Oilfield Services & Equipment

DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, LEGAL ENTITY DISCLOSURE AND THE STATUS OF NON-US ANALYSTS. US Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, 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.

19 September 2016 Europe/United Kingdom

Equity Research Oil & Gas Equipment & Services

Oilfield Services & Equipment Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

James Wicklund

214 979 4111

[email protected]

Gregory Lewis, CFA

212 325 6418

[email protected]

Specialist Sales: Jason Turner

44 20 7888 1395

[email protected]

INITIATION

Curtain rises on recovery

■ Initiating coverage of European Oilfield Services: The worst downturn for a generation has seen over USD200bn (>40%) of E&P capex removed from the market, spurred widespread restructuring and tested many balance sheets. But it has also been a force for good – the industry needed to change after decades of poor operational performance. Unlike 2009, this downturn has been sufficiently long to spur behavioural change – a leaner, fitter and more returns-focused industry should emerge. This will take time to be reflected in financial performance but valuations suggest the market is prepared to look well beyond the current eye-of-the-storm.

■ A phased recovery: We believe we’re close to the bottom, but growth may be slow initially in 2017, with momentum building in 2018. We see a cycle of reactivation rather than reinvestment as existing capacity is gradually absorbed by growing demand. OFS must navigate a precarious low point in the cycle with limited pricing power, balancing the need for asset utilization with an acceptable level of risk that would not derail the recovery. We think oil companies are poised to deliver improved operational/financial performance. Selectively, OFS companies can share in this upside.

■ Differentiation is key: There’s a lot to play for – we are tracking ~USD140bn of contract opportunities globally. Oil companies today have different needs, looking more to OFS for technical expertise and innovative project solutions, while pursuing new commercial models. Differentiation through front-end expertise, technology, distinctive assets, execution track record, even balance sheet, is more important than ever. OFS needs to change with the times – many companies are rising to the challenge but several are merely waiting for recovery to set in and could be left behind.

■ Top picks – Petrofac and Wood Group: Today we think the traditional investor playbook for EU OFS will not work; stock selection is far more important. Our preferred plays are Petrofac (retreating to a high-quality core with optionality) and Wood Group (best-in-class early-cycle recovery play, attractively valued). Our least preferred stocks are Subsea 7 (P&L challenges, overly capital intensive), and AMEC Foster Wheeler (recent outperformance excessive, headwinds underestimated). Our forecasts are conservative – 5-10% below consensus – but we believe we are approaching the end of the OFS downgrade cycle. We expect investors to be looking through the trough to 2018.

Figure 1: Credit Suisse Pan-European and co-covered US Oilfield Services Coverage

Outperform Neutral Underperform

Petrofac (PFC.L), Preferred, TP 1100p Saipem (SPMI.MI), TP EUR0.45 Subsea 7 (SUBC.OL), Least Preferred, TP NOK75

Wood Group (WG.L), Preferred, TP 850p Hunting (HTG.L), TP 500p Amec Foster Wheeler (AMFW.L), Least Preferred, TP 450p

Schoeller-Bleckmann (SBOE.VI), TP EUR70 Aker Solutions (AKSOL.OL), TP NOK35 CGG (GEPH.PA), TP EUR17.5

Technip (TECF.PA), TP EUR65 Core Labs* (CLB.N), TP USD115 Seadrill* (SDRL.N), TP USD1

PGS (PGS.OL), TP NOK27 Tecnicas Reunidas (TRE.MC), TP EUR28

Source: Credit Suisse Research * denotes co-covered stocks. PFC, WG, TEC, PGS, SPM, HTG, AKSO, SUBC, AMFW, and TRE covered by Phillip Lindsay, SBOE and CGG covered by Gregory Brown, CLB and SDRL covered by Gregory Lewis

19 September 2016

Oilfield Services & Equipment 2

Key charts

Figure 2: Global E&P capex Figure 3: OFS cost deflation

Source: Company data, Credit Suisse estimates, the BLOOMBERG PROFESSIONAL ™ service

Source: BP, Credit Suisse Research

Figure 4: Global Rig Count Forecast Figure 5: OFS Capital Discipline

Source: Company data, Credit Suisse estimates, Baker Hughes International Source: Credit Suisse Research

Figure 6: OFS Returns forecast Figure 7: OFS economic return - CFROI®

Source: Credit Suisse Research Source: Credit Suisse HOLT®

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19 September 2016


Table of contents

Executive summary 4

Background to the report 13

10 key themes for the recovery cycle 15

Activity levels and E&P capex 31

‘Fishing where the fish are’ – a snapshot of global OFS bidding activity 35

Subsector outlook 48

Oil price outlook 59

Financing trends and the OFS balance sheet 60

HOLT – An EU OFS Perspective 64

Forecasts and valuation 71

Aker Solutions (AKSOL.OL) 77

Amec Foster Wheeler (AMFW.L) 87

CGG (GEPH.PA) 98

Core Laboratories 108

Hunting Plc (HTG.L) 110

Petrofac (PFC.L) 120

Petroleum Geo Services (PGS.OL) 131

Saipem (SPMI.MI) 142

Schoeller Bleckmann Oilfield Equipment (SBOE.VI) 153

Seadrill 163

Subsea 7 S.A. (SUBC.OL) 165

Technip (TECF.PA) 175

Tecnicas Reunidas (TRE.MC) 191

Wood Group (WG.L) 201

Appendix 211

19 September 2016


Executive summary

■ In this report we initiate coverage of 12 European oil services stocks with 5 Outperform

ratings, 3 Neutrals and 4 Underperforms. On balance, we have a constructive view on

recovery prospects, but the cost curve will ultimately determine where and how quickly

the recovery takes place. At the bottom of the last cycle in 2009, any grouping of OFS

stocks would have delivered significant outperformance relative to the wider market.

Today the situation is far less clear cut – for many reasons, the traditional investor

playbook for EU OFS will not work; stock selection will be far more important in this

cycle. Our top picks are Petrofac and Wood Group, with our least preferred names

being Subsea 7 and AMEC Foster Wheeler.

Figure 8: Pan-European and co-covered US Oilfield Services Coverage





Technip (TECF.PA), TP EUR65 Core Labs* (CLB.N), TP USD115 Seadrill* (SDRL.N), TP USD1

PGS (PGS.OL), TP NOK27 Tecnicas Reunidas (TRE.MC), TP EUR28

Source: Credit Suisse Research, *denotes co-covered stocks. PFC, WG, TEC, PGS, SPM, HTG, AKSO, SUBC, AMFW, and TRE covered by Phillip Lindsay, SBOE and CGG covered by Gregory Brown, CLB and SDRL covered by Gregory Lewis

■ Industry background – The worst downturn for a generation actually masks deep-

rooted problems within the oil & gas industry. Too often in the past, we think the

industry was guilty of poor operational performance, inefficiency, and late / over-budget

projects delivery. High and stable oil prices through last cycle met with industry

complacency; oil & gas has not kept pace with the times – other industries look much

further ahead on project delivery, efficiency, and technology. A creeping cost curve

became reality as several high profile projects (notably offshore) were deemed

uneconomic with oil above USD100/bbl – a reality check. The downturn has been a

brutal one, but in many ways, we think it has been a force for good within the industry.

A leaner, fitter, more functional and collaborative industry is emerging. There are signs

of stabilisation now, and we expect to move towards a gradual recovery in 2017,

momentum building from 2018.

■ Key themes for the recovery cycle – The OFS industry overinvested in the last cycle

for a level of demand that looks unimaginable today. We expect a cycle of reactivation

rather than reinvestment as existing capacity is absorbed by growing demand – new

capital investment won’t be necessary. We think the OFS sector now has a greater

understanding of the demands of the financial sector – there’s more focus on

differentiation, capital intensity and delivering improved returns. The base from which

the sector recovers however is extremely low, and companies must navigate a

precarious low-point of the cycle with limited pricing power. The industry needs to

balance the need to provide utilization to its asset base with a level of risk that doesn’t

potentially derail recovery prospects. Oil companies have lost technical expertise

through restructuring; there’s more responsibility on OFS to deliver better solutions and

value from projects. There’s greater collaboration and changing commercial models

and incentives – this is driving a performance-based culture.

■ Under-investment in front-end project planning is often a root cause of poor project

performance, in our view. Increased man hours are being spent on concept selection,

design scope and development plan optimization. Later-cycle players must be involved

earlier to ensure constructability while minimizing cost / schedule escalation.

Technology differentiation and integration are likely to be more relevant in this cycle.

We think OFS companies that can exercise greater influence over project success are

19 September 2016


likely to be the winners in this next cycle. Inflation threats look limited – there’s simply

too much capacity across the supply chain. However the OFS sector has shed about

40% of its workforce through the downturn and people constraints could be a

bottleneck in a recovery cycle, notwithstanding greater productivity across the industry.

■ E&P capex and activity levels – Well over USD200m / 40% of spending has been

removed from the industry since 2014 – two consecutive years of declining spend

confirm the worst industry downturn since the mid-1980s. We have confidence this

trend will not continue due to a combination of higher oil prices, a rebalancing of oil

demand / supply, improved project economics and rising concerns over future

production. North American E&P should grow capex in 2017, while other oil companies

may well trend down again, but overall we expect a year of stabilization in 2017 in

absolute USD spend (physical activity should be up as oil companies benefit from more

‘bang for buck’), with a growth trend commencing in 2018 and gathering momentum.

US drilling activity bottomed in Q216 and is now demonstrating a gradual recovery,

which we expect to continue – CS assumes US rig count averages 470 in 2016, rising

28% in 2017 and 20% in 2018. Conventional international activity onshore and

marginal / brownfield offshore development should follow next. Despite good initiatives

to improve project economics, we think recovery in higher cost segments like

deepwater will lag.

■ Fishing where the fish are – sector bidding update – Our in-house projects

database has tracked a disappointing USD21bn of awards to market ytd, down 50% on

the comparable period in 2015. Key awards include BP’s Tangguh and Shah Deniz 2,

plus ENI’s Zohr project. Major projects often stall in a downturn – Shell’s Bonga South

West and ADNOC’s Das Island development are good examples of this. However the

global bidding pipeline looks promising with nearly USD140bn of contracts at various

stages in the bidding process. Regionally, the Middle East is the most active, with

large-scale downstream projects like Duqm (Oman), Sitra (Bahrain) and Ras Tanura

Clean Fuels (Saudi Arabia). There are sizable opportunities in Africa, including Mamba

/ Coral in Mozambique, downstream prospects in Algeria, and offshore work in West

Africa. Asia Pacific is active, with offshore developments in India and Indonesia, but

FLNG projects have challenges. The Americas is less active with near-term uncertainty

in Brazil, although US Gulf prospects (like Mad Dog 2 / Vito) look attractive. Europe is

quiet but could see a pick-up in smaller marginal field / tieback developments

(particularly in Norway). We are not actively capturing any renewables work, which

Subsea 7 and others are chasing, or politically-edged projects such as Nordstream II or

Turkish Stream.

■ Financing trends and OFS balance sheet – Many companies have successfully

negotiated refinancings and revised debt covenants and holidays, but often at higher

cost with restrictions. We believe we are close to the bottom-of-the-cycle but rating

agencies continue to downgrade OFS / E&P credit. There’s a lack of liquidity across

the sector and cash flows remain under pressure. Further financial distress and rising

bad debts look likely. Banks are acting with more caution, and while equity markets

have shown support, many issuances to date suggest a lack of enthusiasm. This

financial backdrop and lower appetite for bank lending is also hindering the sector’s

M&A prospects. A simple net-debt-to-EBITDA screen and stress-test under a grey sky

scenario for our coverage clearly illustrates stocks that look over-leveraged – seismic

players CGG, and to a lesser extent, PGS. AMEC Foster Wheeler is also over-

leveraged, but its disposal programme should relieve some pressure. Only half our

coverage pays a dividend, but, for those that do, the average yield is nearly 4%. The

most attractive yield in the sector is Petrofac at nearly 6%, which we believe is

sustainable.

19 September 2016


■ Subsector outlook – The ‘seismic trade’ has worked well coming out of past cyclical

downturns. Exploration spending is unlikely to recover at a similar pace in this recovery

cycle but we think marine seismic has potential to rebalance quickly. Frontier

exploration is out of favour but the market may underestimate how much pent-up

demand there is for seismic data overall. The drilling sector is another classic early

cycle trade but while volumes are likely to pick up through 2017 (notably onshore, US

and internationally), significant oversupply, particularly offshore, suggests poor

profitability. E&C is mixed – offshore (deepwater in particular) continues to struggle

with project economics, despite considerable initiatives to lower break-evens, whereas

onshore looks more attractive. Engineering is seeing more risk transfer but also

greater commercial alignment. Downstream is buoyant, Upstream seeing ‘green-

shoots’, but Subsea remains challenging. Maintenance / brownfield markets should

recover as oil companies play catch-up on deferred expenditure. Equipment will likely

see growing demand for consumable products as short-cycle drilling activity improves

whereas longer-cycle subsea and drilling equipment markets remain lackluster.

■ Forecasts and Valuation – We use a wide framework to forecast including CS

commodity price assumptions, rig count and E&P capex projections, supply / demand

dynamics for each sub-sector, book-to-bill trends, backlog scheduling and contractor

positioning. We are conservative – our forecasts are 7-10% below consensus on

average – but believe we are approaching the end of the OFS downgrade cycle. We

expect investors to be looking through the trough to 2018, but even here the spread of

valuations is wide. PE valuations appear demanding, but high D&A for heavier-asset

plays is depressing EPS at a cyclical trough in 2018, whereas many other stocks are

still early in a recovery cycle. We do not believe 2018 should be perceived as ‘mid-

cycle’. OFS appears more attractive on EV/EBITDA – where the sector trades on

around 6x in 2018e, with many stocks trading well below typical recovery-cycle

multiples. We value the sector on a combination of nearer-term multiples (using SOTP)

and longer-term DCF, and perform blue sky / grey sky analysis. We initiate coverage

with five Outperforms (Petrofac, Wood Group, Schoeller-Bleckmann, Technip and

PGS), three Neutrals (Saipem, Hunting and Aker Solutions) and four Underperforms

(Subsea 7, AMEC Foster Wheeler, CGG and Tecnicas Reunidas). We also have co-

coverage of Core Labs (Neutral) and Seadrill (Underperform).

19 September 2016


■ Preferred stocks

Petrofac, Outperform, TP GBp1100. PFC has made mistakes – strategic and

operational – and a weak H116 book-to-bill hasn’t helped near-term sentiment.

However we believe PFC is retreating back to a high quality core E&C business, and a

well-underpinned 2017 P&L sees PFC trading at a ~40% 2017E PE discount to closest

comp TRE. This is compelling in itself, but we also see considerable optionality as PFC

disposes of non-core assets. An improving book-to-bill trend in H216 and 2017 should

also bolster confidence in 2018 and beyond.

Wood Group, Outperform, TP GBp850. We view WG as a best-in-class engineering

and maintenance franchise with strong management and a robust balance sheet. It

provides investors with early-cycle exposure to US Unconventionals and engineering

studies, while reorganization improves efficiency and business development prospects.

Furthermore, the valuation – 2017E/18E PE of 13x/11x – looks undemanding against

recovery prospects.

While stocks such as PGS have more upside potential based on our target price, we

deem this a higher risk / higher reward situation.

■ Least preferred stocks

Subsea 7, Underperform, TP NOK75. We think SUBC is an excellent project

manager, but, despite fleet rationalization and reorganization, it remains an inherently

capital intensive business. It will be challenging to extract value from an asset base

that became increasingly commoditized through last cycle. Positive book-to-bill and

2016 earnings upgrades have driven significant share price outperformance ytd, but we

think the situation is about to change sharply as positive cycle backlog unwinds in Q3.

AMEC Foster Wheeler, TP GBp450. Sentiment is improving towards AMFW under

leadership of new CEO Jon Lewis. Restructuring stories can often be good stocks to

own, and we expect a positive message on costs at the CMD in November. However

we believe the market should be braced for further backlog deterioration, material

revenue declines in 2017, and a strategy to chase lower quality (construction) revenue

streams. Disposals should relieve some balance sheet pressure but will not de-lever

AMFW to an optimum capital structure. The 2017E EV/EBITDA of nearly 10x, a

premium to peers, and versus historical multiples, suggests the stock has got ahead of

itself. We believe the market underestimates business headwinds into 2017.

Figure 9: Pan-European OFS Upside / Downside Potential to CS Target Prices

Source: Credit Suisse Research

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Figure 10: Valuation Summary

Stock Rating Target Price +/- Segment Investment Case

Aker Solutions NEUTRAL NOK 35 -4% Equipment Headwinds and tailwinds - The potential rebound in the Norwegian MMO market is underestimated by the market, but so is the softness / duration

of the Subsea market downturn. A much improved company but too early to buy for recovery, in our view.

AMEC Foster

Wheeler

UNDERPERFORM GBp 450 -15% EPCM* Too much too soon - the market has warmed to new CEO Jon Lewis; the stock has outperformed peers since his arrival in June. We expect the

November CDM to deliver positive progress on costs, but investors should not underestimate topline pressures, and future mix looks dilutive.

CGG UNDERPERFORM EUR 17.5 -21% Seismic Over leveraged - February's rights issue has provided little headroom to covenants while market conditions have deteriorated further. The

transformation has created a far better quality business mix, but we think the cyclical recovery will be insufficiently strong to delever materially. As

such CGG's premium rating to PGS looks unwarranted.

Core Laboratories NEUTRAL USD 115 6% Equipment High return / high valuation - we believe the market underestimates the lower-for-longer offshore / deepwater cycle; a key market that in the past

has driven attractive incremental margins. CLB's recovery profile is initially more geared into lower quality (Production Enhancement) revenue

lines; the inflection point on better quality Reservoir Description could be a catalyst - too early to buy, in our view.

Hunting NEUTRAL GBp 500 20% Equipment Early cycle - HTG is a play on US unconventionals - an enlarged Well Completion division with more IP should ensure HTG is faster out the blocks

in this cyclical upswing. However recovering pricing will take time and current valuation suggests to us the stock has run too far too soon.

Petrofac OUTPERFORM GBp 1100 36% E&C* Back to core business - Diversification has not worked; a refocused PFC with best-in-class E&C business at its core is a far more attractive

proposition. P&L is stabilising and well underpinned, and valuation vs closest comp (TRE) appears compelling. Non-core asset disposals provide

additional optionality, in our view.

PGS OUTPERFORM NOK 27 63% Seismic Higher risk / higher reward. The rebound in exploration activity may well underperform past cycles, but we think the market underestimates the

level of pent-up demand for multiclient data and production seismic, plus how quickly the contract market could rebalance. Current multiples imply

a far more pessimistic outturn than we see.

Saipem NEUTRAL EUR 0.45 20% E&C Rehabilitation requires patience – long-cycle business slowly moving in the right direction but significant risks remain – pending revenues, litigation

/ arbitration, offshore drilling re-contracting and cash flow. Risk of downgrade to medium-term financial targets.

Schoeller

Bleckmann

OUTPERFORM EUR 70 33% Equipment Best EU play on US unconventionals - Built out Well Completion line in downturn giving faster growth potential in a recovery and greater through-

cycle balance. Niche technology, highly operationally geared. 2018 multiples in line with long-run average but earnings capacity is double our 2018

estimates.

Seadrill UNDERPERFORM USD 1.0 -53% Drilling All drilled out – continues to pay down debt, but much left to do. Sense of urgency illustrated by net leverage - ~10x late by late 2017E.

Fundamentals remain weak – potentially through to the end of the decade, in our view.

Subsea 7 UNDERPERFORM NOK 75 -11% E&C Cycle realities looming -Top-of-the-cycle backlog is about to run out, and concerns about embedded margin and T&Cs on new work, plus

diversification into low-value add wind farm installation. Heavy asset business and harder to extract value from its fleet in an oversupplied offshore

construction market.

Technip OUTPERFORM EUR 65 27% E&C EU bellwether stock - underappreciation of breadth of TEC's business mix and capabilities - deepwater is important, but multiple other avenues for

growth (shallow water, downstream, gas). FMC deal is defensive against a lackluster near-term market, but combination could disproportionately

benefit from its eventual recovery.

Tecnicas

Reunidas

UNDERPERFORM EUR 28 -14% E&C A strong, well-managed and broad-based contracting business with a largely solid execution track record. However, valuation looks challenged,

particularly against weak near-term order intake trends. We prefer PFC.

Wood Group OUTPERFORM GBp 850 23% EPCM Mispriced quality – Well managed, best-in-class engineering and maintenance franchises, robust balance sheet, and more geared into early cycle

recovery than the market appreciates as catch-up spend on deferred maintenance / brownfield modification bolsters growth in Engineering and US

Unconventionals. Restructuring and streamlined structure increase leverage to growing volumes.

Source: Company data, Credit Suisse estimates

ECM – engineering, project management, consultancy, and maintenance. E&C – engineering and construction

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Figure 11: Pan-European OFS Valuation Summary

Company Ticker Rating Analyst Share YTD Target Pot. Up / Div M.Cap P/E EV/EBITDA EV/Sales P/B

Price Perf price Downside yield USD LC 16E 17E 18E 16E 17E 18E 16E 17E 18E 16E 17E 18E

Aker Solutions AKSOL.OL NEUTRAL Phillip Lindsay NKr 36.54 21% NOK 35 -4% 1204 9941 16.7 41.1 46.8 6.0 7.4 7.7 0.4 0.5 0.5 1.4 1.4 1.4

Core Laboratories CLB.N NEUTRAL Gregory Lewis USD 108.3 0% USD 115 6% 2% 4775 4775 71.9 48.1 33.4 44.4 34.1 25.7 8.3 7.5 6.7 12.0 12.1 10.8

Hunting HTG.L NEUTRAL Phillip Lindsay GBp 415.5 22% GBp 500 20% 818 623 n/a n/a 20.4 n/a 16.5 8.6 1.9 1.5 1.2 1.0 1.0 1.0

Schoeller Bleckmann SBOE.VI OUTPERFORM Gregory Brown EUR 52.65 4% EUR 70 33% 1% 945 842 n/a 51.8 19.9 n/a 11.7 7.5 4.8 3.3 2.5 2.0 2.0 1.8

Equipment 12% 14% 1% 16.7 46.4 29.0 6.0 11.9 7.9 2.4 1.8 1.4 1.5 1.5 1.4

Petrofac PFC.L OUTPERFORM Phillip Lindsay GBp 808.0 -9% GBp 1100 36% 6% 3692 2807 11.4 7.8 7.5 6.9 5.3 5.5 0.6 0.6 0.6 2.8 2.3 2.0

Saipem SPMI.MI NEUTRAL Phillip Lindsay EUR 0.38 -60% EUR 0.45 20% 4271 3805 15.0 14.2 14.6 4.2 4.2 4.1 0.5 0.5 0.5 0.5 0.5 0.5

Subsea 7 SUBC.OL UNDERPERFORM Phillip Lindsay NKr 84.70 44% NOK 75 -11% 3357 28039 9.9 50.9 33.0 3.4 6.5 6.0 0.9 0.9 0.9 0.6 0.6 0.6

Technip TECF.PA OUTPERFORM Phillip Lindsay EUR 51.30 12% EUR 65 27% 4% 7043 6276 10.9 15.7 18.0 3.7 4.8 5.3 0.4 0.5 0.5 1.4 1.3 1.3

Tecnicas Reunidas TRE.MC UNDERPERFORM Phillip Lindsay EUR 32.50 -7% EUR 28 -14% 4% 2038 1816 12.7 13.0 12.3 6.5 6.6 6.3 0.3 0.3 0.3 3.5 3.1 2.8

Engineering & Construction -4% 11% 5% 12.0 20.3 17.1 5.1 5.7 5.7 0.6 0.6 0.6 1.8 1.6 1.4

AMEC Foster Wheeler AMFW.L UNDERPERFORM Phillip Lindsay GBp 531.0 24% GBp 450 -15% 4% 2735 2071 10.1 11.3 10.0 8.8 9.5 8.7 0.6 0.6 0.6 1.7 1.7 1.6

Wood Group WG.L OUTPERFORM Phillip Lindsay GBp 688.5 1% GBp 850 23% 4% 3465 2641 13.7 12.5 11.3 8.7 8.2 7.5 0.7 0.7 0.7 1.4 1.3 1.3

Engineering, Consultancy and Maintenance 12% 4% 4% 11.9 11.9 10.6 8.8 8.9 8.1 0.7 0.7 0.6 1.5 1.5 1.4

