater ilicens awards has been a key driver in this equivalent increase in drilling activity across 2010/11 vs. previous unpredented hike across 2006-09. This should see an equivalent years; key regional drivers are South East Asia and Brazil 2,000 increase in drilling activity well into the next decade 400,000 1,800 350,000 8000 40000 1,600 300,000 7000 35000 1,400 6000 30000 1,200 250,000 5000 25000 1,000 200,000 days 4000 20000 Days 800 150,000 3000 15000 600 100,000 Licenses (acreage in km2) (acreage Licenses 2000 10000 400 in (acreage Licenses km2) 1000 5000 200 50,000 0 0 - - 2000 2001 2002 2003 2004 2005 2006 2007 2008 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E 2009E 2010E 2011E drilling days licenses awarded Drilling days Licenses awarded

Source: Deutsche Bank & Wood Mackenzie; *2009 license acreage has yet to be fully updated by WM Source Deutsche Bank & Wood Mackenzie; *2009 license acreage has yet to be fully updated by WM

Page 16 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 24: Deepwater drilling activity will continue to intensify in depths >2000m

30000 Structural shift towards ultra deep water depths in absolute and relative terms Our outlook for drilling 25000 demand points to a material rise in ultra-deepwater 20000 drilling. By 2011 we expect this end of the depth 15000 spectrum to represent 20%

of deepwater drilling days Deepwater days drilling 10000 (vs. 14% 2007)

5000

0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E

> 2400 2000-2399 1600-1999 1200-1599 800-1199 400-799 Source: Wood Mackenzie; Deutsche Bank Onshore drilling outlook appears lacklustre with some support from Middle East and South East Asia Figure 25: Onshore activity

35,000 2,500,000

30,000 2,000,000 25,000

20,000 1,500,000

days 15,000 1,000,000 10,000 500,000 5,000 licenses (acgreage in (acgreage km2) licenses 0 - 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E

drilling days licenses awarded

Source: Wood Mackenzie; Deutsche Bank

Positive implications for rig construction services Our outlook of rig construction spend (newbuild, upgrade and refurbishment) is based on what has already been flagged by the contractors (drillers and E&C companies) and the degree of additional investment that could materialise. Despite the number of deepwater floater new builds coming on-stream, the relative lack of liquidity here (only c. 40% are accessible vs. 90% for jack-ups) against accelerated drilling activity particularly in the ultra- deepwater suggests that the demand for newbuilds will continue albeit at a reduced pace and scale vs. 2006-08.

This is in contrast to the jack-up rig market (offshore and onshore) that appears readily accessible and in turn should see a more severe decline in newbuild investment vs. 2006-08. Notable exceptions here that place upside pressure particularly on the rate of incremental jack-up rig spend include:

The demand for premium jack-up rigs capable of working in harsh environments as the global incremental supply of oil continues to be sourced from more technically challenging prospects (e.g. in the FSU).

Deutsche Bank AG/London Page 17 7 December 2009 Oil & Gas European Oil Services

National oil company investment in rig newbuilds. Figures 26 and 27 show actual capex committed to new builds between 2009 and 2012 sourced by region and origin of the operator; i.e., NOC vs. IOC.

Figure 26: Rig new build spend (2009-12E) by region Figure 27: Rig new build spend (2009-12E) by NOC/IOC

Asia 19% US IOC (i.e private or 27% publicly listed drillers) 40% Europe 10%

Africa Middle Eas t 1% 1%

NOC 60% South America Norw ay 19% 23%

Total 2009-12E capex = $67.5 bn Total 2009-12E capex = $67.5 bn

Source: Deutsche Bank, ODS Petrodata Source: Deutsche Bank, ODS Petrodata On comparing the above to the split of new build spend that occurred between 2003 and 2006, we note that there has been a gradual shift from the traditional investors of rig new builds, such as the US and Europe towards South America, Middle East and Asia. This move has been underpinned by greater participation of NOCs in rig construction and in turn refurbishment/upgrades. Confirming this is our analysis done in conjunction with Wood Mackenzie which shows direct investment by the NOCs in drilling since 1995 (Appendix F).

Robust drilling outlook will continue to support rig upgrade and refurbishment investment particularly for those operating in deepwater This sub sector of rig construction services focuses on extending the life of a rig whether it be through maintenance and/or or extra kitting of equipment to improve its technical capabilities. Volatile commodity prices and general lack of macro visibility has put many refurbishment and upgrade programs on hold, as operators prefer to ‘cold or warm’ stack rigs than upgrade existing fleet. This has been most pertinent within the shallow water drilling segment; deepwater refurbishment has been relatively less impacted. Going forward, we believe that as macro conditions stabilise, we should see renewed interest in rig construction services. Forward demand will be directly correlated to:

Rig attrition. Figures 28 and 29 show that 38% of global rig capacity is above 25-years- old (typical rig run life is 30 years) suggesting that over the next 10 years, these rigs will require some degree of maintenance. This could vary from refurbishment e.g. replacement of corroded parts (basically returning the rig to its original efficiency and capability thus extending its life) through to enhancement of the rig in order to extract more value from it. It is worth noting that we expect a more pro-active maintenance approach in contrast to earlier parts of the cycle where underinvestment i.e., the bare minimum was accepted (drillers, keen to exploit the strong commodity environment, kept maintenance time as low as possible).

Page 18 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 28: Majority of world rig fleet is above 20 years Figure 29: Average age of world fleet is remarkably high old

45.0%

40.0% 120

35.0% 100 Av. age of global fleet = 24 yrs 30.0% 80 25.0% 60 20.0% 40 15.0%

10.0% 20 % of within rigs age range 5.0%

Rigs deliveredRigs per year 0 0.0% 1958 1961 1964 1967 1970 1973 1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009 <5 6-10 11-15 16-20 21-25 >25

Age (yrs)

Source: Deutsche Bank, ODS Petrodata Source: Deutsche Bank , ODS Petrodata

Number of new rigs coming onto the market which will require periodic maintenance (regulators deem five years as the maximum). With a 26% increase in rigs expected across 2009-12 (on 2008 base), we believe this will see a proportionate increase in rig maintenance, which coupled with the requirements of the existing asset base as highlighted above should see demand for refurbishment remain strong longer term.

Lack of financing and general confidence to build speculatively has led to many operators and drillers, particularly in the US, to opt for rig upgrades often in the form of conversion or re-activation. Interestingly, of the total number of re-activated rigs coming on-stream across 2007-11E, 65% are sourced from the US. Given the US drillers have been relatively less inclined to commit to new builds and with lack of financing to build new fleet, we believe the preference to upgrade existing fleet particularly in the deepwater will continue.

Deutsche Bank AG/London Page 19 7 December 2009 Oil & Gas European Oil Services Exploration industry dynamics and relative profitability

Our analysis shows that deepwater global rig liquidity has increased from 26% (2008- 12E) to 40% (2009-12E) and from 70% to 90% in the shallow water segment (current newbuild schedules suggests a 19% increase in global rig capacity vs. current levels). In this section we marry the demand implications of our exploration and appraisal drilling outlook against what appears to be a well supplied market to determine how day rates will evolve by rig class across the near to medium term.

We believe the ultra deepwater market will demonstrate the best performance as supply/demand fundamentals are expected to tighten again beyond 2010. Having fallen from a record level of $700k/day in 2008 and stabilised around $500k/day, we expect rig rates to rise from 2010 (we forecast $600k/day by 2011) as license expiries loom and exploration/appraisal drilling accelerates. With this in mind, we believe incremental demand for best in class assets (younger, latest generation of rigs) will re- shape the deepwater market as new rig owners gradually displace market share traditionally held by more mature drillers (predominantly US based). We expect downward pressure on rig day rates operating in depths lower than 2000m given the greater availability of (older generation) mid-water fleet partly offset by a robust demand outlook. Shallower water day rates should continue to fall but stabilise towards structurally higher levels than mid-cycle. Elsewhere in the exploration complex, rig construction services emerge as an attractive niche particularly in the Middle East.

Drilling services: global rig rate outlook Analysis and prediction of rig rates will be based on a number of continually changing variables that affect the operators and drillers’ perception of how the market will move. Structural factors that influence spot (or leading edge) and long-term (or contracted) rig rates include:

Outlook of exploration and appraisal drilling demand

Our day rate model is Rate of rig replacement defined as the degree with which incremental rig capacity demand driven and (confirmed new builds and upgrades) will be offset by ageing fleet due to be taken off- dependent on our outlook stream for exploration and appraisal Liquidity of the rig market - operators’ willingness to sign up rigs at a premium or activity; analysing the discount to the current leading edge is, in part, based on the accessibility of incremental degree of supply coming on- supply, i.e. the proportion of rigs that are not yet locked up into long-term contracts. stream and more We base our short- to medium-term rig rate forecasts on our understanding of the above importantly operator’s supply/demand dynamics. Macro and geopolitical factors influencing rig rates include: ability to access spare capacity, provides a more Oil and gas prices (higher prices will drive appetite to drill and monetise reserves quickly) complete picture with which The condition of the global economy and level of GDP growth anticipated worldwide and to forecast future day rates at the regional level We believe our near- to mid-term day rate outlook remains intact at sub $70/bbl oil on a sustained basis and against deteriorating macro conditions. This is given the bottom up nature of our demand forecast (linked to the structural dynamics detailed in the last section).

Page 20 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

DB day rate model

First we analyse supply.... Whilst we have not quantified the impact of supply on day rates we address below, albeit qualitatively, the extent to which capacity creep could effect our forecast, if at all. Figures 30-33 show the timing, complexity and degree of incremental rig capacity (already commissioned) expected to come on-stream in the medium term. It is worth noting that rigs capable of drilling in deep and ultra deep waters are also operable in mid and shallower waters. Therefore during periods of low utilisation, owners of fifth/sixth generation rigs (semi-submersibles or drillships) may choose to charter them out in reduced depths.

Figure 30: Latest ODS figures suggest a 19% increase in Figure 31: Drillships; 73% increase in supply expected global capacity by 2012 vs. 2009 (depths greater than 7500ft)

35 155 rigs are currently planned to come on-stream across 09-12E 70 30 35 Drillships are planned to come onstream across 09-12E 60 25

50 20

40 15

30 Number of rigs 10 Number of rigs 20 5 10 0 0 0-2999 3000-4999 5000-7499 7500-9999 >=10000 2009 2010 2011 2012 depth (ft)

2009 2010 2011 2012 Drillship Jackup Semisubmersible Tenders Source: Deutsche Bank and ODS Petrodata Source: Deutsche Bank and ODS Petrodata Figure 32: Semi-submersibles; 20% increase in supply Figure 33: Jackups; 13% increase in supply expected expected (bulk occurring at depths >7500ft) (bulk occurring at depths b/w 300-400ft)

30 60 25 45 Semisubmersible rigs are 69 Jackups rigs are planned planned to come onstream 50 20 across 09-12E to come on stream across 40 09-12E 15 30

Number of rigs 10 20

5 Number of rigs

0 10 0-2999 3000-4999 5000-7499 7500-9999 >=10000 0 depth (ft) 0-199 200-300 300-400 >=400

2009 2010 2011 2012 2009 2010 2011 2012

Source: Deutsche Bank and ODS Petrodata Source: Deutsche Bank and ODS Petrodata Whilst the rig market appears well supplied into the end of the decade, we highlight below counter dynamics that should remove some of the downside risk on rig utilisations.

Rig attrition. Of the expected 19% increase in global capacity, ODS Petrodata estimates that up to a third of that could potentially be ‘soaked up’ in replacing older rigs forced off stream over the next 5-10 years.

Lack of financing and general confidence to build speculatively. Lack of credit availability and the general reluctance to build new rigs has completely removed speculative capacity this year. Whilst we believe deepwater rigs will continue to be built it will be at depressed pace and scale relative to 2006-09.

Deutsche Bank AG/London Page 21 7 December 2009 Oil & Gas European Oil Services

Rig liquidity. Figures 34 and 35 show the proportion of new builds that have yet to be contracted.

Figure 34: Jackup new build spare capacity 2009-12E Figure 35: Semi-submersible and drillship new build spare capacity 2009-12E contracted Jackups 10%

Uncontracted semis and drillships, 40%

Contracted semis and drillships, 60% Number of uncontracted Jackups 90%

Source: Deutsche Bank ,ODS Petrodata Source: Deutsche Bank, ODS Petrodata Despite the number of deepwater floater new builds coming on-stream, the relative lack of liquidity here (c. 40% are accessible) suggests that the market will continue to remain tight in the medium term all else being equal. Conversely, the jack-up rig market (offshore and onshore) appears readily accessible. As the new builds come on stream, we believe this will inevitably place downward pressure on utilisation, assuming that jack-up demand does not vary significantly from current levels.

With regards to the existing rigs already under contract (that could threaten to increase spare capacity dramatically) analysis of the world’s contracted deepwater rigs (detailed further in the next section) shows that the average term length on rigs signed across 2007/08 (>90% of the world’s rigs were re-negotiated during this period) is four years (jackups between 0.5-2 years). Our point here is that spare capacity of existing rigs, at least those drilling in deepwater will not free up before 2011/2012. We believe this should be more than offset by a significant expected up-tick in drilling demand across the same period keeping supply/demand fundamentals robust into the first half of the next decade. With the above in mind, we have utilised the Wood Mackenzie outlook on drilling activity and license expiries to forecast rig rates at various depth intervals in both shallow and deepwater. Note that our forecasts have been made on a yearly basis. So, for example, a driller currently looking to re-negotiate a contract due to expire during 2010 would, for the purpose of our rig model, lock into the rate we estimate in 2010 (at the relevant depth) for the renewed length of the contract term.

The ultra deepwater market As Figures 36-40 show, excess offshore rig capacity (that drove utilisation <80%) between (depths > 6500ft) will 2003 and 2005 appears to have pressured day rates across all depths despite intermittent demonstrate the best increases in drilling activity during broadly the same time frame. We expect downward performance going forward pressure on rig day rates operating in depths lower than 2000m given the greater availability as supply/demand of (older generation) mid-water fleet. In our opinion, the ultra deepwater market (depths fundamentals tighten >2000m) will demonstrate the best performance as supply/demand fundamentals are expected to tighten again beyond 2010. Shallower water day rates should continue to fall but further. stabilise towards structurally higher levels than mid-cycle.

Page 22 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 36: Ultra-deepwater rig rate outlook >2000m/6500ft

2000 700 1800 600 1600 1400 500 1200 400 1000 800 300 600 200 Day rate ('000$k/d)

WM drilling days 400 100 200 0 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E

Drilling days Day rate

Having fallen from a record level of $700k/day in 2008 and stabilised around $500k/day, we expect rig rates to rise from 2010 as licenses expirie loom (expected to peak in 2012), exploration drilling accelerates and appraisal activity intensifies.

Amidst potentially lower rig liquidity, the increase in new ultra deepwater rigs (capable of drilling >6500ft) are not likely to be sufficient to quench the ramp up in drilling activity expected at these depths.

Source: Deutsche Bank and Wood Mackenzie estimates

Figure 37: Rig rate outlook b/w between 400m to Figure 38: Mid deepwater rig rate outlook b/w 800m to 914m/1300-3000ft 1200m/2600-3900ft

8000 450 4000 350 7000 400 300 3500 6000 350 250 300 5000 3000 200 250 4000 200 150 2500 3000 150 100 2000 WM drilling days 2000 100 50 Day rate ('000$k/d)

WM drilling days 1000 50 Day rate ('000$k/d) 1500 0 0 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E 2009E 2010E 2011E Drilling days Day rate Drilling days Day rate

Increase in drilling activity should help support demand Robust drilling outlook should help support current day for rigs operating at the lower end of the deepwater rates despite ramp up of new ultra deepwater rigs that spectrum. may initially be utilised across the mid-water depths.

However, older generation of rigs coming off contract Incremental supply of older generation rigs (that operate coupled with new capacity coming on-stream should mainly across this depth interval) will have negative offset this incremental demand to drill and we expect implications on the supply/demand balance within mid- day rates to remain under pressure. water and we expect day rates to fall albeit moderately.

Source: Deutsche Bank and Wood Mackenzie estimates Source: Deutsche Bank and Wood Mackenzie estimates

Deutsche Bank AG/London Page 23 7 December 2009 Oil & Gas European Oil Services

Figure 39: Shallow water rig rate outlook b/w 0m to Figure 40: Shallow water rig rate outlook b/w 200m to 199m/656ft 399m/656-1300ft

149,000 160.0 7,000 250.0 129,000 140.0 6,000 200.0 109,000 120.0 5,000 100.0 4,000 150.0 89,000 80.0 3,000 69,000 100.0 60.0 2,000

49,000 WM drilling days 50.0 40.0 1,000 Day rate ('000$k/d) WM drillingdays Day rate ('000$k/d) 29,000 20.0 0 0.0 9,000 0.0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E 2000 2001 2002 2003 2004 2005 2006 2007 2008

2009E 2010E 2011E drilling days day rate

drilling days day rate

The uptick in drilling activity beyond 2010 should be Strong drilling outlook should help maintain current jack- offset by a readily accessible jack-up market. This up rates against a backdrop of capacity creep and high should see day rates fall (albeit to a level structurally rig liquidity.

higher than across the first part of the decade) Source: Deutsche Bank and Wood Mackenzie estimates

Source: Deutsche Bank and Wood Mackenzie estimates Ultra-deepwater day rates will stay ‘stronger for longer’ as contract term lengths increase We have updated our extensive contract analysis of all deepwater rigs signed under long- term fixtures since 2004 in order to track the term length of contracts over time.

Figure 41: Term length of semi-submersible and drillship contracts since 2004

100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 2004 2005 2006 2007 2008

Up to 2 years 2-4 years 4+ years

Source: Deutsche Bank, Rigzone, ODS Petrodata Figure 41 shows term lengths on the rise as clients prefer to lock into longer fixtures on fixed day rates (as opposed to accessing the spot market on shorter term leases typically <1 year). This should come as no surprise given the lack of rig liquidity in the deepwater market across 2007/08 which coupled with accelerated global drilling activity (not to mention stricter drilling schedule requirements by host governments) has forced IOCs and independents to sign up rigs well ahead of their release (or delivery if they are newbuild) and for longer periods of time. In parallel we have seen several NOCs (e.g. Petrobras) do the same as they take strategic decisions to invest over 5-10 year periods that justify locking into contracts on rigs

Page 24 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

for 5+ years. The impact this dynamic has on our company model is that it gives us greater visibility beyond our earnings horizon (2012).

Rig construction services: capacity appears over-supplied, Middle East less so Our discussions with industry suggest that China We have analysed current and future capacity across the Middle East, Asia and Australia – offers the lowest pricing on basically the Eastern Hemisphere. With currently 66 yards in the region operating, three of rig construction services, which are undergoing brownfield expansion and four more being built, we believe that the followed by Korea then UAE risk of oversupply is real (notwithstanding yards being built in China that are not public knowledge). However, against our demand outlook and various counter-dynamics discussed and Singapore below (based on our analysis of capacity by region and industry), the risk of margins deteriorating significantly in the medium term appears low in our opinion.

In Figure 42 we show the current regional yard capacity for construction. Oil and gas activities include newbuild and refurbishment of semi-submersible rigs, jack-up rigs, drillships, tension leg platforms, FPSO, FPO, heavy lift carriers, pipelay vessels, crude oil tankers, container vessels, gas carriers (LNG,LPG) etc. Non-oil and gas activities comprise yards that do ship (civil and naval) building, repair and conversion, service crafts, cargo ships, yachts, work boats, etc.

Figure 42: Regional construction capacity – Total of 70 yards (including greenfield)

Yards - Oil and gas sector Greenfield expansions Yards - non Oil and gas sector Greenfield expansions

China 21 (Yantai, COSCO, CSSC, Keppel) Singapore 13 (Keppel. Sembcorp, Clough) UAE 11 (Lamprell, MIS, Dubai Dry Docks, Keppel, Mcdermott, QGM,CCC) Indonesia 5 (Sembcorp, Mcdermott, Labroy Marine, Clough) Korea 3 (Hyundai, Daewoo, Samsung) Philippines 3 (Keppel) Japan 3 (Kawasaki, Mitsui) Azerbaijan 2 (Keppel, Mcdermott) Thailand 2 (Lamprell, Clough) Saudi Arabia 2 (Sembcorp, MIS) Qatar 1 (Keppel) Kazakhstan 1 (Keppel) Kuwait 1 (MIS) India 1 (Sembcorp) Australia 1 (Mermaid Marine)

Source: Deutsche Bank, Company data

Whilst the risk of over supply in the region poses a continuing threat to the industry’s mid- to longer-term pricing power (the fear being that the structure of the rig construction industry will weaken as more capacity comes online), we include below some of the counter- dynamics that should offset the downside risk on the company’s margins across the mid term:

Deutsche Bank AG/London Page 25 7 December 2009 Oil & Gas European Oil Services

The type of construction activity on offer from these yards does not coincide completely with that of rig related construction. Figure 43 shows the proportion of yards that provide oil and gas related construction. Investor perception of construction capacity in The relative lack of pure these regions suggests that there is plenty of it; the reality is that it is being used for a refurbishment capacity variety of products of which non oil and gas represents approximately one-third. Of the suggests this sub-sector will oil and gas portion, the economies of scale on the yards offering newbuild services remain robust… makes it relatively difficult to switch to the (smaller sized) refurbishment projects alone. Figure 44 shows the proportion of oil and gas based capacity that caters for refurbishment. The relative lack of pure refurbishment capacity suggests this sub-sector will continue to be robust and perhaps even more so in the Middle East (only 16% of rig construction capacity is refurbishment based) across the mid term. The downside risk to our outlook is that as incremental demand for newbuilds slows this could force contractors to change their product offering and result in a significant up-tick in refurbishment capacity.

Figure 43: Split of capacity by oil and gas related Figure 44: Split of capacity by refurbishment and construction and others newbuild services Number of yards: 70 Number of yards: 49

30% 37%

47%

70%

16% Non oil and gas Oil and gas New build Refurbishment New build + Refurbishment

Source: Deutsche Bank, Company data Source: Deutsche Bank, Company data

Companies operating specifically in the Middle East sit within three critical barriers to … and even more so in the entry: Middle East New entrants in the region and more specifically UAE which represents the bulk of construction activity in the region will likely lack the long standing relationships that existing contractors have established with the local government not to mention client base, critical prerequisites in being able to open up shop and succeed.

It makes no sense for drillers and oil companies operating here to upgrade or refurbish their rigs anywhere else; transport costs and likely risk of delay and inferior quality far outweighs the potential benefit of cheaper options in e.g. China.

Lack of natural harbours across the Middle East, particularly within the most construction-heavy country, UAE. Indeed, the government recently voiced their inability to expand industrial activity further across their coastline. The profile of incremental capacity is shifting towards Greenfield expansions in the region as shown in Figure 45 suggest that the industry has non-oil and gas based certainly reacted to the demand surge witnessed in rig construction but perhaps not as aggressive as one would have expected (only two ‘oil and gas’ based yards are under activities construction against a current 47 in operation). Equally we show that the profile of this incremental capacity is changing. Figure 46 shows total capex committed by all the companies listed above (Figure 42) since 2004 and a gradual re-weighting towards non- oil and gas based activities.

Page 26 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 45: Greenfield extensions* (oil and gas related) Figure 46: Investment in yard capacity

42 hectares 8,000 m 7,000 Land area 9,000 Quay side 45 6,000 8,000 40 5,000 7,000 35 4,000 58% 6,000 30 56% 5,000 25 3,000 53% 53% 50% 50% 4,000 2,400 m 20 Capex mn) ($ 2,000 3,000 Quay side 15 Quay side (m) 1,000

2,000 10 (hectares) area Land - 1,000 5 2004 2005 2006 2007 2008 2009E - 0

Oil and gas Non - Oil and gas % of Oil and gas Changxing (China) Keppel, Nakilat JV (Qatar)

Source: Deutsche Bank, Company data* all of which will be completed by 2015; note that of the four Source: Deutsche Bank , Company data; greenfield yards under construction two are non oil and gas related

Finally, despite what appears above to be a large number of yards in China (and potentially more that have not been disclosed), the oil and gas industry is split in its view of the quality of product that is on offer there. With drillers having to pay hefty fines on rig delays not to mention a forfeit of day rate, the appetite to change their traditional supplier of choice to new players particularly within Asia is unsurprisingly low. We would caution however that as the product quality of these yards improve (industry consultants Pegasus Global suggest this could be the case within five years), we expect market share to be re-distributed and pricing power to be under renewed pressure particularly on newbuild work given the relatively higher available capacity.

Deutsche Bank AG/London Page 27 7 December 2009 Oil & Gas European Oil Services Global engineering and construction outlook

Our annual review of global E&C capex sees a moderate decline, in aggregate, across 2009-11. Not surprisingly, cost deflation across the supply chain and delays in FIDs has driven a c. 10% drop vs. last year’s outlook (2008-10E). In this section we outline the results of our bottom up analysis by theme and list the key bottlenecks surrounding FIDs which if they were to fully materialise could result in FIDs being delayed beyond 2010. Whilst this would place downside pressure on our 2011 estimates we believe the impact should be limited based on our view that IOCs looking to adhere to mid to longer term targets of production growth would have to invest across 2011/2012. Critical to their reserve replacement will be the need to offset production decline on maturing fields with incrementally new barrels. Having delayed FIDs across 2009-10, we believe IOCs would be under renewed pressure to sustain production at their current levels provided was profitable.

Global capex outlook

Figure 47: Global capex split 2010E

Our capex forecasts should not vary Exploratory, appraisal and significantly in an oil development price world of $70/bbl + spend* 39% (Wood Mackenzie long- term assumption) given the bottom-up nature of Engineering and our analysis construction spend 61%

Source: Deutsche Bank and Wood Mackenzie;* excludes rig construction service capex In partnership with Wood Mackenzie we have conducted our yearly review of global E&C spend that draws from the consultancy’s vast database of individual field models. We have incorporated all upstream/downstream projects likely to be sanctioned across 2010/11 based on our partner’s assessment of potential commercialisation of the world’s current 2P reserve base. These capex forecasts are sense-checked with what is implicit within our own global supply models (IOC and NOC production outlooks) and should not vary significantly in an oil price world of $70/bbl+ (Wood Mackenzie long-term assumption) given the bottom-up nature of our analysis.

Page 28 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 48: Global E&C outlook (NOC + IOC) by theme (av. yearly growth rates 2009-11E shown alongside)

500 15%

LNG plant 4% Deepw ater contribution to global 14% 400 …. spend

Refining & petrochemicals 5 % 13% 300 GTL and Regas -3 % Oilsands -12% 12% Onshore upstream -4% 200 11% Deepwater weighting

Global E&C capex (US $ bn) 100 Shallow w ater -9% 10%

Deepw ater facilities & FPSOs 6% 0 9% 2006 2007 2008 2009E 2010E 2011E Deepw ater subsea 19% Source: Company data, Deutsche Bank & Wood Mackenzie estimates. This year’s review incorporates improved Wood Mackenzie coverage of Middle East, Russia, Canada and South East Asia (including China and Australia - IOC and NOC spend) not to mention further development of our LNG and downstream products. All these factors have helped improve the granularity and accuracy of our capex forecasts. The variance vs. last year’s capex (2009-10E) is, on average -9%. One-third of this drop is due to expanded WM coverage with the balance attributed to:-

Projects being pushed back particularly FIDs that were due for sanctioning in 2009 delayed until 2010 and some indefinitely. This effect was most acute in North America (Permian Basin, Rockies and Gulf Coast fell 41%, 40% and 31% respectively vs. 2008), Brazil and West Africa. The drop off was less pronounced in other regions as a result of i) binding commitments to long lead items and long term contractual obligations particularly in the deepwater market and ii) sanctioning of sprint to market projects (expanded on in the next section),

Greater than expected cost deflation particularly with respect to steel and basic materials; note that prices of more specialised equipment and exotic materials have held up better.

Figure 49: Absolute spend across the global energy complex and expected year-on-year growth rates Year/year growth rates $mn 2007 2008 2009E 2010E 2011E 2008/07 2009E/08 2010E/09E 2011E/10E Av. 2009E-11E Deepwater Sub-sea 9,251 8,147 8,759 9,340 13,219 -12% 8% 7% 42% 19% Deepwater Facilities & FPSOs 27,221 32,347 32,523 32,800 38,219 19% 1% 1% 17% 6% Shallow water upstream (surface 83,555 92,641 78,070 75,891 69,253 11% -16% -3% -9% -9% facilities & infrastructure) Onshore upstream (facilities & 167,925 194,678 174,335 175,641 173,480 16% -10% 1% -1% -4% infrastructure) Gas to liquids (GTL) 2,300 5,150 5,000 3,468 2,131 124% -3% -31% -39% -24% LNG plant 13,006 12,562 10,972 7,328 11,494 -3% -13% -33% 57% 4% Re-gasification terminals 5,397 6,580 6,980 6,926 5,304 22% 6% -1% -23% -6% Oil Sands 15,762 20,535 9,993 9,957 11,572 30% -51% 0% 16% -12% Refining & Petrochemicals 19,735 27,417 44,902 35,898 26,064 39% 64% -20% -27% 5% Other* 10,161 10,337 10,602 9,867 9,691 2% 3% -7% -2% -2% Total E&C capex 354,314 410,395 382,137 367,115 360,428 16% -7% -4% -2% -4% Total E&C capex 2008 346,789 394,758 408,028 416,663 na 14% 3% 2% na 6%** Variance 2% 4% -6% -12% na Source: Company data, Deutsche Bank & Wood Mackenzie estimates; *other includes operations and maintenance capex as well as spend that cannot be categorised by one specific theme; **2008-10E

Deutsche Bank AG/London Page 29 7 December 2009 Oil & Gas European Oil Services

Risks to our forecasts Our forecasts detailed in figure 49 incorporate NOC capex and shows a moderate decline, on aggregate, in global spend to 2011. However, as mentioned above this assumes that company budgets in regards to FID and general ‘sprint to market’ spend go ahead. General risks to this assumption that we identify as key bottlenecks particularly surrounding FIDs include:

Management boards of Oil Cos deliberating the long run demand for the commodity and whether they should continue to commit to production targets that may appear aggressive relative to worst case scenarios of GDP growth (that assume prolonged recession) – volatility in commodity prices does not help visibility either,

Perception by Oil Cos that costs across the supply chain have further to fall,

Regulatory uncertainties particularly pertaining to environmental restraints and carbon. The latter is now being seen as a potentially material part of costing projects across all parts of the oil chain and the uncertainty relates not only to timing of any legislation from the US but also trying to gauge what cost might be involved,

Disagreement between IOCs and NOCS that are operating as part of a consortium and unable to decide collectively on whether to go ahead with the project development,

The potential shift in appetite by NOCs and IOCs in sanctioning ‘speed to market’ projects to ‘marathon market’ projects that see Oil Cos prolong investment decisions with the view to embark on projects offering sustainable LT returns (we expand on this dynamic in the next section) and

Social pressure on governments to invest in infrastructure and other services has left them with less capital relative to the last few years to funnel into new oil and gas projects. No doubt, the volatile oil and gas price does not make an easy case for NOCs to sanction FIDs.