CGG GEPH.PA UNDERPERFORM Gregory Brown EUR 22.06 -46% EUR 17.5 -21% 548 481 n/a n/a n/a 8.0 5.6 4.3 2.1 1.9 1.7 0.3 0.4 0.5

PGS PGS.OL OUTPERFORM Phillip Lindsay NKr 16.60 -51% NOK 27 63% 482 4054 n/a n/a n/a 5.3 3.9 3.0 2.0 1.8 1.6 0.3 0.4 0.4

Seadrill SDRL.N UNDERPERFORM Gregory Lewis USD 2.15 -37% USD 1.0 -53% 1093 1093 2.2 n/a n/a 5.6 10.0 37.5 3.2 4.5 6.2 0.1 0.1 0.1

Seismic and Drilling -45% 3% 0% 2.2 n/a n/a 6.7 4.7 3.6 2.0 1.8 1.6 0.3 0.4 0.4

Pan Euro OFS -6% 8% 4% 11.4 24.2 19.4 6.2 7.6 6.3 1.3 1.1 1.0 1.4 1.3 1.3

Source: Company data, Credit Suisse estimates Prices as of 13th September 2016. Averages omit multiples deemed to be outliers (such as negative P/E)

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Figure 12: Credit Suisse Est vs. Consensus

Company Rating FX CS EBITDA CS EBITDA vs Cons CS EPS CS EPS vs Cons

16E 17E 18E 16E 17E 18E 16E 17E 18E 16E 17E 18E

Aker Solutions NEUTRAL Nkr 1845 1481 1439 -4% -1% -13% 2.19 0.89 0.78 29% -1% -40%

Core Laboratories NEUTRAL US$ 113 148 196 -5% -8% -15% 1.51 2.25 3.25 -4% -3% -7%

Hunting NEUTRAL US$ -46 55 106 93% -5% 19% -0.49 0.04 0.27 15% 95% 66%

Schoeller Bleckmann OUTPERFORM € 3 74 115 -90% -4% 6% -1.92 1.02 2.65 23% -10% 8%

Equipment -2% -5% -1% 16% 20% 7%

Petrofac OUTPERFORM US$ 649 837 818 -14% -5% -3% 0.94 1.36 1.41 -8% 7% 14%

Saipem NEUTRAL € 1297 1226 1168 4% 9% -2% 0.03 0.03 0.03 4% 15% -4%

Subsea 7 UNDERPERFORM US$ 909 475 514 7% -9% -11% 1.04 0.20 0.31 8% -25% -14%

Technip OUTPERFORM € 1119 861 788 -4% -8% -13% 4.69 3.27 2.84 3% 5% -6%

Tecnicas Reunidas UNDERPERFORM € 203 199 210 2% -6% 3% 2.55 2.50 2.64 5% -2% 9%

Engineering & Construction -1% -4% -5% 2% 0% 0%

AMEC Foster Wheeler UNDERPERFORM £ 356 330 360 4% -7% -6% 52.6 47.1 53.0 4% -11% -10%

Wood Group OUTPERFORM US$ 436 462 504 5% 9% 9% 0.66 0.73 0.81 4% 11% 10%

Engineering, Consultancy and Maintenance 5% 1% 2% 4% 0% 0%

CGG UNDERPERFORM US$ 342 495 638 -26% -16% -9% -19.3 -4.56 -0.28 45% -28% -93%

PGS OUTPERFORM US$ 300 415 541 0% 10% 15% -0.90 -0.56 -0.06 12% 14% -43%

Seadrill UNDERPERFORM US$ 1760 984 262 -3% -11% -71% 0.97 -0.19 -1.40 -25% -378% 181%

Seismic and Drilling -10% -6% -22% 11% -7% -68%

Pan-European OFS -2% -4% -7% 8% -3% -8%

Source: Credit Suisse Research. Averages omits distortions (such as % change on low numbers in absolute terms)

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Figure 13: Credit Suisse Global Oilfield Services Valuation Summary

Company Ticker Rating Analyst Share Target Potential P/E EV/EBITDA

Price Price Up/Downside 16E 17E 18E 16E 17E 18E

Baker Hughes BHI.N OUTPERFORM James Wicklund USD 48.3 USD 56.0 16% n/a n/a 24.4 n/a 19.3 9.3

Core Laboratories CLB.N NEUTRAL Gregory Lewis USD 108.3 USD 115.0 6% 71.9 48.1 33.4 44.4 34.1 25.7

Halliburton HAL.N OUTPERFORM James Wicklund USD 41.1 USD 49.0 19% n/a 30.8 14.2 21.4 11.2 7.8

Schlumberger SLB.N OUTPERFORM James Wicklund USD 77.1 USD 87.0 13% 70.2 40.7 22.4 18.0 15.2 11.3

Superior Energy Services SPN.N NEUTRAL James Wicklund USD 15.3 USD 17.0 11% n/a n/a 32.3 31.5 12.4 6.5

Weatherford WFT OUTPERFORM James Wicklund USD 6.3 USD 7.0 12% n/a n/a 50.5 32.4 12.1 7.5

Well Services 13% 71.0 39.9 29.5 29.5 17.4 11.3

Hi-Crush Partners HCLP.N OUTPERFORM James Wicklund USD 15.4 USD 17.0 11% n/a 45.5 8.4 -20.5 19.9 7.2

US Silica SLCA.N OUTPERFORM James Wicklund USD 40.7 USD 49.0 20% n/a 80.3 14.8 92.7 17.4 7.8

Tetra Technologies TTI.N OUTPERFORM Jacob Lundberg USD 5.8 USD 8.0 38% n/a -35.9 29.9 10.5 7.4 5.8

Sand and Chemicals 23% n/a 62.9 17.7 51.6 14.9 7.0

Aker Solutions AKSOL.OL NEUTRAL Phillip Lindsay NKr 36.5 NOK 35.0 -4% 16.7 41.1 46.8 6.0 7.4 7.7

Forum Technologies FET.N OUTPERFORM Jacob Lundberg USD 17.6 USD 19.0 8% n/a n/a 30.4 n/a 24.4 11.2

Frank's International FI.N NEUTRAL James Wicklund USD 11.7 USD 12.0 3% n/a n/a n/a 30.6 14.0 6.9

Hunting HTG.L NEUTRAL Phillip Lindsay GBp 415.5 GBp 500.0 20% n/a n/a 20.4 n/a 16.5 8.6

National Oilwell Varco NOV.N UNDERPERFORM James Wicklund USD 33.1 USD 23.0 -30% n/a n/a 41.1 50.5 22.0 11.8

Oil States OIS.N NEUTRAL James Wicklund USD 28.7 USD 35.0 22% n/a n/a 36.3 32.1 19.6 9.2

Schoeller Bleckmann SBOE.VI OUTPERFORM Gregory Brown EUR 52.7 EUR 70.0 33% n/a 51.8 19.9 n/a 11.7 7.5

Equipment 7% n/a 46.4 32.5 29.8 16.5 9.0

CB&I CBI.N OUTPERFORM Jamie Cook USD 28.4 USD 46.0 62% 5.9 6.8 6.2 4.7 4.8 4.7

Chiyoda 6366.T NEUTRAL Shinji Kuroda JPY 819.0 JPY 700.0 -15% 61.9 52.3 44.5 4.8 4.6 4.3

COOEC 600583.SS OUTPERFORM Horace Tse CNY 7.0 CNY 8.5 22% 12.3 11.4 10.7 6.3 5.7 5.3

JGC 1963.T NEUTRAL Shinji Kuroda JPY 1661.0 JPY 1500.0 -10% 9.7 18.9 20.5 3.7 5.6 6.4

McDermott MDR.N NEUTRAL Jamie Cook USD 4.8 USD 5.5 14% 35.8 32.4 19.4 5.9 5.5 4.7

Fluor FLR.N OUTPERFORM Jamie Cook USD 49.6 USD 59.0 19% 15.3 14.6 12.1 6.6 6.7 5.8

Oceaneering OII.N NEUTRAL James Wicklund USD 25.5 USD 27.0 6% 32.0 n/a n/a 7.5 9.3 10.1

Petrofac PFC.L OUTPERFORM Phillip Lindsay GBp 808.0 GBp 1100.0 36% 11.4 7.8 7.5 6.9 5.3 5.5

Saipem SPMI.MI NEUTRAL Phillip Lindsay EUR 0.4 EUR 0.45 20% 15.0 14.2 14.6 4.2 4.2 4.1

Sinopec Engineering 2386.HK UNDERPERFORM Horace Tse HKD 6.6 HKD 5.3 -19% 10.6 9.4 9.6 4.5 4.0 4.1

Subsea 7 SUBC.OL UNDERPERFORM Phillip Lindsay NKr 84.7 NOK 75.0 -11% 9.9 50.9 33.0 3.4 6.5 6.0

Technip TECF.PA OUTPERFORM Phillip Lindsay EUR 51.3 EUR 65.0 27% 10.9 15.7 18.0 3.7 4.8 5.3

Tecnicas Reunidas TRE.MC UNDERPERFORM Phillip Lindsay EUR 32.5 EUR 28.0 -14% 12.7 13.0 12.3 6.5 6.6 6.3

Engineering & Construction 10% 18.7 20.6 17.4 5.4 5.8 5.7

Source: Credit Suisse Research. Averages omit multiples deemed to be outliers (such as negative P/E) Prices as of 13th September 2016

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Figure 14: Credit Suisse Global Oilfield Services Valuation Summary

Company Ticker Rating Analyst Share Target Potential P/E EV/EBITDA

Price Price Up/Downside 16E 17E 18E 16E 17E 18E

AMEC Foster Wheeler AMFW.L UNDERPERFORM Phillip Lindsay GBp 531.0 GBp 450.0 -15% 10.1 11.3 10.0 8.8 9.5 8.7

Jacobs Engineering JEC.N OUTPERFORM Jamie Cook USD 50.2 USD 60.0 20% 16.2 15.0 13.6 9.0 8.3 7.9

KBR KBR.N OUTPERFORM Jamie Cook USD 14.6 USD 18.0 23% 10.4 11.7 11.2 4.9 5.3 5.1

Wood Group WG.L OUTPERFORM Phillip Lindsay GBp 688.5 GBp 850.0 23% 13.7 12.5 11.3 8.7 8.2 7.5

WorleyParsons WOR.AX OUTPERFORM Mark Samter AUD 7.7 AUD 9.2 20% 12.1 11.3 10.8 7.3 6.8 6.6

Engineering, Consultancy and Maintenance 14% 12.5 12.3 11.4 7.7 7.6 7.2

CGG GEPH.PA UNDERPERFORM Phillip Lindsay EUR 22.1 EUR 17.5 -21% n/a n/a n/a 8.0 5.6 4.3

PGS PGS.OL OUTPERFORM Phillip Lindsay NKr 16.6 NOK 27.0 63% n/a n/a n/a 5.3 3.9 3.0

Seismic 21% n/a n/a n/a 6.7 4.7 3.6

Tenaris TENR.MI UNDERPERFORM Michael Shillaker EUR 11.6 EUR 8.0 -31% n/a n/a n/a 20.2 15.2 11.9

Vallourec VLLP.PA UNDERPERFORM Michael Shillaker EUR 4.0 EUR 3.0 -24% n/a n/a n/a n/a 42.8 15.6

OCTG -28% n/a n/a n/a 20.2 29.0 13.7

Helmerich & Payne HP.N UNDERPERFORM James Wicklund USD 57.2 USD 52.0 -9% n/a n/a n/a 15.2 20.6 19.8

Hilong 1623.HK OUTPERFORM Horace Tse HKD 1.0 HKD 1.8 80% 10.9 6.9 5.8 5.5 4.7 4.2

Nabors NBR.N NEUTRAL James Wicklund USD 9.3 USD 9.0 -3% n/a n/a n/a 9.0 9.6 7.3

Patterson-UTI Energy PTEN.OQ UNDERPERFORM James Wicklund USD 18.4 USD 15.0 -19% n/a n/a n/a 18.3 17.1 10.9

Precision Drilling PDS.N UNDERPERFORM James Wicklund USD 3.8 USD 3.0 -20% n/a n/a n/a 15.2 12.3 9.2

Onshore Drillers 6% n/a n/a n/a 12.6 12.9 10.3

Atwood Oceanics ATW.N NEUTRAL Gregory Lewis USD 7.2 USD 6.0 -17% n/a n/a n/a 2.7 8.4 11.7

COSL 2883.HK OUTPERFORM Horace Tse HKD 6.0 HKD 8.0 32% n/a 38.7 29.1 17.6 11.4 10.3

Diamond Offshore DO.N NEUTRAL Gregory Lewis USD 15.2 USD 18.0 19% 16.0 34.8 n/a 6.6 7.8 12.9

Ensco ESV.N NEUTRAL Gregory Lewis USD 6.9 USD 10.0 45% 4.9 42.2 n/a 5.7 9.2 17.4

Noble Corporation NE.N OUTPERFORM Gregory Lewis USD 5.5 USD 10.0 81% n/a n/a n/a 5.4 8.3 9.1

Pacific Drilling PACD.N NEUTRAL Gregory Lewis USD 3.3 USD 4.0 23% n/a n/a n/a 6.4 14.9 27.3

Rowan RDC.N OUTPERFORM Gregory Lewis USD 12.8 USD 15.0 18% 7.3 n/a n/a 4.0 6.8 12.7

Seadrill SDRL.N UNDERPERFORM Gregory Lewis USD 2.2 USD 1.0 -53% 2.2 n/a n/a 5.6 10.0 37.5

Transocean RIG.N UNDERPERFORM Gregory Lewis USD 9.3 USD 5.0 -46% 12.4 n/a n/a 5.7 10.7 8.4

Offshore Drillers 11% 8.6 38.6 n/a 6.6 9.7 16.4

Global OFS Average 10% 19.2 26.0 21.3 13.8 11.5 9.5

Source: Credit Suisse Research. Averages omit multiples deemed to be outliers (such as negative P/E) Prices as of 13th September 2016

19 September 2016


Industry background The deep-rooted problems of the oil & gas industry are well documented – put simply, the

cost of developing increasingly complex oilfields has outweighed the value created – and

returns have been sub-optimal. A performance-based culture has been lacking, and there

was insufficient accountability for poor project execution. Other industries appear

significantly ahead of oil & gas in terms of project delivery, efficiency and technology. We

think valuable lessons could be learned if the industry is willing to embrace different

practices. The worst downturn in a generation is not a situation to be wasted.

The offshore industry in particular ‘hit a wall’ during the last cycle – many projects were

simply uneconomic even while oil prices were USD100-plus. The unconventional E&P

industry also destroyed value as it chased growth, consequently leading to the

oversupplied oil market that caused oil prices to correct. For the North American land E&P

industry, cumulative industry profit / cash flow was actually negative through the last cycle.

Through the downturn, we’ve seen widespread high grading of acreage (as oil companies

look to maximise near-term production / cash flow), significant deflation and pricing

concessions across the OFS supply chain. Project economics and cost per barrel have

improved, in some cases markedly, but we should be cautious in calling this real value

creation. We believe some value has been created but we’ve also seen a clear

redistribution of cost burden from oil companies to OFS companies – many of the savings

could be considered cyclical rather than structural.

Unlike 2009, the present downturn has been deeper, more protracted and caused more

financial distress. The worst appears to be behind us, but poor visibility on cash flows

could yet deliver further liquidity issues, and the need to secure backlog at the bottom of

the cycle could still see competitive pressures intensify into 2017. These themes are not

unusual in cyclical troughs.

So what is different? The behavior of the industry appears to be changing. The offshore

industry in particular realised change was needed long before the downturn struck. A

protracted downturn and a ‘lower-for-longer’ medium-term outlook are forcing the issue

home.

Deflation has been helpful, but the industry approach to planning projects is different now.

A lot of technical expertise has left oil companies through restructuring. There’s far greater

OFS involvement at the front-end – more man-hours expended, more involvement from

later-cycle players, and more thought around life-of-field project planning.

Oil company-specific standards are being gradually replaced by industry-wide standards,

the industry is now leaner – it can now do more with less, and new and innovative

business models are seeing widespread adoption. For an industry that has tended to be

slow to embrace change and new technologies, this behavioral difference is refreshing.

We note that the whole industry is not behaving in the same way – many oil companies

appear happy to capitalise on the marked deflation seen across the supply chain. All oil

companies should benefit from this, largely to the same degree. Equally, while all OFS

companies have shrunk, many OFS companies have not fundamentally ‘changed’ and

appear to be merely waiting for recovery. Differentiating such companies from those

targeting a structural improvement in through-cycle project economics may be difficult in

the near term; performance divergence will be more evident the longer the cycle

progresses.

While we have not yet seen a meaningful change in the way oil companies engage and

contract with the supply chain, we are starting to see a shift in behavior and contracting

strategies. This can take time – it might take another cycle or two for these changes to be

fully implemented. There is a drive towards greater standardisation (of equipment,

19 September 2016


components, processes, etc), more collaboration between oil companies and the supply

chain, more innovation around technology and project solutions, and wider adoption of an

integrated approach. Ultimately, there’s more commercial alignment across the life-of-field.

For the OFS segment, investors should consider who is driving or embracing such

changes, who is aligning with this more holistic approach around the lifecycle of a project,

who has technology or differentiation (assets or niche skills-set), and who can engineer

the best solutions that can make a difference to oil company returns. We think those

companies that align more effectively with oil companies are likely to achieve greater

customer penetration and share in the potential upside.

More commoditised offerings will simply ride the cycle. However, the over-capacity built up

through the last cycle in some areas (eg, Offshore Drilling and Offshore Construction) is so

extreme that it limits the potential upside to a recovery cycle. We expect a more gradual

recovery than in prior cycles, meaning idle assets can slowly get back to work, but

regaining any pricing power does not appear to be on the medium-term horizon.

Our central assumption is for a stabilisation in global E&P capex through 2017 in absolute

USD terms and a return to growth in 2018 (mid-to-high single digits) with momentum

building towards the end of the decade. The mentality of the industry today looks to have

moved on from ‘what to cut’ to ‘what to do’ – it is now drawing up plans for the next wave

of projects. Oil companies seem to be more content now on where costs have fallen to,

but there are also growing concerns about future production declines. All this suggests a

recovery in activity levels and E&P capex.

In the initial phase of the recovery we’d expect oil companies to focus on lower-cost /

faster-payback projects – US unconventional, international onshore conventional, and

marginal field / tieback developments, brownfield, extension of life and tie-back to existing

facilities in the offshore / subsea sectors. We’d also expect a continuation of larger

greenfield projects that are more strategic in nature. Large-scale and more complex

deepwater projects may be less prominent initially, but should begin to recover in 2018/19

– but we expect such projects to be more phased than previously.

19 September 2016


10 key themes for the recovery cycle In this section, we discuss what we believe will be the most important themes governing

the EU OFS sector in the coming cyclical upswing.

1) Capital discipline and capital intensity

With industry E&P spend down over 40% from the 2014 peak, the oil industry has

responded aggressively to lower oil prices and oil market oversupply. The OFS sector

feels the brunt of this, but is arguably responsible for the predicament in which it finds itself

today. OFS overspent in the last cycle – building capacity (often speculatively, particularly

in the offshore drilling sector) for an exceptionally high level of demand; the OFS asset

base is currently significantly underutilised.

This situation is unlikely to change in the early stages of a recovery. Indeed, the industry

could theoretically grow E&P capex by 10% per annum for the next three to four years and

there would still be oversupply across many parts of the value chain. However, the pace of

asset scrapping and facility mothballing has quickened as the downturn has persisted –

this is helpful to rebalance the market.

In a recovery cycle, companies spend opex rather than capex when adding more shifts,

crews, etc. The need to invest and build additional capacity to meet growing demand is not

there as growth can be achieved from utilising the industry’s existing asset base and

infrastructure. This will likely be a cycle of reactivation rather than reinvestment, which, in

time should be positive for free cash flow, dividend reinstatement and cash returns to

shareholders.

Figure 15: OFS Capex and depreciation forecasts

Note: Excludes asset-light players/companies where data is unavailable. Source: Company data, Credit Suisse estimates

Tangible and intangible asset bases have seen substantial accounting write-offs – across

our coverage, we’ve seen over USD3bn / USD5bn of tangible / intangible asset write-offs

since the downturn began. Investing below depreciation would only erode asset bases

further. In theory, this should enable the OFS sector to grow returns faster than in previous

cycles when it was not uncommon to see companies spending 2-3 times depreciation in

growing their asset bases to support demand growth.

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Key beneficiaries: PFC, TEC, CLB, CGG

19 September 2016


We believe the OFS industry could feasibly run at close to maintenance or sustaining

levels of capex for several years as existing capacity is absorbed gradually in the up-cycle.

Costs associated with reactivation of assets are often substantially less than the cost of

investing in new. The pain felt today is unlikely to be forgotten easily in the market’s

recovery phase – we expect a far more disciplined approach from OFS companies.

This cycle perhaps more than any other illustrates why the OFS sector would benefit from

greater capital discipline. There should be significantly more scrutiny over any new

investments that may be required in the future. Hurdle rates for new investments should

be higher, and adhered to. If the OFS sector can embrace a more returns-focused

approach, this should deliver improved shareholder returns in the long run. This should be

the case even if, as we forecast, future profitability fails to reach previous cycle highs.

Figure 16: EU OFS ROIC trend by sub-sector Figure 17: EU OFS ROIC trend

Source: Credit Suisse estimates, company data Source: Credit Suisse estimates, company data

Lower capital intensity – there were promising signs towards the end of the last cycle

that the more heavy-asset OFS players were looking to reduce capital intensity. The

downturn has focused the industry mind and this process has accelerated; asset bases

have been reduced, markedly in some cases. We don’t see these strategies reversing in a

recovery cycle – this is a structural shift to lower capital intensity.

The value for OFS companies lies in differentiated assets – there is no need to own assets

that provide more commoditised services. This strategy shift is notable in SURF and

Seismic industries, where major providers have scaled back their fleets materially to

mostly high-end vessels, with plans to source more commoditised vessels from third

parties as required. We believe, however, that more could be done given the scale of

oversupply. Other players, like Petrofac, are also scaling back their more capital-intensive

business lines (ie, IES).

We note, however, that the industry could lose some of this benefit in working capital.

We’d expect oil companies to push more onerous terms & conditions onto contractors

during the downcycle (we discuss this below). Contractors may be willing to suffer less

generous payment terms (lower cash advances, less attractive stage payments and so on)

to secure utilisation for their assets, particularly in the low point of the cycle.

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19 September 2016


2) Terms & Conditions, and pricing

The transfer of risk from oil companies to OFS companies should not be underestimated,

particularly in a downturn as material as this one. With industry backlogs continuing to

decline, we are concerned about OFS companies contracting at more onerous terms &

conditions. Too often in the past, we think new contract awards were perceived by the

market as a blind positive; stocks moved on positive book-to-bill trends. However, it is

difficult for the market to understand fully the level of risk in a given contract – investors

should act with more caution now, in our view.

Ideally, there should be a limit to what contractors can accept in terms of risk. If a risk

cannot be priced realistically (uncapped maximum liabilities, for example) or cannot be

insured, the contractor should probably walk away. However, contractors may be more

willing to take a risk on higher liquidated damages, given most contracts rarely come to

this (Petrofac on Laggan Tormore was an exception recently as Total enforced partial

application of liquidated damages in May 2016). Less favourable payment / cash flow

terms are also increasingly common as oil companies look to preserve more cash and

pressure OFS into financing projects.

In theory, if the industry behaves rationally, an oil company should often be disappointed

upon receipt of the bids – in terms of indicative pricing (as greater risks have bumped up

the price), or the level of non-compliant bids (as contractors refuse to take on excessive

risk). Contractors should be particularly diligent in the contracting process with state-

owned entities, although it seems the whole industry has become more contractual in

recent years.

Greater project complexity was pitched as a positive by several players in the last cycle

because of less competition and potential for higher margins, but heightened risks were

overlooked. This was perhaps best illustrated by Subsea 7’s execution challenges and

significant charges on Guara Lula in Brazil. But even where terms & conditions were more

favourable to the contractor, variation / change orders were often fiercely contested,

particularly towards the latter stages of the cycle – several cases are currently in litigation.