Page 30 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Kicking the foundations reveals some green shoots

Despite Wood Mackenzie’s relatively muted outlook for global E&C capex we reveal Upside risks to our sweet spots across the oil services chain which while not immune to the risks outlined forecasts are linked to in the previous section should post impressive growth in 2010-11E assuming a long run faster than expected oil price assumption of $70/bbl. By theme, these include deepwater offshore investment in Shell and construction (SURF and FPSO/facilities), LNG, OPEX spend (shallow/mid waters). By BG’s floating LNG region, Middle East (Saudi, Kuwait and UAE), SE Asia (Australia and India), Africa projects (FLNG), Iraq, (Ghana, Egypt, Angola and Nigeria) and Brazil should emerge as primary drivers of GoM and the Caspian capex. We believe the majority of FIDs here should begin to materialise across H2 2010 (collectively linked to the and continue through 2011. Our analysis also shows that pure NOC investment (NOCs outcome of 2010 capital working alone or with each other) will emerge as a key constituent of oil services’ budgets decided upon by backlog longer term making them potentially a ‘price setter’ in the context of a global IOCs across capex recovery (NOCs are expected to represent 40% of global capex and 20% of all Q4’09/Q1/’10). contracts signed across the OFS sector by 2011).

We leverage our exhaustive database of contracts to show that since 2004, 70% of all contracts awarded across the E&C sector have comprised of sprint to market projects (STM characterised as brownfield developments that may be monetised relatively quickly and at a lower marginal cost of production than a greenfield project/FID). Whilst STMs are not immune to the volatility in commodity prices, our analysis reveals that awards of this nature have been instrumental in sustaining the group’s revenue cover for 2009 around historic levels.

We argue that the upward trend in shallow and deepwater appraisal drilling highlighted in the previous section should spur a proportionate increase in spend directed towards related FEED work and sprint to market projects. As a result we expect 2010 revenue cover for oil service companies exposed to this type of investment (asset light and asset intensive companies alike) to remain robust despite the risk of further potential delays in FIDs across 2010.

‘Sprint to market’ investment will play a pivotal role in oil services’ backlog replenishment A sprint to market project (STM) can take the form of: tie-ins (e.g. of a satellite well to an Our analysis reveals that existing platform), general infrastructure, efficiency improvements and the next phase of a since 2004, 70% of all brownfield development that is already in production. These type of projects are generally contracts awarded across shorter in term length (typically <12 months) given the nature of the work involved vs. an FID the E&C sector have (on average 12-36 months) which is typically representative of a greenfield investment. FEED been sprint to market (front end engineering design) and detailed engineering is highly specialised and will be projects involved in conceptual and detailed engineering of various phases of the development (detailed definition given in Appendix S).

Deutsche Bank AG/London Page 31 7 December 2009 Oil & Gas European Oil Services

Figure 50: FID, Sprint to market and FEED contracts Figure 51: Split of offshore contracts* by FID, Sprint to awarded* to E&C companies (across our coverage market and FEED for asset intensive companies under universe) our coverage

250 78% 100 85% 90 76% 80 80% 200 74% 70 72% 60 75% 150 70% 50 68% 40 70% 100 66% 30 % Sprint% tomarket % Sprint to market 64% 20 65% 50 awarded of contracts Count Count of contracts awarded of contracts Count 62% 10 0 60% 0 60% 2004 2005 2006 2007 2008 2009 2004 2005 2006 2007 2008 2009

FEED/ EPCm FID FEED/ EPCm FID Sprint to market % Sprint to market Sprint to market % Spr i nt to m ar ket (RHS)

Source: Deutsche Bank, Company data; *We analyse the relative split by number of contracts vs. unit value Source: Deutsche Bank, Company data; *We analyse the relative split by number of contracts vs. unit value given the latter is often not disclosed by the company given the latter is often not disclosed by the company We leverage our exhaustive database of contracts to analyse, on aggregate, the proportion of projects represented by our classifications above (shown in figures 50 and 51) and deduce the following:

IOC/NOCs have been actively involved in STM projects during the last few years of high oil and gas prices incentivised by their relatively low marginal cost of production and speed with which first oil and/or gas may be monetised,

FIDs have played a key role in the growth of oil service company backlog particularly within the onshore segment; note an FID will generally possess a greater unit contract value than a STM and the above analysis does not capture this,

The reduction in aggregate number of contracts awarded across the sector will be driven by falling commodity prices and in addition (industry sources such as Pegasus Global would suggest) by IOC/NOCs consideration of marathon projects that offer longer term STM awards been sustainable IRRs in place of STM. Indeed, the current delays in sanctioning FIDs are instrumental in linked to this shift in investment criteria and some of the reasons outlined in the previous sustaining the group’s section, revenue cover for 2009 and 2010 Whilst this dynamic would have contributed to the relative decline across 2008/09 in STM, we note that awards of this nature have nevertheless continued despite deteriorating macro conditions and represent 65% of all contracts awarded this year. Figures 52 and 53 below show that this has been instrumental in sustaining the group’s revenue cover for 2009 and 2010 (calculations shown in Appendix G).

Figure 52: Evolution of 2009E revenue cover – the Figure 53: 2010 revenue cover has in part been driven by group’s visibility for this year has improved significantly continued investment in sprint to market projects

100% 85% 95% 75% 90% 85% 65% 80% 55% 75% 70% 45% 65% 60% 35% 55% Forward revenue year cover (Y+1) Current year revenue cover (Y) (Y) cover revenue year Current 25% Q3' 08 Q4' 08 Q1' 09 Q2' 09 Q3' 09 Q3' 08 Q4' 08 Q1' 09 Q2' 09 Q3' 09

Acergy Saipem Acergy Saipem Subsea 7 Technip Subsea 7 Technip Historical group average (04-07) Historical group average (05-07)

Source: Deutsche Bank, Company data Source: Deutsche Bank, Company data

Page 32 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

We expect 2010 revenue Whilst the future level of margin realisation on all contracts awarded this year has yet to cover for the oil service materialise (we expand on this in the next section) the point to make is that as a result of continued appetite by IOC/NOCs to invest in FEED and sprint to market projects, the services group to be in line with have performed better than expected in being able to keep their resources utilised during a historic levels despite period of limited FIDs and heightened volatility in commodity prices. uncertainty around the timing of FIDs… The question is whether this dynamic will continue in the context of potentially weaker commodity prices and a renewed deterioration of the macro environment across the next 6 …however, this does not say months. Figures 54 and 55 below show shallow and deepwater appraisal drilling activity and much for future levels of subsequent investment in shallow and deepwater subsea respectively. Typically we would topline growth and expect a 1-2 year lag (although in some cases this can be several years if governments delay evolution of margins across sanctioning) between appraisal drilling activity (with respect to those wells spudded the group successfully) and the start of a brownfield development life cycle.

Figure 54: Deepwater appraisal drilling should help fuel Figure 55: Shallow water appraisal drilling should help 2010/11 investment in related FEED work and sprint to support 2010/11 investment in related FEED work and market projects across the E&C complex sprint to market projects across the E&C complex 19,700 30,000 103,700 14,000 93,700 17,700 12,000 25,000 83,700 15,700 73,700 10,000 20,000 13,700 63,700 8,000 11,700 15,000 53,700 6,000 Cap ex ($m n ) 43,700 Cap ex ($m n ) Drilling days Drilling

9,700 days Drilling 10,000 33,700 4,000 7,700 23,700 5,000 5,700 2,000 13,700

3,700 0 3,700 - 2005 2006 2007 2008 2009E 2010E 2011E 2005 2006 2007 2008 2009E 2010E 2011E

Appraisal drilling days Subsea capex (RHS) FPSO capex (RHS) Apprailsal drilling days Subsea capex (RHS) FPSO capex (RHS) Source: Deutsche Bank & Wood Mackenzie estimates. Source: Deutsche Bank & Wood Mackenzie estimates. It is our belief that the upward shift in shallow water and deepwater appraisal drilling highlighted in the previous section will spur a proportionate increase in spend directed towards related FEED work and sprint to market projects (in particular deepwater subsea and facilities/FPSOs). As a result we expect 2010 revenue cover for oil service companies exposed to this type of investment (asset light and asset intensive companies alike) to remain robust despite further potential delays in FIDs across 2010.

Offshore E&C complex: SURF, FPSO, platform facilities and seabed surface investment set for recovery We ‘slice’ our outlook for offshore E&C capex a number of ways in order to reveal the relative levels of investment across the global offshore complex. We focus on:

Shallow water (often termed conventional) vs. deepwater investment,

Deepwater by industry segment e.g. SURF, general infrastructure, facilities, FPSO, seabed related services,

Regional trends e.g. Brazil, Nigeria, Ghana, Angola, Egypt and GoM.

Deutsche Bank AG/London Page 33 7 December 2009 Oil & Gas European Oil Services

Figure 56: Shallow water (conventional) vs. deepwater Figure 57: Global deepwater capex outlook split by global outlook theme

140 60

120 50 100 40 80 30 60

40 20 Capex (US $ bn)

20 10 Global E&C offshoreGlobal E&C capex (US $ bn) 0 0 2006 2007 2008 2009E 2010E 2011E 2006 2007 2008 2009 2010 2011

Shallow w ater Deepaw ater Fixed Platf orm FPSO Floater Subsea Source: Deutsche Bank & Wood Mackenzie estimates. Source: Deutsche Bank & Wood Mackenzie estimates. Figure 56 shows a material decline this year in shallow water capex particularly linked to a slow down in conventional activity in the North Sea, Gulf of Mexico and West Africa (Appendix H shows shallow water capex split by region). This will likely be attributed to the weaker commodity environment given the maturity of these types of fields that require relatively higher commodity prices to justify investment (particularly in regions with higher unit costs of production). Across 2010/11, we expect a moderate decline in shallow water capex which given the low barriers to entry and greater competition (particularly from Asian contractors) should see lower margins (we expand on this in the next section) realised for the oil service companies operating here.

Deepwater SURF and FPSO Our 2010 forecast for deepwater capex is broadly flat vs. 2009 (shown above in figure 56) investment is expected to and is set to accelerate to a level in 2011 that is c. 40% higher than 2007/08 (peak year of drive our positive outlook deepwater investment). Deepwater SURF and FPSO investment appears to drive the bulk of for the subsea segment and this increase and assumes that FIDs are sanctioned from H2 2010 onwards. Figure 58 shows our deepwater capex outlook represented by region and the key countries in our analysis that assumes that FIDs are appear to demonstrate capex growth. sanctioned from H2 2010 onwards Figure 58: Global deepwater capex outlook by region – Brazil, GoM and West Africa appear to be the sweet spots

10 Deepwater capex (USD bn) 0 2005 2006 2007 2008 2009 2010

West Africa Gulf of Mexico Brazil SE Asia Europe ROW (Angola, (Australia, (UK, (Egypt, Ghana, India, Norway) Azerbaijan, Nigeria) Malaysia) Israel)

Source: Deutsche Bank & Wood Mackenzie estimates

Page 34 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Middle East investment should continue to remain buoyant

Figure 59: ME outlook– faster than expected pace of Figure 60: Middle East outlook by theme investment in Iraq would place upside pressure to our forecast 60 60

50 50

40 40

30 30

20 Capex ($bn) 20 Capex bn) (USD 10 10

- - 2006 2007 2008 2009 2010 2011 2006 2007 2008 2009 2010 2011

Fixed Platform Subsea Qatar UAE Oman Yemen Onshore GTL Syria Iran Iraq Israel LNG plant Refining and Petrochemicals Saudi Arabia Bahrain Kuwait

Source: Deutsche Bank & Wood Mackenzie estimates. Source: Deutsche Bank & Wood Mackenzie estimates. Our recent field trip to the Middle East underpins Wood Mackenzie’s expectation for a structurally high level of investment from 2008 onwards. With the exception of Qatar (decline driven by LNG and Pearl GTL capex tailing off towards 2011), figure 59 shows the increasing levels of capex expected particularly in Saudi Arabia and UAE over the next two years namely in upstream oil and gas (primarily offshore) and to a lesser extent refining and general energy infrastructure. We should also start to see renewed capex in Iraq (Rumaila and Zubair oil fields) albeit that the timing of FID remains uncertain.

LNG investment poised for growth, prospects for floating LNG places upside pressure to our estimates

Figure 61: LNG capex outlook- Australia’s Gorgon at the front of the queue

6 Capex (USD bn) 4

- 2006 2007 2008 2009 2010 2011

Angola Australia Indonesia Nigeria Norway Peru Qatar Yemen

Source: Deutsche Bank & Wood Mackenzie estimates. FID approval of Gorgon LNG earlier this year should fuel impressive capex growth in Australia across 2010-12. Elsewhere it appears FIDs are generally being pushed out beyond 2011 (with the exception of Indonesia PNG which WM expects to go ahead over the next 12 months). With regards to FLNG, we expect Shell to begin material investment in its first phase next

Deutsche Bank AG/London Page 35 7 December 2009 Oil & Gas European Oil Services

year and whilst WM have yet to capture the related capex in their LNG model, we believe this places upside pressure to our forecast.

European outlook lacklustre; sprint to market and OPEX spend in UK and Norway robust

Figure 62: Norway, FSU and Russia capex outlook

Capex (USD bn) 30

- 2006 2007 2008 2009 2010 2011

Norway Russia Azerbaijan Georgia Kazakhstan Kyrgyzstan Turkmenistan Uzbekistan Ukraine

Source: Deutsche Bank & Wood Mackenzie estimates. Europe (along with US depicted below) has witnessed some of the sharpest declines in capex across 2009/08. However, despite the high costs and technical challenges, major projects in Norway and FSU continue to attract relatively high levels of industry interest. Previous years' capex budgets set by IOCs in UK and Norway (which shows only moderate declines vs. 2009) confirm the continued attraction of their fiscal terms. Whilst timing of FIDs in all these regions appears uncertain, we expect continued investment in sprint to market projects and OPEX projects. With regards the latter, the long term nature of an operating and maintenance contract makes it a defensive theme despite the volatility in commodity prices.

Global outlook sees Brazil, Ghana and Angola as clear outperformers; upside risk to our estimates linked to Gulf of Mexico and the Caspian WM expect Ghana (Jubilee), Angola (Blocks 17 and 31) and Brazil (Tupi) to undertake FIDs by H2 2010 at the latest. Accelerated investment in the Gulf of Mexico and the Caspian will predominantly be a function of the 2010 capital budgets decided upon by IOCs across Q4 this year. Note that whilst Canada oil sands is expected to continue to decline across our forecast horizon, the Kearl project should see the next phase of its expansion underpinned by Exxon’s ambitious $7.5bn plan over the next 4 years.

Page 36 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 63: Global outlook

450 420 390

... 360 SE Asia -5% 330 300 S. America -4% 270 240 Russia -5% Canada Heavy Oil - 210 12% 180 N. America -6% 150 120 Middle East -5% Global E&C capex (US $ bn) (US capex E&C Global 90 Europe -8% 60 Caspian 7% 30 Africa 10%

2006 2007 2008 2009E 2010E 2011E

Source: Deutsche Bank & Wood Mackenzie estimates. National oil companies with their own agendas Countries such as Angola, UAE, Saudi, Qatar, Brazil and China, that are deploying a significant portion of their resources and people into oil and gas related activities, will not operate under IOCs’ commercial consideration and the aforementioned bottlenecks surrounding FIDs. Amongst others, Gazprom, Petrobras, Sonangol and ADNOC will need to increase their total spend from 2010 to achieve their targeted production growth. There is of course a counter- argument that an uncertain macro outlook could discourage further investment by governments into oil- and gas-related projects, as they seek opportunities in alternative industries that may offer more attractive returns or where there are social needs. Equally with global credit facilities still relatively tight particularly in the emerging nations, NOCs may be forced to abandon projects to preserve cash. Whilst the balance of these dynamics remains unclear to us, we show below that NOC participation appears to have stablised.

Figure 64: NOCs will represent c. 40% of global capex by 2011

440 40% 420 39% 400 38%

n 380 37% 360 340 36% 320 35% 300 34% 280 33%

Global E&C capex E&C Global $b 260 32% 240 220 31% 200 30% 2006 2007 2008 2009E 2010E 2011E

IOC + NOC NOC % of total spend

Source: Deutsche Bank & Wood Mackenzie estimates.

Deutsche Bank AG/London Page 37 7 December 2009 Oil & Gas European Oil Services

Analysis of contracts awarded by NOCs (either alone or in collaboration with each other) in Whilst IOCs may prolong figure 65 confirms the above trend. ONGC, SINOPEC, CNOOC and Petrobras are some of the investment decisions for NOCs that we believe will emerge as key players in the longer term demand for oil services. reasons outlined above, we Whilst IOCs may prolong investment decisions for reasons already outlined above, we argue argue that the structural that the structural increase of NOC investment could set a floor to prices that IOCs will have increase of NOC investment no choice but to accept. could set a floor to prices that IOCs will have no Figure 65: Pure NOC investment (NOCs working alone or with each other) will emerge choice but to accept. as a key constituent of oil services’ backlog longer term making them potentially a ‘price setter’ in the context of a global capex recovery

250 30%

200 25%

150 20%

100 15% % NOC

50 10% Count of contracts awarded of contracts Count

0 5% 2004 2005 2006 2007 2008 2009

NOC IOC Mixed consortium % NOC (RHS)

Source: Deutsche Bank

Page 38 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services E&C industry dynamics and relative profitability

With the exception of the We combine our projections in the last section with strategic analysis of the segment Middle East, other regions to derive our absolute and relative outlook of profitability across the E&C complex. The highlighted in our previous themes we believe will provide out-performance (in terms of capex and margin) across section are more difficult to the near to medium term are frontier developments, Middle East, LNG (and associated infrastructure) and engineering and project management. Shallow water/conventional apply strategic analyses on OPEX and deepwater facilities/FPSOs/subsea both share impressive capex outlooks given each will comprise an but against the potential of excessive margin decline near term this leaves us with a array of different industries broadly neutral view. Themes we expect will under-perform are shallow and services water/conventional CAPEX, oil sands and refining and petrochemicals.

Given company management’s general lack of guidance regarding the level of pricing that has been achieved on more recently signed contracts and the apparent lag on company profitability (we show it can be anything up to three years) we believe this places downside risk on our renewed margin forecasts (which, on aggregate, assumes some contraction across 2009-12). Variations to this trend will clearly depend on each company’s ability to differentiate both within the respective industry and through the operational efficiencies, strategy and business model underpinning it. We expand on this in the next section.

The ‘invisible’ time lag places downside risk on 2010 margins Forecasting the rate of margin expansion/contraction for each company and its respective sub-segments is difficult given the European E&C contractors will generally recognise profits across the life of the project with little or no disclosure regarding the pace and level of margin and contingency released. Figure 66 below shows that the bulk of the profits booked on a contract will typically occur during the latter half of a project.

Figure 66: Typical profit recognition on a capex project linked to the pace of physical completion of the development (terms explained in Appendix S)

14 % 0.6 Absolute percentage contribution from each phase 0.5 31% d

0.4

24% 0.3

0.2 20% Total installed cost (TIC) re-base

0.1 7% 5%

0.0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Month

Front end engineering Project management contract (PMC) Detailed engineering

Procurement (m) Construction (m) Installation (m)

Source: Deutsche Bank; m = management;

Deutsche Bank AG/London Page 39 7 December 2009 Oil & Gas European Oil Services

We leverage our database of contracts to show in figure 67 how the average contract life across the E&C group has changed over time. We exclude the drilling segment given that day rates signed on vessels will generally not vary and possess different terms and conditions.

Figure 67: Average contract term length since 2004 for the group appears to be rising

3.2 3.1 3.1

3.0 2.9 2.9 2.9 2.9 2.8 2.8 2.7

2.7 Average contract duration 2.6

2.5 2004 2005 2006 2007 2008 2009YTD

Source: Deutsche Bank, Company data; Note: *The above analysis is based on contracts disclosed by companies in their press releases 2004-09 YTD and weighted by value. In the cases of Amec and Wood Group contract count has been used in place of monetary weighting given values are not reported for all contracts

Figures 67 and 68 suggest that the current earnings lag for the sector could be anything up to three years from the point of contract award. Note that the nature of the contract be it lump sum or cost plus and also the industry and type of service offered (e.g. opex vs. capex) will determine the full extent of this dynamic by company. Nevertheless the result is that despite the sharp fall in commodity prices across 2008/09, margins, on aggregate for the sector continued to remain steady throughout Q4’08-Q2’09.

Figure 68: Given the profit lag linked to longer term contracts, the sharp fall in commodity prices across 2008/09 should see a delayed reaction to bottom lines across the E&C players on aggregate

80% 105

95 60%

85 40%

75 20% y/y change y/y 65 Oil price ($)

0% 55

-20% 45

-40% 35 2004 2005 2006 2007 2008 2010E 2011E 2009 Q12009 Q22009 Q32009 2009 Q4E2009

Offshore construction avg. EBIT margin change (LHS) Onshore construction avg. EBIT margin change (LHS) Avg. Brent oil price (RHS)

Source: Deutsche Bank, Company data

Page 40 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Given it is unclear what level of pricing has been achieved on more recently signed contracts and this apparent lag on company profitability we believe this places downside risk on our estimates (which already assume some degree of margin contraction). Exceptions to this trend will clearly depend on each company’s ability to differentiate both within the respective industry and through the operational efficiencies, strategy and business model underpinning it. We expand on this in the next section.

Profitability outlook for the E&C sector: mixed performance As with previous years we form a strategic analysis of the industry segments (margin derivation detailed in Appendices Q and R) and combine this with our Wood Mackenzie forecast for capex to derive our absolute and relative outlook of profitability by theme. The relative levels of margin contraction are intuitively based on the structural differences of each industry e.g. level of complexity, barriers to entry, number of players and also the quality and degree of asset intensity it carries. We show this below in figure 69

Figure 69: Current expectations for revenue and margin 2009-11E

Decrease in 30% capex momentum Deepw ater 25% vs. 2008 study subsea 20% Deepw ater 15% Facilities Shallow water 10% LNG (opex) Refining & 5% Petrochemicals 0% Frontier Regas Developments -5% Middle East -10% Shallow water (capex) -15%

Onshore -20% Average capex growth 2009-11E Oil Sands Upstream GTL -25%

-30%

Negative margin outlook vs. 2008 study -35% -40% -350 -300 -250 -200 -150 -100 -50 -

Absolute margin dow nside 2009-11E(bps)

Source: Company data, Deutsche Bank & Wood Mackenzie estimates With the above in mind, we highlight below which themes should outperform/underperform across the oil services chain across 2010/11:-

Shallow water/conventional CAPEX (underperform): margin compression based on the structural weakness of this theme coupled with a marked slowdown in capex (despite continued activity in sprint to market projects).

Oil sands (underperform): poor capex outlook together with significantly lower margins based on weak/supply demand fundamentals in Canada (comprises the bulk of oil sands activity).

Shallow water/conventional OPEX (in-line): positive outlook in spend offset by structural weakness of industry not helped by various contract clauses that gives the client an option to change the fee structure and/or contractor itself (new entrants have accelerated over the last 12 months).

Deutsche Bank AG/London Page 41 7 December 2009 Oil & Gas European Oil Services

Deepwater facilities/FPSOs and susbea (in-line): our positive outlook will be offset by a continued decline in margins, the pace and scale of which remains difficult to gauge. However, company asset quality should drive differentiation meaning that this decline will vary across the group. We expand on this in the next section.

Middle East (outperform): moderate margin decline set against a relatively attractive capex outlook (with reference to the regions highlighted in the previous section) places the Middle East in our top tier of performers. We caution however that increased competition (from the Koreans and Chinese) together with tougher contractual terms poses downside risk on margins.

Frontier developments (outperform): whilst investment in the FSU has historically been bottlenecked around geo-politics we expect a renewed appetite across 2010/11 driven by STM projects followed by FIDs longer term. The high barriers to entry particularly on the complex and harsh environment developments should see margins relatively more resilient.

LNG and associated infrastructure investment (outperform): our positive outlook on this theme coupled with our expectation of a modest decline in margins (structurally robust industry) makes it an attractive theme.

‘High-value’ engineering and project management (outperform): we argue below that the margins realised in the engineering segment will remain resilient due to its structural characteristics and that it will continue to be a sweet spot across the oil service chain. Note it is impossible to derive a capex figure (hence its omission in figure 69 above) given this is a theme that will serve as a function across the entire energy chain. Structural shortage of ‘high value’ (defined as highly technical) engineers and project We argue that the margins managers will continue mid-term. Engineering and in particular project management skills realised in the engineering are one of the least commoditised services across the energy complex primarily given it and project management draws on experience and know how which sits with the older generation of engineers. industry will remain intact Experience in project management and an understanding of how to run projects on time and as demand for these skills budget driven by superior design, tools and systems is valuable to every energy company. grow against a structural Below we analyse the global demographics and absolute number of engineers employed across time and the entire energy segment. Note the underlying data has been sourced from shortage of supply various organisations including the SPE (Society of Petroleum Engineers) and National Science Board of USA.

Figure 70: Global demographics of specialised Figure 71: Net number of (US) engineers and project engineers* – 40% are above 45 years old (where the managers employed by the Energy industry* has majority of project management expertise sits) dramatically slowed since 1990

2.5

2.0

1.5

1.0 Engineers (mn) employed

ears of experience 0.5 Y

0.0 30 40 50 60 1950 1960 1970 1980 1990 2000 2010E Age 2005 2010E

Source: Schlumberger, Society of Petroleum Engineers, Project Management Institute, American Society of Source: Schlumberger, Society of Petroleum Engineers, Project Management Institute, American Society of Civil Engineers, National Society of Professional Engineers; *Energy companies and contractors Civil Engineers, National Society of Professional Engineers; *Energy companies and contractors

Page 42 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 70 above shows the demographic profile of engineers globally and the deteriorating level of more experienced project management (classified broadly as above 40 years old) over time. This has not surprisingly been driven by the lacklustre growth in recruitment since broadly the mid 1990s (illustrated in Figure 71). Contractors have traditionally treated engineering as a ‘loss leader’ (arguably to a lesser degree in the more complex and technically challenging areas of energy) in that it is a means to get the larger EPIC contract We argue that Energy where procurement, construction and installation are the most profitable segments. This, in companies will be least part, explains why over the years the market for engineering and project management reluctant to cut corners services became tighter – as engineering skill and training gravitated towards the more across the engineering commercial and specialised parts of the oil life cycle. design phases of a project development given Demand for specialised engineering and project management services expected to a) They will prefer to partner grow. Below we list some of the dynamics we believe will underpin the demand for this with engineering excellence theme

(history has shown that poor Against a backdrop of lower and more volatile commodity prices, IOCs in particular will design and project be under pressure from their shareholders to execute their current projects successfully management will lead to not least to ensure they meet IRR targets. spiralling costs further on IOC projects are getting more complex (as highlighted in the last section, access to and ultimately delays in reserves are predominantly situated in the deepwater as well non-conventional basins) – production) and this is driving the need for more technical based engineering and project management b) It represents a small excellence. portion of the total project In the context of FID delays, IOCs will continue to invest in optimising the engineering cost as shown in figure 66 design ahead the ultimate award (on complex projects particularly this has led to an above. overall decline in the estimated cost e.g. Gorgon)

Given the slowdown in FIDs and the potential impact this will have on reserve replacement mid-longer term, IOC and NOCs have placed greater emphasis on increasing productivity of their existing oil and gas portfolios.

Energy companies generally prefer to tender the FEED contract separately from the rest of the project phases to ensure that the contractor is offering an objective solution not linked to an internal product that could potentially be used in latter parts of the development. Having shed the bulk of their engineering resource across the last two decades, Energy companies are arguably left with no choice but to rely heavily on service companies to achieve the above. The structural nature of this theme is also linked to the fact that it is not asset intensive and less commoditised. We believe energy companies, whilst expecting contractors’ mark up on their engineers to come down will not be as aggressive as perhaps elsewhere in the oil service chain. This will particularly hold for those contractors that can differentiate in the quality and experience of their engineers and project managers given they are less transactional and have more a value/relationship based service offering. This is in contrast to, for example, procurement, installation and construction, which is asset intensive, more transactional/commoditised and where short-term supply/demand dynamics and levels of contingencies would have made margins far more cyclical across the last few years. This is shown below in Figure 72, which depicts the range of engineering margins vs. other parts of the oil service chain.

Deutsche Bank AG/London Page 43 7 December 2009 Oil & Gas European Oil Services

Figure 72: Engineering margin is less cyclical than more commoditised parts of the oil service chain such as installation and construction*

20.0% 20.0%

18.0% 18.0%

16.0% 16.0%

14.0% 14.0%

12.0% 12.0%

10.0% 10.0%

8.0% 8.0%

6.0% 6.0%

4.0% 4.0%

2.0% 2.0%

0.0% 0.0% 2005 2006 2007 2008 2009E 2010E 2011E 2012E

Margin range of sector* Engineering margin **

Source: Deutsche Bank; Company data, *excludes drillers; ** Average of Amec’s and Wood Group’s margin

Page 44 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Implications for companies’ earnings outlook 2010 and beyond

In this section, we place each company’s industry and regional ‘blueprint’ against our global exploration and E&C projections outlined above. Together with our unique framework that differentiates companies on a number of metrics we model the company’s earnings outlook to 2012 (forecast horizon has been extended from 2011).

On aggregate, we forecast topline growth for the group (9% compounded 2009-12E) against a more cautious outlook on margin (c. 75bps reduction in EBITDA margin). Net, our 2009-12 average earnings outlook for the sector is 8%. We believe Saipem, Amec and Seadrill are optimally placed across the oil services chain and demonstrate superior earnings growth. Those appearing at the weaker end of the industry spectrum based on their relatively poor positioning and business model include Wood Group, Aker Solutions and Subsea 7.

i. Company positioning across the exploration and E&C service spectrum In Figure 73 this is demonstrated, albeit somewhat superficially by showing the companies’ topline ‘blueprint’ across the energy services chain. Our estimate of each company’s absolute exposure is given as a percentage of 2010E group revenue and is based on conversations with management, application of our contract database and the use of divisional splits where given. Note the industry ranking shown along the right of Figure 73 is based on our assessment of capex and margin in the previous sections and these dynamics are considered together. Regional ranking is based on our assessment of capex alone given it is more difficult to apply strategic analysis (each region will comprise a different array of industries and services). Other assumptions are listed below.

Deutsche Bank AG/London Page 45

Page 46 Page 46 Oil Services European Oil&Gas 7 December2009 Figure 73: Company positioning by theme (X=under-performer, XX=neutral, XXX=out-performer)

Aker Estimated segment Acergy Amec Lamprell Petrofac Saipem Seadrill Subsea 7 Technip Tecnicas Wood Group DB outlook 2010-12E Solutions capex 2010E ($ bn)

Onshore drilling 6% X

Shallow water drilling 1% 31% X Exploration and appraisal: drilling services 76 Deepwater drilling XX 7% 55% Ultra deepwater drilling XXX

Surface servicing 7% 8% 41 X

Surface equipment 20% 29 X Exploration: associated well head services Subsurface servicing 7% 4% 27 X

Subsurface equipment and products 6% 68 X

Newbuiilds 22% 3 X

Exploration: Energy Upgrades 60% 2 construction services XXX

Others 6% 4 XX

Onshore/offshore operations and 10% 5% 16% 26% 5% 5% 12% 10 maintenance (OPEX) XX

Deepwater SURF 65% 23% 20% 67% 35% 10% 9 XX

Deepwater Facilities 10% 4% 12% 4% 8% 7% 33 XX

Shallow water SURF/facilities 25% 10% 4% 4% 28% 7% 5% 76 X

Frontier Developments 5% 4% 10% 12% 15 Engineering & Construction XXX services LNG 5% 14% 20% 5% 7 XXX

Re-gas terminals 5% 7 X

Refining & petrochemicals 5% 10% 15% 70% 8% 36 X

Onshore facilities & infastructure 5% 4% 64% 17% 10% 20% 16% 161 X

Gas to liquids 3 X

Heavy Oil sands: extraction 12% 5% X 10 Heavy Oil sands: refining 5% X

Non oil and gas Power 17% 19% XX

Process and others 12% 40% X

Deutsche Bank AG/London Deutsche Bank Total (100%) (100%) (100%) (100%) (100%) (100%) (100%) (100%) (100%) (100%) (100%) $ 616 bn

Group revenues 2010E ($bn) 2.2 9.8 4.8 0.4 4.2 15.7 3.8 2.2 8.7 4.8 4.6

"High - value" engineering and project XXX management (darkest shade = pure play)

Source: Deutsche Bank, Company data

Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009 Figure 74: Company positioning by region (X=under-performer, XX=neutral, XXX=out-performer)

Tecnicas Estimated E&C DB outlook 2010- Acergy Aker Solutions Amec Lamprell Petrofac Saipem Seadrill Subsea 7 Technip Wood Group Reunidas capex 2010E ($bn) 12E

Africa 37% 2% 1% 26% 51% na 29% 19% 6% 2% 49.6 XXX

Middle East 4% 2% 9% 28% 15% na 42% 33% 3% 48.0 XXX

Russia/FSU/Caspian 23% 1% 3% 10% 7% na 2% 10% 1% 41.3 XX

Europe 33% 40% 34% 10% 24% 12% na 29% 10% 37% 29% 30.8 XX

North America 5% 5% 45% 73% na 7% 7% 38% 79.5 X

South America 18% 5% 12% na 28% 7% 3% 12% 31.1 XXX

SE Asia 7% 21% 5% 5% 12% 3% na 7% 8% 11% 10% 76.9 XXX

Canada (Heavy Oil) 12% na 5% 5% 10.0 X

(Total) (100%) (100%) (100%) (100%) (100%) (100%) na (100%) (100%) (100%) (100%) ($367bn)

Group revenues 2010E 2.2 9.8 4.8 0.4 4.2 15.7 3.8 2.2 8.7 4.8 4.6 ($bn) Source: Deutsche Bank, Company data

Assumptions behind figure 73 – Company positioning by theme:

Amec: Earth & Environmental and Process divisions have been included under ‘Non oil and gas’ segment.

Petrofac: Energy Developments division has been excluded.

For the drilling segment, % detailed reflects average of 2009-12 revenue share (so as to capture backend loaded newbuild program).

Wood Group: GTS division has been included under Power.

‘Exploration: associated wellhead services’ capex encompasses exploratory, appraisal and development activities.

Global 2010 capex forecast of $616bn excludes seismic capex of $15bn. Assumptions behind figure 74 – Company positioning by region:

Petrofac: Energy Developments division has been included.

Seadrill: rigs are deployed all over the world and are not allocated to a specific region. Page 47

7 December 2009 Oil & Gas European Oil Services

ii. Review of our ‘fitness’ league table for the Euro OFS Figure 75 below is an update of our framework initiated in January 2009 which leverages our exhaustive contract and asset database to access the Euro Oil Services. We have added two more company metrics:-

Execution capability: whilst this is a subjective assessment of each company’s ability to deliver, we base it on managements’ track record of performance (including anecdotal evidence of project failure if and when they were not listed on the stock market).

Asset quality/differentiation: we differentiate asset intensive companies by their relative and absolute exposure to superior types of vessels. For the offshore drillers this will be represented by ultra-deepwater drilling capability and the latest generation of rigs that are also younger (in contrast to shallower water, older assets). For offshore E&C companies this will be in the form of a ‘multi-purpose’ ship that possesses all or some of the following characteristics: heavy lift capacity, rigid and flexible pipe-laying, wide range of pipe diameter that can be installed, accommodation units, local content and yard space (in order to accommodate the asset) and pipe-laying depth potential (e.g. ultra- deep). In Appendix I we detail each company’s fleet with a focus on these capabilities that together on single vessel should yield a superior return given its high barriers to entry (multi-purpose assets are expensive to build and highly complex). Finally, we differentiate asset light companies by the degree of specialised engineering and project management resource and/or fabrication complexity.

Figure 75: Revised ‘fitness’ league table for the Euro oil services 2010 outlook (X= low; XXX = high) NOC Asset quality/ Backlog Asset/ resource Diversified Balance sheet Contract Execution Overall exposure differentiation longevity* utilisation risk** *** strength**** strategy***** capability 'fitness' level ****** *******

Saipem XX XXX XXX XXX XXX XXX XXX XXX 23 Amec XXX XXX XXX XXX XX X XXX XXX 21 Seadrill XXX XXX XX X XXX XXX XXX XXX 21 Technip XX XXX XX XXX XXX XX XX XXX 20 Tecnicas Reunidas XX XXX X XXX XXX XXX XXX X 19 Petrofac XX XXX XX XX XXX XX XXX X 18 Lamprell X XX XX XXX XXX XX XXX X 17 Acergy XX XX X XX XXX XX XX XX 16 Wood Group XX XX XX X X XX XXX XX 15 Aker Solutions XX XX XX X X X XX XXX 14 Subsea 7 XX XX X X XX XX XX XX 14 Source: Deutsche Bank; * Average of 2008/09. Refer to Appendix J for details, **X contribution to overall fitness is inverted. Refer to Appendix K for detailed analysis; ***Refer to figures 73 and 74 for details, **** Refer to Appendix L for gearing analysis, *****Average of 2008/09. Refer to Appendix M for detailed analysis of contract schedules of companies; ******Average of 2008/09. Refer to Appendix N for details; ******* Refer to Appendix I for detailed analysis of companies’ offshore fleet . We combine the above metrics and place an equal weighting to each to arrive at an overall measure of ‘fitness’ for the company. Each of these assessments should not be viewed stand alone but collectively will form a basis of differentiation. Note the logic behind their choice is expanded on in our note titled ‘Clean Slate’ published Jan’09.

Our renewed earnings outlook: 8% growth (2009-12E) for the group Whilst the outcome of analyses i) and ii) is not necessarily easy to quantify they serve as a critical tool in terms of:

Understanding the drivers behind our company earnings forecasts and current revisions,

Page 48 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Capturing some of the downside risks associated with the current macro and credit environment (and more specifically its impact on the rate of topline and margin change) and in turn,

Justifying the valuation discount/premium each company should trade on relative to our sector benchmark. We expand on this further in the next section (company overview and key recommendations). We detail the implications of our industry and company analyses in figures 76 and 77 below which shows a summary of our earnings adjustments and outlook. Note we have extended our forecast horizon to 2012.

Deutsche Bank AG/London Page 49

Changes to forecasts 2009E-12E growth/(decline) outlook Outlook summary (based on conclusions from figures 73-75) Revenue change EBITDA margin change Revenue EBITDA margin Page 50 Page 50 (%) (bps) growth/ decline Oil Services European Oil&Gas 7 December2009 movement Basis to revenue outlook Basis to margin outlook (CAGR Figure 76: Summary of earnings adjustments and outlook summary (09E-12E) (bps) 09E-12E)

Net income Net income growth/ change (%) decline (CAGR 2009E 2010E 2011E 2009E 2010E 2011E Avg. 2009-11E 09E-12E)

Lag effect of lower priced STM contracts signed on assets that are structurally weaker (mid-tier) should see acute margin compression near to medium term. Expect margins to Robust backlog cover (62%) for 2010 drivenstabilise from a lower base. Reasons why they should remain by STMs (86% of 2009 contracts won) seesrelatively depressed (even if FIDs occur faster than expected) limited downside risk on 2010 consensus. DBare due to i) increasing supply of mid-tier assets (ship Acergy 3.9% 0.0% 0.9% 111 127 54 -7.6% 5.5% 12.8% -351positive outlook on deepwater SURF should conversions emerging from Asia and Europe) coming online drive impressive revenue recovery 2011/12.across 2011/12 ii) lower contingencies in contracts than Upside risk linked to FIDs accelerating earlyprevious years (in part due to IOC/NOCs reluctance to revert 2010 (vs. DB expectations of H2). to peak-cycle terms and conditions) iii) lower priced STM contracts still being executed upon across 2010-11 (average contract life: 2.7 yrs).

DB positive outlook on E&PM, frontier developments and deepwater subsea should drive robust backlog cover (in 2009: Relatively high exposure to engineering and project 73%/23% STM and FEED respectively). management coupled with high asset quality (manufacturing Lacklustre group outlook linked to relativelyof subsea and installation vessels) should see margins stay Aker 0.0% 0.7% -5.1% 0 25 -7 -0.8% -4.2% 1.4% -87low market share across the oil services chainrelatively resilient helped also by implementation of Solutions (exception being subsea, products and impressive operational efficiencies. technologies), slow down in manufacturing products and technologies and process segments.

Diversification beyond oil and gas and expansion into new markets as well as Engineering and project management exposure coupled with AMEC 0.0% 0.0% 0.0% 0 0 0 0.0% 12.9% 8.5% 35increasing market share are all positive driverspositive impact of operational efficiencies and KPIs in of topline. High absolute exposure to contracts should help grow margins. engineering and project management.

Increase in revenue forecast linked to expectation of new contract signatures Margin contraction linked to weak supply/demand particularly in Middle East newbuild and fundamentals (Asia yards under-cutting price). However, high general energy infastructure (windfarms - see barriers to entry in Middle East and strong relationships with Lamprell 6.4% -1.1% 12.1% -8 50 50 6.7% 10.3% 11.6% -42Appendix P which gives an industry outlook clients should see margins stabilise from a lower base. on regional capacity expectations) - driven by DB positive outlook on energy construction services.

Robust backlog cover driven by FIDs awardsMargins expected to stay relatively resilient. However, risk of this year that should see limited risk on 2010poor execution on lump sum contracts and potential of more Petrofac -0.4% -11.5% -0.2% -155 -151 -369 -5.7% 15.0% 15.0% 79consensus. DB positive outlook on Middle aggressive pricing from Asian contractors in the region places East should drive impressive revenue growth.downward pressure on long term margins.

Offshore construction margins will remain resilient given relatively high asset quality anddifferentiation. Uplift in 2012 Diversification across drilling and E&C drives based on new assets coming online that should generate sector leading backlog cover for 2010. Top higher returns given their complexity and multipurpose three market share in several DB preferred capability (yields better economies of scale to client).

Deutsche Bank AG/London Deutsche Bank segments and regions (50% of 2009 contract Saipem 0.0% -0.5% 4.9% 0 -25 -70 -0.8% 9.8% 5.8% 137 Onshore construction margins will be robust given high wins are FIDs and we believe this relative mix exposure to engineering and project management. Offshore will be maintained) should drive impressive drilling margins should increase as higher DBe day rates are revenue growth. crystallised on Saipem rigs coming off contract.

Source: Deutsche Bank

Changes to forecasts 2009E-12E growth/(decline) outlook Outlook summary (based on conclusions from figures 73-75) Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009 Revenue change EBITDA margin change Net income growth/ Revenue EBITDA margin Figure 77: Summary(%) of earnings(bps) adjustments and outlookdecline summarygrowth/ continued….. decline movement Basis to revenue outlook Basis to margin outlook (CAGR (CAGR (09E-12E) (bps) Net income 09E-12E) 09E-12E) change (%)

2009E 2010E 2011E 2009E 2010E 2011E Avg. 2009-11E

Sector leading backlog cover linked to long High absolute exposure to deepwater should support margins term drilling contracts. Postive DB outlook on Seadrill 0.0% -0.1% 0.0% 0 -3 1 -1.2% 20.9% 14.4% -33 longer term underpinned by our positive outlook on day rates deepwater should see utilisations remain in this segment. robust longer term.

Lag effect of lower priced STM contracts signed on assets that are structurally weaker (mid-tier) should see acute margin compression near to medium term. Expect margins to Robust backlog cover (57%) for 2010 driven stabilise from a lower base. Reasons why they should remain by STMs (91% of 2009 contracts won) sees relatively depressed (even if FIDs occur faster than expected) limited downside risk on 2010 consensus. DBare due to i) increasing supply of mid-tier assets (ship Subsea 7 5.7% 0.7% 0.0% 115 54 69 6.6% 0.8% 8.1% -376 positive outlook on deepwater SURF should conversions emerging from Asia and Europe) coming online drive impressive revenue recovery 2011/12. across 2011/12 ii) lower contingencies in contracts than Upside risk linked to FIDs accelerating early previous years (in part due to IOC/NOCs reluctance to revert 2010 (vs. DB expectations of H2). to peak-cycle terms and conditions) iii) lower priced STM contracts still being executed upon across 2010-11 (average contract life: 3.3 yrs).

Diversification across E&C drives robust Combination of mid and high tier assets means that there will backlog cover (67%). Top three market sharebe some lag effect of lower priced STM contracts on assets in several DB preferred segments should that should yield lower margins in subsea. High level of complexity (through superior technologies and engineering) Technip 0.5% 8.9% 5.0% 52 -77 8 4.2% -0.1% 4.2% -136 drive impressive revenue growth (of 2009 contracts: 52% STMs, 10% FIDs, 38% should see robust margins in onshore and offshore segments. FEEDs - we believe this relative mix will be Overall, we expect margins to stabilise from a (moderately) maintained) lower base.

Robust backlog cover driven by FIDs awardsMargins expected to stay relatively resilient. However, risk of Tecnicas this year that should see limited risk on 2010poor execution on lump sum contracts and potential of more 0.0% 0.0% 0.0% 0 0 0 0.0% 12.7% 11.7% 0 Reunidas consensus. DB positive outlook on Middle aggressive pricing from Asian contractors in the region places East should drive impressive revenue growthdownward pressure on long term margins.

Well support segment geared to US rig count;Lower mark up on engineering and project management we assume more exxagerated decline in against a higher fixed cost base(initiatives around operational 2009 and slow recovery in 2010/11. GTS efficiencies remain limited) drives margin contraction 2009-11 business weaker than expected due to slow and relative underperformance vs. comparable peers (whom down in orders linked to macro environmentare - forecasted to grow margins near to medium term). We Wood Group -7.0% -13.7% -12.5% -14 -100 -96 -25.7% 1.2% 2.1% -62 outlook remains lacklustre. High absolute expect margins to stabilise in GTS and Well Support divisions exposure to engineering and project albeit from a lower base. With regards to the latter, reovery management should help drive recovery in tied to pace of pick up in US rig count - we expect moderate 2011/12. Near term however, we expect thisEBIT growth 2009-12. division to underperform peers.

Group 0.8% -1.5% 0.5% 9.1 - 9.0 - 32.6 -2.2% 7.7% 8.7% -76 average

Source: Deutsche Bank Page 51

7 December 2009 Oil & Gas European Oil Services Sector valuation and company winners and losers

Valuation –sector target multiple moved from 2010 to 2011; we continue to argue for a discount against historical multiples Our 2011E EV/DACF for the sector is currently 7.0 (market cap-weighted) which represents c. 33% discount to the sector’s historical average (2000-08) of 10.5x. Given the decline in both exploration and E&C capex we expect over the near to medium term against what appears to be a slowing in earnings momentum (see figure 78 below), we believe that our target sector multiple (2011) should trade at a discount to historical multiples.

Figure 78: The sector remains in growth territory despite earnings momentum slowing

70%

60% 59%

50% 47% 40%

30% 27% EPS CAGR % 20% 8% 10% 5% 8% 0% 2004-07 2005-08 2006-09 2007-10 2008-11 2009-12

Source: Deutsche Bank Estimates At the industry level, based on our analysis above we believe the risk (primarily execution and On balance we argue that margin compression)/reward (primarily revenue) trade off has shifted more into ‘equilibrium’. our sector target multiple However, in light of the lack of visibility surrounding FIDs nearer term linked to the risk of renewed deterioration at the macro level, on balance we argue that our sector target multiple should trade at a 20% should trade at a 20% discount to the historical average (vs. -50% previously). Improved discount (vs. -50% cashflow visibility to the end of the decade (fuelled by robust sector backlog) coupled with a previously) to the historical general improvement in execution and risk sharing between the contractor/client justifies average why we believe this sector should not trade at a deeper discount to historical multiples.

Page 52 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 79: Sector EV/DACF* Figure 80: Company 2011E EV/DACF (sector target: 8.4x)*

11 European historical average Target sector multiple (2011x) 14.0 (2000-08) 10 12.0 9 10.0 8 8.0 7 2011 EV/DACF

EV/DACF 6.0 6

4.0 5

2.0 4

0.0 AMEC Aker Saipem Seadrill Acergy

2008 2009E 2010E 2011E 2012E Technip Lamprell Petrofac Tecnicas Solutions Reunidas Subsea 7 Wood GroupWood Source: Deutsche Bank and company data Source: Deutsche Bank and company data Our implied price targets are supported by our DCF valuation in which we assume ‘peak’ company earnings in 2012 with subsequent linear fade to our mid-cycle scenario in 2015. We have lowered our company discount rates to reflect the reduced market risk premium as well Note our valuation of the as the relatively lower cost of debt vs. last year’s study. We detail changes in company European oil services uses a WACC in Appendix A. This in part drives our price target changes on our universe of stocks combination of earnings and (summarised overleaf). We assume a long-term growth rate of 3% which is the average mid- cash flow techniques, aided cycle rate since 1990 for the oil services. by DCF valuation as an important sanity check *Comparing these companies on any one valuation metric will never yield a perfect result given their differing asset bases/capital structures/regional tax exposures (in turn related to where along the service chain they operate). We consider EV/DACF to be the ‘lesser of the evils’ given the broadly similar capital intensities and gearing levels across the majority of the companies we follow. Exceptions here would be, for example, Saipem, Wood Group, Aker Solutions, Seadrill and Subsea 7’s current net debt position (vs. remainder of the sector, which is net cash), Amec and Petrofac’s asset-light business relative to peers.

Company-specific overview: winners need to have it all In picking our highest conviction stocks, we look for the following investment credentials:

High relative and absolute exposure to our preferred themes and regions,

Ranked towards the top end of our ‘fitness’ league table,

Impressive earnings potential,

Compelling valuation – we would also argue for a premium relative to the sector if the above all co-exist (equally the reverse if they do not).

Deutsche Bank AG/London Page 53 7 December 2009 Oil & Gas European Oil Services

Figure 81: Company specific overview and price target derivation EPS Current Target +/- Target Implied Company DB New CAGR 2011E to sector 2011E PT DCF Comment Old PT (local fx) rec. PT** (09-12E)* EV/DACF (8.4x) EV/DACF (local)

+ Strong balance sheet, exposure to deepwater SURF, robust Acergy backlog cover for 2010. 6% 7.0 -10% 7.5 93 78 Hold 50 85 (NOK) - Lack of diversification leaves it more vulnerable to delay on FIDs. (10%) Net: argue for 10% discount to sector target (previously -30%).

+ Asset quality/ differentiation, robust backlog cover for 2010. Aker Solutions -4% 8.2 -10% 7.5 66 50 Hold - High relative exposure to regions with greater elasticity to oil price; 40 60 weak track record in execution; poor EPS outlook (NOK) (7%) Net: argue for 10% discount to sector target (previously -40%).

+ Impressive EPS growth; well diversified; high backlog longevity; balance sheet strength; low asset/resource utilisation risk; high asset differentiation; exposure to engineering and project management. 950 AMEC (£) 13% 7.2 20% 10.0 1021 897 Buy 850 - Low NOC exposure; overweight cost plus contract strategy, *** (12%) exposure to oil sands (underperforming theme). Net: argue for 20% premium to sector target (previously 40%). + Relatively high EPS growth; exposure to preferred theme rig construction services; high Middle East exposure; low asset/resource utilisation risk; balance sheet strength. Lamprell 10% 6.8 10% 9.2 241 172 Buy - Lack of diversification; low backlog longevity; low NOC exposure; 185 210 (£) over-concentration on few large contracts leaves company at greater (NA) risk than peers to potential client defaults and late payments. Net: argue for 10% premium to sector target (previously inline). + Impressive EPS growth, high exposure to Middle East & NOCs; absolute value underpinned by energy developments division; low asset/resource utilisation risk. Petrofac 970 15% 6.4 0% 8.4 1213 814 Hold 680 (£) - Energy developments sensitive to oil price risk; lack of diversification leaves it more vulnerable to delay on FIDs; low asset **** (14%) differentiation. Net: argue for in line to sector target (previously -10%). + Impressive EPS growth, strong diversification; exposure to several 10% of our preferred themes and regions, asset differentiation, sector 27 Saipem (E) 8.1 20% 10.0 29 33 Buy leading backlog cover for 2010. 23 (0%) - Risk of delay of new rigs coming online. ***** Net: argue for 20% premium to sector target (previously 60%). + Leading exposure to preferred theme ultra-deepwater drilling; valuation compelling and underpinned by robust backlog; sector Seadrill leading EPS growth, high NOC exposure and backlog longevity. 190 21% 5.6 10% 9.2 253 168 Buy 120 (NOK) - Risk of delay of new rigs, balance sheet strength lowest in peer ****** (10%) group; no room for error leaves it over-exposed to credit risk. Net: argue for 10% premium to sector target (previously inline) + Exposure to deepwater SURF, robust backlog cover for 2010 Subsea 7 1% 9.4 -10% 7.5 78 80 Hold - Lack of diversification leaves it more vulnerable to delay on FIDs, 50 80 (NOK) weak balance sheet, lacklustre EPS outlook (2%) Net: argue for 10% discount to sector target (previously -30%) + Strong balance sheet strength; exposure to several preferred

themes, high technological differentiation; robust backlog cover for Technip (E) 0% 5.5 0% 8.4 63 43 Hold 2010 42 53 - Lacklustre EPS outlook (-6%) Net: argue for inline to sector target (no change) + High exposure to Middle East and premium position in

Tecnicas refining/petrochemicals Reunidas 13% 4.6 0% 8.4 43 45 Buy - Lack of diversification leaves it more vulnerable to delays on FIDs 41 44 in the core segment (E) (7%) Net: argue for in line sector target (previously 50% discount) + Exposure to engineering and project management, relatively well

diversified Wood 1% 10.1 -10% 7.5 218 197 Sell 190 210 Group (£) - Lacklustre EPS outlook; weak balance sheet; M&A potential appears unlikely in our view (11%) Net: argue for 10% discount to sector target (no change) Average 8% 7.0

Source: Deutsche Bank and company data; * Bloomberg consensus EPS CAGR (2009-12E) in brackets below; **taken as avg. of price target implied by relative valuation target multiple and fair value; *** includes SOTP GBp932;

**** includes SOTP GBp885; ***** includes SOTP E20, ****** includes our alternative DCF (leading edge dayrates) of NOK156 and implied PT of NOK194 (at 10% premium to 2010E US drillers’ P/E)

Page 54 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Top picks and key recommendation changes

Saipem, combination of relative valuation, DCF and SOTP drives PT re-rating (from E23 to E27) We argue that Saipem should trade at a 20% premium to our 2011 EV/DACF target sector multiple (8.4x) based on:

A unique strategy and business model that should defend Saipem’s market leading share across the engineering and construction (E&C) industry. Based on this, we believe the company is better placed to win (and successfully execute) contracts, particularly those linked to NOCs that are currently actively tendering (Brazil, Middle East), and IOCs that have sanctioned go ahead on FIDs (in particular the Gorgon project in Australia).

Saipem’s sector leading backlog underpins an impressive growth outlook in the near to medium. Analysis of backlog cover at the industry and company level sees Saipem at a comfortable premium relative to its peers and at record levels vs. history (77% of 2010 consensus revenue is already covered by current backlog vs. 2005-7 group historical average of c. 60%),

Solid ‘backlog longevity’ (longer contract life implies topline visibility) that stands out against most comparable peer Technip - a direct function of Saipem’s unique exposure to (longer term) drilling contracts,

Analysis of Saipem’s asset utilisations (leveraging our expansive database of contracts) implies a robust outlook for vessel activity which given their superior differentiation should support our forecasts for margins both in the drilling and offshore construction segments,

Sector leading execution capabilities: despite a change in the company’s risk profile (we have considered four types of execution risk) linked to an impressive expansion of its industry product offering, the company has consistently delivered; analysis of Saipem’s contract strategy and discipline in bidding supports why we believe it will continue to do so and finally

An asset development program that should yield impressive cashflow generation from next year and fuel group EBITDA growth 2010-12; this should bring the company’s gearing comfortably back towards mid-cycle levels (c. 35% debt/equity). Investing across all parts of the oil services chain should underpin the company’s ability to grow market share particularly in regions that are relatively fertile. Amec, PT 950p (previously 850p), diversified (oil and gas/power and process), sector leading cash yield and robust execution We argue that Amec should trade at a 20% premium to our 2011 EV/DACF target sector multiple (8.4x) based on:

The company’s unique business model is that we believe drives superior earnings visibility. The key components that differentiate include: 1) an operational excellence programme that keeps Amec ‘lean’ and improves efficiencies, 2) optimal balance of capex and opex based activities, 3) ‘cost plus’ contract strategy that significantly reduces the relative risk profile of its earnings and offers margin enhancement through key

Deutsche Bank AG/London Page 55 7 December 2009 Oil & Gas European Oil Services

performance indicators, 4) sector leading backlog longevity, and 5) balance sheet strength.

Amec’s diversification across the oil service chain both by region and by industry that A key differentiator of Amec ensures effective penetration of its engineering and project management resources. vs. its peers is the Taken together with the above this drives leading oil and gas margins (on aggregate) vs. transferability of its the peer group. We also expect it to continue to outperform across 2009-12 (35bps vs. engineering and project our sector average outlook of -75bps). management both within Top quartile EPS growth of 13% CAGR 2009-12 (peer group average 8%); critical to this natural resources and across is the contribution of power and process and environmental divisions that are both its other divisions… exposed to industries driven by factors that extend beyond macro dynamics and commodity prices making them arguably contra-cyclical. …this ensures effective The company’s ‘frontlog’ strategy that should yield increased market share as well as penetration of its resource entry into new markets mid to longer term. This places upside pressure on its top line (as the company grows market share from a low base) and gives it greater scale. Seadrill, PT NOK 190 (previously 120), sector leading ultra- deepwater exposure, superior earnings visibility We value Seadrill using a combination of relative and absolute valuation techniques given the various scenarios of day rates that we have analysed as well as differing sector benchmarks with which to compare it to (US and European sector multiples). Our base-case DCF of Number two market share NOK 168 is modelled around our forecasts for day rates. Alternative scenarios assume a) five- globally in ultra-deepwater year payback and b) leading edge day rates. Seadrill currently trades at a discount (P/E 2010: drilling, our preferred theme 7.8x) to the average 2010E P/E multiple for the US drillers (9.8x). We believe it should trade at across the exploration 10% premium, both to our target sector 2011E EV/DACF multiple and to the US drillers industry… (previously inline) based on:

Seadrill’s high relative and absolute exposure to deepwater drilling. Management’s choice to maintain a degree of rig liquidity in their portfolio, evident in that 2 of its new …however given Seadrill’s deepwater units remain un-contracted (vs. global average of 40%) leaves them with high gearing, we cannot sufficient exposure to further capture leading edge day rates. ignore the risk that if $11bn backlog that fuels sector leading earnings growth (21% 2009-12E CAGR vs. anything goes wrong (be it sector average of 8%): Seadrill possesses excellent visibility in earnings beyond 2012 new rigs being delayed, given a portion of their contracts have terms that run at up to six years. This together existing rigs with additional upside to earnings related to higher day rates being signed should underperforming or issues overshadow the risk surrounding delays in rig new-build delivery. In any case even if with their own financial every rig were delayed by a quarter, we calculate it would have an immaterial impact on instruments), the company mid-term earnings growth. is most at risk financially The company’s US listing in Q1’10 that should help improve investors’ perception of the company’s superior asset quality and deepwater exposure vis-à-vis its US peers. We believe that incremental demand for best in class assets (younger, latest generation of rigs) will re-shape the deepwater market and we expect new rig owners such as Seadrill to gradually displace market share traditionally held by more mature drillers (predominantly US based).

A healthier balance sheet supported by the company’s recent convertible bond (which was over-subscribed) and bridging load facilities. However, given Seadrill’s high gearing, we cannot ignore the risk that if anything goes wrong (be it new rigs being delayed, existing rigs underperforming or issues with their own financial instruments), the company remains at risk financially.