In the past, some contractors appear to have bid low and over-relied on variation / change

orders to achieve required / required margins. This is not an option now for OFS players

with oil companies fiercely contesting any deviation from the letter of the contract. As a

result of such issues in 2015, Technip enforced a strict policy to no longer carry out

additional works without explicit sign-off from the customer. The rise in the level of

‘assessed’ or ‘pending’ revenues within working capital balances and receivable write-offs

should act as a deterrent to such behavior.

Thus far in the downturn, there is very little anecdotal evidence that the OFS sector as a

whole is taking on any unreasonable terms & conditions. We’d expect such behavior to be

more prevalent within less well-capitalised players fighting for survival. However, the

market should be cognizant of the pressures to secure work as good cycle backlogs

unwind. Navigating this phase of the cycle is fraught with difficulties – OFS needs to stand

firm.

Deflation and pricing. The OFS supply chain must be prepared to give up some margin

in a downturn – at the extremity, some parts of the value chain are operating at or below

cash breakeven. This is unsustainable – OFS cannot work for nothing. However, the

sector can work for low margins to secure utilisation for key assets / people as a stop-gap

to more benign market conditions. We think the OFS sector has given up more margin in

this cycle than in at least 30 years – the base from which the sector should recover has

been pegged back continually.

Most impacted: SPM, TRE, SUBC, PFC, TEC,

SDRL, AMFW

19 September 2016


Figure 18: Cost deflation over time

Source: BP

The pressure relief valve for OFS is restructuring its own cost base and driving operational

efficiencies – the downturn is forcing the industry to be more efficient. The industry is now

leaner – it can do more with less. The duration of the downturn has been a force for good

in this regard – it has created an environment where the industry can create lasting

change.

The global bellwether, Schlumberger, has said it believes it can recover to 2014 earnings

on a revenue-base some 50% lower. Schlumberger is an exceptional company

undergoing a material transformation. Its financial performance through the downturn

consistently defied market expectations and management believes it can continue to

outperform in a recovery cycle. We think few European OFS companies could deliver this

level of financial performance, although this partly reflects longer-cycle, more contracting-

based, business models.

Given oil market oversupply, there has been less incentive for oil companies to invest

counter-cyclically. However, with oil markets now in balance (or close to balance), oil

company rhetoric is beginning to move away from capital discipline towards concerns over

future production.

Typically, projects sanctioned towards the bottom of a cycle deliver the best financial

returns for oil companies. There are several factors behind this – rock-bottom supply chain

costs, utilisation of the best teams (getting ‘the A-team’ is a priority for oil companies) and

more effective project vetting having been through several recycling phases. We expect

this cycle to be no different in this respect. Regaining any pricing advantage could take

considerable time; it is imperative, therefore, that OFS continues this efficiency drive.

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19 September 2016


3) Fewer standards, more standardisation

Oil industry standards are changing. The post Macondo industry move to build in

additional redundancy, gold plating facilities and over-engineering only appear to have

served to add layers of unnecessary cost and complexity. In some cases this is driven by

regulation, but Macondo was pivotal; the response was a natural one, but in hindsight

appears to have been excessive, in our view.

Even prior to this, the oil industry operated in silos – each company with its own bespoke

set of standards and designs, built up over decades, and insufficient collaboration across

the value chain. This is not easy to reverse, certainly not in any near-term timeframe, and

health and safety or environmental concerns should not be compromised. However, we

are encouraged to see several major oil companies on a drive towards standardising

processes, well designs, and technologies.

Investors could take any CMD presentation from any major oil company and see common

themes and trends around cost efficiency. Oil companies' main concern is ensuring that

many improvements are structural and costs don’t inflate when oil prices recover. Further

standardisation and simplification can play a major role in achieving this goal and ‘copycat’

or repeatable design solutions can deliver real value.

Statoil, for example, has said it believes further standardisation and simplification is key,

from work processes to technology. It now selects well design from 10 prototype designs –

the list was over 50 previously. Similarly, the number of drilling & completion processes

were whittled down from 900 to 200. Recent presentations from majors BP and Shell

shared similar themes.

Figure 19: Oil price breakeven by project type

Source: Quest Offshore

The industry is now looking well past the traditional resource development models –

moving to a more industrial specification / process-driven model versus bespoke design.

Oil companies today are far more interested in the best available solution concept, rather

than one based on their own internal standards. This is a serious cultural change and one

should not assume this change in attitude and approach is representative across the

industry. But we think there’s enough commentary from large integrated companies that

the wider industry is surely taking note.

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Most impacted: WG, AMFW, TEC, SUBC,

SPM, SBOE, HTG

19 September 2016


Future oil development success can also be driven by greater supply chain engagement

and collaboration, in order to improve competence, capacity and efficiency. A good

example of this is FMC Technologies' agreement with four major oil companies (Anadarko,

BP, ConocoPhillips and Shell) to work towards a standardised subsea tree design to

enable the high pressure/high temperature Gulf of Mexico fields to be developed.

Contracting structures and formats can be simplified to reduce cost and complexity,

unbundling contract packages where interface costs are prohibitive. The level of ‘man-

marking’ on projects was excessive – more-competent suppliers should be granted greater

responsibility.

4) Changing commercial models

As we discuss earlier, it is 'normal' in a downturn for oil companies to push more risk onto

their supply chains. However, we think some companies are prepared to put 'more skin in

the game', particularly where there is full understanding of the risks involved or where

technology advantage exists over the oil industry.

Typically, the OFS industry provides services to oil companies at a fixed rate for a given

activity. Incentive-based contracting structures were increasingly common in the last cycle.

AMEC Foster Wheeler championed the use of KPI-mechanisms within opex contracts

where base margin was typically below the industry average but good performance

against KPIs resulted in higher profitability.

However, contractual structures were rarely this black and white – in large developments

with multiple contractors, oil companies looked to align through KPIs relating to the overall

performance on a project. Contractor ‘A’ would suffer if Contractor ‘B’ underperformed.

Such contracts were also hard to enforce when the downturn hit – oil companies might

acknowledge good performance but getting paid appropriately became increasingly

challenging.

However, we see incentive-based contracts being more common. For example, in the Well

Services market, there’s a move for drilling contractors and services providers to be

remunerated/incentivised to beat the ‘authority for expenditure’ (AFE) – a budgetary

document prepared by the operator that lists the expected costs associated with drilling a

well to a specified depth or casing point and then completing the well). If a contractor can

drill faster, for example, it would be better placed to beat the AFE. Schlumberger, for

example, outperformed targets on the Det Norkse Ivar Aasen project.

Figure 20: Det Norkse Ivar Aasen – Schlumberger

performance

Figure 21: Det Norkse Ivar Aasen – Schlumberger

performance vs. AFE and original plan

Source: Schlumberger, Det Norkse Source: Schlumberger, Det Norkse

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Most exposed: TEC, SUBC, AKSO, SPM,

WG, AMFW

19 September 2016


Commercial models such as these are early stage. The Mariner project, where

Schlumberger is providing bundled services to Statoil, is an example of how such a

contract could work. According to Statoil: “The aim for this contract is a long-term

partnership with a performance based compensation format rewarding actual performance

– metres drilled and completed – rather than usage of time and material.”

E&Ps have typically shown more flexibility on commercial models. For example, EnQuest,

on its Kraken development rather than competitively tendering it formed a partnership with

the contractor (Aker Solutions), established a target cost for the project, and worked

collaboratively to design and execute the project. The project was delivered ahead of

schedule and budget.

The Subsea industry has undergone notable change in striving to improve project

economics. Technip and FMC Technologies announced the Forsys JV in Q1 2015,

triggering a chain reaction across the industry with all other major players forming

alliances. Traditionally, operators have set about managing the various interfaces

independently through a central project management function – this approach looks

increasingly dated and inefficient. What the supply chain is presenting here is a structural

improvement in project economics.

5) The importance of ‘the front-end’, and remaining on the critical path

A comprehensive report of oil & gas projects by Ernst & Young (Spotlight on oil and gas

mega projects, October 2014) found that over 60% of mega-projects go over budget and

over 70% are delivered late. We believe NPV destruction over past cycles can more often

than not be attributed to projects being delivered late. The root causes of this can often be

traced back to early-stage project design and planning. The industry has under-invested in

this crucial stage of project planning – inadequate sub-surface definition and risking, sub-

optimal concept selection, and even weak project selection.

Figure 22: Influence on Project Concepts and Expenditures

Source: Wood Group

A thorough evaluation of development concepts before selection is needed, followed by a

more thorough FEED study before reaching final investment decision (FID). This should

not be confused with over-engineering a project, which we think the industry has also

done. More man-hours should be spent on simplifying / optimising the development plan to

ensure projects remain on the critical path in the execution phase.

The decisions made at the front-end ultimately determine a given project’s success.

However, the level of USD investment associated with this stage is typically very small –

typically 2-5% of total investment cost. Expending sufficient man-hours across key areas –

Plan Select Define Engineer Procure ConstructStart up &

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Key beneficiaries: WG, AMFW, AKSO,

TEC, SUBC

19 September 2016


the reservoir, the facilities, and well construction – can enhance cost predictability and

production attainment materially.

In the last cycle, later-cycle players were becoming more involved at the front-end, yielding

greater influence over a project’s lifecycle. We expect this theme to gather momentum in

the current cycle. It’s important that on-the-ground execution expertise is consulted at this

stage for greater understanding of execution issues that could arise with a particular

design. Constructability needs to be understood fully if the industry is to improve on its

poor track record.

A fit-for-purpose approach, with more collaboration between oil companies and the supply

chain should see the benefits extend through to detailed design, fabrication, procurement,

contracting strategies, etc. The role of the services sector is arguably greater now as in-

house capabilities of oil companies have diminished over the past decades – a situation

exacerbated by the expertise shed in the current downturn. There are exceptions to the

rule – we note Chevron appears to be have taken the decision to perform more pre-FEED

project analysis in-house. We do not believe such initiatives are widespread.

Oil companies understand that late delivery of projects can have a material impact on

overall project economics. We think oil companies are typically becoming more ‘value’

than ‘cost’ oriented – the lowest-cost provider of services does not always provide the best

value. A service provider’s track record for on-time delivery will be a greater factor in who

wins the work in the coming cycle.

6) Technology matters

A more returns-focused industry is likely to pay a premium for technology that drives

project returns higher. We expect companies with technology differentiation to outperform

in a recovery cycle. The ability to integrate technologies is an equally important

differentiator. Such providers can become integral to a development’s success and are

viewed increasingly as project lifecycle partners.

In a sluggish Subsea market, we note that the subsea system to be delivered by

OneSubsea was an enabler for the Greater Enfield project in Australia. The subsea trees

being used are fairly standardised, but the integration of these trees with the boosting

system and, most importantly, a unified control system make a marked improvement on

recovery rates and overall project economics.

OneSubsea also delivered boosting technology on Chevron’s signature project in the US

Gulf of Mexico – Jack St Malo – where the operator talked of incremental production of 50-

150 b/e through utilising this technology. OneSubsea delivered the system and booked its

margin – the resource owner extracted far greater value than the technology provider.

Elsewhere in the subsea space we expect new high-pressure/high-temperature

technology to open up frontier parts of the US Gulf of Mexico. FMC Technologies is

developing a 20,000psi subsea production system – an enhanced version of its existing

vertical deepwater tree, which increases the capacity from 150,000psi and 350°

Fahrenheit to 20,000psi and 400°Fahrenheit – such technology could lead to the

commercialisation of the Paleogene discoveries in the US Gulf including BP’s Kaskida and

Tiber.

New technology has also been used to lower development costs, as in the case of

automated platforms. Through using an unmanned platform for handle production from

three satellite fields around Oseberg, Statoil has avoided the cost of a subsea

development. The dry trees used will also be easier and cheaper to perform routine

maintenance. The unmanned facility is made possible by the control technology –

production will be monitored and controlled remotely from the Oseberg field centre.

Removing platform modules such as living facilities has also had a tangible cost benefit.

Key beneficiaries: TEC, SBOE, HTG, CLB, AKSO, CGG, PGS

19 September 2016


Although challenging in a downturn, OFS companies should be exploring ways of

leveraging such advantage for greater financial reward. This could be achieved through

leasing the equipment or some kind of reward mechanism linked to incremental

production. However, OFS companies should be hesitant in taking subsurface risk unless

significant in-house experience exists. Petrofac, we think, overlooked the importance of

such in-house capability as it expanded into its IES business model.

7) Future inflation threats – counting the cost of lost people

In this exceptionally harsh cycle, the industry’s workforce has suffered the most. To date,

the oil & gas industry has shed over 350,000 jobs with the OFS sector bearing the brunt of

this – the industry has culled about 40% of its workforce – with several companies cutting

as much as 50-60%.

The question is where do all these people go? Given the demographics of the industry, a

large proportion have retired or taken early retirement. More often than not oil industry

downturns coincide with wider recessionary environments, but global GDP has been

positive throughout this downturn. As such many are likely to have re-trained or migrated

to more prosperous industries, in our view.

The industry should be able to sustain a higher productivity moving forward but the lack of

skilled and experienced people is a concern to us. Remuneration would need to be

sufficiently attractive to draw people back to the oil & gas industry. Put simply, we think

labour inflation represents the biggest threat of overall cost inflation in the coming cycle.

Elsewhere, we think inflation threats are limited in the medium term. The heavy-asset

service providers (seismic, offshore construction, offshore/onshore drilling, FPSO) have

contributed markedly to cost inflation in prior cycles. However, many such industries are

significantly oversupplied now, notably offshore drilling, and to a lesser extent, offshore

construction. Furthermore, as technology used to lower development costs becomes more

of a differentiating factor, as opposed to the delivery method, we would expect a series of

asset classes – including drilling – to be more marginalised, and potentially commoditised.

We do not see these industries regaining any real pricing traction even several years into

a recovery cycle.

The seismic industry has potential to be different – capacity expansion has been at

historically low levels in recent years and there’s very little new capacity due to come

onstream. The seismic industry typically is not well known for being rational, but recent

behavior has seen a structural reduction in capacity. This market could rebalance sooner

than many think, but reactivations could act as a headwind to any meaningful pricing

recovery.

8) Where have all the ‘elephants’ gone?

The past few cycles have witnessed the rise and ultimate fall (or fail) of ‘the mega-project’

– developments sanctioned at a cost of tens of USD billions. It’s hard to think of many

such projects that delivered according to plan but one can point to several high-profile

cases of value destruction relative to final investment decision economics. Chevron’s

Gorgon LNG project offshore Australia saw development costs escalate to USD54bn –

almost 50% higher than planned at the time of project sanction in 2009. The performance

of the ENI-led Kashagan has been even worse – a case study in how not to develop a

giant resource base – almost a decade late, at a capital cost over five times the original

budget.

With cycle conditions beginning to turn more positive, business development pipelines for

contractors are starting to increase, but typically with smaller projects, particularly in the

upstream sector. West Africa and Australia – two of the more active markets in the last

cycle – are now looking more mature. The ‘big elephant’ discoveries have now largely

been developed. In such markets, operator focus tends to turn to sustaining production.

Greatest impact for: WG, AMFW

Most impacted:SPM, TEC, SUBC, AKSO

19 September 2016


Larger greenfield projects do exist – oil companies are sat on huge portfolios of

undeveloped discoveries, but we expect a more phased approach to development as

operators focus more on schedule delivery and early cash flow. Technology

advancements are enabling longer / larger tieback projects – enabling more cost-effective

exploitation of large resources, notwithstanding significant modifications that may be

required at existing infrastructure.

Our in-house projects tracker database sees far fewer mega projects overall than is

typical, although we would caveat this with several projects where cost estimations are

currently unknown. The largest projects in the upstream sector would be Mamba and

Coral (both in Mozambique), Mad Dog Phase 2 (in the US Gulf), and Jurassic Gas (in the

Middle East). In the downstream space (where costs have typically been more predictable

versus upstream), we would cite several Middle East projects – Sitra, Duqm and Ras

Tanura Clean Fuels.

Figure 23: LNG supply / demand forecast Figure 24: Global supply, demand and supply gap

Source: Company data, Credit Suisse estimates (2016 onwards) Source: Credit Suisse estimates

Many of the mega-project / large elephants from the last cycle were LNG related. As such,

the global market for LNG appears to be extremely well supplied for now, albeit with the

bulk of production tied up on long-term supply contracts. Our in-house view is that LNG

markets don’t move into balance until 2023, which suggests no major final investment

decision should occur between now and the end of the decade. We believe growth from

this segment will be required to meet future demand in the long term (and projects in East

Africa and North America look most attractive at this juncture), but any near-term activity is

likely to involve additional trains on existing LNG developments.

We discuss the sector’s current bidding prospects in our OFS bidding summary - ‘Fishing

where the fish are’ - on page 35.

9) OFS consolidation – the M&A outlook

While the OFS sector largely looks ripe for consolidation, we detect several headwinds to

large-scale sector consolidation, most notably because of sector balance sheets. The

industry is far more leveraged today relative to the last major consolidation round in the

late 1990s. We view leverage as both preventative (there is a lack of financial liquidity and

apparent waning bank appetite to provide acquisition finance to the energy industry), and

prohibitive (potential consolidators have little appetite to consolidate debt).

The white knight deals seen often through the global financial crisis have largely been

absent in this downturn – financial distress is far more widespread; this can be a source of

future activity as banks look to recover some losses on the debt written off. Historically, the

industry sees greater deal flow in the recovery phase of a cycle, as business confidence

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Potentially active: TEC, WG, SBOE, HTG,

AMFW, PFC, AKSO, SPM, SUBC

19 September 2016


grows. While the overall industry is showing signs of bottoming out, there’s more evidence

of stabilisation than recovery. It may take some time for the industry M&A to spring into

action.

We note that significant private equity money has been raised in recent years but, as yet,

very little of it spent. This includes traditional private equity for outright M&A plus special

situations funds looking at distressed debt. However, we think private equity is more likely

to focus on Tier 2 and Tier 3 consolidation – we do not see any top-tier players moving

into private equity hands.

Recent evidence suggests that deals perceived as ‘more of the same’, that potentially

stifle competition, would be difficult to close. The Halliburton / Baker Hughes deal

ultimately fell apart on antitrust grounds. The failed deal ended up being very expensive

for Halliburton – the break-fee on the deal was some USD3.5bn (or about 10% of the

proposed transaction value at the time of deal announcement in November 2014).

Conversely, Schlumberger was able to close its deal for Cameron – there was almost no

overlap between the companies; the deal was complementary and more about vertical

integration. By integrating Cameron, Schlumberger can deliver greater efficiency and

performance through greater integration and technology development between the legacy

Schlumberger and Cameron businesses.

Similarly, the Technip / FMC deal has already received US antitrust clearance and we

expect few antitrust issues – it’s a vertical-integration deal rather than like-for-like

consolidation. The deal appears to have been client-led – oil companies can see the value

creation in an integrated SPS / SURF approach through structurally lower costs and

accelerated development times. Crucially, the combination does not limit customer choice;

operators can still continue to procure SPS / SURF in the traditional way, ie,

independently.

What to expect – We think the volume of transactions has potential to increase,

particularly as the recovery takes hold. With oil companies seeking greater alignment with

the supply chain across the entire asset lifecycle, we believe a continuation of vertical-

integration deals is likely. Any M&A that strives to reduce costs / create value for oil

companies (and the combining entities) would likely be welcomed; deals that reduce

competition would not be.

The initial Technip / FMC Technologies JV did trigger a chain reaction across the subsea

supply chain as other SURF / SPS providers followed suit and formed alliances –

OneSubsea / Schlumberger with Subsea 7, Aker Solutions with Saipem, and GE with

McDermott. However, we are not sure these alliances would choose to consolidate.

Vessel ownership is unlikely to suit the strategies of Schlumberger or GE, whereas cultural

and corporate governance issues could prevent a potential merger between Saipem and

Aker Solutions.

The seismic sector would arguably benefit from consolidation, but we do not see any

obvious candidates. We think the strongest balance sheet lies with WesternGeco (a

subsidiary of the financially robust Schlumberger) but we can’t see a scenario where

Schlumberger would pursue additional capacity. Elsewhere, larger vessel owners (PGS,

CGG) appear to have limited financial flexibility. We believe investors would like to see

more industry capacity controlled by fewer players, but transactions appear unlikely.

However, we do think there could be more consolidation in the multiclient business with

seismic contractors looking to purchase libraries. In June 2015 Spectrum acquired Fugro’s

multiclient library and TGS purchased the bulk of Polarcus’s catalogue (excluding

Australia). More recently, in September, PGS and TGS agreed principal terms to purchase

the majority of Dolphin Geophysical’s surveys in the Barents Sea, Africa, Australia and the

North Sea. We think there may be additional opportunities for multiclient transactions,

particularly financially distressed counterparties.

19 September 2016


Elsewhere within our coverage, we expect Wood Group and Schoeller Bleckmann to

continue to pursue bolt-on acquisition targets that broaden capability and geographic

reach. We do not expect any material activity from the onshore E&C players (Petrofac /

Tecnicas Reunidas, although the former has an active disposal programme); we think

Saipem's strategic options for its underperforming Onshore E&C business could include a

disposal. Hunting’s renegotiated banking facilities limit its ability to act as an acquirer, in

our view although it has been cited in the press (eg Financial Times, 22 June 2015) as an

M&A candidate, but we do not see any obvious trade buyers.

Figure 25: Global Oilfield Services M&A – deal value in USDm

Source: Company data, Credit Suisse Research, based on company data

10) Specific market trends to watch: Brazil, Iran and Decommissioning

Brazil -– re-emergence of an offshore powerhouse

The wider market downturn, the 'Operation Car Wash' probe, a relatively high extraction

cost and Petrobras’ own internal cashflow and financing issues have diminished what was

once considered one of the great hopes for the offshore industry. Recent signs, however,

are encouraging.

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Exposed names: TEC, AKSO, SUBC, SPM,

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19 September 2016


Figure 26: Pre-salt in Brazil – overview of key blocks and companies involved

Source: Credit Suisse Research based on PBR, ANP; Note: STL announced the acquisition of PBR’s stake in Carcara, which is due to close in 3Q16

Around 10 years after the discovery of the pre-salt, one of the most relevant event in the

global oil industry over the past 20 years, the following has occurred:

■ Brazil and PBR have still not grown production meaningfully, with a direct impact to the

companies involved, the country/states/municipalities which depend on oil-revenue for

their budgets, and even other sectors unrelated to oil (a portion of the pre-salt royalties

have to be invested in the Education sector in Brazil);

■ PBR, the company responsible for spearheading the development of the new

resources, is in a much worse financial position than prior to the discovery of those

resources;

■ The local industry has yet to climb the learning curve and be able to be competitive at

an international level, and some local suppliers (including shipyards and OFS) have

filed for bankruptcy or judicial-assisted-recovery;

■ Few other oil companies have meaningfully increased activity in Brazil. The lack of

regular oil licensing rounds and the regulation requirement for PBR to be the sole

operator in new pre-salt areas have impaired the rise of other oil companies in Brazil.

Addressing the above shortcomings indicates the Brazilian Oil model needs reforms on a

number of fronts. The Brazilian Petroleum Institute (IBP), a non-profit private organisation

founded in 1957 that today comprises over 200 associated companies, is one of the most

active and representative bodies of the oil & gas industry in Brazil. The IBP has been

pushing for reforms in the oil sector on a number of fronts that in our view would have a

long-term benefit for the sector, the country, and all the companies involved.

Two examples that we think are most relevant for investors to understand: (a) the review

of the PSC model, notably the removal of the mandatory-PBR operatorship, has a very

limited impact on Petrobras' cash flows, earnings and capex requirements before 2020,

and (b) the enhancement of local content policies by, for instance, allowing for more

flexibility and use of foreign suppliers, can reduce the risks of delays and downgrades of

PBR's oil production curve and its capex needs. Moreover, it could be a positive for

international shipyards in terms of new orders.

19 September 2016


Reforms should be forthcoming. The Brazilian government is sending positive signals

as far as reform is concerned. Whilst early days, the government is drafting a proposal

designed to extend licences with greater flexibility on local content (Upstream, 2

September 2016). The simplification of the unitisation process involving different fiscal

terms is another aim, and the argument for stretching the 'concession' (tax and royalty)

regime to cover reservoir extension is compelling in cases where only a small portion of

the reservoir extends outside of the licence.