Page 56 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Appendix A: Valuation matrices

Figure 82: European oil services valuation table * Listed Share Target (Expensive) Market cap Market cap E.V. Net debt (2010) 04/12/2009 01:40 RIC Currency price Rec share price /Cheap % (local bn) ($bn) ($bn) (local bn) / Equity (%) / D+E (%) Acergy ACY.OL NOK 87 Hold 85 -3% 16.1 2.9 2.3 -3.1 NA NA Aker Solutions AKSO.OL NOK 73 Hold 60 -18% 19.7 3.5 3.9 2.1 NA NA AMEC AMEC.L £ 825 Buy 950 15% 2.8 4.6 3.0 -0.9 NA NA Lamprell LAM.L £ 189 Buy 210 11% 0.4 0.6 0.5 -0.1 NA NA Petrofac PFC.L £ 987 Hold 970 -2% 3.4 5.6 4.4 -0.7 NA NA Saipem SPMI.MI € 22 Buy 27 23% 9.7 14.6 19.2 3.0 81% 45% Seadrill SDRL.OL NOK 138 Buy 190 38% 54.9 9.8 15.3 30.9 90% 47% Subsea 7 SUB.OL NOK 96 Hold 80 -17% 15.8 2.8 3.1 1.4 23% 18% Technip TECF.PA € 47 Hold 53 12% 5.1 7.7 5.0 -1.8 NA NA Tecnicas Reunidas TRE.MC € 36 Buy 44 21% 2.0 3.1 1.7 -0.9 NA NA Wood Group WG.L £ 308 Sell 210 -32% 1.63 2.7 3.08 0.22 25% 20%

Weighted average/total 13% 57.8 European multiples only EV/DACF (x) Free cash yield (x) ROE* (%) RIC 2008 2009E 2010E 2011E 2012E 2008 2009E 2010E 2011E 2012E 2008 2009E 2010E 2011E 2012E Acergy ACY.OL 13.7 3.7 8.6 7.0 5.0 1.3% 13.2% 7.8% 9.5% 11.8% 36.6% 20.1% 10.4% 14.1% 16.7% Aker Solutions AKSO.OL 6.3 4.4 7.5 8.2 7.4 -16.8% 8.1% 2.6% 2.3% 2.4% 19.8% 21.2% 15.8% 13.0% 13.6% AMEC AMEC.L 14.6 7.4 7.9 7.2 6.3 3.3% 4.9% 6.3% 6.9% 7.5% 15.4% 14.3% 15.8% 15.7% 15.5% Lamprell LAM.L 11.9 4.6 9.1 6.8 5.3 -2.7% 10.4% 6.1% 7.9% 9.5% 50.4% 21.8% 17.1% 19.2% 20.4% Petrofac PFC.L 7.5 7.7 7.7 6.4 5.4 5.0% 6.4% 11.1% 12.6% 13.1% 50.8% 48.8% 48.0% 38.9% 32.4% Saipem SPMI.MI 11.1 8.3 9.6 8.1 7.0 -1.3% -6.2% 1.9% 9.2% 10.6% 27.4% 23.4% 18.3% 19.9% 20.6% Seadrill SDRL.OL 46.2 7.7 8.1 5.6 4.1 -31.0% -7.7% 7.5% 19.0% 22.9% 12.4% 30.2% 24.9% 22.1% 18.3% Subsea 7 SUB.OL 0.8 0.5 11.1 9.4 7.0 -4.4% 6.1% 3.4% 6.6% 8.6% 32.2% 29.5% 15.2% 16.2% 17.4% Technip TECF.PA 4.7 3.5 6.8 5.5 4.5 0.9% 6.4% 6.3% 7.1% 8.4% 19.3% 16.0% 10.6% 11.9% 13.4% Tecnicas Reunidas TRE.MC 9.8 6.2 6.1 4.6 3.7 11.3% 11.6% 12.8% 13.1% 12.0% 61.7% 60.7% 51.5% 44.6% 38.4% Wood Group WG.L 8.8 7.1 9.7 10.1 9.9 1.9% -0.5% -1.4% -2.0% -2.9% 23.9% 15.5% 11.4% 11.5% 11.2%

Weighted average 15.3 6.4 8.4 7.0 5.8 -5% 1% 6% 10% 11% 31.8% 27.4% 21.7% 20.6% 19.8% Euro/US comparitive P/E ratio (x) EV/EBITDA (x) PCF ratio (x) PEG RIC 2008 2009E 2010E 2011E 2012E 2008 2009E 2010E 2011E 2012E 2008 2009E 2010E 2011E 2012E 2010 Europe Acergy ACY.OL 12.6 9.5 27.7 18.7 13.9 5.8 3.2 6.7 5.2 3.7 10.5 4.2 9.1 8.2 6.8 0.6 Aker Solutions AKSO.OL 17.7 7.1 11.7 13.0 11.4 8.8 3.8 5.9 6.5 5.8 -31.5 4.6 8.6 9.9 8.6 -1.2 AMEC AMEC.L 16.4 15.2 15.3 14.0 13.0 6.7 5.5 6.0 5.2 4.5 -253.1 14.2 14.6 13.4 12.4 1.7 Lamprell LAM.L 14.5 7.9 13.8 11.0 9.2 12.6 4.6 8.9 6.7 5.2 73.9 7.2 12.9 10.1 8.3 0.5 Petrofac PFC.L 13.0 11.7 12.7 11.9 11.3 6.9 6.6 6.2 5.1 4.4 6.8 7.9 8.4 7.8 7.5 1.8 Saipem SPMI.MI 14.7 10.7 15.2 12.3 10.4 8.7 6.7 7.9 6.6 5.6 6.5 6.1 7.6 6.6 6.1 0.6 Seadrill SDRL.OL 22.8 5.7 7.8 6.1 5.5 17.0 7.0 7.0 4.9 3.5 27.5 3.8 5.8 4.7 4.3 0.3 Subsea 7 SUB.OL 12.2 6.8 18.0 14.5 11.3 6.6 4.1 8.7 7.2 5.3 6.3 4.5 11.5 10.2 8.1 0.7 Technip TECF.PA 10.8 9.4 17.5 14.9 12.4 3.8 2.6 5.2 4.2 3.5 10.6 5.5 8.9 7.7 6.8 1.0 Tecnicas Reunidas TRE.MC 16.1 10.8 10.9 9.6 8.9 10.8 6.0 5.9 4.5 3.6 8.5 7.8 7.2 7.0 7.6 0.8 Wood Group WG.L 14.1 11.5 16.8 14.9 13.7 7.5 5.9 8.4 8.1 7.8 14.8 17.3 24.0 28.2 36.7 1.3

Euro services average 15.5 9.7 14.4 12.1 10.5 9.0 5.6 6.9 5.6 4.7 -10.8 6.8 9.2 8.6 8.3 0.7 European integrated average 8.0 13.8 11.8 NA NA NA NA NA NA NA NA NA NA NA NA Broader European market 14.1 15.4 12.9 14.8 12.7 7.3 8.2 7.0 7.4 6.7 8.8 9.7 7.7 7.3 7.0 US Large Cap Diversified Average 12.1 22.8 20.6 NA NA 7.7 11.2 10.3 NA NA 8.7 12.3 11.5 NA NA US Mid/Small Cap Service & Equipment Suppliers 11.1 24.7 26.4 NA NA 6.5 9.4 9.2 NA NA 8.0 11.9 11.6 NA NA US Equipment Contractors/Drillers average 7.2 8.7 9.8 NA NA 5.2 6.2 6.3 NA NA 6.0 6.9 6.7 NA NA Global services average 10.3 18.2 17.5 NA NA 6.7 9.3 8.8 NA NA 7.7 10.4 9.9 NA NA Source: Deutsche Bank, Company data, * closing share prices as at Thursday, December 3rd 2009.

Deutsche Bank AG/London Page 57 7 December 2009 Oil & Gas European Oil Services

Figure 83: European oil services financial matrix * Reporting Share Net income (reporting currency m) Growth EPS (local currency) CAGR RIC Currency price 2008 2009E 2010E 2011E 2012E (09-10) 2008 2009E 2010E 2011E 2012E (09-12) Acergy ACY.OL $ 87 277 175 103 153 206 -41% 7.6 5.9 3.2 4.7 6.3 1.9% Aker Solutions AKSO.OL NOK 73 1,540 1,966 1,682 1,512 1,728 -14% 5.7 7.3 6.2 5.6 6.4 -4.2% AMEC AMEC.L £ 825 145 147 180 196 212 22% 43.4 44.1 53.7 58.7 63.4 12.9% Lamprell LAM.L $ 189 94 51 45 57 68 -11% 25.2 16.2 13.7 17.2 20.6 8.3% Petrofac PFC.L $ 987p 265 324 438 469 492 35% 41.7 60.6 77.4 83.0 87.1 12.9% Saipem SPMI.MI € 22 693 705 638 789 933 -9% 1.6 1.6 1.4 1.8 2.1 9.8% Seadrill SDRL.OL $ 138 393 1,012 1,258 1,614 1,786 24% 5.3 15.8 17.7 22.8 25.2 16.7% Subsea 7 SUB.OL $ 96 243 242 156 194 248 -36% 8.2 9.2 5.3 6.6 8.5 -2.7% Technip TECF.PA € 47 448 410 290 342 409 -29% 4.2 3.8 2.7 3.2 3.8 -0.1% Tecnicas Reunidas TRE.MC € 36 137 160 187 212 229 17% 2.45 2.86 3.35 3.80 4.10 12.7% Wood Group WG.L $ 308 252 190 161 182 197 -15% 26.0 23.3 18.3 20.7 22.5 -1.2%

Average -5% 6% Reporting Share Revenues (reported currency m) CAGR EBITDA Margin (%) Increase (bp) RIC Currency price 2008 2009E 2010E 2011E 2012E (09-12) 2008 2009E 2010E 2011E 2012E (09-12) Acergy ACY.OL $ 87 2522 2103 2207 2639 3022 13% 22.7% 19.7% 15.5% 15.0% 16.1% -351 Aker Solutions AKSO.OL NOK 73 58252 56425 54347 54038 58816 1% 5.8% 7.3% 6.8% 6.3% 6.5% -87 AMEC AMEC.L £ 825 2606 2605 2880 3105 3324 8% 9.3% 9.8% 10.6% 10.6% 10.5% 67 Lamprell LAM.L $ 189 741 456 421 531 634 12% 13.5% 13.4% 13.0% 13.0% 13.0% -43 Petrofac PFC.L $ 987p 3330 3538 4619 5009 5386 15% 12.6% 13.3% 15.5% 15.3% 14.1% 79 Saipem SPMI.MI € 22 10094 10244 10422 11173 12130 6% 14.2% 15.3% 15.4% 16.5% 16.7% 137 Seadrill SDRL.OL $ 138 2106 3188 3805 4495 4774 14% 44.1% 57.2% 57.1% 57.5% 56.9% -33 Subsea 7 SUB.OL $ 96 2373 2405 2243 2536 3039 8% 21.9% 20.0% 15.7% 15.8% 16.2% -376 Technip TECF.PA € 47 7481 6434 5764 6999 7281 4% 11.3% 13.1% 11.0% 10.6% 11.7% -136 Tecnicas Reunidas TRE.MC € 36 2487 2747 3179 3571 3824 12% 6.0% 6.0% 6.0% 6.0% 6.0% 0 Wood Group WG.L $ 308 5243 4787 4633 4909 5097 2% 9.8% 8.9% 7.9% 8.0% 8.3% -62

Average 9% 18.0% 20.6% 20.1% 20.4% 20.4% -20 Local Share Cash flow per share (local) CAGR Debt adjusted cash flow per share (local) CAGR RIC Currency price 2008 2009E 2010E 2011E 2012E (09-12) 2008 2009E 2010E 2011E 2012E (09-12) Acergy ACY.OL NOK 87 9.0 13.5 9.6 10.6 12.8 -2% 6.6 12.2 8.2 9.1 11.0 -3.3% Aker Solutions AKSO.OL NOK 73 - 3.2 11.2 8.4 7.4 8.5 NA 17.6 13.5 10.9 9.9 11.2 -6% AMEC AMEC.L £ 825 - 2.8 47.3 56.5 61.6 66.4 NA 33.3 57.8 65.6 70.3 74.7 9% Lamprell LAM.L £ 189 4.9 17.6 14.6 18.8 22.7 9% 28.7 19.3 16.2 20.5 24.5 8% Petrofac PFC.L £ 987p 79.1p 90.p 117.9p 126.6p 131.5p 13% 60.7p 76.p 102.p 108.p 109.6p 13% Saipem SPMI.MI € 22 3.5 2.8 2.9 3.3 3.6 9% 2.5 2.9 3.0 3.4 3.7 9% Seadrill SDRL.OL NOK 138 4.4 24.0 23.9 29.4 32.1 10% 4.6 26.0 26.6 31.5 33.2 9% Subsea 7 SUB.OL NOK 96 15.9 13.7 8.3 9.4 11.9 -5% 13.4 15.2 9.4 10.5 12.9 -5% Technip TECF.PA € 47 4.3 6.5 5.3 6.1 7.0 2% 6.5 5.9 4.5 5.3 6.1 1% Tecnicas Reunidas TRE.MC € 36 4.7 4.0 5.1 5.2 4.8 7% 2.9 2.9 3.3 3.7 na na Wood Group WG.L £ 308 24.8p 15.5p 12.8p 10.9p 8.4p -18% 44.7p 43.2p 36.2p 35.7p 37.7p -4%

Average 5% 5% Local Share Dividend per share (local) CAGR Yield (%) RIC Currency price 2008 2009E 2010E 2011E 2012E (09-12) 2008 2009E 2010E 2011E 2012E Acergy ACY.OL NOK 87 1.2 1.3 0.7 1.0 1.4 2% 1.4% 2.2% 0.8% 1.2% 1.6% Aker Solutions AKSO.OL NOK 73 1.6 2.9 2.5 2.2 2.6 -4% 1.6% 5.7% 3.4% 3.1% 3.5% AMEC AMEC.L £ 825 0.2 0.2 0.2 0.2 0.2 13% 2.2% 2.3% 2.3% 2.5% 2.7% Lamprell LAM.L £ 189 0.1 0.0 0.1 0.1 0.1 33% 0.0% 0.0% 2.9% 3.6% 4.4% Petrofac PFC.L £ 987p 13.7p 21.2p 27.1p 29.0p 30.5p 13% 2.5% 3.0% 2.7% 2.9% 3.1% Saipem SPMI.MI € 22 0.6 0.5 0.5 0.6 0.7 10% 2.4% 3.1% 2.2% 2.7% 3.2% Seadrill SDRL.OL NOK 138 8.69 3.12 11.23 11.23 11.23 NA 7.2% 3.4% 8.1% 8.1% 8.1% Subsea 7 SUB.OL NOK 96 - - - - - NA 0.0% 0.0% 0.0% 0.0% 0.0% Technip TECF.PA € 47 1.2 2.1 1.5 1.7 2.1 0% 2.6% 5.7% 3.1% 3.6% 4.3% Tecnicas Reunidas TRE.MC € 36 1.2 1.4 1.7 - - NA 3.1% 4.6% 4.6% 0.0% 0.0% Wood Group WG.L £ 308 4.9p 4.7p 3.7p 4.1p 4.5p -1% 1.3% 1.7% 1.2% 1.3% 1.5%

Weighted average 3.0% 3.4% 3.4% 3.4% 3.7% Local Share Free cash flow (mn) - local CAGR ROACE (clean before goodwill %) RIC Currency price 2008 2009E 2010E 2011E 2012E (09-12) 2008 2009E 2010E 2011E 2012E Acergy ACY.OL NOK 87 244 1,373 1,256 1,531 1,892 11% 43% 30% 21% 36% 63% Aker Solutions AKSO.OL NOK 73 (4,600) 1,126 520 451 464 NA 20% 20% 16% 13% 14% AMEC AMEC.L £ 825 77 110 175 191 206 23% 63% 57% 66% 73% 80% Lamprell LAM.L £ 189 (19) 26 23 30 36 11% 144% 38% 32% 39% 44% Petrofac PFC.L £ 987p 92 154 372 424 440 42% na na na na na Saipem SPMI.MI € 22 (135) (468) 181 891 1,031 NA 17% 14% 11% 13% 15% Seadrill SDRL.OL NOK 138 (15,494) (2,773) 4,097 10,448 12,577 NA 6% 10% 12% 14% 16% Subsea 7 SUB.OL NOK 96 (732) 628 533 1,034 1,362 NA 25% 20% 13% 16% 20% Technip TECF.PA € 47 43 246 321 361 425 20% 64% 47% 31% 37% 45% Tecnicas Reunidas TRE.MC € 36 250 200 260 266 244 7% na na na na na Wood Group WG.L £ 308 37 (7) (22) (33) (48) NA 20% 14% 10% 10% 9%

Weighted Average 26% 21% 18% 21% 25% Local Share Backlog ($ bn) CAGR Dividend payout (%) RIC Currency price 2008 2009E 2010E 2011E 2012E (09-12) 2008 2009E 2010E 2011E 2012E Acergy ACY.OL NOK 87 2.5 2.7 2.7 3.3 4.0 14% 16% 22% 22% 22% 22% Aker Solutions AKSO.OL NOK 73 10.4 6.9 9.3 - - NA 28% 40% 40% 40% 40% AMEC AMEC.L £ 825 NA NA NA NA NA NA 35% 35% 35% 35% 35% Lamprell LAM.L £ 189 0.6 0.9 1.4 2.0 2.6 41% 20% 22% 40% 40% 40% Petrofac PFC.L £ 987p 4.0 9.9 12.2 13.4 14.5 13% 33% 35% 35% 35% 35% Saipem SPMI.MI € 22 28.1 NA NA NA NA NA 35% 33% 33% 33% 33% Seadrill SDRL.OL NOK 138 10,900.0 NA NA NA NA NA 165% 20% 63% 49% 45% Subsea 7 SUB.OL NOK 96 3.3 3.2 3.5 4.2 5.3 19% 0% 0% 0% 0% 0% Technip TECF.PA € 47 10.9 9.6 13.6 15.0 18.4 24% 28% 54% 54% 54% 54% Tecnicas Reunidas TRE.MC € 36 NA NA NA NA NA NA 50% 50% 50% 0% 0% Wood Group WG.L £ 308 NA NA NA NA NA NA 19% 20% 20% 20% 20% Source: Deutsche Bank, Company data, , * closing share prices as at Thursday, December 3rd 2009.

Page 58 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 84: Key valuation and recommendation changes New Cost Listed Share Old New Old New Old New Old DCF Cost of of Company specific risks Curr. price * Rec Rec PT PT WACC WACC DCF (Listed debt Equity curr.) Acergy NOK 87 Hold Hold 50 85 13.5% 11.5% 55 78 4.7% 11.5% Upside: Contract awards and commodity prices. Downside: Lack of diversification leaves it more vulnerable to delay on FIDs; commodity prices and Aker Solutions NOK 73 Hold Hold 40 60 12.5% 11.0% 40 50 3.0% 11.8% Upsideti: Contract i k awards and commodity prices. Downside: Weak track record in execution; commodity prices. AMEC £ 825 Buy Buy 850 950 9.4% 9.4% 913 897 2.6% 9.4% Downside: Backlog cancellation; commodity prices and execution risk. Lamprell £ 189 Buy Buy 185 210 10.0% 10.0% 197 172 5.4% 9.7% Downside: Over-concentration on few large contracts leaves company at greater risk than peers to potential client defaults and late payments; commodity prices and execution risk. Petrofac £ 987 Hold Hold 680 970 11.2% 9.9% 670 814 3.0% 9.9% Upside: Contract awards and commodity prices. Downside: Energy developments sensitive to oil price risk; lack of diversification leaves it more vulnerable to delay on FIDs and execution risk. Saipem € 22 Buy Buy 23 27 10.0% 9.3% 23 33 2.4% 12.0% Downside: Risk of delay of new rigs coming online; commodity prices and execution risk. Seadrill NOK 138 Hold Buy 120 190 13.5% 12.4% 135 168 3.6% 18.5% Downside: Risk of delay of new rigs, balance sheet strength lowest in peer group; no room for error leaves it over-exposed to credit risk; commodity prices and execution risk. Subsea 7 NOK 96 Hold Hold 50 80 13.5% 11.0% 70 80 4.1% 11.9% Upside: Contract awards and commodity prices. Downside: Lack of diversification leaves it more vulnerable to delay on FIDs; commodity prices and execution risk. Technip € 47 Hold Hold 42 53 12.5% 11.5% 38 43 2.3% 11.5% Upside: Contract awards and commodity prices. Downside: Delay in contract awards; commodity prices and execution risk. Tecnicas Reunidas €36 Buy Buy 41 44 10.0% 10.5% 48 45 2.5% 10.5% Downside: Lack of diversification leaves it more vulnerable to delays on FIDs in the core segment; commodity prices and execution risk. Wood Group £ 308 Hold Sell 190 210 11.2% 9.5% 216 197 2.5% 12.2% Upside: M&A potential; contract awards and commodity prices.

Average 11.6% 10.5% Source: Deutsche Bank, Company data; cost of debt and cost of equity are sourced from Bloomberg, * closing share prices as at Thursday, December 3rd 2009.

Deutsche Bank AG/London Page 59 7 December 2009 Oil & Gas European Oil Services

Figure 85: DBe vs Bloomberg consensus DB Estimates Bloomberg Consensus % difference (DBe vs. consensus) CAGR CAGR Average Net Income Curr (mn) 2009E 2010E 2011E 2012E 2009E 2010E 2011E 2012E 2009E 2010E 2011E 2012E (09E-12E) (09E-12E) (09E-12E) Acergy $ 175 103 153 206 6% 164 147 183 219 10% 6% -30% -16% -6% -11% Aker Solutions NOK 1966 1682 1512 1728 -4% 2132 1720 1930 2580 7% -8% -2% -22% -33% -16% AMEC £ 147 180 196 212 13% 159 172 184 226 12% -7% 4% 7% -6% -1% Lamprell $ 51 45 57 68 10% 49 69 69 NA NA 4% -34% -18% NA -16% Petrofac $ 324 438 469 492 15% 326 448 485 477 14% -1% -2% -3% 3% -1% Saipem € 705 638 789 933 10% 701 633 671 697 0% 1% 1% 18% 34% 13% Seadrill $ 1012 1258 1614 1786 21% 1059 1135 1325 1392 10% -4% 11% 22% 28% 14% Subsea 7 $ 242 156 194 248 1% 208 166 204 220 2% 16% -6% -5% 13% 4% Technip € 410 290 342 409 0% 409 287 322 334 -6% 0% 1% 6% 22% 8% Tecnicas Reunidas € 160 187 212 229 13% 150 148 175 184 7% 6% 26% 22% 25% 20% Wood Group $ 190 161 182 197 1% 217 196 233 296 11% -12% -18% -22% -33% -21% Average 8% 7% -1% CAGR CAGR Average Revenue Curr (mn) 2009E 2010E 2011E 2012E 2009E 2010E 2011E 2012E 2009E 2010E 2011E 2012E (09E-12E) (09E-12E) (09E-12E) Acergy $ 2103 2207 2639 3022 13% 2145 2251 2441 2816 9% -2% -2% 8% 7% 3% Aker Solutions NOK 56425 54347 54038 58816 1% 55615 47762 49400 52645 -2% 1% 14% 9% 12% 9% AMEC £ 2605 2880 3105 3324 8% 2775 2851 2990 3549 9% -6% 1% 4% -6% -2% Lamprell $ 456 421 531 634 12% 502 470 519 NA NA -9% -10% 2% NA -6% Petrofac $ 3538 4619 5009 5386 15% 3634 4404 4757 4958 11% -3% 5% 5% 9% 4% Saipem € 10244 10422 11173 12130 6% 10183 9539 10047 9742 -1% 1% 9% 11% 25% 11% Seadrill $ 3188 3805 4495 4774 14% 3246 3863 4312 4553 12% -2% -1% 4% 5% 1% Subsea 7 $ 2405 2243 2536 3039 8% 2313 2171 2430 2596 4% 4% 3% 4% 17% 7% Technip € 6434 5764 6999 7281 4% 6448 5646 6027 6316 -1% 0% 2% 16% 15% 8% Tecnicas Reunidas € 2747 3179 3571 3824 12% 2669 2617 2892 3045 4% 3% 21% 23% 26% 18% Wood Group $ 4787 4633 4909 5097 2% 4872 4783 5049 5903 7% -2% -3% -3% -14% -5% Average 9% 5% 5% CAGR CAGR Average EBITDA margin 2009E 2010E 2011E 2012E 2009E 2010E 2011E 2012E 2009E 2010E 2011E 2012E (09E-12E) (09E-12E) (09E-12E) Acergy 19.7% 15.5% 15.0% 16.1% -6% 16.6% 15.5% 16.5% 15.7% -2% 18% 0% -9% 3% 3% Aker Solutions 7.3% 6.8% 6.3% 6.5% -4% 7.6% 7.4% 7.7% 8.6% 4% -4% -8% -19% -25% -14% AMEC 9.8% 10.6% 10.6% 10.5% 2% 8.3% 8.5% 9.2% 8.5% 1% 18% 24% 14% 24% 20% Lamprell 13.4% 13.0% 13.0% 13.0% -1% 12.4% 15.3% 15.5% NA NA 8% -15% -16% NA -8% Petrofac 13.3% 15.5% 15.3% 14.1% 2% 14.1% 18.1% 17.4% 14.8% 1% -6% -14% -12% -5% -9% Saipem 15.3% 15.4% 16.5% 16.7% 3% 15.3% 16.5% 16.2% 17.2% 4% 0% -7% 1% -3% -2% Seadrill 57.2% 57.1% 57.5% 56.9% 0% 52.6% 52.4% 53.2% 50.3% -1% 9% 9% 8% 13% 10% Subsea 7 20.0% 15.7% 15.8% 16.2% -7% 18.6% 17.4% 17.6% 19.4% 1% 8% -10% -10% -16% -7% Technip 13.1% 11.0% 10.6% 11.7% -4% 12.7% 11.2% 11.6% 11.7% -3% 3% -1% -9% 0% -2% Tecnicas Reunidas 6.0% 6.0% 6.0% 6.0% 0% 6.0% 6.0% 6.0% 6.1% 1% 0% 1% 1% -2% 0% Wood Group 8.9% 7.9% 8.0% 8.3% -2% 9.1% 8.6% 9.0% 9.0% 0% -3% -8% -10% -9% -8% Average -2% 1% -2% Source: Deutsche Bank, Bloomberg

Page 60 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Appendix B: Exploration, appraisal and development capex split

Figure 86: Exploration, appraisal and development outlook broken down by industry

300,000

250,000

200,000

150,000

100,000$mn

50,000

0 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009E 2010E 2011E

Surface servicing Surface equipment Subsurface servicing Subsurface equipment & products Drilling rigs Seismic

Source: Deutsche Bank, Wood Mackenzie, Spears and associates, company data

Please see Appendix T for a description of the above categories.

Deutsche Bank AG/London Page 61 7 December 2009 Oil & Gas European Oil Services Deepwater drilling activity vs. oil price

Figure 87: Deepwater appraisal and successful exploration wells drilled globally vs. oil price

120 121

100 101

80 81

60 61 Wells drilled

40 41 Appraisal/ successful exploration

20 21

0 1 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Oil price (WTI) Successful exploration Appraisal

Source: Deutsche Bank, Wood Mackenzie

Page 62 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Appendix C: Snapshot of each company’s financing

We have analysed the debt position, spread of maturity and interest rates to assess the refinancing risks for companies under our coverage. The underlying refinancing risk potential for companies is measured by taking a look at the timing of debt maturity (bond loans, bank loans, convertible bonds etc) along with the company’s current cash position, access to un- drawn credit facilities and their expected free cash flow generation. Data has been sourced from 2008 annual reports (the exception being Seadrill where an update on its debt repayment schedule is available in quarterly results).

Figure 88: Acergy Figure 89: Aker Solutions

700 9,000 600 8,000 500 7,000 400 6,000 5,000 300 4,000 USD mnUSD 200 NOK mn 3,000 2,000 100 1,000 - - * 2009 2010 2011 2012 2013 2014 2009 2010 2011 2012 2013 Cash Cash LT debt LT debt ST debt ST Year of maturity of LT debt Year of maturity of debt LT debt maturity Free cash flow LT debt maturity Free cash flow

- Convertible note maturing in 2013. - Robust cash position and free cash flow should cater - Strong cash position and free cash potential should for LT debt maturities. cater for future re-financing requirements. - Un-drawn revolving credit facility of Euro 750mn expiring in Oct 2012, with option of 2x1 year extension. Source: Company data, Deutsche Bank; * includes the NOK2.1bn bond issued in 2009. .Source: Company data, Deutsche Bank

Figure 90: Amec Figure 91: Lamprell

700 180 600 150 500 400 120 300 90 GBP mn GBP 200 mn Euro 60 100 Nil 30 Nil 0 - Debt 2009 2010 2011 2012 Cash Debt 2009 2010 2011 2012 Cash

Free cash flow Free cash flow

- Strong net cash position supported by positive free - No debt. cash flows. Source: Company data, Deutsche Bank

Source: Company data, Deutsche Bank

Deutsche Bank AG/London Page 63 7 December 2009 Oil & Gas European Oil Services

Figure 92: Petrofac Figure 93: Saipem

2,800 750 600 2,100

450 1,400 300 700 USD mn 150 mn Euro - - (700) 1 yr Cash 1-2 yrs 2-3 yrs 3-4 yrs 4-5 yrs 2009 2010 2011 2012 2013 After Cash LT debt ST debt ST > 5 years> 5 LT debt ST debt ST Year of maturity of LT debt Year of maturity of total debt

LT debt maturity Free cash flow Debt maturity Free cash flow

- Petrofac has a strong net cash position. - 78% of loan is provided for by Eni, which has a 43% - Strong free cash flows should cater for future stake in Saipem. Eni provides strong financial backing refinancing requirements. for Saipem and thus the refinancing risk is low. - Following the aggressive capex spend in 2009-11E,

Source: Company data, Deutsche Bank; the free cash flows from 2010E should cover the long term debt maturities. - Unused lines of credit available to the extent of $926mn.

Source: Company data, Deutsche Bank

Figure 94: Seadrill Figure 95: Subsea7

8,000 500 7,000 400 6,000 300 5,000 4,000 200 3,000 USD mn

USD mn 100 2,000 1,000 - - 2009 2010 2011 2012 2017 (1,000) Cash LT debt ST debt ST 2009 2010 2011 2012 Cash after LT debt ST debt ST Year of maturity of total debt

Year of maturity of debt and2013

Debt maturity Free cash flow Debt maturity Free cash flow

- Has the highest debt exposure relative to peers. - Two convertible bond loans maturing in 2011 and 2017. - Strong free cash flows after 2010E provides sufficient cover to meet long term debt maturities. - Free cash flows should cater for future re-financing

Source: Company data, Deutsche Bank requirements.

Source: Company data, Deutsche Bank

Page 64 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 96: Technip Figure 97: Tecnicas Reunidas

2,800 500 2,400 400 Maturity details not available 2,000 1,600 300 1,200

Euro mn Euro 200 800 mn Euro 400 100 - - 2009 2010 2011 Cash LT debt ST debt ST 2009 2010 2011 2012 Year of maturity of LT debt Cash LT debt ST debt ST

Debt maturity Free cash flow Free cash flow

- Strong net cash position (even after excluding pre- - Strong free cash flows should cater for future payments from lump sum turnkey contracts which refinancing requirements.

represent broadly 50%). Source: Company data, Deutsche Bank - Free cash flows should cater for future refinancing requirements.

Source: Company data, Deutsche Bank

Figure 98: Wood Group

400 350 300 ST debt maturing in one year and 250 LT debt maturing between 2-5 200 150

USD mn 100 50 - (50) 2009 2010 2011 2012 2013 Cash LT debt ST debt ST Year of maturity of Total debt Debt maturity Free cash flow

- Robust free cash flows should cater for future refinancing requirements. - Un-drawn borrowing facilities (floating rate) available :$38mn expiring in one year and $436mn expiring between 2 and 5 years.

Source: Company data, Deutsche Bank

Deutsche Bank AG/London Page 65 7 December 2009 Oil & Gas European Oil Services Appendix D: Shallow water drilling duration

Figure 99: Shallow water average drilling duration

100% 80

70 80%

60 60%

40% 40 Average drilling days per well per days drilling Average 20% 30 Proportion of wells drilled across water depths water drilled across wells of Proportion

0% 20 2000 2001 2002 2003 2004 2005 2006 2007 2008

0-99 100-199 200-299 300-399 Exploration (RHS) Appraisal (RHS)

Source: Deutsche Bank, Wood Mackenzie

Page 66 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Appendix E: Regional spread of contracted newbuild rigs

Figure 100: Contracts signed for semi-submersible rigs and drillships coming online 2009-12

3% 3% 4%

10%

39%

14%

27%

Uncontracted S America GOM E Hemisphere Europe Africa Russia

Source: ODS Petrodata, Deutsche Bank

Figure 101: Contracts signed for Jackup rigs coming online 2009-12

1% 3% 3% 4%

89%

Uncontracted E Hemisphere S America Middle East Europe

Source: ODS Petrodata, Deutsche Bank

Deutsche Bank AG/London Page 67 7 December 2009 Oil & Gas European Oil Services Appendix F: NOC/IOC/Independents investment in drilling

Figure 102: Snapshot of investment in drilling by operators since 1995

1600

1400

1200

1000

800 Wells drilled 600

400

200

0 N America Africa S America South East Asia Europe

Independent E&P IOC NOC

Source: Deutsche Bank, Wood Mackenzie

Figure 103: Investment in drilling, by operator in Figure 104: Investment in drilling, by operator in Africa N America

180 70 160 60 140 50 120 100 40

80 30 Wells drilled 60 Wells drilled 20 40 10 20 0 0 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Independent E&P IOC NOC Independent E&P IOC NOC Source: Deutsche Bank, Wood Mackenzie Source: Deutsche Bank, Wood Mackenzie

Page 68 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 105: Investment in drilling, by operator in Figure 106: Investment in drilling, by operator in South S America East Asia

80 45

70 40 35 60 30 50 25 40 20

Wells drilled 30 Wells drilled 15 20 10 10 5 0 0 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Independent E&P IOC NOC Independent E&P IOC NOC Source: Deutsche Bank, Wood Mackenzie Source: Deutsche Bank, Wood Mackenzie

Figure 107: Investment in drilling, by operator in Europe

Wells drilled 6

0 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Independent E&P IOC

Source: Deutsche Bank, Wood Mackenzie

Deutsche Bank AG/London Page 69

Page 70 Page 70 Oil Services European Oil&Gas 7 December2009 Appendix G: Calculations behind backlog cover analysis

Figure 108: Detailed working of backlog cover for forward year Future year (FY) for which revenue cover is calculated 2008 2009E 2010E Backlog as at end of quarter Q3 2006 Q4 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009

Acergy Backlog 2,618 2,587 2,557 3,031 2,745 3,175 3,972 3,649 3,281 2,511 2,432 2,415 2,628 (USD mn) Backlog expected to be booked as revenue in FY * 27% 21% 32% 42% 16% 21% 28% 36% 33% 30% 33% 44% 53% Implied revenue 707 543 818 1,273 439 667 1,112 1,314 1,083 753 803 1,063 1,393

Revenue of F Y 2,522 2,522 2,522 2,522 2,145 2,145 2,145 2,145 2,655 2,242 2,097 2,076 2,251

Backlog cover of FY revenue (X) 28% 22% 32% 50% 20% 31% 52% 61% 41% 34% 38% 51% 62% % of FY revenue dependant on incremental contracts (1-X) 72% 78% 68% 50% 80% 69% 48% 39% 59% 66% 62% 49% 38%

Saipem Backlog 12,804 13,090 13,268 13,348 13,343 15,390 15,409 16,191 19,041 19,105 19,045 19,015 18,354 (EUR mn) Backlog expected to be booked as revenue in FY * 19% 23% 26% 30% 40% Implied revenue 3,600 4,394 5,000 5,705 7,300

Revenue of F Y 10,094 10,094 10,094 10,094 9,828 9,828 9,828 9,828 10,961 9,539 9,816 9,566 9,539

Backlog cover of FY revenue (X) 33% 46% 51% 60% 77% % of FY revenue dependant on incremental contracts (1-X) 67% 54% 49% 40% 23%

Subsea 7 Backlog 3,500 3,748 3,809 3,938 4,200 4,200 3,911 3,745 4,100 3,300 2,907 2,864 2,976 (USD mn) Backlog expected to be booked as revenue in FY * 22% 20% 28% 30% 21% 24% 27% 32% 22% 24% 25% 33% 41% Implied revenue 760 765 1,062 1,189 895 1,017 1,073 1,197 884 794 732 954 1,232

Revenue of F Y 2,373 2,373 2,373 2,373 2,243 2,243 2,243 2,243 2,511 2,171 2,036 2,003 2,171

Backlog cover of FY revenue (X) 32% 32% 45% 50% 40% 45% 48% 53% 35% 37% 36% 48% 57% % of FY revenue dependant on incremental contracts (1-X) 68% 68% 55% 50% 60% 55% 52% 47% 65% 63% 64% 52% 43%

Technip Backlog 10,852 10,273 9,879 9,670 9,411 9,390 8,625 8,053 7,717 7,208 6,928 6,066 7,541 (EUR mn) Backlog expected to be booked as revenue in FY * 33% 33% 39% 46% 21% 25% 31% 42% 28% 23% 31% 42% 50% Implied revenue 3,616 3,402 3,855 4,432 2,009 2,321 2,649 3,342 2,140 1,685 2,153 2,573 3,785

Revenue of F Y 7,481 7,481 7,481 7,481 6,417 6,417 6,417 6,417 6,210 5,646 5,573 5,785 5,646

Backlog cover of FY revenue (X) 48% 45% 52% 59% 31% 36% 41% 52% 34% 30% 39% 44% 67% % of FY revenue dependant on incremental contracts (1-X) 52% 55% 48% 41% 69% 64% 59% 48% 66% 70% 61% 56% 33%

Source: Deutsche Bank, company data, * As per company guidance Deutsche Bank AG/London Deutsche Bank

Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009 Figure 109: Detailed working of backlog cover for current year Q3 2006 Q4 2006 Q1 2007 Q2 2007 Q3 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Acergy Backlog 2,618 2,587 2,557 3,031 2,745 2,745 3,175 3,972 3,649 3,281 3,281 2,511 2,432 2,415 2,628 (USD mn) Current year (CY) for which revenue cover is calculated 2007 2007 Q2-Q4 '07 Q3-Q4 '07 Q4 '07 2008 2008 Q2-Q4 '08 Q3-Q4 '08 Q4 '08 2009 2009 Q2-Q4 '09 Q3-Q4 '09 Q4 '09 Backlog expected to be booked as revenue in CY * 47% 67% 56% 45% 27% 57% 70% 48% 35% 22% 45% 57% 50% 38% 21% Implied revenue 1,230 1,733 1,432 1,364 741 1,565 2,223 1,907 1,277 722 1,476 1,431 1,216 918 552

Revenue of CY 2,663 2,663 2,098 1,464 709 2,906 2,700 1,887 1,144 568 2,579 2,284 1,683 1,117 558

Backlog cover of CY revenue (X) 46% 65% 68% 93% 100% 54% 82% 100% 100% 100% 57% 63% 72% 82% 99% % of CY revenue dependant on incremental contracts (1-X) 54% 35% 32% 7% 0% 46% 18% 0% 0% 0% 43% 37% 28% 18% 1%

Q3 2006 Q4 2006 Q1 2007 Q2 2007 Q3 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Saipem Backlog 12,804 13,090 13,268 13,348 13,343 13,343 15,390 15,409 16,191 19,041 19,041 19,105 19,045 19,015 18,354 (EUR mn) Current year (CY) for which revenue cover is calculated 2007 2007 Q2-Q4 '07 Q3-Q4 '07 Q4 '07 2008 2008 Q2-Q4 '08 Q3-Q4 '08 Q4 '08 2009 2009 Q2-Q4 '09 Q3-Q4 '09 Q4 '09 Backlog expected to be booked as revenue in CY * 42% 28% 18% 45% 35% 30% 14% 38% 38% 29% 20% 11% Implied revenue 5,536 3,798 2,355 6,983 5,398 4,819 2,663 7,300 7,260 5,490 3,856 1,968

Revenue of CY 9,530 9,530 7,340 4,795 2,018 10,094 10,094 7,858 5,475 2,833 10,563 9,850 7,270 4,670 2,483

Backlog cover of CY revenue (X) 75% 79% 100% 69% 69% 88% 94% 69% 74% 76% 83% 79% % of CY revenue dependant on incremental contracts (1-X) 25% 21% 0% 31% 31% 12% 6% 31% 26% 24% 17% 21%

Q3 2006 Q4 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Subsea 7 Backlog 3,500 3,748 3,809 3,938 4,228 4,200 4,200 3,911 3,745 4,085 4,100 3,300 2,907 2,864 2,976 (USD mn) Current year (CY) for which revenue cover is calculated 2007 2007 Q2-Q4 '07 Q3-Q4 '07 2008 2008 Q2-Q4 '08 Q3-Q4 '08 2009 2009 Q2-Q4 '09 Q3-Q4 '09 Q4 '09 Backlog expected to be booked as revenue in CY * 35% 44% 33% 24% 13% 37% 41% 38% 31% 14% 40% 52% 45% 33% 16% Implied revenue 1,225 1,637 1,268 931 554 1,542 1,710 1,505 1,153 591 1,651 1,701 1,315 938 474

Revenue of CY 2,187 2,187 1,711 1,180 562 2,409 2,373 1,811 1,212 584 2,454 2,265 1,639 1,002 412

Backlog cover of CY revenue (X) 56% 75% 74% 79% 99% 64% 72% 83% 95% 100% 67% 75% 80% 94% 115% % of CY revenue dependant on incremental contracts (1-X) 44% 25% 26% 21% 1% 36% 28% 17% 5% 0% 33% 25% 20% 6% -15%

Q3 2006 Q4 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Technip Backlog 10,852 10,273 9,879 9,670 9,411 9,411 9,390 8,625 8,053 7,717 7,717 7,208 6,928 6,066 7,541 (EUR mn) Current year (CY) for which revenue cover is calculated 2007 2007 Q2-Q4 '07 Q3-Q4 '07 2008 2008 Q2-Q4 '08 Q3-Q4 '08 2009 2009 Q2-Q4 '09 Q3-Q4 '09 Q4 '09 Backlog expected to be booked as revenue in CY * 51% 56% 46% 37% 24% 55% 62% 57% 45% 20% 52% 72% 62% 50% 18% Implied revenue 5,496 5,749 4,526 3,568 2,214 5,188 5,850 4,902 3,600 1,577 4,000 5,165 4,323 3,008 1,377

Revenue of CY 7,887 7,887 6,112 4,267 2,101 7,328 7,481 5,665 3,841 1,908 6,420 6,184 4,722 3,116 1,436

Backlog cover of CY revenue (X) 70% 73% 74% 84% 100% 71% 78% 87% 94% 83% 62% 84% 92% 97% 96% % of CY revenue dependant on incremental contracts (1-X) 30% 27% 26% 16% 0% 29% 22% 13% 6% 17% 38% 16% 8% 3% 4%

Source: Deutsche Bank, company data, * As per company guidance Page 71

7 December 2009 Oil & Gas European Oil Services Appendix H: Regional split of shallow water capex

Figure 110: Regional split of shallow water capex 2006-11E

120,000

100,000

80,000

60,000 Capex ($mn)

40,000

20,000

- 2006 2007 2008 2009E 2010E 2011E

Africa Europe Middle East Russia SE Asia Cas pian S. America N. A merica

Source: Deutsche Bank, Wood Mackenzie

Page 72 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Appendix I: Detailed overview of companies’ fleet

Figure 111: Summary of offshore asset profiles of companies; newbuild vessels coming online from 2010 shown in brackets Category Acergy Saipem Subsea 7 Technip Seadrill Cons. & pipelay ship 6 1(+1) 4 (+1) 2 Construction ship 4726 Pipelay ship 2 3 (+1) 3 (+2) 2 (+2) Semisubmersible rig 5 (+2) 8 (+2) Drillship 1 (+1) 3 (+1) Jack up rig 6 9 (+3) Tender rig 14 (+3) Pipelay barge 2 8 Cargo barge 7 Diving support vessel (+1) 1 (+1) 6 7 Inspection maintenance repair (IMR) vessel 3 3 Remotely operated vehicle (ROV) support vessel 1 4 Source: Deutsche Bank, Company data

Deutsche Bank AG/London Page 73

Page 74 Page 74 Oil Services European Oil&Gas 7 December2009 Figure 112: Key characteristics of Acergy’s E&C offshore vessles

Deck load Deck area Crane Net Diving Diving ROV Vessel name Vessel type Category Piplelay type Accom. Divers ROVs (t m2) (m2) capacity (t) tonnage system depth (m) depth

Acergy Polaris Derrick Lay Barge Pipelay barge S-lay and J-lay 5,000 900 1,440 262 4,572 2 work class 3000 Acergy Falcon Rigid And Flexible Pipelay Ship Pipelay ship Flex + rigid (J) 2,120 1,600 74 141 2 work class 3000 Sapura 3000 (50% stake) DP Heavy Lift And Pipelay Vessel Pipelay ship S-lay and J-lay 20,000 2,000 3,420 330 2 work class Acergy Orion Derrick Lay Barge Pipelay barge Rigid 165 Acergy Discovery Subsea Construction And Flowline Lay Ship Cons. & pipelay ship Flex 5,000 1,000 150 111 200-450 18 Acergy Harrier Construction Support Ship Construction ship - 810 1,140 123 86 Saturation 350 18 1 SCV 3000 2000 1 observ. class 600 Acergy Hawk Construction Support Ship Construction ship Flex (option exists) 3,960 792 250 140 Acergy Legend ROV support vessel RSV - - 434 34 54 338 2 ROVs Polar Queen Flexible pipelay and subsea construction ship Cons. & pipelay ship Flex 12,450 1,660 350 121 5,700 2 work class 2000 Skandi Acergy Heavy Construction Ship Construction ship - 7,000 2,100 400 140 Toisa Proteus Heavy Construction And Dive Support Ship Cons. & pipelay ship Flex 3,500 1,900 390 104 2,521 Acergy Condor Deepwater Construction Support Ship Cons. & pipelay ship Flex 1,800 - 145 100 2,552 2 work class 3000 Pertinacia Subsea Construction And Flowline Lay Ship Cons. & pipelay ship Flex 45 77 2,400 Acergy Eagle Subsea Construction And Flowline Lay Ship Cons. & pipelay ship Flex + rigid - 1,280 405 101 300 16 2 work class 3000 Acergy Osprey Diving And Construction Support Ship Construction ship - 4,500 1,100 140 102 Saturation 360 18 Acergy Petrel IMR And Survey Ship IMR - 5 350 27 48 Acergy Viking IMR And Survey Ship IMR - 5 750 1,000 60 Far Saga IMR Vessel IMR - 10 665 153 63 Acergy Havila (H1 2010) Diving Support Vessel DSV - 10 1,050 290 120 Saturation 400 24 Source: Deutsche Bank, Company data

Deutsche Bank AG/London Deutsche Bank

Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009 Figure 113: Key characteristics of Saipem’s E&C offshore vessles (excludes drilling*)

Deck load Deck area Crane Vessel name Vessel type Category Piplelay type Accom. (t m2) (m2) capacity (t)

Saipem 3000 Self propelled DP crane vessel Construction ship 54,000 3,000 2,191 195 Saipem FDS Multi-purpose monohull DP crane and pipelay (J-lay) vessel Cons. & pipelay ship J-Lay 4,000 660 235 Castoro Sei Semisubmersible pipelay vessel Pipelay ship Rigid 3,600 1,525 120 330 Castoro II Derrick/lay barge Pipelay barge 1,178 248 Castoro Otto Self propelled derrick/lay ship Pipelay ship 6,699 2,291 339 Saipem 7000 Semisubmersible crane and pipelaying (J-lay) DP vessel Pipelay ship J-Lay 15,000 9,000 17,500 725 S 355 Derrick/lay barge Pipelay barge 3,200 1,300 590 206 Crawler Derrick/lay barge Pipelay barge 600 230 Normand Cutter Installation and Construction Construction ship 1,600 300 114 DP Reel Installation and Construction Construction ship 700 50 50 Hos Innovator Installation and Construction Construction ship 3,760 752 36 Harvey Discovery Installation andConstruction Construction ship 4,050 900 46 OC 280 Installation and Construction Construction ship 3,715 743 66 S 44 Launching/cargo barge Cargo barge 8,500 S 600 Launching/cargo barge Cargo barge Castoro XI Heavy duty cargo barge Cargo barge 5,200 S45 Launching/cargo barge Cargo barge 6,500 Castoro 9 Launching/cargo barge Cargo barge S42 Launching/cargo barge Cargo barge 3,450 SB 103 Cargo barge Cargo barge Semac 1 Semisubmersible pipelay barge Pipelay barge 5,000 518 362 Castoro 10 Trench/pipelay barge Pipelay barge 3,600 1,000 188 168 SB 230 Work/pipelaying/accommodation barge Pipelay barge 86 120 Castoro 12 Shallow water pipelay barge, Caspian Sea service Pipelay barge 55 150 Ersai 1 Construction/ lifting vessel Construction ship 2,100 Saipem TRB Trench/pipelay barge Pipelay barge 67 45 TRB Tender 4 post trenching/backfilling crafts IMR 4 Bar Protector DP dive support vessel DSV 800 100 109 Grampian Surveyor Survey and IRM IMR 600 100 Far Sovereign Multi-functional anchor handling tug and service vessel IMR 2,200 100 70 Castoro One (Q3 2011) Pipe lay vessel Pipelay ship Saipem FDS2 (Q2 2011) Field development vessel Cons. & pipelay ship New DSV (Q3 2011) DSV DSV Source: Deutsche Bank, Company data; * Saipem additionally has 6 Jackup rigs, 5 semi-submersible rigs (+2 newbuild rigs) and 1 drillship (+1 newbuild)

Page 75

Page 76 Page 76 Oil Services European Oil&Gas 7 December2009

Figure 114: Key characteristics of Subsea 7’s E&C offshore vessles

Deck load Deck area Crane Net Diving Diving ROV Vessel name Vessel type Category Piplelay type Accom. Divers ROVs (t m2) (m2) capacity (t) tonnage system depth (m) depth

Amazonia ROV support vessel RSV 1,000 610 50 58 Kommandor 3000 Pipelay Pipelay ship Flex 1,000 750 260 73 2,319 2 work class Lochnagar Pipelay Pipelay ship Flex 326 73 1,923 2 work class 2000 Normand Seven Pipelay Pipelay ship Flex 20,000 2,000 280 100 2 work class 3000 Seven Oceans Pipelay Pipelay ship Rigid + Flex 6,500 650 402 120 5,460 2 work class 3000 Seven Seas Pipelay and construction vessel Cons. & pipelay ship Flex (J-lay) 17,500 1,750 472 120 5,475 2 work class 3000 Seven Sisters Construction vessel Construction ship - 1,150 150 100 1,450 Skandi Navica Pipelay Pipelay ship Rigid + Flex 3,000 480 66 73 1,859 Skandi Neptune Pipelay and construction vessel Cons. & pipelay ship Vertical + Flex 9,400 1,180 150 106 2,383 2 work class 3000 Skandi Seven Construction vessel Construction ship NA 13,000 1,300 256 120 Subsea Viking Pipelay and construction vessel Cons. & pipelay ship Flex 5,750 1,150 100 70 2,220 2 work class 3000 1 observ. class Toisa Perseus Pipelay and construction vessel Cons. & pipelay ship Vertical 7,900 1,580 180 106 2,085 2 work class Rockwater 1 Dive support vessel DSV NA 2,750 550 120 94 Saturation 300 15 Rockwater 2 Dive support vessel DSV NA 5,750 1,150 307 106 1,797 Saturation 300 16 Seven Atlantic Dive support vessel DSV NA 12,000 1,200 145 150 Saturation 350 24 2 ROVs 3000 Seven Pelican Dive support vessel DSV NA 6,830 800 65 105 Saturation 370 18 1 Observ. class Seven Spray Air diving support vessel DSV - 11 - 50 2

1 Observ. Class Toisa Polaris Dive support vessel DSV NA 4,350 870 150 103 2,471 Saturation 231 181 work class Kommandor Subsea ROV support vessel RSV NA 1,600 320 5 44 Seisranger ROV support vessel RSV NA 2,600 520 50 69 Normand Subsea 7 (Q4 2ROV support vessel RSV NA 7,050 705 140 90 Seven Pacific (Q4 2010) Construction Support Ship Cons. & pipelay ship Vertical 17,000 1,700 310 100 2 work class 3,000 Source: Deutsche Bank, Company data

Deutsche Bank AG/London Deutsche Bank

Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009

Figure 115: Key characteristics of Technip’s E&C offshore vessles

Deck load Deck area Crane Net Diving Diving ROV Vessel name Vessel type Category Piplelay type Accom. Divers ROVs (t m2) (m2) capacity (t) tonnage system depth (m) depth

Apache Reeled pipelay/ umbilical systems Pipelay ship Reel lay 1,175 235 79 95 Constructor Construction/ installation systems Cons. & pipelay ship Flex 16,500 1,650 325 110 Rigid & flex Deep Blue Reeled pipelay/ umbilical systems Cons. & pipelay ship 690 442 160 (reel-lay & J-lay) Deep Pioneer Construction/ installation systems Construction ship 2,230 190 105 2,260 Orelia Diver support systems DSV 1,750 1,800 200 99 Saturation 350 18 Skandi Achiever Diver support systems DSV 660 148 100 Saturation 300 18 1 observ. class 1 observ. class 1500 Skandi Arctic Diver support systems DSV 5,500 1,700 140 Saturation 350 242 work class 2000 Sunrise 2000 Flexible pipelay/ umbilical systems Pipelay ship Flex 140 92 Wellservicer Construction and DSV Construction ship 1,140 1,113 40 139 300 18 Alliance Diver support systems DSV 1,500 550 143 80 300 16 1 observ. class Seamec 1 Construction Support Ship Construction ship 500 335 45 90 767 Seamec 2 Diver support systems DSV 3,200 640 80 90 1,298 200 3 Seamec 3 Diver support systems DSV 3,200 640 50 90 1,298 Saturation 450 3 Venturer Construction and DSV Construction ship 3,000 1,700 230 98 300 16 Geoholm Construction/ survey support systems Construction ship Seamec Princess Diver support systems DSV North Ocean 103 Normand Pioneer Construction/ installation systems Construction ship Brazilian pipelay veesel (end 2009) Pipelay Pipelay ship New pipelay vessel (end 2010) Pipelay Pipelay ship Rigid + flex 17,000 1,700 220 140 2 work class 3,000 Source: Deutsche Bank, Company data

Page 77

7 December 2009 Oil & Gas European Oil Services Appendix J: ‘Backlog longevity’ calculation explained

We have built upon our extensive database of contract awards to compute the average duration of contracts for each company across different segments since 2006. Companies do not report all contract awards due to issues with client confidentiality and so the scope of this analysis is limited to the extent of contract awards reported by companies in their press releases. Our assumptions include:

Contracts have been divided broadly into three segments – Engineering & Construction (E&C), Power (P) & Drilling (D). E&C and P contracts are further categorised based on the type of spend it is from the client’s perspective; i.e., whether it is capital expenditure (C) (typically engineering, construction and/or installation related) or operating expenditure (O) (typically maintenance related).

Contract duration has been weighted by its relative value. In the case of Amec and Wood Group however, where contract values were not available consistently, our weighting was done on the basis of their respective contract counts in each segment.

Where the term length was not available, we have taken the yearly average for that particular sub segment. If the average for the year was not available, that of the previous year was taken.

Figure 116: Average contract duration - 2008 Figure 117: Average contract duration - 2009

4.9 5.3 100% 4.5 100% 4.0 4.0 80% 4.5 4.4 80% 3.5 3.6 3.2 3.0 3.0 3.9 3.0 2.9 60% 3.8 60% 2.8 2.7 2.7 2.5 3.4 2.0 40% 3.0 2.9 2.8 40% 1.5 2.7 20% 2.6 2.4 2.3 20% 1.0 1.0

2.0 Segment split by value * Average contract duration

1.9 value* by split Segment 0.5 0% Average contract duration 1.5 0% Acergy Saipem Technip AMEC * Lamprell Petrofac Tecnicas Subsea 7 Subsea Acergy Seadrill Saipem Technip AMEC * Lamprell Petrofac Tecnicas Subsea 7 Subsea Aker Solutions Wood Group * Aker Solutions Wood Group * E&C (capex) E&C (opex) Power Drilling Company average E&C (capex) E&C (opex) Power Drilling Company average

Source: Deutsche Bank, Company data

* In the case of Amec and Woodgroup, since contract values are not available we have used contract count

Page 78 Deutsche Bank AG/London

Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009 Figure 118: Average contract age calculation

Average age Average age Average age Average age Average age Average age Weight Weight Weight Weight Weight Weight Acergy(yrs) Aker(yrs) Amec(yrs) Lamprell(yrs) Petrofac(yrs) Saipem (yrs) Segment C/O * Segment C/O C/O Segment Segment C/O C/O Segment Segment C/O C/O Segment Segment C/O C/O Segment Segment C/O C/O Segment Segment C/O C/O Se gment 2009 C 100% 4.0 93% 3.0 80% 3.0 100% 1.0 97% 3.2 100% 2.8 O NA NA 7% 2.4 20% 3.0 NA NA 3% 4.9 NA NA C NA NA NA 0.0 100% 2.0 2.0 100% 2.2 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 PP O NANA NANA NANA NANANA NANANA NANANA 2.8 D - NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 19% 100% 3.8 3.8 4.0 2.9 2.7 1.0 3.2 3.0 2008 C 100% 2.7 74% 2.4 75% 4.1 100% 2.0 90% 2.4 98% 3.5 O NA NA2.7 26% 2.5 2.4 25% 4.0 4.1 NA NA 10% 3.6 2% 5.0 3.6 Company avg. E&CC 100% NA NA NA 4.0 0.0 98% NA NA NA 3.0 0.0 78%56% 3.3 100% NA3.0 NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 E&C 100% 1.0 100% 3.22.6 81% 83% PP O NA NA NA NA NA NA 22% 10.0 NA NA NA NA NA NA NA NA NA D -100% NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 17% 100% 2.8 2.8 100%2% 44% 2.2 100% 2.7 2.4 4.4 2.0 2.6 3.4 2007 C 86% 1.1 94% 2.3 65% 2.0 100% 1.7 95%2.0 2.3 100% 2.5 O 14% 3.9 6% 3.02.3 35% 4.2 NA NA 5% 1.1 NA NA C NA NA NA 0.01.5 100% 1.8 1.8 78%57% 1.9 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 2.5 Company avg. 2.3 2.3 78% O NANANA NANA 22%3.535% NANANA NANANA NANANA DE&C - NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 22% 100% 4.1 4.1 PP 100% 99% 43%65% 2.8 4.8 1.5 2.3 2.6 1.7 2.3 2.8 100% 2006 C 100% 1.9 92% 2.3 71% 7.2 95% 0.6 98% 2.5 92% 2.6 92% O NA NA 8% 3.0 29% 3.36.1 5% 0.11.7 2% 1.0 8%2.5 6.0 E&CC 100% NA NA NA 0.0 100% 2.0 2.02.3 100%88% 2.0 NA NA100% NA 0.0 NA NA NA 0.0 NA NA NA 0.0 1.9 13% 72% 2.9 Company avg.O NANANA NANA NANA NANANA2.0 NANANA NANANA D - NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 28% 100% 4.6 4.6 100% PP 1.9 2.3 5.6 0.6 2.5 3.4 Source: Deutsche Bank, Company data, * C/O refers to Capex/ Opex Company avg. 1% 100% 0.6 Figure 119: Average contract age calculation continued…

Average age Average age Average age Average age Average age Weight Weight Weight Weight Weight (yrs) (yrs) (yrs) (yrs) (yrs) Segment C/O * Segment C/O C/O Segment Segment C/O C/O8% Segment Segment C/O C/O Segment Segment C/O C/O Segment Segment C/O C/O Segment 2009 C NA NA 86% 2.3 100% 2.8 100% 3.6 82% 3.5 O NA NA 14% 5.7 NA NA NA NA 18% 2.3 C NA NA NA 0.0 0% NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 44% 0.3 O 0%NANA NANANA NANANA 56%4.4 D - 100% 100% 0.2 0.2 0% NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 0% NA NA 0.0 Seadrill 0.2Subsea 7 2.7 Technip 2.8 3.6Tecnicas 3.0 Woodgroup 2008 C NA NA 67% 1.6 100% 1.9 100% 2.9 82% 2.4 NA 0.0 100% O NA NA 33% 8.5 NA NA NA NA 18% 4.3 C NA NA NA 0.0 0% NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 70% 1.6 2.7 E&CNA 0.0 100%2.7 100% 2.8 100% 3.6 65%31% 3.3 O 0%NANA NANANA NANANA 30%6.5 PPD - 100% 100% 4.9 4.9 0% NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 0% NA NA 0.0 69%35% 2.6 4.9 3.9 1.9 2.9 2.8 2007 C NA NA 95% 2.9 100% 2.1 100% 3.5 69%2.9 1.7 3.5 O NA NA 5% 3.3 NA NA NA NA 31% 2.8 C NA NA NA 0.0 0% NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 42% 0.8 3.1 1.9 48% 5.7 O 0%NANA NANANA NANANA 58%9.1 2.0 E&C 100% D - 100% 100% 3.5 3.5 0% NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 0% NA NA 0.0 Company avg. 3.9 100% PP 3.5 3.0 2.1 3.552% 3.8 2006 CNA NA NA 100% 4.1 100%100% 2.0 100% 2.9 72% 2.2 E&C O NA NA 0% NA3.0 NA NA NA NA 28% 3.2 C NA NA NA 0.0 0% NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 33%2.9 0.8 O 0%NANA NANANA NANANA 67%6.0 0.0 100% 2.1 D - 100% 100% 3.2 3.2 0% NA NA 0.0 NA NA NA 0.0 NA NA NA 0.0 0% NA NA 0.0 19% 2.54.3 E&C 100% Company avg. 3.2 4.1 2.0 2.9 2.8 Source: DeutschePP Bank, Company data, * C/O refers to Capex/ Opex 100% 81% NA 0.0

Page 79 4.1 100% 100%

2.0

Company avg. PP 7 December 2009 Oil & Gas European Oil Services Appendix K: Asset utilisations

In analysing the degree of asset utilisation covered by existing contracts, we attempted to ‘map’ contracts to specific assets and in turn estimate the ‘un-contracted’ capacity for 2009- 12E. The key constraint was the limited data available on contracts reported. We have analysed contracts awarded across 2006-09 YTD.

Our assumptions include:

Vessels have been divided into three broad categories: Construction & Pipelay, Drilling and FPSO. We have classified vessels outside these categories into ‘others’.

Based on the contract award date and duration, we have apportioned utilisation % by years for each asset. Where the details of term length were not available, we have used the average term length for the year of the respective company.

We have assumed 100% utilisation where a vessel is working on multiple contracts during a year as we have not been able to apportion utilisation specifically across the contracts. Where the asset is being fully engaged we have highlighted this in grey.

For simplicity we have used 100% to indicate continual operation. In reality however vessels typically work for a maximum of 90-95% a year due to yard stay/ repairs.