Recently, the Brazilian Senate passed a bill that exempts PBR from the minimum

mandatory stake of 30% and operatorship in all pre-salt fields. Alternatively, according to

the amended bill, as it was approved, PBR will have the right of preference to the 30%

stake and operatorship. The bill will now go to the lower house. The end of the mandatory

stake and operatorship in all pre-salt fields, if it becomes law, would be positive for PBR

shareholders in the medium and long terms, in our view, because it would reduce the risk

of future mandatory capital commitments. This is important because developments can be

brought forward.

In the long term we would expect the ownership of larger fields to mirror the Libra PSC,

which includes Petrobras (40%), Total (20%), Shell (20%), CNPC (10%) and CNOOC

(10%). Petrobras may well look to monetise other undeveloped discoveries in its portfolio.

Such investments are likely to attract foreign ownership, particularly given how prolific

production has been in initial pre-salt developments.

The near-term scale of the Brazilian opportunity is unlikely to match that of the last cycle.

However, with a wider portfolio of operators likely to bring developments forward, activity

levels could ramp up faster than the market expects currently. For this to be realised,

further regulatory changes, such as a relaxation of local content provision, may also be

required.

A similar theme is also emerging in Mexico, albeit at a slower pace. Pemex is retaining a

45% stake in the Trion discovery but developing the field in conjunction with an

international equity partner (a first under new legislation). Trion and other undeveloped

reserves across the Perdido basin (which mirrors the US Gulf’s geology) are the earliest

opportunity for Pemex to increase production. The equity sale of Trion is running parallel

with the deepwater licence round set for December 2016. The deepwater round, which

covers 10 blocks, is again open to international investment. Mexico should be considered

a key opportunity for OFS companies, in our view.

Iran

In November 2015, Iran presented new legislation governing contracts including foreign

investment to a meeting of leading international operators and contractors. Saipem,

Technip, Tecnicas Reunidas and Petrofac were amongst those to have sent

representatives to the meeting. In August 2016, Iran approved contractual terms for

‘Iranian Petroleum Contracts’ (IPCs) and NIOC (National Iranian Oil Company) has plans

to tender contracts for the development of several oil & gas fields over the next 6-12

months. Early progress appears promising, but real activity will take time, perhaps several

years.

In the first tender under the new IPC model, Iran is looking to invite IOCs to bid on the

development of the South Azadegan project in October, according to MEED. The field,

located in western Iran and on the border with Iraq, is one of the joint fields that NIOC

aims to prioritise by utilising technology and investment from international partners. NIOC

had already launched an initial tender for the construction of a central processing facility

and had received bids from 16 partnerships – including Petrofac, Saipem and Samsung in

consortia with various local contractors.

19 September 2016


The potential reopening of Iran could be a significant medium-term opportunity for the

drilling contractors and E&C operators. Several companies in our coverage have a track

record in Iran, most notably Saipem. Saipem has signed three MOUs covering the

development of the Toos Gas Field, the revamp of the Pars Shiraz and Tabriz refineries,

and the development of various pipelines. Also, Petrofac has in the past worked on

Dorood and worked directly with NIOC on a number of projects, while Technip had also

delivered a number of steam crackers and polyethylene plants at the turn of the century.

The near-term projects pipeline is formed of NIOC-operated projects. These are, however,

held back by the requirement to offer a fully financed package, and arranging Iranian

project-based finance is still difficult at this stage. However, the Iranian government has

recently launched the process to screen local E&P candidates that will eventually form a

shortlist of qualified local partners for IOCs to choose from.

Any initial IOC-backed projects could well be natural gas-related. The fiscal terms on offer

for oil fields are unlikely to be as attractive as those for natural gas as NIOC has

considerable experience of developing oil fields. International operators' IP may be

required on more complex gas projects. This could also represent the key area of

opportunity for the OFS value chain.

Decommissioning – how soon is now?

We think the downturn has helped to bring decommissioning activity forward as some

production is unviable at current oil prices. Many operators are looking to bring forward

Cessation of Production (CoP) dates, although in many cases the intention remains to

delay decommissioning spend where possible. Contractor enquiry levels are at a record

high for decommissioning work although project timing is difficult to predict.

In its most recent Decommissioning Insight report in 2015, Oil and Gas UK increased its

projected spend on decommissioning by nearly 20%. It predicts expenditure of GBP16.9bn

as 47 new projects entered the survey during the downturn. While the timeframe

associated with the majority of new projects appears back-end loaded in its forecast

period, we should not underestimate the potential for projects to be brought forward in a

lower-for-longer oil price scenario. In the very long term, nearly 500 installations will have

to be removed, which could cost around GBP50bn in today’s money.

Making this spend a reality would ultimately be determined by how prepared the industry is

to embrace decommissioning and bite the bullet on the large proportion of stock classed

as 'temporarily suspended' (where operators hope that new technologies could yield a

return to production). For us the main prohibiting factor is the cost and complexity of the

work – the removal of 30-40-year-old platforms (that weren’t necessarily designed to be

removed) is far more challenging than it was to install them, although more modern

platform removal is significantly less challenging.

Although the concept of decommissioning has been around for a long time, the actual

level of activity is still in its infancy. Forward planning is key – planning, shutting down,

cleaning up, preparing the deck space, etc, can take years before the physical act of

decommissioning begins. If operators defer planning, they run the risk of an inefficient

decommissioning schedule and escalating costs.

Some integrated oil companies have adopted a proactive approach – ConocoPhillips for

example has built up a team internally over several years with a 'learn by doing' strategy

on projects such as Ekofisk, whereas Shell has been planning for the Brent Field

Decommissioning for the best part of a decade during which it has commissioned over 300

separate studies, several consultations and scientific assessments and had extensive

dialogue with stakeholders – this is despite Shell owning the field for all of its life. Despite

extensive planning, it could take at least another 10 years to decommission fully the four

remaining Brent platforms.

Key beneficiaries: WG, AMFW, HTG, PFC,

SPM, SUBC, TEC

19 September 2016


However, there are also many examples where operator planning has been insufficient. In

our view, the main risks to the projected levels of spend materialising in the medium-to-

long term are a sustained oil price recovery, new technology lowering break-even

thresholds on installations, and oil companies ‘delaying the inevitable’ and converting

installations into a ‘cold state’.

Opportunities for the OFS value chain are increasing – Marathon has submitted its first

draft to the OGA for the decommissioning of the Brae area facilities, while BP’s Miller

campaign is currently being bid. We also see opportunities on Murchison and Thames on

the UKCS.

For subsea players, Subsea 7 has some exposure through its Seaway Heavy Lift JV and

there should be ‘lighter’ opportunities for several other players such as Technip, Bibby

Offshore and DOF Subsea with the removal of subsea installations, re-routing piping, etc.

The decommissioning market should generate new business opportunities, but given the

projected near-term spend in this area, it perhaps provides some cushion against the

downturn without necessarily moving the needle.

In addition to the removal of infrastructure from the seabed, there is a considerable plug

and abandonment (P&A) opportunity. For several years the UK Continental Shelf has seen

increasing volumes of P&A work where the likes of Schlumberger have been active.

However, abandoning wells is very service and technology intensive. The industry is

evaluating potential to minimise cost/risk and increase efficiency of the P&A process.

Heerema, for example, has an integrated tool that addresses these issues – a fit-for-

purpose P&A tool that combines jacket and P&A module removal. Hunting may also be

able to capitalise on this trend as its Titan product range is particularly well suited to P&A

work, whilst companies such as Proserv offer considerable cutting capability.

19 September 2016


Activity levels and E&P capex In this section we review activity levels and industry spending levels. In essence we think

US drilling and completion activity bottomed during the summer 2016 months, but

international drilling activity continues to trend down. This could continue through H216,

before stabilising early in 2017. Industry E&P capex will see two consecutive years of

significant decline (in 2015/16E) for the first time since the mid-1980s. We do not expect a

third year of material declines. However, nor do we expect material growth in 2017.

Rig counts

The US drilling rig count bottomed in Q216. Industry sentiment and strategy has begun to

change slowly as cost reductions have caught up with activity and business declines, and

the market is reversing out of the worst down-cycle in a generation. However, the recovery

is likely to be staged, and at least in terms of rig count, the pace of growth slow. With oil

prices in the USD40-50 range, we expect North American E&P to prioritise completion of

DUC inventory as the best current cash return investment. Early indications confirm this

emerging trend.

Leading-edge initial production rates of wells today average around 1,000bopd. This

means that development of the DUC inventory can have a significant initial production

impact. While production can fall 60-70% in the first year before declining to a fairly stable

base after a couple of years, initial production could take the steam out of a potential

recovery, given wider oil market oversupply. Our central assumption is the industry’s

inventory of DUCs is worked through gradually over the next 18-24 months.

We see onshore US activity recovering before anything else. Conventional international

onshore will follow next, whereas longer-cycle offshore markets will likely lag, with

deepwater potentially lacking any real impetus until 2018 at least. In The Recovery

Coming into Focus (1 June 2016), Credit Suisse assumes US rig count averages 470 in

2016, rising 28% in 2017, 20% in 2018, and 6-8% longer term. The Permian Basin has

potential to be the most active basin with 4x the inventory of any other oil shale basin and

the best overall economics – it could account for half of total US shale oil production by the

close of 2018.

Figure 27: US rig count cycle comparison – rebased at cycle peak

Source: Baker Hughes International

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19 September 2016


Any recovery in the US is unlikely to see the operational fleet match the 1,900-plus rigs of

just two years ago. The forced efficiencies of the downturn – which have seen long-term

production per rig increase by 16x over 10 years will likely cap the overall number of rigs

going back to work.

Figure 28: Credit Suisse global rig count forecasts

Source: Credit Suisse estimates, EIA, Baker Hughes International

Figure 29: Credit Suisse US rig count forecast

Source: Credit Suisse estimates, Baker Hughes International, EIA

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19 September 2016


E&P capex

All OFS customer groups have cut back on E&P capex aggressively in this downturn –

industry spending was down around 25% y-o-y in 2015, and, we expect further declines in

excess of 20% in 2016. We are still several months away from the 2017 budgeting

process, but we are confident this trend will not continue – our best estimate is for a flat

year. As a proxy, we’ve used Credit Suisse global energy coverage capex estimates for

2017/18, which indicate a 1% decline for group spend.

Figure 30: Group capex cuts in the last vs. current

cycle Figure 31: Group capex by OFS customer group

in USD millions, unless otherwise stated in USD millions, unless otherwise stated

Source: Company data, Credit Suisse estimates[the BLOOMBERG PROFESSIONAL™ service

Source: Company data, Credit Suisse estimates, the BLOOMBERG PROFESSIONAL™ service

There are notable differences across OFS customer groups. Short-cycle-dominated, North

American E&P spend is forecast to recover nearly 20% as completion activity picks up and

more rigs are put back to work. Conversely, major IOCs and international E&P operators

are forecast to cut again, by 10% and 11%, respectively. The NOC grouping (which

includes companies such as Petrobras, ONGC, Sinopec and Rosneft, but excludes

several large spending NOCs such as Saudi Aramco and KOC) is forecast to increase

spend by 3% after two years of steep cuts. The significant pipeline of projects in the

Middle East suggests to us that this could underestimate actual NOC spend.

Overall however, several factors give us confidence that we should at least see some

stabilisation in spending levels in 2017.

■ Oil prices – Although Brent we saw a seasonal dip in the summer months to the low

USD40s, oil prices are currently back at around USD50/bbl and significantly up on the

January lows of USD28/bbl. We see a Q4 2016 strengthening with further

improvements into 2017 / 2018 (CS estimate: USD56.25/bbl / USD67.50).

■ Oil demand / supply – The Credit Suisse global oils team believes global supply and

demand effectively rebalanced during the summer of 2016. Brexit and other

macroeconomic headwinds cloud the demand picture somewhat, indicating the market

deficit may not be sustained over the next 12 months. We see a more material deficit

position building from H217.

■ Improved project economics – We think the OFS industry has ‘given up’ all it can in

terms of deflation; oil companies are unlikely to be able to squeeze much more out of

the supply chain. Some deflation is cyclical in nature (rig rates and seismic vessel

rates, for example), but the downturn has been sufficiently long and harsh to drive

structural change – new best practices, new working models, etc. We believe the

industry is now re-focused on development priorities.

-28%

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19 September 2016


■ Future production concerns – Decline rates at existing fields are increasing and oil

companies are now voicing concerns over sustaining future production. The downturn

has seen weaker investment in the existing well stock and cutbacks on non-essential

maintenance. We see the industry now focused on marginal field development,

brownfield and tieback activity. There is often a grey area between opex and capex

around this type of work, and it can be easier to secure opex budget than capex in a

downturn.

19 September 2016


‘Fishing where the fish are’ In this section, we provide a global summary of bidding activity across key upstream and

downstream developments. Our in-house projects database has tracked a disappointing

USD21bn of awards to market ytd, down 50% on the comparable period in 2015. Awards

have been split roughly 60/40% between offshore and onshore – a marked difference to

the substantial weighting towards onshore projects in both 2015 and 2014. Key awards

include BP’s Tangguh and Shah Deniz 2, plus ENI’s Zohr project.

Major projects often stall in a downturn – Shell’s Bonga South West and ADNOC’s Das

Island development are good examples of this. However the global bidding pipeline looks

promising with nearly USD140bn of contracts at various stages in the bidding process.

Regionally, the Middle East is the most active, with large-scale downstream projects like

Duqm (Oman), Sitra (Bahrain) and Ras Tanura Clean Fuels (Saudi Arabia). There are

sizable opportunities in Africa, including Mamba / Coral in Mozambique, downstream

prospects in Algeria, and offshore work in West Africa. Asia Pacific is active, with offshore

developments in India and Indonesia, but FLNG projects have challenges. The Americas

is less active with near-term uncertainty in Brazil, although US Gulf prospects (like Mad

Dog 2 / Vito) look attractive. Europe is quiet but could see a pick-up in smaller marginal

field / tieback developments (particularly in Norway).

We are not actively capturing any renewables work, which Subsea 7 and others are

chasing, or politically-edged projects such as Nordstream II or Turkish Stream. Overall, we

view the current level of bidding as normal (ie, low) based on positioning in the cycle (ie,

towards the bottom). We’d expect keen pricing for contracts to persist as contractors and

equipment providers look to rebuild decimated backlogs and provide utilisation for their

asset bases, particularly offshore.

Figure 32: Project award seasonality Figure 33: Project awards by region

Source: Company data, Credit Suisse Research, Thomson Reuters, UpstreamOnline, MEED, AOG, data correct as of September 7

th 2016


th 2016

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19 September 2016


Figure 34: Active and submitted bids by region Figure 35: Top 10 prospects

Source: Company data Credit Suisse Research, Thomson Reuters, UpstreamOnline, MEED, AOG, data correct as of September 7

th 2016


th 2016

Africa

Eni has received technical bids for the SURF package for the OCTP project off Ghana.

According to Africa Oil and Gas (AOG), 11th August, having missed out on Phase 1,

Saipem is the favourite to secure the 63km subsea gas pipeline portion of the SURF

package, which also includes the associated subsea system, gas treatment facilities on

the FPSO and an onshore receiving facility. Commercial tenders are due in September.

The three consortia bidding on Eni’s Coral South FLNG project have increased the design

capacity of the vessel by 35% while managing to keep costs around USD5.5bn. According

to AOG, the Technip/JGC/Samsung Heavy Industries consortium has beaten the

Saipem/Chiyoda/Hyundai Heavy Industries and KBR/DSME alternatives to win the supply

contract; Technip is also seen as favourite for the SURF contract, with GE the preferred

bidder for the subsea system. The Coral field has around 9tcf of recoverable gas reserves

and is likely to come onstream by 2020.

Eni’s next large LNG development is the Mamba project. Having launched an EPC tender

for two 5mmtpda LNG trains at the Afungi LNG complex in early 2015, the Italian major

has received commercial bids from Technip/Samsung/China Huanqiu C&E,

CB&I/Chiyoda/Saipem and JGC/Fluor, according to oil industry journal Upstream Online,

22 July. Mamba’s initial phase will consist of 21 subsea wells in 1,800m of water tied back

to the LNG trains via four 60km, 22-inch flowlines. We think an investment decision on the

field is unlikely, however, until Eni closes discussions on potential farm-in investment in

the area.

Eni has also issued invitations to tender for a 150kbpd leased FPSO at the Zabazaba

project off Nigeria. The FPSO will initially receive crude from 24 development wells on the

Zabazaba field, before a further 10 wells from the Etan field are tied back in a second

phase. According to AOG, 28th April, Eni has pre-approved Bumi Armada, BW Offshore,

Saipem and SBM/COOEC for the supply of the vessel. AOG also said that in addition to

the FPSO, Eni is also expected to tender for the SURF and SPS packages on the field

with Emas, Heerema, Saipem, Subsea 7 and Technip approached for the SURF work, and

Aker Solutions, FMC, GE and OneSubsea approached for the SPS package. The field will

also require a series of umbilicals for which Aker Solutions, JDR, Nexans, Oceaneering

and Technip are each due to submit bids in September, with award set for H2 2017.

Eni has re-engineered the Loango project as an integrated drilling and production platform.

Initially, Eni planned to develop the field with two 11,000mT production platforms, but after

technical studies reverted to a sole facility to lower costs. According to Upstream Online,

19th August, Saipem and McDermott are amongst those likely to receive invitations to

Africa

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19 September 2016


tender from Eni, but COOEC and Hyundai Heavy Industries have not qualified. The

winning contractor will have to manage local content, which is likely to cover the local

fabrication of small pieces of equipment and personnel during hook-up and commissioning

work. Technical and commercial offers are likely to be submitted by the close of 2016, with

Eni expected to award a contract in Q2 2017. The integrated facility is expected to have

more than 20 well slots, and will accommodate 70 people. The platform will eventually be

linked by an oil line to four separate wellhead platforms.

BP has made a final investment decision on the Atoll field off Egypt. The field, which

contains 1.5tcf of gas and 31m barrels of condensate, is being fast tracked with three

early-stage production wells expected to be tied back to shore by 2018. Having recently

secured work on BP's other Egyptian upstream developments (East and West Nile Delta),

Subsea 7 and OneSubsea are favourites for the respective SURF and SPS packages

(according to AOG, 23 June). The initial phase of development will seek to produce

300mmcf/d of gas before ramping up in subsequent phases.

BP is also reviewing bids for the SURF and SPS packages on Platina field in Angola.

Originally designed as part of the Block 18 PCC project (with Chumbo and Cesio), BP is

now looking to develop Platina as an eight-well tieback to the Greater Plutonio FPSO.

Having delivered the wells for Greater Plutonio, FMC is considered favourite for the SPS

system, according to AOG, 12th May, while Subsea 7 is likely to beat Saipem to the SURF

package. However, with the development yet to be approved, the project may stall and the

initial number of trees may be cut to lower the initial development cost.

In May, Shell cancelled the outstanding FPSO, SURF and SPS tenders for its oft-delayed

Bonga Southwest field as contractors were unable to remove sufficient cost to make the

field economic. Instead, Shell is now looking to relaunch the project, for the third time, as a

leased FPSO playing host to 48 trees. According to AOG, 26th May, the re-tender will

commence in Q1 2017 and consist of a 48-tree subsea system, a SURF package

including 82km of flowlines, three water injection lines and four production loops as well as

around 70km of umbilicals and a 98km gas export pipeline. According to AOG, in the most

recent tendering round, Subsea 7 was favourite for the SURF package, while HHI was

slated to deliver the FPSO and Nexans had beaten competition for the umbilicals.

Chevron has returned to its deepwater Nsiko FPSO project in Nigeria and has contracted

KBR subsidiary Granherne to update its FEED work. According to AOG, 25th August,

Chevron is looking to bring new production onstream from 2020, but the progress of Nsiko

depends on whether current bidding on Eni’s Zabazaba project comes to a conclusion and

whether bidding on the revised Bonga Southwest field restarts early in 2017. Nsiko was

originally due onstream in 2010 after Doris had performed subsea FEED work, but the

project stalled due to the amount of local content required.

The Mozambique National Petroleum Institute is close to awarding a series of multiclient

seismic and data licensing agreements across Rovuma, South Rovuma, Zambezi Delta,

onshore South Mozambique and in the Mozambique basin, according to Upstream, 19

August. Seven seismic contractors have reportedly bid for the Zambezi Delta work.

WesternGeco, CGG, Spectrum, Polarcus, PGS, Ion Geophysical are competing against

TGS for the 15,000skm of 3D seismic data as well as gravity, magnetic and bathymetric

information on ExxonMobil's blocks Z5-C and Z5-D. CGG and Spectrum are also

reportedly competing for 5,000km of 2D on the Rovuma basin.

Having been put on hold since January 2015, Total has returned to Zinia Phase 2 in

Angola. Initial bids for the SPS and SURF packages came in 30% above Total's

expectations, but now the French IOC has gone back to contractors in an effort to take

advantage of lower supply chain costs, according to AOG, 11th August. The AOG report

said FMC was previously considered favourite for the SPS package, while Subsea 7 was

bidding on the SURF contract. The contract package will also include brownfield

modifications consisting of five new modules on the Zinia platform.

19 September 2016


Figure 36: African prospects Figure 37: African prospects by segment

Source: Company data, Credit Suisse Research, data as of 7th September 2016 Source: Company data, Credit Suisse Research, data as of 7

th September 2016

Figure 38: African prospects by country (USDm) Figure 39: African prospects by operator

Source: Company data, Credit Suisse Research, data as of 7th September 2016 Source: Company data, Credit Suisse Research, data as of 7

th September 2016

Figure 40: Top 10 African prospects

in USD millions, unless otherwise stated

Source: Company data, MEED, Company data, Credit Suisse Research, data as of 7th September 2016

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19 September 2016


Asia Pacific

In India, ONGC has reportedly launched a USD1.5bn integrated SURF and SPS package

for 35 subsea trees, associated subsea control systems, infield umbilicals and pipelines,

manifolds, pipelines, 400km of subsea flowlines and a 50km export line. The project also

includes 176km of umbilicals and a series of flexible risers and flowlines. According to

Upstream, 3rd

July, a series of partnerships including Technip/FMC, McDermott/GE/L&T,

Saipem/Aker Solutions and Subsea 7/OneSubsea have expressed interest for the project

that will move into a bidding process by year-end. There are additional (smaller) bids for

an FPSO and a fixed platform.

In Australia, Woodside’s Browse project has been postponed. Its original development

plan was to deploy three standalone FLNG vessels that would be nearly identical to Shell’s

Prelude FLNG facility. However, weak LNG markets have stalled the project following

completion of the FEED. We believe that Woodside is now likely to lower the capacity of

the planned FLNG vessel to less than 2mtpa (Prelude is 5.3mtpa) and shorten the length

to 350m (to allow yards outside of South Korea to fabricate the facility). Woodside has also

deferred the Lambert Deep project, a satellite field on Australia’s North West Shelf.

After re-engineering, Hess is moving ahead with Equus in Australia. According to

Upstream, 3rd

June, the redesigned facility will be far smaller than originally planned, but

production capacity will be the same. Wood Group/Samsung Heavy Industries,

McDermott/Keppel and SBM Offshore are expected to bid. The project also includes an

18-tree SPS package, which FMC and OneSubsea are bidding, and there’s a 200km

subsea pipeline.

ConocoPhillips has moved the Caldita-Barossa project into the pre-FEED phase.

According to Upstream, 12th August, Conoco has launched three separate pre-FEED

tenders for the proposed FPSO, SPS, and SURF systems; WorleyParsons, Fluor and KBR

have been invited to tender for the FPSO, while McDermott, Subsea 7 and Technip are

likely to tender for the SURF package. After pre-FEED work is completed in early 2017

Conoco will look to progress the project into the FEED stage. Caldita-Barossa is likely to

be developed with a VLCC-size newbuild FPSO tied back to shore with a 270km pipeline.

CNOOC has launched three tenders for the Wenchang 10-3 field development. According

to Upstream, 19th August, CNOOC has approached Technip, GE and Nexans for a 25km

umbilical, GE, OneSubsea, FMC and Aker Solutions for six subsea trees (four firm, two

options) and a production system, as well as Technip, NOV, GE, Tiangin Nepture Offshore

and Orient Cable for two flexible pipes – a 6-inch condensate flexible and an 8-inch, 22km

gas flowline. The contract marks the first presence of two Chinese flexible manufacturers –

Tiangin and Orient Cable – in the offshore market. The subsea trees will be tied back to a

central equipment platform as part of a development that is scheduled to produce first gas

in 2018, at a peak rate of around 660mcm per year.