Figure 120: Average utilisations of vessels (related to Figure 121: % of contracts disclosed* that have no subsea contracts disclosed*) and depreciation/EBITDA vessel accounted for (but by their definition will be using one)

80% 40% 100% 100% 75% 35% 90% 90% 70% 30% 80% 80% 70% 70% 65% 25% 60% 60% 60% 20% 50% 50% 55% 15% 40% 40%

50% 10% 30% 30% for accounted Average utilisation 09-12

% of contracts reported contracts of % 20% 20%

45% 5% Avg. Depreciation/ EBITDA 09-12 10% 10% 40% 0% 0% 0% vessels no have that contracts of % Subsea 7 Acergy Technip Seadrill Saipem Subsea 7 Acergy Technip Seadrill Saipem Average utilisation 09-12 (LHS) Avg. 2009-12 Depreciation/EBITDA % of contracts reported % of contracts disclosed that have no vessels accounted for

Source: Deutsche Bank, Company data; *note we have analysed all contracts that have been disclosed; Source: Deutsche Bank, Company data; *note we have analysed all contracts that have been disclosed; generally speaking this does not represent all of the contracts won - this is shown on the figure121 alongside generally speaking this does not represent all of the contracts won - this is shown on LHS y-axis

Page 80 Deutsche Bank AG/London

Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009 Figure 122: Acergy asset utilisation Vessle type Contract award Date Client Name Region Term Estimated 2008 2009 2010 2011 2012 term (yrs) Acergy Polaris Rigid pipelay 29-Nov-07 ExxonMobil Angola Starting in 4Q 08 2.7 2-Jan-08 Total Angola 2.7 15-Dec-08 Angola LNG Ltd. Angola Engineering will start immediately 2.7 and Offshore installation will start in Q4'09 22-Sep-09 Total E&P Angola and BP Angola Engineering will start immediately 4.0 Angola and Offshore installation will start in Q2'10 100% 100% 100% 100% 100% Acergy Falcon Rigid pipelay 13-Feb-08 EnCana Canada NA 2.7 100% 100% 70% 0% 0% Sapura 3000 (50% stake) Rigid pipelay 16-Jul-07 Murphy Sa bah Oil Co Malaysia NA 1.1 50% 17-Mar-09 Sabah Shell Petroleum Malaysia Engineering will commence with 4.0 Company Limited (SSPC) immediate effect, with offshore installation scheduled to commence in 2010. 2-Oct-09 Apache Energy Limited Australia Engg. and project preparations starts 4.0 immediately, Offshore installation scheduled to commence in late 2010

50% 0% 100% 100% 100% Acergy Orion Rigid pipelay 29-May-09 MOBIL Producing Nigeria Nigeria NA 4.0 50% 100% 100% 100% Unlimited (MPN) Acergy Discovery Subsea construction 13-Feb-08 EnCana Canada NA 2.7 85% 100% 85% 0% 0% Acergy Harrier Subsea construction 30-Oct-07 Petrobras Brazil 3 years + 3 years optional 100% 100% 75% 0% 0% Acergy Hawk Subsea construction 15-Dec-08 Angola LNG Ltd. Angola Engineering will start immediately 2.7 25% and Offshore installation will start in Q4'09 22-Sep-09 Total E&P Angola and BP Angola Engineering will start immediately 4.0 Angola and Offshore installation will start in Q2'10 25% 100% 100% 100% Acergy Legend Subsea construction 15-Dec-08 Angola LNG Ltd. Angola Engineering will start immediately 2.7 25% and Offshore installation will start in Q4'09 22-Sep-09 Total E&P Angola and BP Angola Engineering will start immediately 4.0 Angola and Offshore installation will start in Q2'10 25% 100% 100% 100% Polar Queen (chartered) Subsea construction 29-Nov-07 ExxonMobil Angola Starting in 4Q 08 1.1 2-Jan-08 Total Angola NA 2.7 14-Jul-09 Petrobras Brazil 4 years (Option for 4 years) 100% 100% commencing early 2010 100% 100% 100% 100% 100% Skandi Acergy Subsea construction 28 -Aug-08 BP Norge SA (on behalf of Skarv Norwegian Sea Installation will commence in H2 2010 2.7 50% 100% 100% Licensees) Toisa Proteus (chartered) Subsea construction 3-Jul-07 Apac he Energy Australia NA 1.1 13-Feb-08 Woodside Australia NA 2.7 1-Jul-09 BHP Billiton Australia Commencing in the second half of 4.0 100% 100% 2009. 100% 100% 100% 100% 100% Acergy Condor Flexible pipelay Pertinacia Flexible pipelay Acergy Eagle Subsea construction Acergy Osprey Subsea construction SHL S5000 (through JV, 1H Subsea construction 2010) Acergy Havila (1H 2010) Subsea construction Others Acergy Petrel Survey/ IMR ships 30-Jan-07 Statoil Norway 5 years 0% 0% 0% 0% 0% Acergy Viking Survey/ IMR ships 30-Jan-07 Statoil Norway 5 years 100% 100% 100% 100% 75% Far Saga Survey/ IMR ships Source:Normand Deutsche Mermaid Bank, Company Survey/ data IMR ships

Page 81 Polar Bjorn Survey/ IMR ships

Page 82 Page 82 Oil Services European Oil&Gas 7 December2009 Figure 123: Saipem asset utilisation Contract award Estimated term Date Client Name Region Term (yrs) 2008 2009 2010 2011 2012 Semac pipelayer Construction Vessel 28-Oct-08 PDVSA Gas S.A. Venezuela End of 2009 17% 100% 0% 0% 0% Saipem 3000 Self propelled DP crane vessel 5-Oct-05 Total Angola 3Q 2006 5-May-05 Total Nigeria 2008 2-Dec-05 Esso Exploration Angola NA 14-Jun-06 Eni Congo Summer 2007 28-Dec-06 CNR International Gabon Q2 2009 28-Dec-06 Cabinda Gulf Oil Company Angola Q2-Q4 2008 4-Apr-07 Cabinda Gulf Oil Company Angola Q2 2008 28-Mar-08 Elf Petroleum Nigeria Limited (Total) Nigeria 2011 28-May-08 Total Angola Second Half of 2009 28-Jul-09 Esso Exploration Angola 2011 14-Oct-09 SNEPCo Nigeria NA 3 100% 100% 100% 100% 100% Saipem FDS (earlier Saibos Multi-purpose monohull dynamically 7-May-03 Esso Exploration Angola Angola Q3 2005 FDS) positioned crane and pipelay (J-lay) 5-Oct-05 Total Angola 3Q 2006 vessel 5-May-05 Total Nigeria 2008 2-Dec-05 Esso Exploration Angola NA 4-Aug-06 Burullus Gas Company Egypt End 2007 28-Mar-08 Elf Petroleum Nigeria Limited (Total) Nigeria 2011 28-May-08 Burullus Gas Company Egypt Second Half of 2009 28-Jul-09 Esso Exploration Angola 2011 14-Oct-09 SNEPCo Nigeria NA 3 100% 100% 100% 100% 100% Castoro Sei Semisubmersible pipelay vessel 24-Aug-04 BBL Company UK 3Q 2006 8-Mar-05 Talisman Energy UK 3Q 2006 14-Jun-06 Total UK Q4 2007 14-Jun-06 Maersk Oil OG Gas UK Q4 2007 16-Feb-07 MEDGAZ Algeria/ Spain 2008 100% 19-Sep-07 ENAGAS Spain 1 year 100% 100% 100% 0% 0% 0% Castoro 6 Pipelaying Vessel 28-Nov-03 BP UK 2Q 2005 22-Dec-03 EnCana UK UK Summer/ 3Q 2006 30-Mar-04 Dolphin Energy Limited Qatar 1H 2006

Castoro 7 28-Jul-09 Eni Italy 25%0%0%0% Castoro II Derrick/lay barge 19-Sep-07 Saudi Aramco Saudi Arabia 7 years 100% 100% 100% 100% 100% Castoro Otto Self propelled derrick/lay ship 16-Jul-03 Elf Petroleum Nigeria Limited (Total) Nigeria Q4 2005 16-Jul-03 Nigerian National Petroleum Corporation/Mobil Nigeria Q2 2005 2-Dec-05 Thai Oil Thailand Summer 2007 4-Apr-07 Eni Australia Q3 2008 75% 13-May-09 Premier Oil Natuna Sea B.V. Indonesia Completion by Q4 2011 50% 100% 100% 75% 50% 100% 100% 0% Source: Deutsche Bank, Company data Deutsche Bank AG/London Deutsche Bank

Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009 Figure 124: Saipem asset utilization continued… Contract award Estimated term Date Client Name Region Term (yrs) 2008 2009 2010 2011 2012 Saipem 7000 Semisubmersible crane and 28-Nov-03 ExxonMobil Canada N America Summer 2006 pipelaying (J-lay) DP vessel 22-Dec-03 EnCana UK UK Summer/ 3Q 2006 3-Jun-04 Norsk Hydro Norway Summer 2006 27-Oct-04 Aker Kvaerner Offshore Partners (AKOP) Norway 2008 2-Dec-05 Pemex Exploracion y Produccion Mexico 2H 2006 4-Aug-06 Companhia Mexilhao do Brasil Brazil H1 2009 16-Feb-07 MEDGAZ Algeria/ Spain 2008 4-Apr-07 BP Norway 2008-2010 100% 100% 100% 100% 0% 0% S 355 Derrick/lay barge 14-Jun-06 Devon Energy N America NA 4-Apr-07 Cabinda Gulf Oil Company Angola Q2 2008 50% 50%0%0%0%0% Crawler Derrick/lay barge 4-Apr-07 BG Tunisia Q2 2008 50% 9-Jul-07 Petrobel Egypt H2 2007 50%0%0%0%0% Castoro One (Under Constr.) Pipe lay vessel Saipem FDS2 (Under Constr.) Field development vessel New DSV (Under Constr.) DSV Normand Cutter Installation and Construction DP Reel Installation and Construction Hos Innovator Installation and Construction Harvey Discovery Installation and Construction OC 280 Installation and Construction FPSO Firenze FPSO FPSO Mystras FPSO FPSO Cidade de Vitória FPSO FPSO Gimboa FPSO

Others

S 44 Launching/cargo barge S 600 Launching/cargo barge Castoro XI Heavy duty cargo barge S45 Launching/cargo barge Castoro 9 Launching/cargo barge S42 Launching/cargo barge SB 103 Cargo barge Semac 1 Semisubmersible pipelay barge Kencana HL Trans Thai-Malaysia (TTM) Castoro 10 Trench/pipelay barge 2007 0% 0% 0% 0% 0% Petroleum Authority of Thailand (PTT) Castoro 8 Trench/pipelay barge 14-Jun-06 Taiwanese National Oil Company SB 230 Work/pipelaying/accommodatio n barge Castoro 12 Shallow water pipelay barge, Caspian Sea service Ersai 1 Ersai Caspian Contractor Llc Saipem TRB Trench/pipelay barge TRB Tender 4 post trenching/backfilling crafts Piper Lay Barge Bar Protector DP dive support vessel Grampian Surveyor Survey and IRM Far Sovereign Multi-functional anchor handling tug and service vessel Source: Deutsche Bank, Company data

Page 83

Page 84 Page 84 Oil Services European Oil&Gas 7 December2009

Figure 125: Saipem asset utilization … drilling Contract award Estimated term Date Client Name Region Term (yrs) 2008 2009 2010 2011 2012 Jack up Perro Negro 2 96% 45% 90% 90% 90% Perro Negro 3 60% 90% 90% 90% 90% Perro Negro 4 21-Feb-03 Petrobel Africa End 2004 19-Jan-05 Petrobel Africa 2 years 100% 90% 90% 90% 90% Perro Negro 5 94% 90% 90% 90% 90% Perro Negro 6 (Under 90% 90% 90% 90% Perro Negro 7 100% 90% 90% 90% 90% Semisub Scarabeo 3 100% 69% 90% 90% 90% Scarabeo 4 100% 40% 90% 90% 90% Scarabeo 5 70% 90% 90% 90% 90% Scarabeo 6 100% 65% 90% 68% 0% Scarabeo 7 75% 87% 90% 90% 90% Scarabeo 8 (Under Constr.) 48% 90% 90% Scarabeo 9 (Under Constr.) 48% 90% 90% Drillship Saipem 10000 100% 90% 90% 90% 90% Saipem 12000(Under Constr.) 32% 90% 90%

Onshore Number of rigs Rig power 42 HP<=1500 98% 78% 79% 79% 79% 29 1500

7 December 2009 Oil & Gas European Oil Services

Figure 126: Seadrill asset utilisation Client Name Location Start date End date 2008 2009 2010 2011 2012 Drillships existing West Navigator Shell Norway Oct-05 Dec-08 100% Shell Norway Jan-09 Dec-12 100% 100% 100% 100% 100% 100% 100% 100% 100% West Capella Total Nigeria Mar-09 Mar-14 83% 100% 100% 100% Total 83% 100% 100% 100% West Polaris Exxon Worldwide Oct-08 Oct-11 25% 100% 100% 75% Exxon Worldwide Oct-11 Oct-12 25% 75% 25% 100% 100% 100% 75% Drillships newbuild West Gemini 0% 0% 0% 0% 0% 0% Semisub existing West Alpha StatoilHydro Norway Feb-06 Apr-09 100% 33% Consortium Norway May-09 Feb-12 67%100%100%17% 100% 100% 100% 100% 17% West Venture StatoilHydro Norway Feb-00 Jul-10 100% 100% 58% Option 1X1 Aug-10 Aug-11 100% 100% 58% 0% 0% West Phoenix Total Norway Dec-08 Jan-12 100% 100% 100% 100% 0% 100% 100% 100% 100% 0% West Sirius Devon GOM Jul-08 Jul-14 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% West Hercules Husky NA Nov-08 Nov-11 100% 100% 100% 92% 0% 100% 100% 100% 92% 0% West Aquarius Exxon Worldwide Feb-09 Feb-13 100% 100% 100% 100% 100% 100% 100% 100% West Eminence Petrobras Brazil Jun-09 Jun-15 100% 100% 100% 100% 100% 100% 100% 100% West Taurus Petrobras Brazil Feb-09 Feb-15 100% 100% 100% 100% 100% 100% 100% 100% Semisub newbuild West Orion Petrobras Brazil Jul-10 Jul-16 100% 100% 100% 100% 100% 100% West Capricorn 0% 0% 0% 0% Jackup existing West Epsilon StatoilHydro Oct-06 Dec-10 100% 100% 100% 100% 100% 100% 0% 0% West Janus NA NA Jun-07 Jul-08 58% PCPPOC Malaysia Aug-08 Aug-11 42% 100% 100% 67% 100% 100% 100% 67% 0% West Larissa Viesto Petro Vietnam Oct-07 Mar-09 100% 25% Malaysia Mar-09 Dec-09 75% 100% 100% 0% 0% 0% West Titania (Sold)

West Prospero Exxon Malaysia Jul-07 Oct-08 75% Talisman Oct-08 Nov-08 17% RSPC East Africa Dec-09 Jun-10 8% 50% 92% 8% 50% 0% 0% West Atlas Coogee Resources Australia Sep-07 Jan-09 100% 8% Coogee Resources Australia Feb-09 Oct-09 75% 100% 83% 0% 0% 0% West Triton Apache Australia Jan-08 Feb-09 100% 17% PTTEP Australia Australia Aug-09 Nov-09 33% 100% 50% 0% 0% 0% West Ariel VSP Vietnam Jan-09 Aug-09 67% VSP Vietnam Aug-09 Oct-10 33% 100% 83% 100% 100% 83% 0% 0% Source: Deutsche Bank, Company data

Deutsche Bank AG/London Page 85 7 December 2009 Oil & Gas European Oil Services

Figure 127: Seadrill asset utilisation continued… Client Name Location Start date End date 2008 2009 2010 2011 2012 Jackup newbuild West Callisto 0% 0% 0% 0% 0% 0% West Juno 0% 0% 0% 0% 0% 0% West Leda 0% 0% 0% 0% 0% 0% West Elara 0% 0% 0% 0% 0% 0% Tender existing T3 NA NA Dec-07 Jun-08 50% PTT Thailand Jul-08 Jun-12 50% 100% 100% 100% 58% 100% 100% 100% 100% 58% T4 NA NA Apr-03 Apr-08 33% Chevron Thailand Jul-08 Jul-13 58% 100% 100% 100% 100% 92% 100% 100% 100% 100% T6 CPOC/Carigali/PTTEP Thailand Dec-07 Dec-10 100% 100% 100% 100% 100% 100% 0% 0% T7 Chevron Thailand Nov-06 Oct-11 100% 100% 100% 83% 0% 100% 100% 100% 83% 0% T8 (Warm Stacked) Total Congo May-07 May-08 May-08 Jun-09

T9 Exxon Malaysia Feb-06 Jan-09 100% 8% Exxon Malaysia Feb-09 Jan-12 92% 100% 100% 8% 100% 100% 100% 100% 8% T10 CarigaliHess JDA-Gulf of Thailand Sep-07 Aug-10 100% 100% 67% Option 1 year Sep-10 Aug-11 100% 100% 67% 0% 0% Teknik Berkat Aug-07 Apr-08 33% PetroCarigali Malaysia Apr-08 Apr-12 67% 100% 100% 100% 33% 100% 100% 100% 100% 33% West Alliance Jan-08 Jan-10 100% 8% Southeast Asia Jan-10 Jan-15 92% 100% 100% 100% 100% 100% 100% 100% 100% West Menang Total Congo Jan-08 Dec-10 100% 100% 100% 100% 100% 100% 0% 0% West Pelaut Shell Brunei Apr-04 Mar-09 100% 25% Apr-09 Mar-12 75%100%100%25% 100% 100% 100% 100% 25% West Setia Murphy Malaysia Dec-06 Dec-08 100% Murphy Malaysia Jan-09 May-09 42% Cabinda gulf Oil co./Chevron Angola Aug-09 Aug-12 42%100%100%67% 100% 83% 100% 100% 67% West Berani Newfield Malaysia Jan-07 Dec-08 100% conocoPhillips Indonesia Jan-09 Dec-11 100% 100% 100% 0% 100% 100% 100% 100% 0% T11 May-08 May-13 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Tender newbuild T12 0% 0% 0% 0% 0% 0% West Vencedor Cabinda gulf Oil co./Chevron Angola Mar-10 Mar-15 75% 100% 100% 75% 100% 100% West Berani III 0% 0% 0% 0% Source: Deutsche Bank, Company data

Page 86 Deutsche Bank AG/London

Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009 Figure 128: Subsea 7 asset utilisation Vessel type Contract award Client Name Region Term Estimated term (yrs) 2008 2009 2010 2010 2012 Date Sealion Amazonia Pipelay and construction vessel Kommandor 3000 Pipelay and construction vessel Lochnagar Pipelay and construction vessel Normand Seven Pipelay and construction vessel 10-Sep-09 Petrobras Brazil 4 years, commencing 25%100%100%100% in Q3'09

Seven Oceans Pipelay and construction vessel 23-Jul-07 Petrobras Brazil 2010 100% 20-Aug-08 Marathon Oil corporation USA Strating in Q3 2009 1.6 10% 100% 100% 100% 10% 0% Seven Seas Pipelay and construction vessel 29-Nov-07 BP Norge AS North Sea Engg. starts 1.6 immediately, offshore installation between 2009-2011 3-Jul-08 Not disclosed West Africa NA 1.6 50% 3-Sep-08 A/S Norske Shell North Sea Engg. starts 1.6 immediately, offshore installation scheduled in 2009. 4-Mar-09 StatoilHydro North Sea Completion by 2.3 September 2009 50%100%100%100%100% Seven Sisters Pipelay and construction vessel 16-Jul-08 Venture Production Plc North Sea Starting Late 2008 1.6 25% 100% 35% 0% Seven Navica Pipelay and construction vessel 3-Oct-07 BP Norge AS North Sea Starting in 2010, 1.6 offshore operations start in Q2'2010 16-Jul-08 Venture Production Plc North Sea Starting Late 2008 1.6 25% 25-Sep-09 Santos Limited Australia NA 2.7 25%100%100%100%100% Skandi Neptune Pipelay and construction vessel Skandi Seven Pipelay and construction vessel Subsea Viking Pipelay and construction vessel Toisa Perseus Pipelay and construction vessel

Others

Rockwater 1 Dive support vessel 16-Jul-08 Venture Production Plc North Sea Starting Late 2008 1.6 25% 100% 35% 0% 0% Rockwater 2 Dive support vessel 25-Sep-09 Santos Limited Australia NA 2.7 25% 100% 100% 45% Seven Atlantic Dive support vessel Skandi Bergen ROV support vessel Pelican Dive support vessel 19-Aug-09 Maersk Oil North Sea UK North Sea Work commences in 2.3 38% 100% 33% 0% Ltd Q4'09 Seven Spray Air diving support vessel Toisa Polaris Dive support vessel Kommandor Subsea 2000 ROV support vessel Kommandor Subsea ROV support vessel Normand Subsea 7 ROV support vessel Seisranger ROV & survey support vessel Nordica

Source: Deutsche Bank, Company data

Page 87

Page 88 Page 88 Oil Services European Oil&Gas 7 December2009 Figure 129: Technip asset utilisation Vessel type Contract award Client Name Region Term Estimated 2008 2009 2010 2011 2012 Date term (yrs) Apache Construction and Pipelaying Vessel 10-Oct-08 E.ON Ruhrgas UK North Sea Ltd North Sea Offshore installation is scheduled to 1.9 commence in the second quarter of 2009. 17-Oct-08 Wintershall Noordzee B.V. * North Sea Offshore operations are scheduled to 1.9 commence in the first quarter of 2009. 5-Jun-07 Talisman Energy Norway 2008-2009 13-Jul-07 Mariner Energy, Inc * Gulf of Mexico Q4 2007 9-Aug-07 Statoil Norway Summer 2008 29-Aug-07 Statoil Norway 2009 26-May-09 BHP Billiton* Trinidad & NA 2.8 50% Tobago 100% 100% 100% 100% 50% Constrcutor Construction and Pipelaying Vessel 5-Dec-07 Aker Resources India 2008

21-Jan-08 Petrobras America Gulf of Mexico Offshore installation is scheduled to 1.9 commence in the third quarter of 2009 17-Jul-08 Nigerian Agip Exploration Ltd. Nigeria Summer 2009 8-Dec-08 Aker India Offshore installation is scheduled for the first 1.9 half of 2009 100% 100% 100% 100% 0% Deep Blue Construction and Pipelaying Vessel 27-Feb-07 BHP Billiton * US Q1 2008

28-Mar-07 Shell * Mexico Q4 2007 13-Aug-07 Bluewater Industries* Gulf of Mexico 2008 4-Sep-07 Petrobras Brazil Q4 2008 2-Jan-08 Total Angola Offshore installation will commence in 2010 1.9

17-Jan-08 Shell * Gulf of Mexico NA 1.9 21-Jan-08 Petrobras America Gulf of Mexico Offshore installation is scheduled to 1.9 commence in the third quarter of 2009 19-Jun-08 Callon Petroleun Company * Gulf of Mexico 3Q 2008 12-Sep-08 BP Angola Angola H1 2010 12-May-09 Bluewater Industries* Gulf of Mexico Q1'10 and Q2'10 2-Jun-09 Anadarko Petroleum* Gulf of Mexico NA 2.8 17-Jul-09 Anadarko Petroleum Corp* Gulf of Mexico Q3 2010 25-Aug-09 Marathon Oil Company Gulf of Mexico Q2 2010 25-Sep-09 BP Gulf of Mexico Q3 2010 22-Oct-09 Tullow Ghana Ltd Ghana NA 2.8 9-Nov-09 Eni US Gulf of Mexico Apr-10 100% 100% 100% 100% 100% Deep Pioneer Construction and Pipelaying Vessel 2-Jan-08 Total Angola Offshore installation will commence in 2010 1.9

9-Apr-08 Husky Oil Operations Ltd Canada Offshore installati on is scheduled for 2009 1.9 12-May-09 Bluewater Industries* Gulf of Mexico Q1'10 and Q2'10 22-Oct-09 Tullow Ghana Ltd Ghana NA 2.8 9-Nov-09 Eni US Gulf of Mexico Apr-10 0% 100% 100% 100% 100% Normand Progress Construction and Pipelaying Vessel 22-Oct-08 Petrobras Brazil 2 years (+2 years option) 17% 100% 83% 0% 0%

Orelia Construction and Pipelaying Vessel 10-Oct-08 E.ON Ruhrgas UK North Sea Ltd North Sea Offshore installation is scheduled to 1.9 0% 80% 100% 0% 0% commence in the second quarter of 2009. Skandi Achiever Construction and Pipelaying Vessel 17-Oct-08 Wintershall Noordzee B.V. * North Sea Offshore operations are scheduled to 1.9 0% 0% 0% commence in the first quarter of 2009. 9-Nov-09 Eni US Gulf of Mexico Apr-10 0% 100% 100% 0% 0% Skandi Arctic Construction and Pipelaying Vessel 18-Jun-08 Statoil Hydro Norway 2009 50% 100% 50% 0% 0% Deutsche Bank AG/London Deutsche Bank Sunrise 2000 Construction and Pipelaying Vessel 6-Mar-07 Petrobras Brazil 4 years 100% 100% 25% 100% 100% TS7 Construction and Pipelaying Vessel 30-Apr-08 MISC Berhad * Vietnam Q4 2008 50% 0% 0% 0% 0% Wellservicer Construction and Pipelaying Vessel 9-Apr-08 Husky Oil Operations Ltd Canada Offshore installation is scheduled for 2009 1.9 100% 80% 0% 0% Alliance Construction and Pipelaying Vessel Seamec 1 Construction and Pipelaying Vessel Seamec 2 Construction and Pipelaying Vessel Seamec 3 Construction and Pipelaying Vessel Venturer Construction and Pipelaying Vessel Source:Geoholm Deutsche Bank, Company Construction data and Pipelaying Vessel Seamec Princess Construction and Pipelaying Vessel

7 December 2009 Oil & Gas European Oil Services Appendix L: Gearing analysis

Figure 130: Net cash* (debt)/ market cap

70%

50% 30%

10% -10%

-30%

Net cash/ Market cap -50%

-70% AMEC Acergy Seadrill Saipem Technip Lamprell Petrofac Subsea 7 Wood Group Group Wood Aker Solutions Tecnicas Reunidas

Source: Deutsche Bank, company data; *For Technicas, Technip, Acergy, Saipem and Subsea 7 we have included pre-payments. Broadly speaking, pre-payments will represent c. 40% of net cash (fluctuations however can see this proportion up to 65%).

Deutsche Bank AG/London Page 89 7 December 2009 Oil & Gas European Oil Services Appendix M: Contract strategy analysis

Figure 131: Acergy contract strategy Figure 132: Aker Solutions contract strategy

100% 24% 100% 8% 90% 90% 8% 22% 80% 80% 7% 70% 20% 70% 7% 60% 6% 60% 18% 50% 50% 6% 40% 16% 40% 5% % contracts % % contracts EBITDA margin EBITDA 30% 14% margin EBITDA 30% 5% 20% 20% 4% 12% 10% 10% 4% 0% 10% 0% 3% 2004 2005 2006 2007 2008 2009 YTD 2004 2005 2006 2007 2008 2009 YTD

Lump sum Cost plus (Capex) Cost plus (Opex) Lump sum Cost plus (Capex) Cost plus (Opex) Unit price EBITDA margin * Unit price EBITDA margin *

Source: Deutsche Bank and company data, * 2007 EBITDA margin is after considering the $27 mn provisions Source: Deutsche Bank and company data, * Excludes pulping and power division which is discontinued. on losses in the Mexilhao Trunkline Project (Q4'07). Figure 133: Amec contract strategy Figure 134: Lamprell contract strategy

100% 11.0% 100% 20% 90% 19% 90% 10.0% 80% 80% 18% 9.0% 70% 70% 17% 60% 8.0% 60% 16% 50% 7.0% 50% 15% 40% 6.0% 40% 14% % contracts % % contracts

30% margin EBITDA

EBITDA margin 30% 13% 5.0% 20% 20% 12% 4.0% 10% 10% 11% 0% 3.0% 0% 10% 2005 2006 2007 2008 2009 YTD 2004 2005 2006 2007 2008 2009 YTD

Lump sum Cost plus (Capex) Cost plus (Opex) Lump sum Cost plus (Capex) Cost plus (Opex) Unit price EBITDA margin Unit price EBITDA margin

Source: Deutsche Bank, company data Source: Deutsche Bank, company data Figure 135: Petrofac contract strategy Figure 136: Saipem contract strategy

100% 11.0% 100% 12.5% 90% 90% 12.0% 80% 10.0% 80% 11.5% 70% 70% 9.0% 60% 60% 11.0% 50% 8.0% 50% 10.5% 40% 40% 10.0% % contracts % contracts % 7.0% 30% EBITDA margin 30% EBITDA margin 9.5% 20% 20% 6.0% 9.0% 10% 10% 0% 5.0% 0% 8.5% 2004 2005 2006 2007 2008 2009 YTD 2004 2005 2006 2007 2008 2009 YTD

Lump sum Cost plus (Capex) Cost plus (Opex) Lump sum Cost plus (Capex) Cost plus (Opex) Unit price EBITDA margin * Unit price EBITDA margin *

Source: Deutsche Bank and company data, * Excludes pulping and power division which is discontinued. Source: Deutsche Bank and company data, * Excludes Drilling business

Page 90 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 137: Subsea 7 contract strategy Figure 138: Technip contract strategy

100% 14% 100% 24% 90% 13% 90% 22% 80% 12% 80% 70% 11% 70% 20% 60% 10% 60% 18% 50% 9% 50% 16% 40% 8% 40% contracts % EBITDA margin EBITDA % contracts % c 30% 7% 30% 14% margin EBITDA 20% 6% 20% 12% 10% 5% 10% 0% 4% 0% 10% 2004 2005 2006 2007 2008 2009 YTD 2005 2006 2007 2008 2009 YTD

Lump sum Cost plus (Capex) Cost plus (Opex) Lump sum Cost plus (Capex) Cost plus (Opex) Unit price EBITDA margin Unit price EBITDA margin *

Source: Deutsche Bank, company data Source: Deutsche Bank and company data,.* 2007 EBITDA margin includes the impact of $50mn charge for petrochemical project in Saudi Arabia (Q3'07) and also the impact of $200mn charge in Qatargas and $70mn charge in other projects (Q4'07) Figure 139: Tecnicas contract strategy Figure 140: Wood Group contract strategy

100% 6.5% 100% 10.0% 90% 90% 6.0% 80% 80% 9.0% 70% 5.5% 70% 60% 5.0% 60% 8.0% 50% 50% 4.5% 40% 40% 7.0% % contracts % contracts 30% margin EBITDA 4.0% 30% EBITDA margin 20% 20% 6.0% 3.5% 10% 10% 0% 3.0% 0% 5.0% 2004 2005 2006 2007 2008 2009 YTD 2005 2006 2007 2008 2009 YTD

Lump sum Cost plus (Capex) Cost plus (Opex) Lump sum Cost plus (Capex) Cost plus (Opex) Unit price EBITDA margin Unit price EBITDA margin

Source: Deutsche Bank, company data Source: Deutsche Bank, company data

Deutsche Bank AG/London Page 91 7 December 2009 Oil & Gas European Oil Services Appendix N: NOC/IOC exposure

Figure 141: NOC/IOC split in contract wins across 2008/ 09 YTD

Wood Aker TecnicasPetrofac Saipem Seadrill Subsea 7 Group Acergy Technip Solutions AMEC Lamprell 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2009 YTD 2009 YTD 2009 YTD 2009 YTD 2009 YTD 2009 YTD 2009 YTD 2009 YTD 2009 YTD 2009 YTD 2009 YTD

NOC Pure IOC Average NOC exposure

Source: Deutsche Bank, Company data; Lamprell is based in the Middle East and we expect, near term, for it to win contracts from NOCs which currently represent 10% of its bid pipeline.

Page 92 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Appendix O: Licenses awarded by depth (onshore and offshore)

Figure 142: Deepwater exploration licenses (i.e. >400m) Figure 143: Deepwater development license term lengths awarded since 2000 have risen significantly are generally a lot longer than exploration licenses

1,400 30 1,200 25 1,000 20 800 15 600 Years 10 400 Licenses awarded Licenses 5 200 - - 2000 2001 2002 2003 2004 2005 2006 2007 2008 2000 2001 2002 2003 2004 2005 2006 2007 2008

Exploration Exploration Development

Source: Wood Mackenzie, Deutsche Bank Source: Wood Mackenzie, Deutsche Bank Figure 144: Shallow water licenses (i.e. <400m) awarded Figure 145: Shallow water license average term length since 2000 has increased almost tenfold since 2000 has remained broadly constant

30 1,200 25 1,000 20 800 15

600 Years 10 400 5 200 Count of licenses awarded - - 2000 2001 2002 2003 2004 2005 2006 2007 2008 2000 2001 2002 2003 2004 2005 2006 2007 2008 Exploration Development

Source: Wood Mackenzie, Deutsche Bank Source: Wood Mackenzie, Deutsche Bank Figure 146: Onshore licenses awarded since 2000 has Figure 147: Onshore license average term length since increased almost fourfold 2000 has remained broadly constant

30 2,100 25 1,800 20 1,500 15 1,200 Years 10 900 5 600 - 300 Count of licenses awarded licenses of Count 2000 2001 2002 2003 2004 2005 2006 2007 2008 - 2000 2001 2002 2003 2004 2005 2006 2007 2008 Exploration Development

Source: Wood Mackenzie, Deutsche Bank Source: Wood Mackenzie, Deutsche Bank

Deutsche Bank AG/London Page 93 7 December 2009 Oil & Gas European Oil Services Appendix P: Wind power capacity

Figure 148: Global annual wind power capacity Figure 149: Global installed wind power capacity additions

350,000 60,000 300,000 50,000 250,000 40,000 200,000 MW

MW 30,000 150,000

20,000 100,000

10,000 50,000

0 - 2007 2008 2009 2010 2011 2012 2013 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Europe North America Asia Latin America Pac if ic Middle East and Africa

Source: Deutsche Bank, GWEC Source: Deutsche Bank, GWEC Wind power capacity (2007/08) by region

Figure 150: Installed wind power capacity in Europe Figure 151: Installed wind power capacity in N America

18,000 30,000 16,000 14,000 25,000 12,000 10,000 20,000

MW 8,000

MW 15,000 6,000 4,000 10,000 2,000 - 5,000 UK Italy Spain ROE *

Ireland Poland - Turkey France Austria Greece Portugal Norway Sweden Denmark USA Canada Netherlands

End 2007 End 2008 End 2007 End 2008

Source: Deutsche Bank, GWEC, * Rest of Europe includes - Belgium,Bulgaria, Croatia, Cyprus, Czech Source: Deutsche Bank, GWEC, Republic, Estonia, Faroe Islands, Finland, Hungary, Latvia, Lithuania, Luxembourg, Romania, Russia, Slovakia, Switzerland, Ukraine Figure 152: Installed wind power capacity in Asia Figure 153: Installed wind power capacity in Latin America & Caribbean

12,000 400 350 10,000 300

8,000 250 W

M 200 W

M 6,000 150 100 4,000 50 2,000 -

- Brazil Mexico

India Japan Taiw an South Korea Others * Others * Argentina Caribbean Costa Rica

End 2007 End 2008 End 2007 End 2008

Source: Deutsche Bank, GWEC, * Others include - Philippines, Thailand, Bangladesh, Indonesia, Sri Lanka Source: Deutsche Bank, GWEC, * Others include - Colombia, Chile, Cuba

Page 94 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 154: Installed wind power capacity in Pacific Figure 155: Installed wind power capacity in Middle East region and Africa

1,400 400

1,200 350

300 1,000 250 800

MW 200 MW 600 150

400 100

200 50

- - Australia New Zealand Pacific Islands Egypt Morocco Iran Tunisia Others *

End 2007 End 2008 End 2007 End 2008 Source: Deutsche Bank, GWEC Source: Deutsche Bank, GWEC, * Others include - South Africa, Cape Verde, Israel, Lebanon, Nigeria, Jordan

Deutsche Bank AG/London Page 95 7 December 2009 Oil & Gas European Oil Services Appendix Q: Strategic analysis of the E&C themes

Given the array of functions that exists within the oil service industry, it is no surprise that Having established which each theme across the ‘oil chain’ described above will have its own characteristic competing markets we expect to show forces. Advanced technology and specialised hardware, relevant project management experience, local presence via assets or resource, strong financial capabilities as well as the the greatest growth in degree of capacity creep are to list but a few of the internal dynamics that will underpin each spend, we identify their segment’s relative and absolute margins near term. degree of margin achievement both in Whilst difficult to quantify, intuitively we know that a theme, for example, with high barriers absolute and relative terms to entry, limited competition and suffering little capacity creep and cost inflation, should realise top-quartile margins against a backcloth of strong demand for its services. With this in mind we have analysed the effect of competitive forces (please refer to Appendix R) upon each of the major oil service sub-segments. Our conclusions and their implications for margins are summarised in Figure 156. This strategic analysis has helped us to determine which themes we believe are best placed to deliver relative performance over the forecast period.

Having liaised with the companies under our coverage, as well as Wood Mackenzie and various other industry professionals, we show on the next page the degree of margin evolution (both relative and absolute) we think each theme could realise across our forecast horizon.

Page 96 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 156: Degree of absolute and relative margin achievement across the development capex spectrum Typical EBITDA 2009-12E-Base Theme Summary of strategic analysis (see Appendix R) margins* case scenario* E&C themes Offshore infrastructure - Medium levels of substitution and high barriers to entry suggest that this industry is deepwater SURF structurally robust with margins expected stay resilient relative to other service segments. 15% -XX/XXX Near term however, we expect a cyclical shift in pricing power to Oil Cos and acute margin compression. Offshore facilities - deepwater 6-7% -XX/XXX As above. Onshore/offshore frontier (non- Medium levels of substitution and high barriers to entry suggest that this industry is conventional) structurally robust. Near term, we expect a cyclical shift in pricing power to Oil Cos) and 5-6% -XX moderate margin compression (exception being on larger contracts with limited competition). LNG Medium levels of substitution and barriers to entry (highest for FLNG) suggest that structurally this industry is robust with medium quartile margins expected relative to other 5-6% -XX service segments onshore. Near term, we expect a cyclical shift in pricing power to Oil Cos and moderate margin compression (exception being on $1bn+ contracts with limited competition). Onshore facilities & infrastructure Structurally weak industry with lower quartile margins (relative to other onshore themes). Near term, however, we expect a range of margin outcomes linked to regional 4-11% -XX/XXX supply/demand dynamics and relationships with client. This should see higher margins achieved in Middle East given the structurally lower cost base. Offshore infrastructure – shallow Structurally weak industry with bottom quartile margins. Near term we expect acute water OPEX margin compression due to new entrants. Upper end of margin achieved with NOCs and 3-8% -XXX/XXXX internationally based clients relative to UK and Norway which are typically IOC based and where supply/demand fundamentals are weaker. Heavy Oil sand plants Whilst this industry is a relatively fertile one, we believe the large number of players operating within oil sands against a sharp slowdown in investment will see acute margin 3-8% -XXX/XXXX compression. Exceptions here are contractors whom can offer differentiated technology and project management services. Offshore facilities - shallow water Structurally weak industry with bottom quartile margins (relative to other offshore themes). 3-4% -XXX Near term, we expect compression in margins due to a cyclical shift in pricing power. Refining and petrochemicals Structurally weak industry with bottom quartile margins (relative to other onshore themes). 3-4% -XXXX Near term, we expect acute margin compression due to a cyclical shift in pricing power and the large number of players operating in this segment. Gas to Liquids plants 3-4% -X/XX Industry still relatively fertile but structurally robust. Re-gas terminals Structurally weak industry with bottom quartile margins (relative to other onshore themes). 3-4% -XXXX Near term, we expect acute margin compression due to a cyclical shift in pricing power. * x = lowest margin downside, xxxx = highest margin downside Source: Company data, Deutsche Bank & Wood Mackenzie estimates

Deutsche Bank AG/London Page 97 7 December 2009 Oil & Gas European Oil Services Appendix R: Porter’s 5 forces on key service segments

Figure 157: Deepwater sub-sea (SURF & equipment) and facilities – We expect mid quartile margin decline near term

BarriersBarriers toto entryentry – – high high •Capital•Capital intensiveintensive businessbusiness whosewhose participantsparticipants leverageleverage thethe necessarynecessary equipmentequipment (e.g.(e.g. heavyheavy lift/pipe-layinglift/pipe-laying vessels,vessels, remoteremote operatingoperating vehicles)vehicles) andand theirtheir geographicgeographic flexibilityflexibility toto winwin deepwaterdeepwater projects.projects. (Lead(Lead timetime onon vesselvessel newnew buildsbuilds betweenbetween 3-43-4 yearsyears andand averageaverage vesselvessel costcost c.c. $350mn)$350mn) •Advanced•Advanced technologytechnology (often(often withwith longlong patentpatent expiries)expiries) onon subseasubsea equipment/systems equipment/systems andand toto aa lesserlesser degree,degree, pipe-layingpipe-laying vessels/operationsvessels/operations •Technical•Technical humanhuman expertiseexpertise inin deepwaterdeepwater (not(not toto mention current advances into ultra-deep) with StrengthStrength ofof suppliers:suppliers: mediummedium mention current advances into ultra-deep) with establishedestablished tracktrack recordsrecords •Suppliers•Suppliers equallyequally splitsplit betweenbetween steelsteel forfor constructionconstruction andand subcontractingsubcontracting functionsfunctions thatthat willwill includeinclude procurement,procurement, constructionconstruction andand installationinstallation StrengthStrength ofof buyers:buyers: medium dependingdepending onon levellevel ofof inin househouse LevelsLevels ofof substitutesubstitute competitioncompetition -- medium medium:: medium capacitycapacity (e.g.(e.g. ownerowner ofof vessels)vessels) •Medium levels of PlayersPlayers looklook toto seekseek marketmarket shareshare withwith expansionexpansion ofof theirtheir •Medium levels of •Prices•Prices ofof specialisedspecialised equipmentequipment installation capacity through new builds, vessel charters or substitutionsubstitution andand highhigh barriersbarriers installation capacity through new builds, vessel charters or to entry suggest that this shouldshould bebe resilient.resilient. convertedconverted shipsships to entry suggest that this industryindustry isis structurallystructurally robustrobust •Note•Note thatthat decreasedecrease inin rawraw TechnipTechnip (~25%), (~25%), SaipemSaipem (~30%), (~30%), AcergyAcergy (~15%), (~15%), materialmaterial andand sub-contractingsub-contracting •Medium•Medium term,term, expectexpect Aker Solutions, Seven Seas, Subsea 7 (b/w c. 5-10% cyclical led shift in pricing pricesprices potentiallypotentially passedpassed throughthrough Aker Solutions, Seven Seas, Subsea 7 (b/w c. 5-10% cyclical led shift in pricing each) power to Oil Co’s and toto BuyerBuyer dependingdepending onon initialinitial each) power to Oil Co’s and subsequent margin termsterms && conditionsconditions ofof OilOil ServiceService subsequent margin company-Buyercompany-Buyer contract.contract. contractioncontraction despitedespite limitedlimited numbernumber ofof playersplayers

ThreatThreat ofof substitutes:substitutes: lowlow •NOC•NOC andand IOCIOC investmentinvestment shiftingshifting awayaway fromfrom shallowshallow waterwater fieldsfields asas economicseconomics becomebecome moremore attractiveattractive inin deepwater.deepwater. •Size•Size ofof reserves,reserves, ultimateultimate recoveriesrecoveries andand ratesrates ofof flowflow potentiallypotentially higherhigher inin deepwater.deepwater.

Source: Deutsche Bank

Page 98 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 158: Shallow water sub-sea and facilities – We expect high quartile margin decline near term

BarriersBarriers toto entryentry –– low low •Capital•Capital intensityintensity (pipe-laying(pipe-laying vesselsvessels etc)etc) representrepresent aa lowlow barrierbarrier herehere givengiven thethe existingexisting networknetwork ofof vesselsvessels supportingsupporting suchsuch aa maturemature businessbusiness e.g.e.g. leasingleasing wouldwould bebe aa simplesimple costcost effectiveeffective optionoption •Utilises•Utilises moremore conventionalconventional (less(less technicallytechnically challenging)challenging) typestypes ofof equipmentequipment

StrengthStrength ofof suppliers:suppliers: mediummedium •Suppliers•Suppliers equallyequally splitsplit betweenbetween steelsteel forfor constructionconstruction andand subcontractingsubcontracting functionsfunctions thatthat willwill includeinclude procurement,procurement, Levels of substitute competition - high constructionconstruction andand installationinstallation Levels of substitute competition - high depending on level of in house depending on level of in house PlayersPlayers looklook toto seekseek marketmarket shareshare withwith expansionexpansion ofof theirtheir capacity (e.g. owner of vessels) capacity (e.g. owner of vessels) installationinstallation capacitycapacity throughthrough newnew builds,builds, vesselvessel charterscharters oror StrengthStrength ofof buyers:buyers: highhigh •Prices•Prices ofof specialisedspecialised equipmentequipment convertedconverted shipsships oftenoften designeddesigned forfor dualdual purposepurpose i.e.i.e. deepdeep andand •High levels of substitution shouldshould bebe resilient.resilient. shallowshallow waterwater •High levels of substitution andand lowlow barriersbarriers toto entryentry •Note that decrease in raw TechnipTechnip (~20%), (~20%), SaipemSaipem (~25%), (~25%), AcergyAcergy (~10%), (~10%), SubseaSubsea 7 7 •Note that decrease in raw suggestsuggest thatthat thisthis industryindustry isis material and sub-contracting (~10%),(~10%), material and sub-contracting structurallystructurally weakweak pricesprices potentiallypotentially passedpassed throughthrough Aker Solutions, SBM Offshore, Samsung, Mcdermott, Aker Solutions, SBM Offshore, Samsung, Mcdermott, •Medium term, expect toto BuyerBuyer dependingdepending onon initialinitial Heerema, Hyundai <5% •Medium term, expect Heerema, Hyundai <5% cyclical led shift in pricing termsterms && conditionsconditions ofof OilOil ServiceService cyclical led shift in pricing power to Oil Co’s and company-Buyercompany-Buyer contract.contract. power to Oil Co’s and acuteacute marginmargin contractioncontraction despitedespite limitedlimited numbernumber ofof playersplayers

ThreatThreat ofof substitutes:substitutes: highhigh •NOC•NOC andand IOCIOC investmentinvestment shiftingshifting towardstowards deepwaterdeepwater fieldsfields asas economicseconomics becomebecome moremore attractive.attractive. •Size•Size ofof reserves,reserves, ultimateultimate recoveriesrecoveries andand ratesrates ofof flowflow potentiallypotentially higherhigher inin deepwater.deepwater. Source: Deutsche Bank

Figure 159: Onshore/offshore frontier developments – We expect low quartile margin decline near term

BarriersBarriers toto entryentry –– high high •Technical•Technical humanhuman expertiseexpertise andand locallocal presencepresence inin somesome ofof thethe harshestharshest weatherweather conditionsconditions OilOil ServiceService companiescompanies willwill encounterencounter •Superior•Superior technologytechnology (often(often withwith longlong patentpatent expiries)expiries) onon subseasubsea equipment equipment andand advancedadvanced pipe-pipe- laylay vessels/operationsvessels/operations ableable toto dealdeal withwith harshharsh operatingoperating environmentsenvironments

StrengthStrength ofof suppliers:suppliers: mediummedium •Main•Main supplysupply isis steelsteel (up(up toto 50%50% ofof costcost base)base) withwith remainderremainder ofof StrengthStrength ofof buyers:buyers: mediummedium supplysupply chainchain splitsplit acrossacross variousvarious sub-contractingsub-contracting functionsfunctions (e.g.(e.g. •Medium•Medium levelslevels ofof Levels of substitute competition - medium construction,construction, procurement)procurement) Levels of substitute competition - medium substitutionsubstitution andand barriersbarriers toto Players look to seek market share with expansion of entryentry suggestsuggest thatthat thisthis •Prices•Prices ofof specialisedspecialised equipmentequipment Players look to seek market share with expansion of resource base in these frontier areas via build of local industryindustry isis structurallystructurally robustrobust shouldshould bebe resilient.resilient. resource base in these frontier areas via build of local contentcontent (increased(increased involvementinvolvement ofof locallocal personnel)personnel) andand •Medium•Medium term,term, expectexpect marginmargin •Note•Note thatthat decreasedecrease inin rawraw constructionconstruction yardsyards (greenfield(greenfield or or brownfieldbrownfield expansion) expansion) contractioncontraction forfor OilOil ServicesServices materialmaterial andand sub-contractingsub-contracting duedue toto downsidedownside pressurepressure onon pricesprices potentiallypotentially passedpassed throughthrough Saipem,Saipem, Technip,Technip, AkerAker Solutions, Solutions, Petrofac,Petrofac, Daewoo,Daewoo, suppliersupplier pricesprices andand greatergreater toto BuyerBuyer dependingdepending onon initialinitial Linde,Linde, Hyundai,Hyundai, SNCSNC LavalinLavalin resistanceresistance fromfrom OilOil co’sco’s termsterms && conditionsconditions ofof OilOil ServiceService (exception:(exception: $1bn+$1bn+ contractscontracts company-Buyercompany-Buyer contract.contract. withwith limitedlimited competition)competition)

ThreatThreat ofof substitutes:substitutes: mediummedium •NOC•NOC andand IOCIOC investmentinvestment shiftingshifting awayaway fromfrom traditionaltraditional moremore accessibleaccessible areasareas asas economicseconomics becomebecome moremore attractiveattractive inin frontierfrontier developmentsdevelopments •Size•Size ofof reservesreserves andand ultimateultimate recoveriesrecoveries potentiallypotentially higherhigher inin frontierfrontier developmentsdevelopments

Source: Deutsche Bank

Deutsche Bank AG/London Page 99 7 December 2009 Oil & Gas European Oil Services

Figure 160: LNG – We expect low quartile margin decline near term

BarriersBarriers toto entryentry –– medium medium •Large•Large scalescale projectsprojects requiring requiring contractorscontractors withwith strongstrong balancebalance sheetssheets givengiven turnturn keykey naturenature ofof LNGLNG awardsawards •Established•Established relationshipsrelationships withwith NOCsNOCs (from (from whomwhom aa largerlarger numbernumber ofof LNGLNG contractscontracts originate)originate) •Regional•Regional presencepresence andand partnershippartnership withwith locallocal personnel.personnel. NecessaryNecessary infrastructureinfrastructure (e.g.(e.g. yards)yards) requiredrequired forfor constructionconstruction andand installationinstallation phasesphases •Technology licensed out selectively StrengthStrength ofof suppliers:suppliers: mediummedium •Technology licensed out selectively •Main•Main supplysupply isis steelsteel (up(up toto 50%50% ofof costcost base)base) withwith remainderremainder ofof StrengthStrength ofof buyersbuyers -- low low supplysupply chainchain splitsplit acrossacross variousvarious sub-contractingsub-contracting functionsfunctions (e.g.(e.g. •Medium•Medium levelslevels ofof construction, procurement) substitutionsubstitution andand barriersbarriers toto construction, procurement) LevelsLevels ofof substitutesubstitute competitioncompetition -- medium medium entryentry suggestsuggest thatthat thisthis •Prices•Prices ofof specialisedspecialised equipmentequipment OnlyOnly largestlargest playersplayers ableable toto handlehandle increasingincreasing industryindustry isis structurallystructurally shouldshould bebe resilient.resilient. numbernumber ofof EPICEPIC contractscontracts valuedvalued >> $1bn.$1bn. robustrobust •Note•Note thatthat decreasedecrease inin rawraw TechnipTechnip (~5%), (~5%), ChiyodaChiyoda (~5%),(~5%), JGCJGC (~5%),(~5%), •Medium•Medium term,term, expectexpect materialmaterial andand sub-contractingsub-contracting SiapemSiapem (~5%) (~5%) marginmargin contractioncontraction forfor OilOil pricesprices potentiallypotentially passedpassed throughthrough ServicesServices duedue toto downsidedownside toto BuyerBuyer dependingdepending onon initialinitial SNCSNC LavalinLavalin , , KBR,KBR, CBI,CBI, SamsungSamsung (<5%)(<5%) pressurepressure onon suppliersupplier pricesprices termsterms && conditionsconditions ofof OilOil ServiceService andand greatergreater resistanceresistance fromfrom company-Buyercompany-Buyer contract.contract. OilOil co’sco’s (exception: (exception: $1bn+$1bn+ contractscontracts withwith limitedlimited competition)competition)

ThreatThreat ofof substitutes:substitutes: lowlow •Economies•Economies ofof scalescale (bolt(bolt onon liquefactionliquefaction trainstrains aroundaround existingexisting infrastructureinfrastructure && establishedestablished supplysupply chain)chain) increasesincreases attractivenessattractiveness ofof LNGLNG vs.vs. otherother advancedadvanced energyenergy alternativesalternatives e.g.e.g. GTLGTL •Monetisation•Monetisation ofof gasgas usingusing pipelinespipelines increasinglyincreasingly difficultdifficult forfor strandedstranded reserves.reserves. LNGLNG moremore feasiblefeasible optionoption

Source: Deutsche Bank

Page 100 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 161: Deepwater drilling – Day rates expected to show varying results; however structurally a robust industry

BarriersBarriers toto entryentry –– high high •Capital•Capital intensiveintensive businessbusiness whosewhose participantsparticipants leverageleverage thethe necessarynecessary assetsassets (e.g.(e.g. drillships,drillships, semi-semi- submersiblesubmersible rigs)rigs) andand theirtheir geographicgeographic flexibilityflexibility toto winwin deepwaterdeepwater drillingdrilling contracts.contracts. (Lead(Lead timetime onon rigrig newnew buildsbuilds betweenbetween 3-43-4 yearsyears andand averageaverage rigrig costcost betweenbetween $100-300mn)$100-300mn) •Advanced•Advanced drillingdrilling technologytechnology requiredrequired onon ultraultra deepwaterdeepwater fieldsfields •Technical•Technical humanhuman expertiseexpertise withwith establishedestablished tracktrack recordsrecords

StrengthStrength ofof suppliers:suppliers: lowlow StrengthStrength ofof buyers:buyers: lowlow Levels of substitute competition - medium •Key•Key supplysupply toto drillersdrillers willwill bebe drilldrill Levels of substitute competition - medium •Medium•Medium levelslevels ofof substitutionsubstitution bitbit componentscomponents e.g.e.g. casing,casing, PlayersPlayers looklook toto seekseek marketmarket shareshare withwith expansionexpansion ofof theirtheir andand highhigh barriersbarriers toto entryentry specialisedspecialised fluidsfluids forfor wellwell holehole drillingdrilling capacitycapacity throughthrough newnew buildsbuilds andand rigrig charterscharters suggestsuggest thatthat thisthis industryindustry isis etc.etc. ExpectExpect cyclicalcyclical ledled uptickuptick in in structurallystructurally robustrobust Transocean 15%, Seadrill 10%, Pride 5%, Saipem 2%, demanddemand forfor thesethese materialsmaterials andand Transocean 15%, Seadrill 10%, Pride 5%, Saipem 2%, Nabors, Scorpion, Fred Olsen <1% •Expect•Expect marginmargin expansionexpansion forfor aa subsequentsubsequent riserise inin suppliersupplier pricesprices Nabors, Scorpion, Fred Olsen <1% limitedlimited numbernumber ofof playsplays givengiven •In•In thethe contextcontext ofof newnew buildbuild increasingincreasing demanddemand forfor capacitycapacity mainmain supplysupply isis steelsteel deepwaterdeepwater drillingdrilling againstagainst aa relativelyrelatively tighttight supplysupply outlookoutlook

ThreatThreat ofof substitutes:substitutes: lowlow •NOC•NOC andand IOCIOC investmentinvestment shiftingshifting towardstowards deepwaterdeepwater fieldsfields asas economicseconomics becomebecome moremore attractive.attractive. •Size•Size ofof reserves,reserves, ultimateultimate recoveriesrecoveries andand ratesrates ofof flowflow potentiallypotentially higherhigher inin deepwaterdeepwater

Source: Deutsche Bank

Deutsche Bank AG/London Page 101 7 December 2009 Oil & Gas European Oil Services

Figure 162: Heavy oil sands – We expect high quartile margin decline near term

BarriersBarriers toto entryentry –– high high •Capital•Capital intensiveintensive businessbusiness whosewhose participantsparticipants leverageleverage thethe necessarynecessary equipmentequipment (e.g.(e.g. heavyheavy liftinglifting truckstrucks andand miningmining equipment)equipment) toto winwin projects.projects. •Established•Established infrastructureinfrastructure notnot toto mentionmention relationshipsrelationships withwith IOCsIOCs and and NOCs;NOCs; tracktrack recordrecord oftenoften resultsresults inin repeatrepeat contractor-clientcontractor-client businessbusiness andand reluctancereluctance fromfrom clientclient toto changechange •Advanced•Advanced technologytechnology (often(often withwith longlong patentpatent expiries)expiries) onon typestypes ofof extractionextraction methodsmethods e.g.e.g. inin situsitu bitumenbitumen productionproduction oror processesprocesses e.g.e.g. tailingtailing management.management. •Technical•Technical humanhuman expertiseexpertise andand knowknow howhow hardhard toto reproducereproduce

StrengthStrength ofof buyers:buyers: lowlow StrengthStrength ofof suppliers:suppliers: mediummedium •Medium•Medium levelslevels ofof LevelsLevels ofof substitutesubstitute competitioncompetition -- medium medium •Suppliers•Suppliers equallyequally splitsplit betweenbetween substitutionsubstitution andand barriersbarriers toto steelsteel forfor constructionconstruction andand PlayersPlayers looklook toto seekseek marketmarket shareshare asas theythey buildbuild tracktrack recordrecord entryentry suggestsuggest thatthat thisthis subcontractingsubcontracting functionsfunctions thatthat willwill andand relationshipsrelationships withwith clientclient basebase (a(a pre-requisitepre-requisite forfor winningwinning industryindustry isis structurallystructurally robustrobust includeinclude procurement,procurement, contracts)contracts) oftenoften throughthrough longlong standingstanding contactscontacts inin otherother •Medium•Medium term,term, expectexpect construction.construction. industriesindustries marginmargin contractioncontraction forfor OilOil •Prices•Prices ofof specialisedspecialised equipmentequipment ColtColt WorleyWorley ParsonsParsons (5%), (5%), JacobsJacobs (5%),(5%), FluorFluor (5%), (5%), AmecAmec ServicesServices duedue toto downsidedownside shouldshould bebe resilient.resilient. (5%),(5%), HatchHatch (5%),(5%), SNCSNC LavalinLavalin (5%) (5%) pressurepressure onon suppliersupplier pricesprices andand greatergreater resistanceresistance fromfrom •Note•Note thatthat decreasedecrease inin rawraw Technip,Technip, SNC,SNC, Equinox,Equinox, Vista,Vista, Gemini,Gemini, IMVIMV (b/w(b/w c.c. 2-5%2-5% OilOil co’sco’s materialmaterial andand sub-contractingsub-contracting each)each) pricesprices potentiallypotentially passedpassed throughthrough toto BuyerBuyer dependingdepending onon initialinitial termsterms && conditionsconditions ofof OilOil ServiceService company-Buyercompany-Buyer contract.contract.