19 September 2016


Figure 41: Asia Pacific prospects Figure 42: Asia Pacific prospects by segment

Source: Company data, Credit Suisse Research, data correct as of September 7th 2016 Source: Company data, Credit Suisse Research, data correct as of September 7

th 2016

Figure 43: Asia Pacific prospects (USDm) Figure 44: Asia Pacific prospects by operator

Source:: Company data, Credit Suisse Research, data correct as of September 7th 2016 Source Company data, Credit Suisse Research, data correct as of September 7

th 2016

Figure 45: Top 10 Asia Pacific prospects


Source: Company data, Credit Suisse Research, data correct as of September 7th 2016

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19 September 2016


The Middle East

After awarding Phase 1A of Bul Hanine to McDermott, Qatar Petroleum has launched the

EPC tender for Phase 1B, consisting of topsides for four wellhead platforms, one manifold

platform and more than 100km of subsea pipelines, umbilicals and cables. The package is

worth in excess of USD500m, according to Upstream, 5th August. McDermott, NPCC,

Saipem and Technip are expected to be invited to bid, with the process beginning late in

2016 and award planned for H217. Bul Hanine is being redeveloped to boost recovery

rates and increase recoverable reserves.

The development of a central processing and associated facilities at South Azadegan in

Iran has attracted bids from 16 partnerships, according to Upstream, 26th August. Saipem

has joined with local contractor Jahanpars, while Petrofac is working with Kayson and GS

E&C has joined with Mapna. The USD800m contract includes procurement of equipment

and construction of a central treatment and export plant as well as a fire-fighting facility

nearby and the construction of a permanent camp and warehouses. Pedec has also

launched a pre-qualification tender for construction and commissioning of surface facilities,

including flowlines for 20 wells at the field, which was the largest discovery in Iran since

the 1970s when it was announced in 1999.

Some of the partnerships bidding for South Azadegan are also bidding for the USD800m

Aftab plant, reports Upstream, 2nd

September. The contract for the construction of the

Aftab gas processing facilities was originally tendered in 2014, but was withdrawn after a

lack of interest. The project is the fourth tender of the first phase of Kish, which was

discovered in 2006 and holds around 1bn barrels of condensate. The gas treatment facility

will have a 1bcfd capacity from 12 wells and will feed the IGAT pipeline distribution

network while processing 11kbpd of condensate. The EPC tender was originally due to

close on 16 June 2016, but has been extended because of problems with the plant’s basic

design, according to the report.

In Bahrain, Bapco has received EPC bids for the planned $5bn modernisation of the Sitra

refinery. According to MEED, 28th July, JGC/GS E&C, Technip/Tecnicas

Reunidas/Samsung Engineering, Fluor/Hyundai/Daewoo and CB&I/Petrofac were invited

to bid for the modernising project to upgrade the GCC's oldest refinery and increase

capacity.

In Saudi Arabia, the Farabi Petrochemicals Company has invited bids for a new chemicals

plant in Yanbu. According to MEED, 7th August, Farabi Petrochemicals has prequalified

CTCI, GS E&C, Hanwha E&C, Petrofac, Saipem and Tecnicas Reunidas for the USD1bn

EPC project, which will produce specialty chemicals using diesel feedstock. AMEC Foster

Wheeler has performed the FEED, including technology selection heavy oil treatment.

Saudi Aramco has received technical and commercial bids for about USD3bn of work on

the Ras Tanura refinery Clean Fuels Project according to MEED, 17th August. JGC,

Samsung Engineering, Hyundai Engineering & Construction, Tecnicas Reunidas and GS

Engineering bid for the main processing unit, while Petrofac and L&T bid for the offsite and

utilities package. The project is much delayed, with bids in 2013 coming well over budget,

but this time Aramco has awarded early works and site preparation to a local contractor in

May, suggesting that the project will go ahead, according to the report.

Petrofac and Tecnicas Reunidas are considered frontrunners for Saudi Aramco’s

Uthmaniyah ethanol feed recovery project, worth USD800-900m according to MEED, 17th

August. Several other players reportedly prequalified including GS E&C, JGC, Daewoo

E&C, and Samsung Engineering. The project covers recovery of ethane, propane and

NGLs from sales gas at the plant site, processing associated gas from Ghawar, the

Kingdom’s largest oilfield.

19 September 2016


Saudi Aramco has issued tender documents to its LTA partners (McDermott, Saipem, the

L&T/Emas joint venture and Dynamic Industries) for an EPC job covering four offshore

jackets and three observation platforms to be installed across the Karan, Berri, Hasbah

and Arabiyah fields. The bidding parties were due to submit their commercial proposals in

late August with a view to commencing work early in 2017.

In Kuwait, Technip, Saipem, Amec Foster Wheeler and Tecnicas Reunidas are amongst

20 pre-qualified bidders for the KNPC's molten sulphur-handling facility, according to

MEED, 10 August; the project will be constructed at the Mina al-Ahmadi refinery for a total

cost of around $100m.

KOC has invited a series of E&C contractors including Petrofac, Saipem and Tecnicas to

build a new oil-gathering centre known as GC32, according to MEED, 24th July. The

project will be built near the Burgan oilfield and the scope has recently been expanded to

include a booster station modification, which has driven the cost estimate close to $2bn,

according to MEED. AMEC Foster Wheeler completed FEED for the gathering centre in

late 2014.

After awarding Technip the USD1bn contract to upgrade the Jebel Ali refinery by adding

jet and diesel hydrotreaters in August, Enoc is said to be considering further expansion at

the 120kbd facility, according to MEED, 11th August. As part of its five-year strategy Enoc

will seek to expand capacity at Jebel Ali by a further 50% (to over 200kbd) by the end of

2018 as it looks to supply up to 60% of jet fuel volumes at Dubai's airports by 2050.

Technip's award for the first phase of the expansion is its largest in the GCC since the

USD1.7bn conversion of the Satorp refinery in Saudi Arabia in 2009.

As part of the development of the Duqm project, OTTCO has prequalified a series of

contractors for the USD400m crude storage terminal. According to MEED, 25th August,

Saipem, Daewoo E&C, Larsen & Toubro and Van Oord are amongst the nine contractors

prequalified to bid on the EPC tender which is expected by the end of the year. The first

phase of the development will have a crude storage capacity of 6-10 million barrels, which

could be expanded further. The terminal will be connected via a 440km pipeline to a crude

pipeline from Oman's main offshore oil fields. In March 2016 IPIC and the Oman Oil

Company launched two separate USD2bn EPC tenders for the oil-processing facilities at

the Duqm Refinery.

19 September 2016


Figure 46: Middle East prospects Figure 47: Middle East prospects by segment


th 2016

Figure 48: Middle East prospects (USDm) Figure 49: Middle East prospects by operator

Source: Company data, Credit Suisse Research, data correct as of September 7th 2016 Source Company data, Credit Suisse Research, data correct as of September 7

th 2016

Figure 50: Top Middle East prospects


Source: Company data, Credit Suisse Research, data correct as of September 7th 2016

Offshore

OnshoreEPC

Midstream

Brownfield

Decommissioning

0 2000 4000 6000 8000 10000 12000

Abu Dhabi

Saudi Arabia

Kuwait

Oman

Bahrain

Iraq

UAE

Iran

Qatar

Kazakhstan

Saudi Aramco

KOC

ADCO

Bapco

IPIC.Oman Oil Company

Takreer

BP

Zadco

Adma-Opco

Others

0

1000

2000

3000

4000

5000

6000

Duqm Sitra Ras TanuraClean Fuels

Rumalia Ruwais LNG ImportTermianl

Upper Zakum GC32 Fujairahbiofuels

Master GasGathering

System

19 September 2016


Europe

Having spent the past two years in pre-FEED and halving the cost from USD12bn to

around USD6bn, Statoil could move Johan Castberg into the FEED stage by November,

according to Upstream, 31st August. Aker Solutions and Statoil have collaborated during

the pre-FEED stage to simplify a series of components and have switched the

development concept from a semi-submersible unit to an FPSO. Statoil has also reduced

the subsea scope of the project with fewer wells, templates and flowlines, which has

allowed for a smaller turret with fewer risers to connect to the FPSO. During pre-FEED,

Aker Solutions was able to increase the volume of the vessel to 1.1m barrels of storage

without increasing the overall size. Statoil estimates the three Castberg reservoirs hold

450-650m barrels of oil and Statoil is aiming to commence production in 2022. The FPSO

will be designed with spare deck capacity for additional modules so that future discoveries

in the Barents Sea can be tied back to the facility.

BP and Ithaca are expected to take an investment decision on Vorlich, offshore Norway in

2017, reports Upstream, 15th April. KBR subsidiary Granherne has carried out pre-FEED

studies, but the full scale of the development is unlikely to be finalised until the nearby

Cappercaille prospect is drilled. Vorlich was discovered in 2014 and is located 10km north

of Ithaca’s Greater Stella Area development. According to the report, any EPC package is

likely to include a SURF and SPS element in a tieback to the FPF-1 FPSO, which is

currently in transit to the Greater Stella Area.

To improve commercial viability, Dea is considering an integrated SURF and SPS

package for the Zidane gas discovery in the Norwegian North Sea. The USD1.5bn

development is likely to be developed via a tieback to Statoil’s Heidrun TLP, which would

require additional modifications to handle the produced gas. Technip and FMC are

reported to have offered an integrated package, while the Subsea7/OneSubsea

partnership has also bid. The package could be worth up to USD500m, according to

Upstream, 2nd

September. Norwegian MMO contractors Aibel, Kvaerner and Aker

Solutions are preparing bids for the Heidrun modifications.

Statoil has submitted the field development plan on the Utgard tieback and plans to award

contracts in late 2016/early 2017, reports Upstream, 12th August. Utgard will be developed

as a two-well subsea tieback to the existing Sleipner A facility via a 21km pipeline. The two

wells will be controlled remotely from the existing platform. The potential package will also

include a series of topside modifications at Sleipner to handle the additional gas and

condensate production, while processed liquids will be exported to the Kaarsto plant. Dry

gas will be transported via the Gassled pipeline.

After submitting a development plan for Utgard, Statoil has moved onto the Byrding

discovery, having reduced the overall project cost by over 65%. The 11m barrel field had

previously been considered too small to be profitable, but according to Upstream, 19th

August, Statoil has reduced the project scope and cut the budget to around USD122m,

from USD425m. Byrding will now be developed as a tieback through a single, two-pronged

well to be drilled from a vacant slot in the subsea template serving the Fram H-Nord field,

7km away. Production will flow via an existing pipeline to Troll C, which will require a small

amount of modification. Byrding is due onstream by Q3 2017, and is set to stay in

production for 8-10 years.

Marathon Oil has submitted the first draft of its decommissioning plan for the Brae

development to the OGA in the UK. The complex consists of Brae A, Bravo and East Brae,

and acts as a hub for 12 fields, having been in production since 1983. Given their suite of

heavy construction vessels, we think that Heerema, Allseas and Saipem are possible

candidates to perform the lift work but a multitude of companies could potentially be

involved in a decommissioning job of such scale.

19 September 2016


Figure 51: European prospects by field Figure 52: European prospects by segment


th 2016

Figure 53: European prospects by country (USDm) Figure 54: European prospects by operator


th 2016

Figure 55: European prospects by sub-sector (USDm)

Source Company data, Credit Suisse Research, data correct as of September 7th 2016

CulzeanZidane

Captain EOR

ByrdingVega B

EPCSURF

Brownfield

T&I

SPSEPIC

0 500 1000 1500 2000 2500 3000

UK

Norway

Italy

Maersk OilDEA

Chevron

Statoil Edison

0

500

1000

1500

2000

2500

EPC SURF Brownfield SPS T&I

19 September 2016


Americas

ExxonMobil has launched a FEED tender for the largest oil discovery of 2015, Liza, in

Guyana. According to Upstream, 19th August, Modec and SBM Offshore are amongst

those competing for the study that centres on an extended well test FPSO with 60,000bd

capacity in the initial phase before a larger 120-150,000bd unit for the full field

development. Exxon has previously indicated potential recoverable reserves of 800m-to-

1.4bn oil equivalent barrels. In perspective the largest field currently in the Gulf of Mexico

– BP’s Thunderhorse – is a one billion barrel field. Development plans are unclear at this

point, but a field of this scale would represent a major OFS opportunity.

After a multi-year attempt to lower development costs, BP has opened tendering on

Mad Dog 2 in the US Gulf. According to Upstream, 26th July, BP has received bids for the

construction of the semisubmersible from three South Korean yards, Keppel and

Sembcorp in Singapore, a joint venture between Fluor and COOEC, Kiewit Offshore

Services, plus Technip has several potential Chinese partners. BP has previously

announced plans to reduce development costs to below USD10bn for Mad Dog from

USD20bn-plus proposals in 2013/14. At Q216 results, BP indicated the final investment

decision could happen before year-end.

Anadarko is deliberating between spar and semi-submersible development concepts for

the Shenandoah project in the US Gulf of Mexico. The US independent has taken the

project through to the FEED stage where it is evaluating between a spar-based dry-tree

solution provided by Technip and a wet-tree semi-submersible platform proposed by SBM

Offshore. Before taking an investment decision, which is likely in 2017, Anadarko will

continue to appraise the discovery by drilling further appraisal wells throughout 2016.

In Brazil, Aker Solutions and FMC are said to be competing for the 23 remaining subsea

trees on Libra, according to Upstream, 29th July. FMC has been awarded four already

through its long-standing frame agreement for the first-phase development. 10 trees are

required for extended well tests expected to be carried out by the Pioneiro de Libra FPSO

starting in early 2017, while 17 are for the Libra pilot project, expected onstream in 2020.

There’s also a USD300m drill pipe riser intervention services tender on Libra, which could

include five dual-bore risers, and four drill pipe riser systems. According to Upstream, 2nd

August, Weatherford, Aker Solutions and FMC have submitted bids to Petrobras.

For the FPSO on Libra, Petrobras has decided to re-issue the tender for the USD2bn unit

with 180,000bd oil-processing and 42mcf/d of gas-processing capacity. According to

Upstream, 26th August, contractors such as SBM and Bluewater expressed concerns with

the highly detailed and stringent local content requirements (which had 60 separate

categories), although Modec bid without imposing reservations or qualifications. The

dayrate for the vessel could be USD800-900,000/day, and 80% local content provision is

required. The charter period is for over 20 years.

Petrobras has also chosen to rebid the contract for the Sepia FPSO, according to

Upstream, 26th August. Despite the vessel being smaller than that required at Libra,

dayrates could be in excess of USD1m as financing costs are high with Petrobras as the

sole investor (local content provision is sub-70%). The Sepia FPSO is scheduled to be

contracted for 21 years and have the capacity to produce 180,000bpd and 5MMcmd of

gas upon commencement of production, currently scheduled for 2020.

In Canada, Upstream, 12th

August, reported that Petronas will instigate a full review of the

Pacific Northwest LNG facility before committing to a capital investment. The project is still

pending the release of the CEAA’s environmental report that was put on hold in March but

subsequently resumed in June. Bechtel and the Technip/Samsung Engineering/China

Huanqiu, KBR/JGC consortia had previously submitted proposals to build two LNG trains

at Lelu Island as part of an USD8bn EPCC contract, according to the report.

19 September 2016


Figure 56: Americas prospects Figure 57: Americas prospects by segment

Source Company data, Credit Suisse Research, data correct as of September 7th 2016 Source: Company data, Credit Suisse Research, data correct as of September 7

th 2016

Figure 58: Americas prospects by country (USDm) Figure 59: Americas prospects by operator


th 2016

Figure 60: Americas prospects by sub-sector (USDm)

Source Company data, Credit Suisse Research, data correct as of September 7th 2016

Offshore

Onshore

EPC

Floating

Other Equipment

SPS

0 2000 4000 6000 8000

USA

Brazil

Mexico

Canada

Guyana

Falkland Islands

BP

Petrobras

Pemex

Shell

Premier Oil

0

2000

4000

6000

8000

10000

12000

EPC Floating Other Equipment SPS

19 September 2016


Subsector outlook In this section we discuss the outlook for the OFS’s many sub-sectors – seismic, onshore

drilling, offshore drilling, E&C (onshore and offshore), EPCM / maintenance, and

equipment manufacture.

Seismic

Global CS coverage with seismic exposure – PGS, CGG, Schlumberger

In the traditional OFS investor playbook, ‘the seismic trade’ has worked well coming out of a downturn – for example, PGS doubled in 2009, with share price momentum continuing somewhat into 2010. Seismic is an early-cycle industry that traditionally benefits from an uptick in exploration spending and we’ve noted a clear sentiment change from oil companies and the seismic industry through the Q2 2016 reporting season.

Oil industry exploration successes over the past 10 years have bolstered the industry’s development portfolios. We’d expect greater focus on monetising development portfolios. In addition, oil companies are using low E&P valuations to acquire proven barrels (deemed “organic capex”) through bolt-on M&A, and bypassing riskier exploration. Furthermore, there’s very little appetite for frontier exploration at current oil prices; we don’t see this changing in 2017/18.

All this, however, does not mean exploration cannot also grow – as many have commented, prevailing levels of exploration spend are unsustainable to replace and grow the reserves required to meet future demand. We think the pace of recovery is unlikely to match the ‘gallop’ we saw coming out of 2008/09, but a decent ‘canter’ can be expected.

This downturn has been particularly harsh on seismic – it peaked in 2013, well before other sub-sectors, and 2016 represents the third consecutive year of declining exploration spend for the industry. Key players have had to reduce people / costs by up to 50% and some smaller players have gone bankrupt. Streamer capacity is nearly half the 2013 peak – a rational response from an industry that has seen more than its fair share of irrational behavior in past cycles.

Interestingly, the actual volume of seismic acquired is currently higher than pre-2010 levels as acquisition techniques have continued to improve (according to PGS estimates), but this is nearly 40% below the 2013 peak. We think oil companies will allocate more capital to exploration / seismic spending in 2017. We also see potential for a strong Q4 2016 late sales bump – we note that several players had record or close-to-record late sales in Q4 2009).

Given the industry’s supply response, we think the market has potential to rebalance

quickly in an upturn, with potential for positive EBITDA margins on contract work in 2017

(contract pricing likely to remain at broadly break-even cash cost in H2 2016). Vessel

reactivations, however, can act as a headwind to improving pricing.

Encouragingly, the industry looks structurally different coming out of this cycle – there’s

only one newbuild vessel under construction (PGS’s Ranform Hyperion; scheduled for

delivery Q1 2017). This is in stark contrast to the last cycle (there was a 33% net addition

to the fleet in 2009-2012) and to other heavy-asset industries such as offshore drilling

where the over-capacity situation could outweigh a multi-year demand expansion.

A large proportion of industry capacity has been scrapped or cold stacked; very little is

‘warm’. Of the 300 or so ‘lost’ streamers, we think less than half this number could be

brought back online, and the cost of reactivation should not be underestimated. The

industry has lowered vessel maintenance spend through cannibalising equipment from

stacked vessels. As such, the capital investment required to bring cold-stacked capacity

would require more new equipment and could be as much as USD50m (with lead times up

9-12 months). We’d need a sustained recovery for the economics of a reactivation to stack

up – and given the pain that the industry has endured, we don’t expect a rush.

19 September 2016


Licensing rounds / regional trends – overall licensing round activity has been trending

at normal cycle levels, but levels of interest have been mixed. Norway is conducting its

23rd licensing round exclusively in Barents Sea (more beneficial for TGS / WesternGeco),

and the APA wraparound (for which PGS is well aligned) with bids due in September

2016. Bids for the 29th UKCS round, launched in July, are due in October, while

Greenland continues to hold rounds yearly. Canada is scheduled for another round in

November for the East Coast, whereas Greenland will undergo annual rounds between

now and 2018.

Western US Gulf of Mexico sales (in August 2016) were disappointing but we are

optimistic about the Central US Gulf round in March 2017, given the potential for fast

payback tie-back projects. The fourth phase of Mexico’s Round 1 is scheduled to take

place in December 2016, but interest could again be lacklustre until the deepwater rounds

commence in 2017, with two subsequent rounds proposed by 2019.

Figure 61: Upcoming licence round activity

Source: Company data, TGS-NOPEC Geophysical Company ASA

We see potential for the return of activity in Brazil with a new pre-salt round tentatively

earmarked for mid-2017. Oil company interest may well be high depending on the

prospectivity of the blocks on offer (the most recent rounds offered acreage in the less

prolific basins) and the final fiscal framework. Should the round go ahead, CGG and PGS

would expect to be able to monetise their extensive multiclient libraries. African regions

Angola and Congo are likely to be more opportunistic on the timing of rounds.

Central GoM – March 2017

Western GoM – August 2016

Canada Onshore – at least monthly

Mexico Round 1 (L04) in Dec 16, Round 2 announced for 2017. 2 more round proposed by 2019

Newfoundland & Labrador – Nov 2016

Nova Scotia – Q4 2016 (3

year rolling plan)

Brazil – mid-2017

Australia – Q3 2016 (2016 round launch)

New Zealand – Sep 2016 (bids due)

Indonesia – Aug & Oct 2016 (bids due)

Norway 23rd

Round – May 2016 (blocks

awarded)

Norway APA – Sep 2016 (bids due)

UK 29th Round – Oct 2016 (bids due)

Greenland – Dec 2016, 2017, 2018 (bids due)

Ongoing uncertainty

Several prospective rounds look positive,

but deepwater timing is uncertain

19 September 2016


Onshore and Offshore drilling

Global CS coverage with exposure: Saipem, Seadrill, Noble, Ensco, Diamond, Rowan,

Transocean, Atwood, Nabors Industries, Patterson-UTI Energy, Helmerich & Payne,

Precision Drilling

Onshore drilling – US

In three of the past five cycles, US onshore drilling names have been amongst the best-

performing OFS stocks. We would expect somewhat of a ‘sentiment trade’ again as we

recover from this cycle, but we urge caution. Why? In essence the industry looks very

different now versus the past – longer-term contracts were more prevalent in the last

cycle, as such onshore drilling margins have been more resilient in this downturn versus

past cycles. As contracts roll off, we’d expect re-contracting (which is subject to demand)

for many rigs at current spot rates, which are close to cash breakeven. This dynamic puts

the brakes on margin expansion.

Figure 62: US rig count forecast

Source: Company data, Credit Suisse estimates, Baker Hughes International

Onshore drilling – International

The prospects for recovery in international markets look less attractive. Continued political

issues across Venezuela have stifled demand and the rig count is currently around 25%

off its July 2014 peak, surpassing the 15% peak-to-trough from the last cycle. While the

Middle East and Asian regions have continued to offer gainful employment for the regional

drilling fleets, the relative buoyancy of the market has been unable to offset declines in

Europe/CIS and the Latin American market. Near term, we see further downward pressure

for Europe/CIS owing to weaker exploration activity in Russia alongside a weaker African

market driven by a roll-off of Nigerian contracts.

0

100

200

300

400

500

600

700

800

900


US Rig Count Horizontal

Onshore US should be the initial beneficiary of

the recovery

Downward pressure in Europe/CIS but a

resilient Middle Eastern market

19 September 2016


Figure 63: Indexed US and international rig counts Figure 64: International rig count forecasts

Source: Company data, Credit Suisse estimates, Baker Hughes International Source: Company data, Credit Suisse estimates, Baker Hughes International

Offshore drilling

The offshore drilling trade also worked well coming out of prior cycles, particularly the last

cycle. However, an improved oil price from the beginning of the year does not change

fundamentally a challenged offshore environment and considerable supply overhang.

We draw parallels with the rig overbuild cycle in the late 1970s / early 1980s – from which

it took almost 20 years for a recovery cycle in newbuild activity to take shape. Appetite for

frontier exploration looks among the weakest historically and the medium-term outlook for

deepwater looks subdued – we think at least until 2018.

Figure 65: Jack-up and floating retirements (number

of rigs) Figure 66: Stacked floating fleet (number of rigs)

Source Infield Systems Source: Infield Systems

Notwithstanding historically high levels of rig scrapping / stacking (46 floaters removed

from active fleet ytd, and over 100 since 2H 2013), re-balancing this market looks some

way off and E&P spending is trending down again in 2016. About 80% of the 114 jack-ups

under construction have not been contracted for work. Many of these assets were ordered

speculatively, including a series of private equity-backed contracts, and in the absence of

securing active work, these rigs are unlikely to be delivered. 60% of the 40 floaters at

various stages of construction also lack any firm work. We also believe cold-stacked units

could return faster than the market expects (in some cases reactivation could be possible

in less than three months).

20

30

40

50

60

70

80

90

100

International US

0

200

400

600

800

1,000

1,200


LatAm Rig Count Europe/CIS Africa Middle East/Asia

19

7 10

2012

1

0

17

29

16

0

10

20

30

40

50

60

2012 2013 2014 2015 2016 ytd

Jackup Floater

0

20

40

60

80

100

120

140

160

2010-01-16 2012-01-16 2014-01-16 2016-01-16

Cold Stacked Ready Stacked

19 September 2016


Leading-edge dayrates are 60% below the late-2013 / early-2014 peak, although data

points are few and far between given the lack of contracting. Tendering activity remains

low with operators deferring tenders to 2017/18 and beyond, and the active floater fleet

continues to trend down as contracts expire. Over 80 floater contracts roll off between now

and the end of 2017 – rigs being used currently on development drilling programmes may

yet be re-contracted, but we expect a high proportion to be cold / warm stacked or even

scrapped.

Figure 67: Offshore drilling dayrates by asset type Figure 68: Offshore drilling utilisation

Source: Infield Systems Source: Infield Systems

E&C

Global CS coverage: Technip, Saipem, Subsea 7, Petrofac, Tecnicas Reunidas,

McDermott, KBR, Fluor, Jacobs

It’s been a poor year for project awards, and industry backlogs have declined. Year to

date, we’ve tracked over USD21bn of awards to market, a 50% decline compared with the

first nine months of 2015, and a 70% decline compared with 2014. Our in-house projects

database shows that awards have been split roughly 60/40% between offshore and

onshore – a marked difference to the substantial weighting towards onshore projects in

both 2015 and 2014. The potential pipeline of contract award opportunities tracked by CS

is significant at ~USD140bn, although timing of awards to market remains uncertain.

Offshore E&C

The offshore E&C industry is in the midst of a transformation. Projects undertaken at

USD100 oil failed to make attractive returns on investment. Over the past two years oil

companies have shifted from a production growth strategy to a return growth strategy; so

what limited capital there is has been allocated to the highest return opportunities – with

US shale an option with meaningful scale, capital allocation is unlikely to shift back to

offshore and deepwater immediately.

That said, offshore’s problems are overstated, in our view. While the spending cycle is

unlikely to recover before 2018, the offshore E&C industry has made considerable efforts

to reduce breakeven costs through more efficient processes, standardisation, cost

deflation and simplification. Key amongst which is the formation of a series of joint

ventures and alliances, and in the case of Technip and FMC Technologies, vertical

integration, to deliver a more integrated service offering to the offshore client base.

The alliances that have formed have changed the competitive landscape for the offshore

market. Clients now have the choice between a sole-sourced vendor-based solution, the

traditional procurement-based solution and a blend of the two. The alliances have also

linked the various parts of the offshore value chain together, particularly in the subsea

sector where shared skills and services across a wide variety of technology are now on

offer.

0

50

100

150

200

250

300

350

400

450

500

2004200520062007200820092010201120122013201420152016

US

D/d

ay

Jackups Floaters

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

100

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900

2010-01-16 2012-01-16 2014-01-16 2016-01-16

Operational Ready Stacked Utilisation (RHA)

Progress on costs but outlook for new project

capex still weak

19 September 2016


Figure 69: The links of the subsea value chain

Source: Company data, Credit Suisse research

Despite such efforts, the likelihood of a meaningful uptick in the next budgeting cycle, with

oil still in the USD40-50 range seems very low. The Majors, which account for nearly 85%

of offshore spending, are likely to wait until the next budgeting round – October-November

2017 – to include significant offshore projects in their planning cycles outside of a small

number of exceptions. As such, we expect near-term investment to be focused on smaller

subsea tiebacks rather than major greenfield development.

Downhole

completion / ESPs

Subsea pumps /

metering units

Subsea processing

and compression

Control systems

Subsea trees and

manifolds

Umbilicals

Installation & hook-

up

Flexible risers &

flowlines

Seismic and

Reservoir

characterisation

Well Intervention

(WI/LWI)

ROV / IMR related

workSupply vessels &

diving support

Forsys

OneSubsea

Subsea 7 / GranherneAker / Baker

Aker / Baker/ Saipem

19 September 2016


Figure 70: Offshore project awards by region Figure 71: Key unawarded Offshore EPC projects


Source: Company data, Credit Suisse research, UpstreamOnline, MEED, AOG, Thomson Reuters[

Source: Company data, Credit Suisse research, MEED, UpstreamOnline, AOG, Thomson Reuters

Onshore E&C

The Middle East is typically the bedrock of onshore E&C activity, but 2016 has been

disappointing thus far. At the start of 2016, MEED was tracking some USD90bn of

potential awards, with two-thirds at the tendering stage. This positive outlook has yet to

result in any real project award momentum. The main awards to industry have included

the onshore portion of BP’s Tangguh project and a series of projects in Saudi Arabia.

However, several more projects in Kuwait, Abu Dhabi, Saudi Arabia and Bahrain have

stalled.

There is little obvious seasonality to project awards (although very little is usually

sanctioned during Ramadan – which typically takes place in late Q2 / early Q3). The value

of project awards within the GCC has fallen every quarter (sequentially) since Q3 2015,

with Q2 2016 at a three-year low. Petrofac has discussed a bidding pipeline of USD21bn.

There are several live bidding situations that could result in major awards to industry in H2

2016 or 2017. Several potential projects could be sanctioned – in Saudi Arabia (Ras

Tanura Clean Fuels, bidding scheduled for H2 2016), Oman (Duqm refinery, technical bids

submitted in May, awaiting timing of commercial bids), Bahrain (Babco refinery expansion,

October 2016 deadline for EPC bids), and Kuwait (Jurassic gas projects, LNG terminal). In

Abu Dhabi, the gas-processing plant at the Al-Dabbiya oilfield sour gas project has been

put on indefinite hold (Upstream Online, 29 July). However, the main single prize to

industry in the medium term is the oils-to-chemicals (OTC) complex in Saudi Arabia (a JV

between Saudi Aramco and Sabic). Feasibility studies should conclude in 2017 with

MEED (29 June) indicating the value could be up to USD30bn.

The reliance of MENA economies on hydrocarbons (oil in particular) is well documented –

oil price turbulence has a disproportionate impact on state finances; the financial strength

of these economies has diminished. According to MEED (13 July), the volume of

syndicated loans increased in H1 2016 to almost USD75bn (from under USD50bn in H1 /

H2 2015, and USD30-35bn in H1 / H2 2014) driven by sovereigns borrowing to sustain

public spending, with several National Oil Companies borrowing to fund project

programmes. In addition, project finance volumes in H1 2016 were the highest since

2009/10, while export credit agency financing is also becoming more prevalent as fiscal

deficits rise.

An increasingly cash-strapped customer base is pushing less favorable cash payment

terms onto contractors – lower or zero upfront cash advances are replaced by more

meaningful cash inflows on milestones. But in some cases, milestone-related cash

payments are also less generous. In addition, variation order negotiations / payments are

0 10,000 20,000 30,000 40,000 50,000

2014

2015

2016 ytd

Africa Asia Pacific Europe Americas Middle East

0

1000

2000

3000

4000

5000

6000

7000

8000

19 September 2016


increasingly deferred until the latter stages of construction (contractors are cautious

performing any changes to scope without customer sign-off). However, lead contractors

may be incentivised to preserve payment structures with their own supply chain to avoid

any critical path slippage. This would see cash receipts lagging behind revenue / margin

recognition – in essence contractors will fund more of the projects.

Traditionally, in cyclical downturns, competitive pressures intensify as companies re-focus

on the MENA region to shore up dwindling volumes elsewhere. However, while there is

little empirical evidence on the competitive environment, we do not believe there is (nor do

we expect to see) widespread pricing indiscipline. In addition, we think the cash-flow

dynamics discussed above, as well as rising maximum aggregate liabilities may be acting

as a barrier to entry.

There are opportunities and threats in project procurement. Widespread deflation for raw

materials and components has lowered project costs. We believe some contractors (eg,

Petrofac) capitalised on a weakening supply chain through 2015 to bolster margin

potential on newly acquired backlog. This represents a one-off benefit as conservative

contractors typically do not take risk on procurement prices. In addition, we believe larger

companies with stronger backlog benefit most during a downturn as the supply chain fights

to secure volume. A key risk to existing backlogs is supply chain counter-party risk – low

volumes in the market could threaten the solvency of the supply chain.

Figure 72: Onshore EPC project awards by region Figure 73: Key unawarded Onshore EPC projects


Source: Company data, Credit Suisse research, MEED, UpstreamOnline, AOG Source: Company data, Credit Suisse research, MEED, UpstreamOnline, AOG

EPCM / Maintenance

Global CS coverage: Wood Group, AMEC Foster Wheeler, WorleyParsons

The market for engineering has trended down since H2 2014 as the industry (offshore in

particular) began to struggle with project IRRs – several projects were deferred, and the

detailed engineering volumes dried up as significant cutbacks in E&P capital expenditure

took hold in 2015 / 2016. Upstream and Subsea markets have been the worst affected

(although the former is now showing signs of recovery) with downstream relatively resilient

(albeit increasingly competitive).

Oil company ‘project recycling’ has preserved front-end engineering man-hours at high

levels – oil companies typically evaluate future development candidates, but in a downturn

as material as this one, only the best IRR or strategic projects are sanctioned. The

industry’s portfolio of undeveloped discoveries is significant. All this we think supports an

eventual medium-term recovery in engineering markets.

0 10,000 20,000 30,000 40,000 50,000 60,000

2014

2015

2016 ytd

Africa Asia Pacific Europe Americas Middle East

0

1000

2000

3000

4000

5000

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7000

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9000

19 September 2016


However, there are notable risks on the long road to recovery – in some markets (notably

Subsea), the competitive landscape has seen significant change as later-cycle players

team up to compete at the front-end. Oil companies typically require an independent view

from pure engineering houses, but their overall role on projects could be diminished. There

is merit in involving later-cycle players at the front-end to understand execution challenges

better. Greater standardisation and modularisation across the industry arguably also limits

an engineer’s ability to add value.

An offsetting positive is that oil companies are spending more time at the front-end – such

work for engineering companies is typically high ‘value’ but low volume. Historically the

industry spends very little hard cash (2-5% of total investment costs) at the front-end

relative to the total project cycle time (30-40%). Poorly kept schedules have often been

blamed for poor project financial performance, but we think poor project selection has also

been a factor. In essence, we now see far greater scrutiny of project portfolios and project

viability at the front-end of a project.

Chevron has flagged technology shortfalls and poor-quality FEED work for project

installation problems. Consequently, Chevron is moving earlier-phase engineering work in-

house. However, we do not see this as a trend – the lack of in-house knowledge and

experience at oil companies (exacerbated by headcount reductions) can compete rarely

with the track record of a specialist engineering house. We could see greater migration of

engineering talent from OFS to oil companies, but this is not a new trend.

One strategy from key players to offset customer cost pressures has been to migrate more

engineering work to lower-cost/high-value centres (in countries such as India and

Columbia). We think this theme has been coming for a while – engineering companies

looking for margin gains have long argued the case for more man-hours in low-cost / high-

value centres, but customers were concerned about quality. However, engineering quality

has improved and there’s been less pushback from cost-conscious customers through the

downturn.

Maintenance/opex volumes have held up relatively better than capex-related spend.

However, non-essential expenditures have been deferred (lower call-off volumes within

frame contracts) and pricing has been under pressure on re-contracting long-term

agreements. North Sea and US onshore markets have been particularly challenged.

Looking ahead, there are encouraging signs that modification volumes should pick up in

the North Sea from 2017 (particularly Norway) and we think US onshore markets

bottomed in Q2 2016.

Figure 74: EPCM reimbursable vs. fixed price

exposure Figure 75: EPCM capex vs. opex exposure

Source: Company data, based on FY15 actuals, Credit Suisse research Source: Company data, based on FY15 actuals, Credit Suisse research

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Reimbursable Fixed Price

0% 20% 40% 60% 80% 100%

Wood Group

AMFW

WorleyParsons

Capex Opex

19 September 2016


Equipment manufacturers

Global coverage: Hunting, Schoeller Bleckmann, Aker Solutions, CGG, Technip, FMC

Technologies, Weir, Core Labs, NOV, Baker Hughes, Franks International, Forum Energy

Technologies

Shorter-cycle businesses manufacturing consumable products that are exposed to near-

term drilling activity have experienced rapidly declining volumes and profitability through

this cyclical downturn. At the depths of current activity levels, many players are currently

generating negative EBITDA – extensive efforts to restructure cost bases have not kept

pace with the deterioration in activity.

The North American rig count has the largest bearing on these businesses, and after

experiencing a double dip, is now recovering from its Q216 bottom. The drilled but

uncompleted wells (DUCs) began to be completed. The summer 2016 months were

turbulent with oil prices again trending down towards USD40/bbl but this has proved a

temporary setback and rig counts have continued to improve

We’d expect short-cycle players to demonstrate a strong and early recovery as (1)

inventories have been drawn incredibly low and (2) the industry works through its

inventory of ~2,500 DUCs – this could take two years. The recovery will likely be led by

volumes, with margin recovery from higher throughput / additional shifts within existing

facilities. A pricing recovery would likely lag behind, perhaps materially so, as the return to

three-shift / 24/7 operation looks to be several years away – Credit Suisse forecasts NAM

oil rig count in 2018 of 764 (versus a peak of over 1,900 in September 2014).

Longer-cycle businesses including subsea and drilling capital equipment continue to eat

into good-quality backlog secured in a more favourable market. However, book-to-bill

trends continue to be weak, and we’ve also seen several examples of deliveries being

stretched out and even cancellations (notably in drilling), while services work has dried up

in many regions.

We’d expect the industry book-to-bill to remain well below 1x through 2016 and into 2017.

This is likely to intensify competitive pressures as management teams look to provide

utilisation and keep plants operational. While there are opportunities for subsea equipment

manufacturers, these look markedly different to the last cycle. The bulk of work being

actively tendered is formed of two and four well tiebacks to existing infrastructure, rather

than the 10-12-well packages that have typically formed much of deepwater greenfield

work.

Offshore market analyst Infield Systems forecasts a total of 146 subsea tree awards in

2016 under a bull case, but only 35 in its base case assumptions. We would expect a

figure in the range of 60-80, with only a small number of prospects converting into firm

orders for the subsea equipment supply chain.

We think there are some good initiatives from various subsea players to improve project

economics. The creation of Forsys (a FMC / Technip JV) triggered a chain reaction across

the industry with the formation of several alliances such as OneSubsea / Subsea 7 and

Aker Solutions / Saipem. The oil industry appears to be embracing such initiatives given

the sheer volume of FEED studies – Forsys alone is working on over 30 studies. This

response is a key driver behind the decision to merge Technip with FMC Technologies

(deal completion scheduled for Q117).

19 September 2016


Figure 76: Subsea tree order forecast Figure 77: Subsea tiebacks onstream forecast


Figure 78: Offshore EPIC (engineering, procurement, installation and construction)capex forecast

in millions, unless otherwise stated

Source: Infield Systems

Figure 79: SPS Systems currently being bid Figure 80: Deepwater EPIC capex

Numbers of trees, unless otherwise stated in millions, unless otherwise stated

Source: Credit Suisse research, Upstream Online, AOG, company data, Source: Infield Systems

375 286 407 543 230 15335

8397

76 48 41

28

163

284 322 348

0

100

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2010 2011 2012 2013 2014 2015 2016e 2017e 2018e 2019e 2020e

Firm Plan / Awarded Firm Plan Probable Possible

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2016e 2017e 2018e 2019e 2020e

Africa Asia Australasia Europe Latin America Middle East North America

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Operational Firm Plan Probable Possible Other*

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2010 2011 2012 2013 2014 2015 2016e 2017e 2018e 2019e 2020e


19 September 2016


Oil price outlook In this section, to provide some context to the oil price framework in which we evaluate the

oilfield services sector, we provide a brief summary of the Credit Suisse view on oil prices,

provided by our Global Energy strategist, Jan Stuart.

Two years after the onset of the latest 'great oil price collapse', we can report that a

recovery that started late in March quickly saw oil prices hurdle their 200-day moving

average (in April) for both Brent and WTI. Since early June, however, this oil price

recovery has lost momentum. What's more, demand-side headwinds are gathering in a

way that they had not for any length of time since the middle of 2013, when the broader

US economic recovery began in earnest.

Post Brexit, we now expect below-trend oil demand growth in 2017, which mutes our

upward trajectory and delays an inflection of Brent and WTI into the USD55-60 range until

Q2-17. While the real impact of Brexit remains unknowable at this point, it is the latest and

probably strongest catalyst for a slowdown of global growth that is likely to have a

pronounced negative impact on oil demand in the second half of this year and in 2017.

We forecast a little less than 900kb/d global oil demand growth in 2017 (~0.9%). Our 2016

demand growth forecast has come down by about 1.5% to 1,400kb/d owing in part to the

Brexit-related revision to Q4 growth, and due in part to recent data points in non-OECD

countries (China, Brazil etc) coming in more bearish than expected.

However, real declines in non-Opec production are emerging this year, with Brazil, China,

Mexico and the US all falling. We expect non-Opec yoy supply declines to continue in

2017, with the US flat yoy, and Non-Opec (ex US)1 down -210kb/d. In 2016 we forecast a

total non-Opec yoy decline of 1,100kb/d, with almost half coming from Nopexus. For

reference, total non-Opec supply grew 1.5mb/d in 2015, with two-thirds of that growth

coming from the US.

Taken together, we think the rebalancing of global crude markets is well underway, albeit

at a sluggish pace. We believe the big drivers behind crude markets are too constructive

for a further steep pullback:

■ Global oil supply is falling, by any measure; and demand continues to grow, perhaps

less rapidly in a post-Brexit world – but there are no signs that consumption is about

decline sharply;

■ The fundamental rebalance is happening and the risk of a repeat of last year’s 2H oil

price is more like a tail-risk.

Figure 81: CS oil price forecast Figure 82: CS oil price forecast (WTI, $/b)

Brent Futures WTI Futures

2011 $110.91 $95.11

2012 $111.68 $94.15

2013 $108.70 $98.05

2014 $99.38 $92.89

2015 $53.60 $48.79

2016e $44.53 $49.78 $53.59 $48.70

2017e $56.25 $53.19 $55.00 $52.05

2018e $67.50 $56.02 $65.00 $54.20

2019e $67.50 $58.03 $65.00 $55.59 Long-term $70.00 $67.50

Source: Credit Suisse estimates, the BLOOMBERG PROFESSIONAL™ service Source: Credit Suisse estimates, the BLOOMBERG PROFESSIONAL™ service

19 September 2016


Financing trends and the OFS balance sheet There is currently a lack of liquidity in the wider energy sector – in some cases this is

leading to financial distress, rising bad debts, and protracted / challenging debt facility

renegotiations. This financial backdrop and lower appetite for bank lending is also

hindering the sector’s M&A prospects.

An August 2016 report from debt ratings agency Moody’s stated that ~USD110bn of debt

(USD60bn in bonds / term loans, USD45bn in RCFs) associated with severely strained

OFS companies will mature or expire by end-2021 (almost half of this by end-2019).

Investment-grade companies are unlikely to face significant challenges re-financing, but

the situation is different for speculative-grade companies (that account for 65% of the

USD110bn).

Bank risk committees overseeing energy lending books are understandably acting with

more caution through the downturn. Many oil / OFS company refinancings have seen the

size of a company’s banking consortium grow – ‘strength in numbers’ – as banks de-risk

lending books. Others, however, have seen support for corporates waning and banks

stepping back to reduce exposure to Energy.

The energy industry is cyclical. However, the duration of this downturn will likely test

banks' ability to support short-cycle businesses burning cash with limited visibility, or their

ability to forecast future financial performance accurately. It’s equally challenging for banks

looking at asset-heavy businesses (rigs and other vessel-related services, etc) where key

assets run the risk of laying idle for an extended period of time – establishing a sensible

valuation for such assets is not easy.

With many debt instruments trading at significant discounts to par value (some high yield

bonds were trading at 20-30 cents in the dollar when oil prices were sub-USD30/bbl), one

would expect the banks’ risk appetite to be waning. The overall pool of banks now willing

to lend to the energy sector appears to be reducing, and those banks that are still active

have adopted a risk-averse approach.

Many companies across the OFS/E&P space have precarious cash-flow positions and net

leverage can rise quickly in volatile markets. With liquidity drying up, banks will need to

evaluate whether to be generous in granting banking covenant flexibility/holidays. We’ve

seen signs of rising financial distress, particularly among smaller, less well-capitalised /

private OFS players.

Figure 83: North American OFS bankruptcies

2015-16 ytd

Figure 84: Secured vs. unsecured debt defaults

2015-16ytd

Source: Haynes and Boone Oilfield Services Bankruptcy Tracker Source: Haynes and Boone Oilfield Services Bankruptcy Tracker

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

01/15/2015 06/12/2015 09/21/2015 12/16/2015 03/10/2016 04/29/2016 06/07/2016

US

Dm

Secured Unsecured

Secured66%

Unsecured

34%

19 September 2016


Available sources of finance and lending covenant relaxation

Banks have been ‘tightening their belts’ towards the energy sector, debt coupons are

rising, credit agency downgrades are prevalent, and the breadth of financing options

available to the sector is shrinking. Lacking alternatives, many players may draw down

more on expensive revolving credit facilities just to stay afloat. Although such facilities are

often ‘covenant-lite’, they can have financial covenants that ‘spring’ into action under

certain circumstances.

There have been several examples of banks relaxing debt covenants (eg, Seadrill,

Hunting, AMEC Foster Wheeler, CGG and PGS) to help a company through the downturn

– a rational approach in a cyclical sector to support companies rather than inherit an asset

base they may be ill-equipped to operate. However, this often results in a rising cost of

debt for the corporate.

Lenders often look towards management teams with considerable experience – those that

have navigated more than one cycle successfully. This is often more important than asset

backing (given the risk of idleness). Some comfort can also be found in a company’s

backlog, although we’d expect a greater degree of due diligence ‘quality’. Lenders will also

look to cash-generating assets and the likelihood these assets continue to generate cash.

We’ve seen a spate of refinancing and rights issues – Saipem’s proposed EUR3.5bn

rights issue coincided with ENI deconsolidating Saipem’s debt and a major debt

refinancing package (EUR1.6bn bridge to bond, EUR1.6bn term loan and a EUR1.5bn

RCF). In the seismic market, CGG raised EUR350m to pay the cash cost of its

transformation plan, while PGS performed a USD100m private placement representing

around 10% of its share capital.

Looking across sectors, those exposed to the low end of the market (sub-suppliers) and

mainly short-cycle activity (including rental businesses) are likely to be under strain. Asset-

heavy players (drillers, vessel owners etc) will likely be burdened by payment obligations

matched to weakening order books, although many drillers have deferred newbuild rig

deliveries and payments successfully. The drilling sector, in particular, still has significant

speculative capacity (about 80% of the 114 jack-ups under construction and over half the

floaters under construction do not have operating contracts); rig financing in the absence

of firm operating contracts is challenging.

The OFS balance sheet lacks strength

Figure 85: Net Debt to EBITDA – 2016E Figure 86: Net Debt to EBITDA – 2017E

Source: Company data, Credit Suisse estimates for all Source: Credit Suisse estimates

-3

-2

-1

0

1

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6

7

CGG PGS AMFW PFC SPM WG AKSO SUBC TEC TRE

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CGG AMFW PGS SPM AKSO PFC WG SUBC TEC TRE

19 September 2016


A simple screen of the European OFS balance sheet shows a mixed picture. In the above

charts, we have taken out companies not subject to financial covenants in 2016/17 (either

through a covenant holiday, as Hunting was able to negotiate in July 2016, or because

such covenants do not exist – as is the case with Schoeller Bleckmann). Several

companies we cover (Technip, Subsea 7, Tecnicas Reunidas) operate with net cash

positions. The company with the most extreme net leverage position is Seadrill at nearly

10x in 2017e – given weak fundamentals for offshore drilling, we are concerned equity

investors could be diluted further following two debt-for-equity exchanges already settled

in 2016. The seismic stocks, PGS and CGG, have successfully negotiated more relaxed

debt covenants, however, current trading remains challenging and our net leverage is

sensitive to even modest changes in financial performance.