ThreatThreat ofof substitutes:substitutes: mediummedium •NOC•NOC andand IOCIOC investmentinvestment shiftingshifting awayaway fromfrom traditionaltraditional moremore accessibleaccessible areasareas asas economicseconomics becomebecome moremore attractiveattractive inin oiloil sandssands •Size•Size ofof reservesreserves andand ultimateultimate recoveriesrecoveries potentiallypotentially higherhigher inin oiloil sandssands

Source: Deutsche Bank

Page 102 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

Figure 163: Rig construction services – We expect mid quartile margin decline near term

BarriersBarriers toto entryentry –– medium medium •Established•Established relationshipsrelationships withwith IOCs,IOCs, NOCsNOCs and and oiloil serviceservice companies;companies; tracktrack recordrecord oftenoften resultsresults inin repeatrepeat contractor-clientcontractor-client businessbusiness andand reluctancereluctance fromfrom clientclient toto changechange •Location•Location andand partnershippartnership withwith locallocal governmentgovernment andand personnel.personnel. ClientsClients willwill oftenoften optopt forfor contractorscontractors locatedlocated inin closeclose proximityproximity •Necessary•Necessary expertiseexpertise andand infrastructureinfrastructure (e.g.(e.g. yards)yards) requiredrequired forfor constructionconstruction andand procurementprocurement phases.phases. •Large•Large scalescale projectsprojects requiresrequires contractorscontractors withwith strongstrong balancebalance sheetssheets givengiven turnturn keykey naturenature ofof awardsawards

LevelsLevels ofof substitutesubstitute competition…competition… …by…by theme:theme: mediummedium StrengthStrength ofof suppliers:suppliers: mediummedium •Large•Large scalescale playersplayers (operating(operating EPICEPIC contractscontracts >> $500mn)$500mn) seekingseeking to to taketake •Main•Main supplysupply isis steelsteel (up(up toto 35%35% onon smallersmaller sizedsized projectsprojects andand acceptaccept lowerlower pricesprices (advantaged(advantaged byby economies economies ofof costcost base)base) withwith remainderremainder ofof ofof scale)scale) couldcould alteralter marketmarket shareshare withinwithin eacheach ofof thethe themesthemes below:below: Strength of buyers - high supplysupply chainchain splitsplit acrossacross variousvarious Strength of buyers - high sub-contracting functions (e.g. Jack-upJack-up refurbishmentrefurbishment andand newnew buildbuild constructionconstruction players:players: sub-contracting functions (e.g. •Relatively•Relatively highhigh levelslevels ofof construction, procurement) construction, procurement) LamprellLamprell (40%), (40%), KeppelKeppel FELSFELS (20%),(20%), PPLPPL (15%),(15%), MaritimeMaritime IndustrialIndustrial ServicesServices substitutionsubstitution (increasingly(increasingly fromfrom (5-10%),(5-10%), QGMQGM (5-10%),(5-10%), DubaiDubai DryDry docksdocks (5%)(5%) China)China) andand lowlow barriersbarriers toto entryentry suggestsuggest thatthat thisthis industryindustry isis •Note that decrease in raw Semi-subSemi-sub refurbishmentrefurbishment && newnew buildbuild constructionconstruction players:players: •Note that decrease in raw structurallystructurally weakweak materialmaterial andand sub-contractingsub-contracting Keppel (15%), Sembcorop Marine (10%), Jurong (10%), J Ray Mc Dermott Keppel (15%), Sembcorop Marine (10%), Jurong (10%), J Ray Mc Dermott •Medium term, expect acute pricesprices potentiallypotentially passedpassed throughthrough (10%), DubaiDryDocks (15%), PPL (10%), Samsung (10%) Daewoo (10%), •Medium term, expect acute (10%), DubaiDryDocks (15%), PPL (10%), Samsung (10%) Daewoo (10%), margin contraction for Oil toto BuyerBuyer dependingdepending onon initialinitial Lamprell, MIS, QGM (all <10%) margin contraction for Oil Lamprell, MIS, QGM (all <10%) Services due to downside termsterms && conditionsconditions ofof OilOil ServiceService Services due to downside …by region: high pressure on supplier prices company-Buyercompany-Buyer contract.contract. …by region: high pressure on supplier prices •Threat of ‘geographical substitution’ is real: regional markets will amidstamidst weakerweaker supply/demandsupply/demand •Threat of ‘geographical substitution’ is real: regional markets will fundamentals increasinglyincreasingly competecompete againstagainst eacheach otherother forfor businessbusiness fundamentals RegionalRegional playersplayers (includes(includes semi/jackupsemi/jackup refurb refurb and and newnew builds):builds): MiddleMiddle EastEast -- mainly mainly UAEUAE (25%),(25%), SingaporeSingapore (40%),(40%), S.ES.E AsiaAsia (15%)(15%) USA/GoMUSA/GoM (15%), (15%), WestWest AfricaAfrica (5%),(5%),

ThreatThreat ofof substitutes:substitutes: lowlow •Industry•Industry itselfitself hashas nono alternativealternative Source: Deutsche Bank

Deutsche Bank AG/London Page 103 7 December 2009 Oil & Gas European Oil Services Appendix S: The CAPEX/OPEX ‘life cycle’ explained

Identifying EPIC across the CAPEX ‘value chain’

FEED (front end engineering design) and detailed engineering: highly specialised and will be involved in conceptual and detailed engineering of various phases of the development (typically in the form of design contracts awarded to the oil service company). Of course the type of qualification be it electrical, mechanical, structural and civil will determine where in the life cycle of the project the engineers will focus on.

Project management: will be involved in construction, procurement, installation to final commissioning of the development. These types of engineers will be armed with years of experience in troubleshooting, logistics/scheduling and execution. An understanding of public policy and cultural perspectives in the country/region of operation is also essential. Note that they are capable or working both in oil and gas and related industries such as power & process and their skills are generally transferable (more so in the onshore segment as offshore tends to be more specialised within oil and gas).

Procurement: sourcing the necessary equipment (e.g. drilling packages, distillation columns, reactors etc) and resources (e.g. raw materials such as cement, steel and concrete) from the appropriate supplier and assuming responsibility for logistics and pricing.

Installation: implementing the engineering design (often in parallel with the scheduling and securing of equipment). Offshore activities will require installation vessels (either owned in-house or outsourced) capable of pipe-laying and heavy lift. Across the last few years, we have seen IOCs and the more Construction – in conjunction with installation/procurement and either performed in- house or outsourced via sub-contractors, typically locally based. experienced NOCs prefer to contract the engineering and Figure 164: Typical revenue recognition on a capex project project management functions 14 % 0.6 separately in order to provide Absolute percentage contribution from each the right solution that centres phase 0.5 31%

on timely and efficient d completion at an optimal cost 0.4

(rather than the contractor 24% 0.3 taking possession of the entire project and arguably try to sell 0.2

20%

internal products that work re-base (TIC) cost installed Total

0.1 around its own engineering 7% 5% solution). 0.0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 Month

Front end engineering Project management contract (PMC) Detailed engineering

Procurement (m) Construction (m) Installation (m)

Source: Deutsche Bank; m = management;

Page 104 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

It is important to clarify:

The margins realised across each project phase will depend on the type of contract entered into as well as the industry in which it is operating in. In theory, the structural characteristics of e.g. upstream deepwater engineering or frontier developments are greater (and so should generate a higher relative margin) than e.g. simple upstream onshore engineering which will have less barriers to entry and more players. Note that internal advantages such as cost structure and operational efficiency should also differentiate each company’s margin realisation. The profile depicted above applies to all energy-related capex projects i.e. oil and gas, power, process and associated infrastructure.

The FEED and detailed engineering design phases will represent no more than 5-10% of the total cost of the project.

Pureplay engineering and project management companies do not own any assets and therefore will not be directly involved in the physical undertaking of these phases. A contract of this nature would typically be in the form of an EPICm – i.e. management of engineering, procurement, installation and construction). Note that onshore developments and simple facilities which are typically repeatable solutions and where there is usually a cost focus and less product or engineering differentiation will be generally be packaged as part of an EPIC lump sum contract. This is because no real technology/knowledge input is required at the front end. Also it is a relatively mature supply chain therefore easier to package up the solution. Complex projects (technically/environmentally challenging) will have bespoke solutions that often involve more technologically based products.

An engineering, procurement, installation and construction management contract will generally be c. $500mn. This is given the procurement, installation and construction phases will be more cost intensive (involves raw materials, equipment, installation using various types of vessels and finally construction activities). The procurement, construction and installation phases (which will tend to also include commissioning and start-up) are generally tendered together in the form of a single contract however can also be tendered separately. The reason why an energy company may prefer to opt for the latter is to lower the risk of giving the work to one contractor preferring to choose best in class. It is worth mentioning that the engineering element of a large EPIC contract may be sub-contracted to a specialist (e.g. Amec and Wood Group).

Understanding ‘OPEX’ Below we show the opex profile typified for an energy development (be it oil, gas, power or process) that generally represents c. 30-40% of the total field life cost (indexed to 1 with the balance comprising capex; see Figure 165).

Deutsche Bank AG/London Page 105 7 December 2009 Oil & Gas European Oil Services

Figure 165: Typical revenue recognition for on an opex contract

0.4 Absolute percentage 30% contribution from each phase 0.3

0.2 70

0.1 Total after life cost (TAC) re-based

0.0 0 5 10 15 20 years+

Years Operations and maintenance Decommissioning

Source: Deutsche Bank The long-term nature of an operating and maintenance contract provides excellent visibility for an oil service company given it is generally signed for 5-years+ and termed on periodic renewals aimed at giving the client an option to change the fee structure and/or the contractor itself.

Page 106 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Appendix T: Global oil service spectrum explained

The global service spectrum is highly fragmented. So we take a step back and return to the basics in establishing how the various themes mentioned above, such as ‘wellhead operations’, ‘drilling’, ‘SURF’, ‘oil sands’, ‘LNG’, etc., fit into the service jigsaw (shown in Figures 166 and 167 in the form of flow sheets).

Deutsche Bank AG/London Page 107

Page 108 Page 108 Oil Services European Oil&Gas 7 December2009 Figure 166: Backbone functions of the service sector across the oil life cycle* Undiscovered oil and gas underneath seabed / ground

Exploratory, appraisal and development capex (below ‘mudline’) mainly US based companies (private & listed) with Exploration (seismic, drilling, well operations, rig relatively fewer Europeans / Asian construction) (broken down in next chart ) players

Mud line (seabed or dry land) Engineering and construction (discovered oil and gas Mud line (seabed or dry land) underneath seabed / ground) Engineering & construction capex (above ‘mudline’) mainly European and Asian based Offshore Onshore companies (listed and private) with relatively fewer US players ECI of frontier ECI of oils sands. Surface facilities** Subsea Infrastructure & ECI of developments Extraction Equipment** conventional oil (harsh operating includes mining & gas Shallow- Deepwater Shallow- Deepwater environments) (<75m) and ‘in water water processing situ’ steam facilities ECI of fixed ECI or leasing of floating 1) Conventional ECI of advanced ECI of: injection(>75m) platforms platforms: trunklines subsea 1) Umbilicals, risers and flowlines (SURF) 1) Semi-submersibles 2) Subsea equipment / equipment / 2) Rigid & flexible pipes (SPAR, tension leg systems systems 3) Topsides and hulls of platforms platforms) 3) Topsides and hulls 2) Floating production of platforms storage and offloading ships (FPSOs)

Produced Oil or Oil Produced Gas sands Deutsche Bank AG/London Deutsche Bank

Brownfield and greenfield ECI of: Maintenance modification and operational ECI of liquefaction plants (LNG) ECI of gas to liquid 1) Refineries management of offshore / onshore facilities followed by ECI of re-gasification plants (GTL) 2) Petrochemicals plants terminals 3) Oil sands upgraders and process plants Source: Deutsche Bank *ECI is engineering, construction and installation; **Installation phase completed using various heavy lifting/pipe-laying/inspection vessels (owned or leased by E&C company) also known as lift boats

Deutsche Bank AG/London AG/London Deutsche Bank Oil Services European Oil&Gas 7 December2009

Figure 167: Backbone functions of the service sector within exploration based activities Below ‘mudline’ (seabed or dry land) Exploration* Below ‘mudline’ (seabed or dry land)

Exploration, appraisal & Exploration, appraisal & development of well development of well

Drilling Associated Well head Services Engineering, procurement and Services construction of drilling rigs

Surface Subsurface Floater rigs Fixed rigs Equipment Sub/semi- Drillships Tenders/ Jack-ups Servicing Equipment Servicing and products mersibles barges (onshore/offshore)

1) 3rd/4th 1) Pressure 1) Surface 1) Casing & tubing 1) 2nd 1) Anchoring 1) Logging while services and generation: pumping** (e.g., equipment (e.g., drilling generation: system used 1) JU products (inc benign/harsh 200/250/300 etc cementing and valves & surface 2) mud logging benign/harsh over dynamic cementation) environment through to 400ft stimulation) and trees, pressure and 3) Wireline weatherrd/4 th positioning so 2) Coiled tubing 2) 5th/6th (water depth) compression flow control) logging (e.g., well 2)generation:3 depths are 3) Completion generation: equivalent to services 2) Rig equipment intervention, benign/harsh only typically 2) Production well (e.g., power tongs) equipment (e.g., th th deckload up to drilling up to openhole and 3) 5 /6 up to 500ft. testing. 3) Unit TCP, tractors, safety 5000tn/water 30,000ft cased hole). generation: Benign tools) depth up to 3) rental and fishing manufacturing 4) Directional deckload up to 2) Harsh or 4) Downhole drilling 12,000ft environment 4) Operations and (e.g., plug valves) drilling 5000tn/water benign tools (equivalent to only maintenance. 5) Operations depth up to environment 5) Drill bits drilling depth of 5) Solids control and maintenance 12,000ft 3) Standard or 6) drilling & 40,000 ft) and waste (equivalent to high specification 6) Inspection and completion fluids management coating drilling depth of 7) Specialty 7) Coiled tubing 40,000 ft) chemicals (excludes 8) tubulars Rig Construction manufacturing of) 9) Well servicing Services (other than above) 10) Artificial lift (e.g. electrical submersible, Newbuilds Upgrades Others rod/gas lift and 1) Semi-sub, drillship, jack-up (onshore and 1) Refurbishment of all types of drilling rigs 1) Maintenance and repair: rigs typically taken offline progressive cavity offshore) & tender construction 2) Re-activation – but may also be done while in operation using pumps) 3) Conversion remote operating vehicles) 2) Construction and refurbishment of lift boats*** i.e. heavy lift construction vessels Page 109 Source: Deutsche Bank; *Note we have excluded seismic operations; **we have placed this within ‘surface’ activities but can arguably be placed in ‘subsurface’ (servicing) also; ***’lift boats’ are different to ‘rigs’ in that they are used for E&C type operations within the offshore segment. Underlying driver for this market will therefore not be exploration but offshore E&C; for simplicity we have included lift boats here as they are typically built by the same companies that construct rigs

7 December 2009 Oil & Gas European Oil Services Appendix U: Glossary of terms and simplifications

Understanding contingencies Contingencies are captured either within the estimated costs for conditions or situations (often called “knowns”) or under management reserves (‘known unknowns’) i.e. they are not included in estimated costs. Contingency is an amount that must be added by the contractor to account explicitly or implicitly for knowns, i.e., those risks which are likely to occur but cannot be specifically identified at the time the estimate is prepared. Contingency thus is the amount added to the estimate to allow for providing for expenses that experience shows will likely be required, and are therefore part of the total estimated cost (not an extra), and conditions arising during the execution of the project which could not be specifically priced, foreseen or anticipated. Contingency is typically managed by the project manager and the amount is established by issues such as design definition level, estimating methodology, time frame and the probability of meeting the required schedule, whether the project involves new or emerging technology, remoteness of job site, infrastructure requirements, engineering physical progress, degree of equipment and material commitment, etc. Management reserve is an amount that the contractors’ manage, rather than the project manager, establishes to cover for execution performance risks that may arise from “known unknowns” and is not included in the estimated project cost. These “known unknowns” are risks that are neither explicit nor normally expected, i.e., risks that are typically discrete events with a low frequency of occurrence and a high severity of impact, such as shortages of trained contract administration/project controls personnel, shortages of resources, technology failures, etc.

Oil service companies and different project teams within the same company quantify risk into contingency differently for different project delivery methods and contract types. The difference in booking lump sum contracts and cost reimbursable contracts can be summed up in how the oil service company evaluates contingency. In a lump sum bid, the contingency is included in the booked backlog, and may or may not increase the margin that is realized at completion of the project. For example, if the risks included in the contingency do not emerge, margin is increased. On the other hand, if risks were not properly and adequately estimated, margins at completion will be less, such as when project execution delays occur. Note, however, that an owner/operator’s use of prescriptive specifications is tantamount to saying that this is what the owner/operator wants and expects. The oil service company only has risk associated with its execution of exactly what is called for in the contract documents. In other words, the company’s duty is to conduct a reasonably prudent review of the plans and specifications. Oil service companies recently have increased their exposure, however, to the performance of sub-contractors. When allocating construction risks, appropriate allocation is not achieved due to the inferior bargaining position held by lower tier parties. Oil service companies tend to push risk down to the lowest level through successive levels of contracting. This approach almost guarantees project delays and increased costs because:

It pushes risk to the lowest level in the contracting chain where the firms have the least financial depth.

The lowest levels have to accept the risk because they do not have the clout to ward off the allocation.

The ability of the firms who are left with the risk can do very little to alter the risk should it emerge on the project.

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The result is that accountability is not in line with the risk and oil service companies have to fund the completion of the project, and try and recover the costs from the sub-contractors or through “extras” from the project’s owner/operator.

Variation orders, extras and changes – what’s the difference? “Variation orders” (relating to turnkey projects) are submitted when the scope of the project changes due to a shift in client scheduling/demands, change in design specifications or execution problems that have incurred additional costs. Whilst these are usually realised across the life of the contract, delays in their approval often mean that they cannot be booked (under new IFRS rules, change orders cannot be accounted for until they are formally acknowledged by the client). Indeed, the greatest risk to contractors is that despite delivering on the contract, the client does not agree with the value of the variation orders claimed leading to a ripple of legal procedures and ultimate charges to the company’s P&L relating to the specific problem contract.

An “Extra” is an item of work or a method of performing work that is not normally required to complete to the original scope of work. It can arise in the same type contexts as changes, but it is outside what was or would be assumed as necessary to complete the original project scope. Extras are the responsibility of the owner/operator no matter the type of contract, unless there is an issue with the E&C ’s performance. For instance, issues related to the “standard of care” which the owner/operator demanded.

A “Variation” generally applies to Unit Price type contracts where the quantities are actually estimated and made a part of the contract. Variations are the difference between an estimated quantity and the quantity actually required to complete the item of work. Generally the contract specifies a band (+/-) around the estimated quantity for which the price is valid. “Variations” are the responsibility of the owner/operator, unless there is an issue with the contractor’s performance. For instance, issues related to the “standard of care” which the owner/operator demanded or issues, such as, if the E&C under-estimated the quantity. As is obvious, issues are emerging currently as project costs increase and/or are accompanied by delay concerning the “standards of care” that are applicable. Where there are disagreements between owner/operators and contractor, a change, extra and/or variation morphs into a “claim.” A claim is a bona fide disagreement between the owner/operators and the contractor for a project as to a change, extra or variation. As far as backlog and revenue recognition against such backlog is concerned, all or some of claims are booked provided the oil service company makes a reasonable assessment of the likely magnitude it will recover. If the project owner/operators and the contractor cannot agree with respect to a claim, the claim further morphs into a “dispute.” Once again, there are considerable differences between publicly traded firms in regards to whether the cost of disputed items and/or some portion should be booked and/or revenue recognised. Oil service companies must assure that they do not recognise revenue from claims or disputes that is in excess of the amount of likely recovery because it will necessitate a write down if the amount is not ultimately recovered.

As is obvious, internal or external misunderstandings create a large amount is risk which must be managed by all stakeholders. The heart of risk management is the process by which changes, extras, variations, claims and disputes are handled at the corporate level or the project level. For owner/operators it is the means of preventing or reducing contractors’ costs through efficient oversight and quality management. For contractors it means costs are properly identified and recorded, and they do not give away assets to owner/operators by improper or inadequate processes.

Deutsche Bank AG/London Page 111 7 December 2009 Oil & Gas European Oil Services

Understanding the contract strategy The contract strategy represents the way in which these delivery systems are packaged and paid for by the client. What is common across all types is that the owner/shareholder will insist (via the contract provisions) that the contractor, in return for being paid to execute those functions, also accepts the risk of performing those functions as per the standard and conditions laid down in the contract. We identify four generic contracting types that represent the bulk (>95%) of contracts signed between the client (NOC or IOC) and oil service companies:

Lump sum: The client pays a fixed price for any combination mentioned above. In the majority of cases it will be the entire project cycle; so the combination spans engineering, procurement, installation and construction. Note that a FEED contract by itself will rarely be awarded on a lump sum basis as here the emphasis is on quality and breadth of technical content. The client will not want this to be constrained by a fixed price.

The bid packages are presented and the one that is chosen forms the basis of the project award value. The key characteristic here is that any unforeseen cost that is not strictly underwritten within the original contract will likely be assumed by the contractor (unless there is a change in the scope of the project in which case the unforeseen cost is chargeable to the client).

The fixed price that envelops the contract should, in theory, accommodate a worst-case scenario in case execution risks become a reality. This ‘buffer’ is calculated in the form of a contingency and can represent up to 15% of the asking price. The best case scenario is that these are not exercised in which case they are ‘released’ and materialise as additional ‘cream’ on top of the base price/margin. In the worst-case scenario, these risks exceed the contingencies put in place and erode the base margin to an extent that the contractor loses money on the project. Cost plus: The oil service company is able to recover its costs within a contractually defined structure. These costs typically include construction labour, materials, equipment, sub- contractors and overheads. The asking price is equivalent to a percentage or fixed amount for contingency and profit. This is split into a base portion (or ‘recovery cost’) X% and an additional Y% that is termed ‘fee at risk’ (can be fixed or variable i.e. a % of the recovery cost). If the contractor meets and/or exceeds the original specifications, it pockets the additional Y%. Conversely, the fee at risk is forfeited.

A common misperception is that there is no risk on the ‘X’% earned. Normally, if the contractor issues a poor design or demonstrates inefficiencies that result in a breach of contract, then the entire fee can be forfeited. Worst case, the contractor may actually lose money on the project if the additional costs are rebuffed by the client and exceed those implied in the base margin.

The owner/shareholder bears a significantly higher cost and schedule risk than in a lump sum contract and so its direct management of the project will be higher. As a result the client is far more likely to detect errors and defects at no additional cost to itself under a cost plus contract. Equally, given the increased management attention and performance measures, an owner may actually hold the contractor to a much more strict interpretation of the ‘standard of care’ expected (and paid for) than under any other contract strategy. Cost plus + KPIs (key performance indicators): Same as above but includes an extra performance-related constituent (in addition to the ‘Y’%). The ability to realise this is measured against a specific set of well-defined performance metrics including: 1) achieved delivery vs. the original schedule and 2) the

Page 112 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

ability to provide cost or operational efficiencies to the client beyond the original project scope. For example, assume that a project has a series of 10 specific intermediate milestone dates by which certain construction activities have to be achieved. Each of these milestones may represent a point of evaluation against a KPI set on achieving the completion of the project by the respective date. The parties can agree, for example, that achievement of any one milestone is a performance ranking of “0”, missing any one milestone is a performance ranking of “-1” and beating a milestone date is a performance ranking of “+1”. In this example, the contractor would be eligible for an incentive payment for achieving “+1” on a milestone and a penalty for achieving “-1”.

Note that while ideally all cost plus contracts would be structured to have KPIs, the reality is that not all clients accept performance-related incentives (taking the view that ‘Y’ is sufficient). Therefore, it is up to the oil service company to keep its exposure to this type of contract strategy as high as possible relative to cost plus. Unit price (also termed target price or convertible lump sum) A hybrid of cost plus and lump sum. This type of contract is only applicable for entire project cycles. It begins as a cost plus up to the point where all procurement is secured (and priced) and necessary sub-contractors are in place.

The client pays a fixed price for work based on the “all-inclusive cost” of a unit of an installed commodity. For example: assume the commodity is 10cm diameter single wall carbon steel pipe. The contractor would develop a “fixed price” per linear meter of pipe installed which would include the total cost to procure the pipe; the cost to ship, store and handle the pipe; the labour and materials costs to install the pipe; and, overhead and profit amounts. In effect, the price per unit installed is firm; however the number of units to be installed is not fixed. The contractor presumably bears no risk if the number of units increases or decreases during execution.

A hybrid between unit price and cost plus is one in which the cost to procure the commodity is removed from the “all-inclusive cost” of a unit. Typically in this contracting strategy the owner retains the responsibility and the cost risk of purchasing the commodity, while the contractor retains the responsibility to accurately price the cost of receiving, handling, and installing the commodity at a fixed cost, which again includes overheads and profit. The hybrid leaves the performance risk with the contractor. Again, the contractor presumably bears no risk should the total number of units increase or decrease. Glossary AHTS (Anchor Handling, Tug & Supply ship): Combination vessels operating in the offshore market, intended for use in anchor-handling, tug operations and transportation of supplies.

Conventional/shallow waters: Depth of up to 400 metres (1,300ft).

Cost plus: The client is charged a day rate or project rate across the life of the project, with any extra work required to complete the job added to the bill.

Deep waters: Depths of over 400 metres (1,300 ft).

Commissioning: Series of processes and procedures undertaken in order to start operations of a gas pipeline, associated plants and equipment.

Decommissioning: Series of processes and procedures undertaken in order to end operations of a gas pipeline, associated plants and equipment. It may occur at the end of the life of the plant, following an accident, for technical or financial reasons, and/or on environmental or safety grounds.

Deutsche Bank AG/London Page 113 7 December 2009 Oil & Gas European Oil Services

Development (of a gas or oil field): All operations associated with the construction of facilities to enable the production of oil and gas.

Drillship: A maritime vessel modified to include a drilling rig and special station-keeping equipment. The vessel is typically capable of operating in deep water. A drillship must stay relatively stationary on location in the water for extended periods of time. This positioning may be accomplished with multiple anchors, dynamic propulsion (thrusters) or a combination of these. Drillships typically carry larger payloads than semi-submersible drilling vessels, but their motion characteristics are usually inferior.

Dynamically Positioned Heavy Lift Vessel: Vessel equipped with a heavy-lift crane, capable of holding a precise position through the use of thrusters, thereby counteracting the force of the wind, sea, current, etc.

EPC (Engineering, Procurement, and Construction): A type of contract typical of the onshore construction sector, comprising the provision of engineering services, procurement of materials and construction. The term ‘turnkey’ indicates that the system is delivered to the client ready for operations, i.e. already commissioned.

EPIC (Engineering, Procurement, Installation, Construction): A type of contract typical of the offshore construction sector, which relates to the realisation of a complex project where the global or main contractor (usually a construction company or a consortium) provides the engineering services, procurement of materials, construction of the system and its infrastructure, transport to site, installation and commissioning/preparatory activities to the start-up of operations.

FEED: Front-End Engineering Design

Facilities: Auxiliary services, structures and installations required to support the main systems.

Flexible flowline: Flexible pipe laid on the seabed for the transportation of production or injection fluids. It is generally an infield line, linking a sub-sea structure to another structure or to a production facility. Its length ranges from a few hundred metres to several kilometres.

Flexible riser: Riser constructed with flexible pipe (see Riser).

Floaters: Floating production units including floating platforms, and FPSOs.

Floatover: Type of module installation onto offshore platforms that does not require lifting operations. A specialised vessel transporting the module uses a ballast system to position itself directly above the location where the module is to be installed; it then proceeds to de- ballast and lower the module into place. Once this has been completed the vessel backs off and the module is secured to the support structure.

FPSO vessel: Floating Production, Storage and Offloading system comprising a large tanker equipped with a high-capacity production facility. This system, moored at the bow to maintain a geo-stationary position, is effectively a temporarily fixed platform that uses risers to connect the sub-sea wellheads to the on-board processing, storage and offloading systems.

FPU (Floating Production Unit): A ship-shaped floater or a semi-submersible used to process and export oil and gas

Page 114 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services

GTL (Gas-to-Liquids): Transformation of natural gas into liquid fuel (Fischer Tropsch technology).

Hydrotesting: Operation involving high-pressure (higher than operational pressure) water being pumped into a pipeline to ensure that it is devoid of defects.

IRM (Inspection, Repair and Maintenance): Routine inspection and servicing of offshore installations and sub-sea infrastructures.

Jacket: Platform underside structure fixed to the seabed using piles.

Jack-up: Mobile self-lifting unit comprising a hull and retractable legs, used for offshore drilling operations.

J-laying: Method of pipe-laying that utilises an almost vertical launch ramp, making the pipe configuration resemble a ‘J’. This configuration is suited to deep-water pipe-laying.

LNG: Liquefied natural gas is obtained by cooling down natural gas to minus 160°C at normal pressure. Gas is liquefied to make it facilitate its transportation from the place of extraction to that of processing and/or utilisation. A tonne of LNG equates to 1,400 cubic metres of gas.

Lump-sum or LSTK (lump sum turnkey project): One fixed price for the project that will typically encompass engineering, procurement, installation and construction activities.

Midstream: Sector comprising all those activities relating to the construction and management of the oil transport infrastructure.

Mobile offshore drilling unit: A generic term for several classes of self-contained floatable or floating drilling machines such as jackups, semi-submersibles, and submersibles.

Mooring buoy: Offshore mooring system.

NOC: National Oil Company

Offshore/Onshore: The term offshore indicates a portion of open sea and, by induction, the activities carried out in such area, while onshore refers to land operations.

Pre-commissioning: Comprises pipeline washing out and drying.

Regasification terminal: Coastal plant that accepts deliveries of liquefied natural gas and processes it back into gaseous form for injection into the pipeline system. Also known as a receiving terminal.

Riser: Manifold connecting the sub-sea wellhead to the surface.

ROV (Remotely Operated Vehicle): An unmanned sub-sea vehicle remotely controlled from a vessel or an offshore platform. It is equipped with manipulator arms that enable it to perform simple operations.

S-laying: Method of pipe-laying that utilises the elastic properties afforded by steel, making the pipe configuration resemble an ‘S’, with one end on the seabed and the other under tension onboard the ship. This configuration is suited to medium to shallow-water laying.

Spar: Floating production system, anchored to the seabed through a semi-rigid mooring system, comprising a vertical cylindrical hull supporting the platform structure.

Deutsche Bank AG/London Page 115 7 December 2009 Oil & Gas European Oil Services

Spool: Connection between a sub-sea pipeline and the platform riser, or between the terminations of two pipelines.

Submersible/semi-submersible drilling rig: A particular type of floating vessel, usually used as a mobile offshore drilling unit (MODU) that is supported primarily on large pontoon- like structures submerged below the sea surface.

Sub-sea Technology: All products and services required to install and operate production installations on the seabed.

SURF facilities: Sub-sea Umbilicals Risers Flowlines – pipelines and equipment connecting the well or sub-sea system to a floating unit.

Template: Rigid and modular sub-sea structure where the oilfield wellheads are located.

Tendons: Pulling cables used on tension leg platforms used to ensure platform stability during operations.

Tension leg platform (TLP): Fixed-type floating platform held in position by a system of tendons and anchored to ballast caissons located on the seabed. These platforms are used in ultra-deep waters.

Tie-in: Connection between a production line and a sub-sea wellhead or simply a connection between two pipeline sections.

Topside: Portion of platform above the jacket.

Trunkline: Large diameter oil pipeline connecting large storage facilities to the production facilities, refineries and/or onshore terminals. Used in shallow waters.

Trenching: Burying of offshore or onshore pipelines.

Umbilical: Flexible connecting sheath, containing flexible pipes and cables.

Upstream/Downstream: The term upstream relates to exploration and production operations. The term downstream relates to all those operations that follow exploration and production operations in the oil sector.

Wellhead: Fixed structure separating the well from the outside environment.

Wellservicing: Intervention in sub-sea production wells carried out from a floating rig or a dynamically positioned vessel.

Workover: Major maintenance operation on a well or replacement of sub-sea equipment used to transport the oil to the surface.

Sources:

http://lnglicensing.conocophillips.com/about/glossary/index.htm http://www.glossary.oilfield.slb.com/Display.cfm?Term=submersible%20drilling%20rig http://www.rabt.se/index.php?id=102&L=1 http://www.skibskredit.dk/Default.aspx?ID=503 http://www.technip.com/english/html_top/p_glossaire.html Saipem Annual Report 2004

Page 116 Deutsche Bank AG/London 7 December 2009 Oil & Gas European Oil Services Appendix 1

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Buy: Based on a current 12- month view of total shareholder return (TSR = percentage change in share price from 400 47% current price to projected target price plus pro-jected 43% dividend yield ) , we recommend that investors buy the 300 stock. 200 37% 29% Sell: Based on a current 12-month view of total share-holder 9% return, we recommend that investors sell the stock 100 37%

Hold: We take a neutral view on the stock 12-months out 0 and, based on this time horizon, do not recommend either a Buy or Sell. Buy Hold Sell Notes: 1. Newly issued research recommendations and target Companies Covered Cos. w/ Banking Relationship prices always supersede previously published research. European Universe 2. Ratings definitions prior to 27 January, 2007 were: Buy: Expected total return (including dividends) of 10% or more over a 12-month period Hold: Expected total return (including dividends) between -10% and 10% over a 12-month period Sell: Expected total return (including dividends) of -10% or worse over a 12-month period

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