AMEC Foster Wheeler screens a high net leverage position, but if it delivers successfully

on its GBP500m disposal plan, it would de-lever to more comfortable levels. Similarly, we

see no leverage issues with Petrofac, particularly with IES disposals reducing net debt.

Elsewhere, we have few concerns about financial leverage across our coverage.

One note of caution with our analysis here is that banks seemingly allow different

interpretations of what constitutes EBITDA and what needs to be included/excluded in

calculations of net debt. We have not adjusted our calculations to reflect such nuances

due to lack of disclosure.

Stress testing the OFS balance sheet – blue sky and grey sky scenarios

We consider our base case forecasts to be conservative, but at the bottom of any cycle,

there’s a degree of uncertainty as to how oil prices and E&P capital spending may develop

in 2017/18, and thus the pace at which the OFS sector can emerge from this downturn.

Financial liquidity constraints for the wider industry are an additional factor. As such, we

incorporate our blue / grey sky sensitivities.

Figure 87: Blue sky net debt to EBITDA – 2016E Figure 88: Blue sky net debt to EBITDA – 2017E

Source: Company data, Credit Suisse estimates Source: Credit Suisse estimates

-3

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7


-3

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CGG PGS AMFW SPM PFC AKSO WG SUBC TEC TRE

19 September 2016


In the companies section, we describe the assumptions we make for each company within

our blue sky / grey sky scenarios. The above / below charts illustrate how sensitive many

companies in this sector are to relatively modest movements in revenue and margins..

Figure 89: Grey sky net debt to EBITDA – 2016E Figure 90: Grey sky net debt to EBITDA – 2017E


Dividend sustainability

Several companies have suspended or cut dividends already – some proactively so,

despite comfort from backlog underpinning near-term earnings, and others more

reactionary to the severity of the cycle. Only about half the companies in our coverage pay

dividends currently. For dividend-paying companies, the current sector dividend yield may

appear attractive at around 4% for 2016/17E, although the range is wide – <1% for

Schoeller Bleckmann to nearly 6% at Petrofac. Thus far only Wood Group has grown its

dividend through the downturn and plans to grow it again in 2016 by double digit.

For the majority of the dividend-paying companies, the dividend yield is supported by a

strong balance sheet. AMEC Foster Wheeler’s dividend perhaps looks most at risk, but H1

results also delivered a strong message on dividend sustainability. For Petrofac, the board

has committed to sustaining the DPS at 2014 levels in its three-year business plan. We

believe the balance sheet deleveraging and a (backlog-supported) improvement in

financial performance in 2016/17E provide support for what looks to be an attractive yield.

Figure 91: 2016E EU OFS dividend yield Figure 92: 2017E EU OFS dividend yield


-4

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8


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CGG AMFW PGS AKSO SPM PFC WG SUBC TEC TRE

5.9%

4.3%4.0% 3.9%

3.5%

2.0%

0.9%

0%

1%

2%

3%

4%

5%

6%

7%

PFC TRE AMFW TEC WG CLB SBO

6.3%

4.3%

3.5%3.9% 3.9%

2.0%

0.9%

0%

1%

2%

3%

4%

5%

6%

7%

PFC TRE AMFW TEC WG CLB SBO

19 September 2016


Credit Suisse HOLT® and EU OFS

The HOLT methodology uses a proprietary performance measure known as Cash Flow

Return on Investment (CFROI®). This is an approximation of the economic return, or an

estimate of the average real internal rate of return, earned by a firm on the portfolio of

projects that constitute its operating assets. A firm's CFROI can be compared directly with

its real cost of capital (the investors' real discount rate) to see if the firm is creating

economic wealth. By removing accounting and inflation distortions, the CFROI allows for

global comparability across sectors, regions and time, and is also a more comprehensive

metric than the traditional ROIC and ROE.

European OFS vs Global OFS

HOLT provides us with a framework to express aggregate economic returns over a 20-

year perspective of value creation or destruction.

In Figure 93, we note that returns for European Oil and Gas Equipment firms have seen

three periods of particularly depressing returns – 1999, 2003 and the current trough in

2015/16. The pressures on margins and asset efficiencies were apparent throughout the

last cycle where the sector failed to recover the level of financial performance it delivered

in 2006-08 (2008 was the peak of what was a super-cycle for these companies). The OFS

industry over-invested through the last cycle and failed to deliver economic returns to

2006-08 levels. The depressed levels of returns we see currently reflect the harshest of

industry downturns.

History suggests recovery is imminent, as expressed by market expectations (green dot),

pricing in a recovery to cost of capital levels of c5% over the next five years. Consensus

(pink bars) also trends up in the near term as sell side analysts expect more positive

forecasts from these stocks, albeit at a slower pace of recovery versus prior cycles.

Figure 93: Relative Wealth and Sales, Margins, Turns from HOLT

Source: Company data, Credit Suisse HOLT

19 September 2016


Historical market expectations vs consensus forecasts

The industry as a whole has been facing consensus downgrades (pink bars) since 2014 in

the face of resilient market expectations (green dots). This trend has resulted in the widest

spread in expectations between analysts’ expression of the near-term corporate

profitability and market-implied expectations of the recovery over the next five years – see

Figure 94. It is interesting to note the buy side / sell side expectations decoupled in 2011,

after the initial recovery phase in 2009-10.

Currently forecast returns are at a 20-year low at 2.7%. It is worth noting that in previous

troughs (1999 and 2003), analyst expectations did not trend below 6.0% costs of capital

levels, clearly indicative of a particularly harsh cyclical downturn.

Figure 94: CFROI from HOLT


Given this backdrop, two distinct observations can be made. One is that stock selection is

critical. The market appears convinced recovery is inevitable, but with the correlation

towards cost of capital levels, there will be winners and losers. We position our top picks

across this cohort. Secondly it is interesting to position the Oil and Gas Services firms

versus the Energy or Capital Goods sectors as a whole. We use the HOLT Discount Rate

to help us distinguish between sectors and regions within the Oil and Gas Service industry

(Figure 95).

HOLT discount rates are solved for using firms' forecast cash flows and market prices.

HOLT derives discount rates by equating firms' enterprise values to the net present value

of their forecast free cash flows (FCFFs). Therefore, we solve for a forward-looking, or ex

ante, yield as opposed to ex post as described by CAPM (capital asset pricing model). The

HOLT discount rate thus results in a relative valuation approach and is similar to

calculating a yield-to-maturity on a bond.

19 September 2016


In Figure 95 below, we compare the discount rate of Global Energy at 5.8% vs. Global Oil

and Gas Services at 3.5% – a spread of 230bps. On this measure as well, a strong

recovery appears to be well priced in relative to the wider Energy sector.

Global Cap Goods also commands a higher discount rate at 4.4% – a 90bps premium to

Global Oil and Gas Services.

Within Global Oil and Gas Equipment Services, there are regional divergences to note.

The US is priced for the lowest yield in history at 2.5%, even below its 5th percentile,

dragging down the global average of the industry.

Europe ex UK on this measure is the most attractive at 5.6%, equivalent to its 10-year

median. NJA firms are above historical medians but below Europe at 5.2%. UK firms are

at their 25th percentiles at c4.4% and below historical medians.

Figure 95: Market Implied Discount Rate from HOLT


19 September 2016


European Oil and Gas Equipment Services – CS

coverage

A returns overview

From our coverage universe of 12 companies, the levels and trends of CFROI by the

individual companies vary markedly, but there’s a distinct decline in the near-term returns

for nearly the entire universe (see Figure 96 light blue bars) reflecting extremely

challenging market conditions towards the bottom of the cycle.

The companies below are ranked from the least to the most demanding market

expectations within each sub sector. Attractive names on HOLT default are: Technip,

Tecnicas Reunidas and Subsea7 in E&C, Aker Solutions in Equipment.

It is worth noting that all the UK companies – Petrofac, Wood Group, AMEC Foster

Wheeler and Hunting – have demanding expectations – in line with their low implied

yields, expressed by the HOLT discount rates above.

Challenged European names in HOLT appear to be Schoeller-Bleckmann, CGG and PGS.

Figure 96: Return on Capital – CFROI from HOLT


19 September 2016


HOLT Economic PE

It is also useful to analyse how the market is valuing the future economic returns for these

players. By using HOLT to compare systematically what the market is pricing in to the

invested capital today (HOLT Price to Book), versus the near-term expectations for

corporate profitability (HOLT forecast CFROI), we can screen for overvalued and

undervalued names.

Figure 97 below shows this relationship between HOLT Price to Book and forward returns

on capital. For this portfolio of 12 companies under our coverage, there is high correlation

of 80% between the corporate performance as expressed by the HOLT CFROI and near-

term valuation.

The UK engineering players – AMEC Foster Wheeler (Underperform) and Wood Group

(Outperform) – are currently trading at a premium relative to other European players, as

are equipment players Schoeller Bleckmann (Outperform) and Hunting (Neutral). The

Nordic companies are almost fair valued, according to HOLT – Subsea 7 (Underperform),

Aker Solutions (Neutral) and PGS (Outperform). E&C players Saipem (Neutral) and

Technip (Outperform) appear the most attractive options on a P/B vs CFROI relationship,

with Tecnicas Reunidas (Underperform) and Petrofac (Outperform) not far behind.

Figure 97: Price to Book and CFROI from HOLT


19 September 2016


Overlay momentum to current valuations

Overall sentiment for the Oil and Gas Equipment Services remains pessimistic. The

CFROI revisions in Figure 98 refer to changes in EPS estimates by IBES consensus

forecasts in aggregate. Whilst downgrades continue, the trend has been improving, and

positive revisions will be instrumental in supporting further potential upside to current

optimistic expectations.

Figure 98: CFROI Revisions from HOLT

Source: Credit Suisse HOLT

Identifying revision contributors

Analysing the momentum across our coverage suggests that Subsea 7, Technip and Aker

Solutions have had upgrades over the past 13 weeks cumulative. CGG, Petrofac and

Tecnicas have turned positive more recently in the past four weeks.

Figure 99: 13-week CFROI Revisions from HOLT Figure 100: 4-week CFROI Revisions from HOLT

Source: Credit Suisse HOLT Source: Credit Suisse HOLT

19 September 2016


Driving returns forward to create value

Mapping the current positioning is interesting. Understanding how each of the individual

companies drives the level of returns would help us to gauge where further improvements

can be expected. Within the HOLT framework, this is interpreted neatly within a Dupont-

style analysis – Margins and Asset Efficiency.

The figure below reflects the drivers of returns, in terms of margins and asset efficiency

across our coverage. It positions where the firms are today, defending the levels of CFROI

as expressed by the size of the bubbles.

Figure 101: Drivers of Returns - Margins and Asset Efficiency

Source: HOLT®

Tecnicas Reunidas and AMEC Foster Wheeler are examples of firms trading at the

highest asset efficiency levels amongst this cohort. They are also trading at the highest

levels relative to their own history, indicating strong balance sheet management. However,

margins for AMEC Foster are 140bps below seven-year medians and Tecnicas Reunidas

is at the lowest level of its 14-year history.

At the other end of the spectrum are Subsea 7, CGG and PGS where margins are at

historical highs in contrast to asset turns, where they have reached the lowest levels

relative to history and are nearly the worst of this peer group. Top-line growth is crucial for

these companies to expect cash flows and returns to recover over the next few years.

19 September 2016


Forecasts and valuation In this section, we discuss our approach to forecasting for and valuing the OFS sector.

Approach to forecasting – We use a wide framework in determining forecasts for each

company. The overarching assumptions begin with Credit Suisse's commodity price

assumptions for oil & gas markets, CS rig count assumptions and views / projections for

E&P capex. We analyse growth potential and supply / demand dynamics for each

subsector, and consider how each company could perform against this. We analyse book-

to-bill trends, order backlog and backlog scheduling, and historical and peer group relative

performance. We also use our in-house projects tracker to evaluate contractor positioning,

and consider licence round data and expectations. Within cash flow, we forecast capex

and working capital but tend not to forecast M&A or share buybacks (even if this is a part

of the company's strategy).

Valuation discussion – We think investors will use a range or combination of metrics

when evaluating the relative attractiveness of the OFS sector and its constituent parts.

Current-year EV/EBITDA and PE multiples are unlikely to feature too highly in investors'

approach at the bottom-of-the-cycle, although EV / Sales (for asset-light companies) and

price-to-book or price-to-tangible book (for heavier-asset plays) can often provide an

indication of where stocks might bottom out. With oil prices (and the stock prices) now well

off the bottom, these metrics may become less relevant in a recovery cycle but remain

important in assessing downside risk.

As the recovery cycle progresses, we think the market might focus more on the mid-cycle

earnings potential of the OFS sector. In particular, we think investors are looking towards

the last year of a typical three-year consensus forecast, ie, 2018. In our own models, we

prepare through-cycle analysis – this considers what a company could, on average, earn

through a cycle (we typically model a 5-6-year cycle to 2021/22), and typical through-cycle

multiples. We do not use this analysis to determine target prices, but more as an indication

of where stocks could move to over a longer-term horizon.

Our approach – In this report, we approach the valuation using an equally weighted (50%

each) combination of longer-term discounted cash flows (DCF), and nearer-term multiples

(using a sum-of-the-parts approach) using 2017E and 2018E. In DCF, we've used five-

year average monthly beta values, considered equity market risk premium and risk-free

rates in determining WACC for each stock, and assumed long-term growth across the

sector at 2%. For SOTP we apply EBITDA multiples to each division based on business

quality, comparable companies, historical multiples, cycle phasing and growth

expectations.

Blue sky / Grey sky scenarios – For each stock under our coverage, we provide blue

and grey sky scenarios to our base-case estimates. The forecast variables we use are

principally divisional revenue and divisional margin assumptions. For example, a blue /

grey sky scenario will typically assume a growth premium / discount to our base-case

assumptions. In addition, within our valuation framework, we would also assume higher /

lower long-term growth for our DCF, and higher / lower multiples within our SOTP.

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Figure 102: Valuation Summary

Stock Rating Target Price +/- Segment Investment Case

Aker Solutions NEUTRAL NOK 35 -4% Equipment Headwinds and tailwinds - The potential rebound in the Norwegian MMO market is underestimated by the market, but so is the softness / duration

of the Subsea market downturn. A much improved company but too early to buy for recovery, in our view.

AMEC Foster

Wheeler

UNDERPERFORM GBp 450 -15% EPCM* Too much too soon - the market has warmed to new CEO Jon Lewis; the stock has outperformed peers since his arrival in June. We expect the

November CDM to deliver positive progress on costs, but investors should not underestimate topline pressures, and future mix looks dilutive.

CGG UNDERPERFORM EUR 17.5 -21% Seismic Over leveraged - February's rights issue has provided little headroom to covenants while market conditions have deteriorated further. The

transformation has created a far better quality business mix, but we think the cyclical recovery will be insufficiently strong to delever materially. As

such CGG's premium rating to PGS looks unwarranted.

Core Laboratories NEUTRAL USD 115 6% Equipment High return / high valuation - we believe the market underestimates the lower-for-longer offshore / deepwater cycle; a key market that in the past

has driven attractive incremental margins. CLB's recovery profile is initially more geared into lower quality (Production Enhancement) revenue

lines; the inflection point on better quality Reservoir Description could be a catalyst - too early to buy, in our view.

Hunting NEUTRAL GBp 500 20% Equipment Early cycle - HTG is a play on US unconventionals - an enlarged Well Completion division with more IP should ensure HTG is faster out the blocks

in this cyclical upswing. However recovering pricing will take time and current valuation suggests to us the stock has run too far too soon.

Petrofac OUTPERFORM GBp 1100 36% E&C* Back to core business - Diversification has not worked; a refocused PFC with best-in-class E&C business at its core is a far more attractive

proposition. P&L is stabilising and well underpinned, and valuation vs closest comp (TRE) appears compelling. Non-core asset disposals provide

additional optionality, in our view.

PGS OUTPERFORM NOK 27 63% Seismic Higher risk / higher reward. The rebound in exploration activity may well underperform past cycles, but we think the market underestimates the

level of pent-up demand for multiclient data and production seismic, plus how quickly the contract market could rebalance. Current multiples imply

a far more pessimistic outturn than we see.

Saipem NEUTRAL EUR 0.45 20% E&C Rehabilitation requires patience – long-cycle business slowly moving in the right direction but significant risks remain – pending revenues, litigation

/ arbitration, offshore drilling re-contracting and cash flow. Risk of downgrade to medium-term financial targets.

Schoeller

Bleckmann

OUTPERFORM EUR 70 33% Equipment Best EU play on US unconventionals - Built out Well Completion line in downturn giving faster growth potential in a recovery and greater through-

cycle balance. Niche technology, highly operationally geared. 2018 multiples in line with long-run average but earnings capacity is double our 2018

estimates.

Seadrill UNDERPERFORM USD 1.0 -53% Drilling All drilled out – continues to pay down debt, but much left to do. Sense of urgency illustrated by net leverage - ~10x late by late 2017E.

Fundamentals remain weak – potentially through to the end of the decade, in our view.

Subsea 7 UNDERPERFORM NOK 75 -11% E&C Cycle realities looming - Top-of-the-cycle backlog is about to run out, and concerns about embedded margin and T&Cs on new work, plus

diversification into low-value add wind farm installation. Heavy asset business and harder to extract value from its fleet in an oversupplied offshore

construction market.

Technip OUTPERFORM EUR 65 27% E&C EU bellwether stock - underappreciation of breadth of TEC's business mix and capabilities - deepwater is important, but multiple other avenues for

growth (shallow water, downstream, gas). FMC deal is defensive against a lackluster near-term market, but combination could disproportionately

benefit from its eventual recovery.

Tecnicas

Reunidas

UNDERPERFORM EUR 28 -14% E&C A strong, well-managed and broad-based contracting business with a largely solid execution track record. However, valuation looks challenged,

particularly against weak near-term order intake trends. We prefer PFC.

Wood Group OUTPERFORM GBp 850 23% EPCM Mispriced quality – Well managed, best-in-class engineering and maintenance franchises, robust balance sheet, and more geared into early cycle

recovery than the market appreciates as catch-up spend on deferred maintenance / brownfield modification bolsters growth in Engineering and US

Unconventionals. Restructuring and streamlined structure increase leverage to growing volumes.

Source: Company data, Credit Suisse estimates; ECM – engineering, project management, consultancy, and maintenance. E&C – engineering and construction

19 September 2016


Preferred stocks

Petrofac, Outperform, TP GBp1100. We think PFC has made mistakes – strategic and

operational – and a weak H116 book-to-bill hasn’t helped near-term sentiment. However,

PFC is retreating back to a high-quality core E&C business, and a well-underpinned 2017

P&L sees PFC trading at a ~40% 2017E PE discount to closest comp TRE. This looks

compelling in itself, but we see considerable optionality as PFC disposes of its non-core

assets. An improving book-to-bill trend in H216 and 2017 should also bolster confidence in

2018 and beyond. In addition, PFC has the highest dividend yield in our coverage at ~6%.

Wood Group, Outperform, TP GBp850. We view Wood Group as a best-in-class

engineering and maintenance franchise with strong management and a robust balance

sheet. It provides investors with early-cycle exposure to US Unconventionals and

engineering studies, while reorganisation improves efficiency and business development

prospects. Furthermore, the valuation – 2017E/18E PE of 13x/11x – looks undemanding

against recovery prospects, and we view the ~4% dividend yield as solid.

Least preferred stocks

Subsea 7, Underperform, TP NOK75. SUBC is an excellent project manager, but,

despite fleet rationalisation and reorganisation, it remains an inherently capital-intensive

business. We believe it will be challenging to extract value from an asset base that

became increasingly commoditised through the last cycle. Positive book-to-bill and 2016

earnings upgrades have driven significant share price outperformance ytd, but we think

the situation is likely to change materially as positive cycle backlog finally unwinds in Q3.

AMEC Foster Wheeler, Underperform, TP GBp450. We believe sentiment is improving

towards AMFW under the leadership of new CEO Jon Lewis. Restructuring stories are

often good stocks to own, and we expect a positive message on costs at the CMD in

November. However, we think the market should be braced for further backlog

deterioration, material revenue declines in 2017, and a strategy to chase lower-quality

(construction) revenue streams. Disposals should relieve some balance sheet pressure

but are unlikely to de-lever AMFW to an optimum capital structure, in our view. The 2017E

EV/EBITDA of nearly 10x, a premium to peers, and versus historical multiples, suggests

that the stock has got ahead of itself. We believe the market underestimates business

headwinds into 2017.

Figure 103: Pan-European oilfield services stock selection





Technip (TECF.PA), TP EUR65 Core Labs* (CLB.N), TP USD115 Seadrill* (SDRL.N), TP USD1.00

PGS (PGS.OL), TP NOK27 Tecnicas Reuindas (TRE.MC), TP EUR28

Source: Credit Suisse Research * denotes co-covered stocks. PFC, WG, TEC, PGS, SPM, HTG, AKSO, SUBC, AMFW, and TRE covered by Phillip Lindsay, SBOE and CGG covered by Gregory Brown, CLB and SDRL covered by Gregory Lewis]

Top US pick

U.S. Silica (Outperform, TP USD49.00, a US Focus List stock). This cycle, sand is the

most leveraged OFS sub-segment to the recovery in production and activity in North

America. We expect sand demand in 2018 to eclipse the demand level of 2014. Our rig

count forecast, which drives our sand model, is ~25% below the upper end of the

consensus range. This implies further potential upside for sales, margins, and the stock

price to the degree our forecast proves conservative. Sand stocks should replace land

drillers this cycle as the most levered to a recovery in NAM activity. Our colleague James

Wicklund covers the stock.

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Figure 104: Pan-European OFS Valuation Summary

Company Ticker Rating Analyst Share YTD Target Pot. Up / Div M.Cap P/E EV/EBITDA EV/Sales P/B

Price Perf price Downside yield USD LC 16E 17E 18E 16E 17E 18E 16E 17E 18E 16E 17E 18E

Aker Solutions AKSOL.OL NEUTRAL Phillip Lindsay NKr 36.54 21% NOK 35 -4% 1204 9941 16.7 41.1 46.8 6.0 7.4 7.7 0.4 0.5 0.5 1.4 1.4 1.4

Core Laboratories CLB.N NEUTRAL Gregory Lewis USD 108.3 0% USD 115 6% 2% 4775 4775 71.9 48.1 33.4 44.4 34.1 25.7 8.3 7.5 6.7 12.0 12.1 10.8

Hunting HTG.L NEUTRAL Phillip Lindsay GBp 415.5 22% GBp 500 20% 818 623 n/a n/a 20.4 n/a 16.5 8.6 1.9 1.5 1.2 1.0 1.0 1.0

Schoeller Bleckmann SBOE.VI OUTPERFORM Gregory Brown EUR 52.65 4% EUR 70 33% 1% 945 842 n/a 51.8 19.9 n/a 11.7 7.5 4.8 3.3 2.5 2.0 2.0 1.8

Equipment 12% 14% 1% 16.7 46.4 29.0 6.0 11.9 7.9 2.4 1.8 1.4 1.5 1.5 1.4

Petrofac PFC.L OUTPERFORM Phillip Lindsay GBp 808.0 -9% GBp 1100 36% 6% 3692 2807 11.4 7.8 7.5 6.9 5.3 5.5 0.6 0.6 0.6 2.8 2.3 2.0

Saipem SPMI.MI NEUTRAL Phillip Lindsay EUR 0.38 -60% EUR 0.45 20% 4271 3805 15.0 14.2 14.6 4.2 4.2 4.1 0.5 0.5 0.5 0.5 0.5 0.5

Subsea 7 SUBC.OL UNDERPERFORM Phillip Lindsay NKr 84.70 44% NOK 75 -11% 3357 28039 9.9 50.9 33.0 3.4 6.5 6.0 0.9 0.9 0.9 0.6 0.6 0.6

Technip TECF.PA OUTPERFORM Phillip Lindsay EUR 51.30 12% EUR 65 27% 4% 7043 6276 10.9 15.7 18.0 3.7 4.8 5.3 0.4 0.5 0.5 1.4 1.3 1.3

Tecnicas Reunidas TRE.MC UNDERPERFORM Phillip Lindsay EUR 32.50 -7% EUR 28 -14% 4% 2038 1816 12.7 13.0 12.3 6.5 6.6 6.3 0.3 0.3 0.3 3.5 3.1 2.8

Engineering & Construction -4% 11% 5% 12.0 20.3 17.1 5.1 5.7 5.7 0.6 0.6 0.6 1.8 1.6 1.4

AMEC Foster Wheeler AMFW.L UNDERPERFORM Phillip Lindsay GBp 531.0 24% GBp 450 -15% 4% 2735 2071 10.1 11.3 10.0 8.8 9.5 8.7 0.6 0.6 0.6 1.7 1.7 1.6

Wood Group WG.L OUTPERFORM Phillip Lindsay GBp 688.5 1% GBp 850 23% 4% 3465 2641 13.7 12.5 11.3 8.7 8.2 7.5 0.7 0.7 0.7 1.4 1.3 1.3

Engineering, Consultancy and Maintenance 12% 4% 4% 11.9 11.9 10.6 8.8 8.9 8.1 0.7 0.7 0.6 1.5 1.5 1.4

CGG GEPH.PA UNDERPERFORM Gregory Brown EUR 22.06 -46% EUR 17.5 -21% 548 481 n/a n/a n/a 8.0 5.6 4.3 2.1 1.9 1.7 0.3 0.4 0.5

PGS PGS.OL OUTPERFORM Phillip Lindsay NKr 16.60 -51% NOK 27 63% 482 4054 n/a n/a n/a 5.3 3.9 3.0 2.0 1.8 1.6 0.3 0.4 0.4

Seadrill SDRL.N UNDERPERFORM Gregory Lewis USD 2.15 -37% USD 1.0 -53% 1093 1093 2.2 n/a n/a 5.6 10.0 37.5 3.2 4.5 6.2 0.1 0.1 0.1

Seismic and Drilling -45% 3% 0% 2.2 n/a n/a 6.7 4.7 3.6 2.0 1.8 1.6 0.3 0.4 0.4

Pan Euro OFS -6% 8% 4% 11.4 24.2 19.4 6.2 7.6 6.3 1.3 1.1 1.0 1.4 1.3 1.3

Source: Company data, Credit Suisse estimates Prices as of 13th September 2016. Averages omit multiples deemed to be outliers (such as negative P/E)

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Figure 105: Credit Suisse estimates vs. consensus

Company Rating Currency CS EBITDA CS EBITDA vs Cons CS EPS CS EPS vs Cons

16E 17E 18E 16E 17E 18E 16E 17E 18E 16E 17E 18E

Aker Solutions NEUTRAL Nkr 1845 1481 1439 -4% -1% -13% 2.19 0.89 0.78 29% -1% -40%

Core Laboratories NEUTRAL US$ 113 148 196 -5% -8% -15% 1.51 2.25 3.25 -4% -3% -7%

Hunting NEUTRAL US$ -46 55 106 93% -5% 19% -0.49 0.04 0.27 15% 95% 66%

Schoeller Bleckmann OUTPERFORM € 3 74 115 -90% -4% 6% -1.92 1.02 2.65 23% -10% 8%

Equipment -2% -5% -1% 16% 20% 7%

Petrofac OUTPERFORM US$ 649 837 818 -14% -5% -3% 0.94 1.36 1.41 -8% 7% 14%

Saipem NEUTRAL € 1297 1226 1168 4% 9% -2% 0.03 0.03 0.03 4% 15% -4%

Subsea 7 UNDERPERFORM US$ 909 475 514 7% -9% -11% 1.04 0.20 0.31 8% -25% -14%

Technip OUTPERFORM € 1119 861 788 -4% -8% -13% 4.69 3.27 2.84 3% 5% -6%

Tecnicas Reunidas UNDERPERFORM € 203 199 210 2% -6% 3% 2.55 2.50 2.64 5% -2% 9%

Engineering & Construction -1% -4% -5% 2% 0% 0%

AMEC Foster Wheeler UNDERPERFORM £ 356 330 360 4% -7% -6% 52.6 47.1 53.0 4% -11% -10%

Wood Group OUTPERFORM US$ 436 462 504 5% 9% 9% 0.66 0.73 0.81 4% 11% 10%

Engineering, Consultancy and Maintenance 5% 1% 2% 4% 0% 0%

CGG UNDERPERFORM US$ 342 495 638 -26% -16% -9% -19.3 -4.56 -0.28 45% -28% -93%

PGS OUTPERFORM US$ 300 415 541 0% 10% 15% -0.90 -0.56 -0.06 12% 14% -43%

Seadrill UNDERPERFORM US$ 1760 984 262 -3% -11% -71% 0.97 -0.19 -1.40 -25% -378% 181%

Seismic and Drilling -10% -6% -22% 11% -7% -68%

Pan-European OFS -2% -4% -7% 8% -3% -8%

Source: Credit Suisse Research. Averages omits distortions (such as % change on low numbers in absolute terms)

19 September 2016


Figure 106: 2017E blue sky / grey sky comparison

2017E

EBITDA EV/EBITDA EPS P/E

Base Blue Sky Grey Sky Base Blue Sky Grey Sky Base Blue Sky Grey Sky Base Blue Sky Grey Sky

AKSO 1481 1881 1136 7.4 5.9 10.4 0.9 1.6 0.3 41.1 23.2 114.7

AMFW 330.2 368.1 272 9.5 7.8 11.6 47.4 59.7 35.9 11.3 8.9 14.8

CGG 495 542 453 5.6 5.0 5.9 -4.6 -4.2 -4.9 -5.4 -6.0 -5.1

HTG 55 78 40 16.5 11.6 21.4 0.0 0.1 0.0 134.0 49.2 -1111.3

PFC 837 1018 678 5.3 4.2 6.9 1.4 1.7 1.0 7.8 6.0 10.6

PGS 415 457 376 4.0 3.8 4.7 -0.9 -0.5 -0.6 -3.6 -4.2 -4.0

SPM 1226 1521 971 4.2 3.4 5.7 0.0 0.0 0.0 14.2 10.1 30.0

SBO 74 90 59 11.7 10.5 16.0 1.0 1.5 0.6 51.8 39.0 99.0

SUBC 475 554 405 6.5 5.7 8.2 0.2 0.3 0.1 50.9 35.3 102.0

TEC 861 1102 680 4.8 4.3 7.7 3.3 4.4 2.3 15.7 11.9 22.8

TRE 199 261 134 6.6 4.7 9.8 2.5 3.5 1.7 13.0 9.3 19.1

WG 462 601 349 8.3 6.4 11.4 0.7 1.0 0.5 12.5 9.4 17.5

Source: Credit Suisse estimates, prices as of 13th September. Exchange rates used: EUR/USD1.12, GBP/USD 1.37, NOK/USD0.12

Figure 107: 2018E blue sky / grey sky comparison

2018E

EBITDA EV/EBITDA EPS P/E

Base Blue Sky Grey Sky Base Blue Sky Grey Sky Base Blue Sky Grey Sky Base Blue Sky Grey Sky

AKSO 1439 1947 1030 7.7 5.3 11.2 0.8 1.5 0.2 46.8 23.7 184.1

AMFW 360 399.8 299.5 8.7 7.1 10.6 53.3 66.1 41.3 10.0 8.0 12.9

CGG 638 714 571 4.3 3.8 4.7 -0.3 0.5 -0.9 -88.5 51.5 -28.4

HTG 106 148 75 8.6 5.7 10.4 0.3 0.4 0.2 20.4 13.0 32.3

PFC 818 1058 623 5.5 3.9 7.6 1.4 1.9 1.0 7.5 5.4 10.9

PGS 541 622 469 3.1 2.5 3.6 -0.6 0.0 -0.1 -35.1 -98.2 -27.3

SPM 1168 1553 859 4.1 3.0 6.2 0.0 0.0 0.0 14.6 9.6 34.8

SBO 115 143 91 7.5 6.3 10.2 2.7 3.5 1.9 19.9 17.0 31.0

SUBC 514 622 422 6.0 4.9 7.9 0.3 0.5 0.2 33.0 24.0 56.9

TEC 788 1074 583 5.3 4.2 9.3 2.8 4.1 1.8 18.0 12.7 29.0

TRE 210 294 133 6.3 4.1 10.5 2.6 3.9 1.7 12.3 8.3 19.4

WG 504 703 353 7.6 5.1 11.1 0.8 1.2 0.5 11.3 7.9 17.0

Source: Credit Suisse estimates, prices as of 13th September. Exchange rates used: EUR/USD1.12, GBP/USD 1.37, NOK/USD0.12

19 September 2016


Europe/Norway Oil & Gas Equipment & Services

Aker Solutions (AKSOL.OL) Rating NEUTRAL [V] Price (13 Sep 16, Nkr) 36.54 Target price (Nkr) 35.00 Market Cap (Nkr m) 9,940.5 Enterprise value (Nkr m) 11,019.4 *Stock ratings are relative to the coverage universe in each

analyst's or each team's respective sector.

¹Target price is for 12 months.

[V] = Stock Considered Volatile (see Disclosure Appendix)

Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Headwinds and tailwinds

■ Initiate with Neutral, NOK35 TP: AKSO is one of most improved companies

operationally in our coverage, and the one driving the most cultural change

since CEO Araujo’s appointment in July 2014. Its past reputation for

execution problems and profit warnings is being replaced gradually by one of

solid execution and consistent performance. Near-term P&L is cushioned

from the full force of the downturn by good execution of large subsea projects

(notably Kaombo) awarded in the last cycle, and unsustainably high

engineering margins. A recovering MMO market in Norway provides further

P&L support from 2017, but we see growing headwinds elsewhere across the

group, notably in Subsea.

■ Within Subsea, we think AKSO has developed some differentiated strategic

alliances (notably with BHI and ABB) and technologies (ie Powerjump).

However, we are concerned about Subsea volumes/margins in 2018/19,

given relatively weak recovery prospects for subsea markets, AKSO’s

strategic positioning, and under-absorption of an expanded fixed cost base.

■ Catalysts: We see pent-up demand in Norwegian MMO and think AKSO’s

competitive position is strong, despite losing some share. This should drive

an improving book-to-bill. Subsea award potential is notable in Norway, but

generating, and sustaining, a positive book-to-bill through H216 and 2017

looks challenging given the weak outlook for subsea markets. We also note

the Norwegian government lock-up expires in June 2017.

■ Valuation: We derive a NOK35 TP from an equally weighted combination of

SOTP and DCF. AKSO is a story of headwinds (Subsea) and tailwinds

(MMO). We see AKSO trading on an EV/EBITDA of around 8x in 2017E/18E

with 2018 our view of trough, but AKSO would require significant volume

growth (given high D&A) to compress an exceptionally high PE of ~50x in

2018E. However, deepwater markets look challenged at least until 2018 and

we believe it’s too early to buy AKSO for a recovery.

Share price performance

The price relative chart measures performance against the

OBX INDEX which closed at 532.5 on 13/09/16

On 13/09/16 the spot exchange rate was Nkr9.28/Eu 1.-

Eu.89/US$1

Performance 1M 3M 12M Absolute (%) 1.0 11.1 19.3 Relative (%) 3.5 6.8 15.5

Financial and valuation metrics

Year 12/15A 12/16E 12/17E 12/18E Revenue (Nkr m) 31,896 25,815 23,825 23,334 EBITDAX (Nkr m) 1841.0 1845.4 1481.5 1439.3 Adjusted net income (Nkr m) 1072.8 595.7 241.9 212.6 CS EPS (adj.) (Nkr) 3.94 2.19 0.89 0.78 Prev. EPS (Nkr) ROIC avg (%) 9.8 8.5 4.3 4.0 P/E (adj.) (x) 9.3 16.7 41.1 46.8 P/E rel. (%) 72.9 104.0 314.5 422.1 EV/EBITDAX (x) 5.3 6.3 7.8 7.7

Dividend (12/16E, Nkr) 0.00 Net debt/equity (12/16E,%) 22.4 Dividend yield (12/16E,%) 0.0 Net debt (12/16E, Nkr m) 1,599.1 BV/share (12/16E, Nkr) 25.4 IC (12/16E, Nkr m) 8,736.7 Free float (%) 52.5 EV/IC (12/16E, (x) 1.3 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Aker Solutions (AKSOL.OL)

Price (13 Sep 2016): Nkr36.54; Rating: NEUTRAL [V]; Target Price: Nkr35.00; Analyst: Phillip Lindsay

Income statement (Nkr m) 12/15A 12/16E 12/17E 12/18E

Revenue 31,896 25,815 23,825 23,334 EBITDA 1,841 1,845 1,481 1,439 Depr. & amort. (719) (859) (897) (894) EBIT 1,122 987 585 545 Net interest exp. (272) (225) (225) (230) Associates 0 0 0 0 PBT 685 761 360 315 Income taxes (302) (263) (124) (109) Profit after tax 383 499 236 206 Minorities 8 8 6 6 Preferred dividends - - - - Associates & other 682 89 0 0 Net profit 1,073 596 242 213 Other NPAT adjustments (682) (89) 0 0 Reported net income 391 507 242 213

Cash flow (Nkr m) 12/15A 12/16E 12/17E 12/18E

EBIT 1,122 987 585 545 Net interest (212) 0 0 0 Cash taxes paid (742) 0 0 0 Change in working capital 1,022 (2,466) (584) 35 Other cash and non-cash items 581 633 672 665 Cash flow from operations 1,771 (847) 672 1,244 CAPEX (841) (710) (596) (583) Free cashflow to the firm 1,025 (1,450) 115 699 Acquisitions (3) 0 0 0 Divestments 3 0 0 0 Other investment/(outflows) (457) (207) (119) (117) Cash flow from investments (1,298) (916) (715) (700) Net share issue/(repurchase) (6) 0 0 0 Dividends paid (394) 0 0 0 Issuance (retirement) of debt 98 0 0 0 Cashflow from financing (323) 0 0 0 Changes in net cash/debt 653 (1,763) (42) 544 Net debt at start 489 (164) 1,599 1,641 Change in net debt (653) 1,763 42 (544) Net debt at end (164) 1,599 1,641 1,097

Balance sheet (Nkr m) 12/15A 12/16E 12/17E 12/18E

Assets Total current assets 17,191 15,156 14,966 15,273 Total assets 27,728 25,751 25,378 25,492 Liabilities Total current liabilities 17,078 14,594 13,980 13,881 Total liabilities 21,097 18,613 17,999 17,900 Total equity and liabilities 27,728 25,751 25,378 25,492

Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 272 272 272 272 CS EPS (adj.) (Nkr) 3.94 2.19 0.89 0.78 Prev. EPS (Nkr) Dividend (Nkr) 0.00 0.00 0.00 0.00 Free cash flow per share (Nkr) 3.42 (5.72) 0.28 2.43

Valuation 12/15A 12/16E 12/17E 12/18E

EV/Sales (x) 0.3 0.4 0.5 0.5 EV/EBITDA (x) 5.3 6.3 7.8 7.7 EV/EBIT (x) 8.7 11.7 19.8 20.3 Dividend yield (%) 0.00 0.00 0.00 0.00 P/E (x) 9.3 16.7 41.1 46.8

ROE analysis (%) 12/15A 12/16E 12/17E 12/18E

ROE (%) 17.8 9.0 3.4 2.9 ROIC (avg.) (%) 9.8 8.5 4.3 4.0

Credit ratios 12/15A 12/16E 12/17E 12/18E

Net debt/equity (%) (2.5) 22.4 22.2 14.5 Dividend payout ratio (%) 0.0 0.0 0.0 0.0

Company Background

Norwegian based provider of products, systems and services, primarily to the offshore oil and gas industry. Aker Solutions is a leading manufacturer of subsea trees and umbilicals as well as an international engineering house and maintenance provider.

Blue/Grey Sky Scenario

Our Blue Sky Scenario (Nkr) 62.00

We assume Subsea blue sky revenues +7.5% from base case, with margins +1% for 2017 and beyond (we dilute impact for 2016). For Field Development, we assume blue sky revenues +5.0% and margins +0.5% from base case for 2017 and beyond (we dilute the

impact for 2016). In our SOTP, we assume Subsea / Field Development multiples 1.5 / 1.0pts higher than our base case, whereas the DCF assumes +0.25% vs base case for long-term growth

Our Grey Sky Scenario (Nkr) 17.00

We assume Subsea grey sky revenues -7.5% from base case, with margins -1% for 2017 and beyond (we dilute impact for 2016). For Field Development, we assume grey sky revenues -5.0% and margins -0.5% from base case for 2017 and beyond (we dilute the impact for 2016). In our SOTP, we assume Subsea / Field Development multiples 1.5 / 1.0pts lower than base case, whereas the DCF assumes -0.25% lower vs base case for long-term growth


The price relative chart measures performance against the OBX INDEX which

closed at 532.5 on 13/09/16

On 13/09/16 the spot exchange rate was Nkr9.28/Eu 1.- Eu.89/US$1

Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates

19 September 2016


Key charts

Figure 108: Deepwater EPIC capex by region Figure 109: Subsea order forecast



Figure 110: Subsea revenue vs. EBITDA % Figure 111: Field Design revenue vs. EBITDA %

Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates

Figure 112: Subsea order intake vs. book to bill Figure 113: Field Design order intake vs. book to bill

Source: Company data Source: Company data

375 286 407 543 230 15335

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19 September 2016


Aker Solutions (AKSO)

Divisional review: Subsea – Peak equipment delivery on Kaombo is this year, with

delivery declining through 2017. This trend continues in 2018 but a pick-up in associated

services / commissioning activity should provide a cushion to lower equipment deliveries.

The other major project of note in the portfolio, Moho Nord, will see deliveries wind down

materially in 2016. We think both projects were awarded with favourable terms and

conditions and should be supportive of near-term margins as projects wind down,

contingencies are released (assuming good execution) and services volumes increase.

We think AKSO’s best opportunities for new work lie in Norway (Johan Castberg, and

Snorre 2040). Brazil volumes should remain steady through 2017, but we are concerned

over what form any possible renewal of its existing frame agreement with Petrobras will

take (current deal expires H1 2018). The Umbilicals business looks well placed through

2018 given strong visibility at the Moss plant provided by the Zohr contract and a relatively

buoyant US Offshore market. New technologies, such as PowerJump, and Vectus 6.0

have medium-term potential, but are unlikely to be pivotal near term.

Divisional review: Field Development – AKSO has grown its book with other oil

companies (BP and ConocoPhillips) in and outside of Norway after losing its main supplier

status for maintenance and modifications work with Statoil. The MMO business has

undergone significant restructuring in recent years, but MMO markets should bottom out in

2016 with growth in 2017, on our estimates. We think brownfield economics are sufficiently

attractive to drive a pick-up in demand from here and think AKSO is well placed for a

range of modifications, hook-up and commissioning work. The Engineering business

benefits from peak man-hours on Johan Sverdrup in 2016, dropping off somewhat in 2017.

However, despite extensive office rationalisation, we think current margins are

unsustainable. On business development, we think AKSO’s best opportunities lie in Asia,

the North Sea and the Middle East.

Order backlog and new order potential – Order backlog is nearly 30% below the 2014

peak, equating to around 1.35x our 2016 revenue forecasts. Subsea book-to-bill has been

running at 0.4-0.5x for the past six quarters, and we see continued deterioration in Subsea

backlog through 2017 as large contracts like Kaombo unwind. The main project award

opportunities we see for Subsea are currently in Norway. Field Development appears to

be in a better place with book-to-bill trending above 1x for the past six quarters cumulative

and the outlook improving for project award activity, notably in the Norwegian MMO

market

Balance sheet and dividend – AKSO’s volatile cash flow can largely be attributable to a

disproportionately large Subsea contract (Kaombo). Advance and milestone payments

created an advantageous 2015 year-end net cash position. This unwinds materially

through 2016E leading to a net debt-to-EBITDA position of close to 1x, a position that

could worsen slightly in 2017, on our estimates. Capex is being cut back materially – we

assume capex/depreciation at or below 1x in 2016-18E – and AKSO is not paying a

dividend through the downturn.

Forecasts – Our sales/EBITDA forecasts are broadly in line with consensus for 2016/17.

We are most different for 2018 – our sales/EBITDA forecasts are 5%/12% below

consensus, respectively. We believe H2 2016/FY 2017 order intake in Subsea will not be

sufficient to deliver the P&L growth that the market currently assumes. High D&A

magnifies the impact on EBIT/EPS where we are more than 30% below consensus on

both measures.

Valuation and view – We initiate on AKSO with a Neutral rating and a target price of

NOK35. We believe the softness and the duration of the Subsea market downturn are

underestimated by the market. On our base-case forecasts, we see AKSO trading on an

EV/EBITDA of around 8x in 2017/18E with 2018E our view of trough. However, given high

19 September 2016


D&A, relatively modest movements in EBITDA are exacerbated at the bottom line – the PE

for 2017E/18E is 42-47x. While this has potential to move down materially as the Subsea

recovery cycle takes hold (towards the end of the decade, we think), we think it’s too early

to buy AKSO for recovery. We expect the stock to become more interesting as the timing

of the Subsea cycle becomes clearer, and as the Norwegian government lock-up expires.

We derive our target price from equally weighted DCF and SOTP methodologies, detailed

in the below table.

Blue sky / Grey sky scenario

■ In Subsea, we assume blue / grey sky revenues +/- 7.5% from our base-case scenario

with margins +/- 1% for 2017E and beyond (we dilute the impact for 2016;)

■ For Field Development, we assume blue / grey sky revenues +/- 5.0% and margins

+/- 0.5% from our base-case scenario for 2017 and beyond (we dilute the impact for

2016);

■ In our SOTP, we assume Subsea / field Development multiples 1.5 / 1.0pts higher /

lower than our base case, whereas our DCF assumes +/- 0.25% for long-term growth.

Figure 114: Valuation summary – Aker Solutions

SOTP (NOKm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV

EBITDA Sales Multiple Implied 2017E 2018E

Subsea 978 12225 8.5 0.68 8313 7804

Field Design 703 11725 6.0 0.36 4221 4498

Eliminations -200 -125 7.3 0 -1450 -1500

Total 1481 23825 7.3 0.7 11084 10802

net cash / (debt) -1524 -980

Associates / minorities 234 234

Implied market value 9793 10056

No. of shares (diluted) 272 272

Implied value per share (NOK) 36.00 37.00

DCF (NOKm)

Assumptions: Beta Risk WACC LT Growth 2017E 2018E

premium

1.50 5.5% 8.75% 2%

EV 9978 10751

Net (debt) / cash -1524 -980


MV 8687 10004

Implied value per share, NOK 31.93 36.77

Valuation summary (NOK/share) Average 2017E 2018E

SOTP 36.48 36.00 36.96

DCF 34.35 31.93 36.77

Overall average (equally weighted) 35

Blue Sky / Grey Sky

Blue sky valuation % diff to base Average 2017E 2018E

SOTP 66% 60.73 57.82 63.65

DCF 85% 63.53 59.66 67.41

Overall average (equally weighted) 75% 62

Grey sky valuation % diff to base Average 2017E 2018E

SOTP -48% 18.94 19.62 18.25

DCF -53% 16.04 14.53 17.55

Overall average (equally weighted) -51% 17

19 September 2016


Credit Suisse HOLT®

We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate

performance and valuation framework.

The charts below reflect our forecasts for sales, margins and returns. The extended 10

year forecast allows us to express our view of the near term recovery and factor in the

next cycle within this business. Based on our assumptions, HOLT calculates returns to

decline from 9.3% in 2016 to 7.7% by 2021. Thereafter we capture the next cycle and

forecast returns to dip to 5.1% in 2022 and recover to 7.9% by 2025.

Beyond the explicit forecast window, HOLT assumes the CFROI and discount rate fade to

6%, while asset growth fades to 2.5% - incorporating the economic reality of competition

which causes the CFROI and growth rate to regress to the mean. For comparability, we

group Aker Solutions, Schoeller Bleckmann, and Hunting into an “Oil and Gas Equipment”

cohort and apply a long term average discount rate of 5.6% for each.

The above assumptions suggest a HOLT warranted value of NOK 32.19, which is close to

our target price of NOK35.

19 September 2016


Figure 115: Aker Solutions in HOLT


Current Price: NOK 36.54 Warranted Price: NOK 32.19 Valuation date: 13-Sep-16

Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E

NOK -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % 13.2 -3.3 -19.1 -7.7 -2.1

EBITDA Mgn, % 8.6 5.8 7.1 6.2 6.2

Asset Turns, x 2.20 1.8 1.5 1.3 1.2

CFROI®, % 17.0 9.3 9.3 5.7 4.6

Disc Rate, % 5.6 5.9 5.6 5.6 5.6

Asset Grth, % -9.5 18.0 -5.5 0.1 2.8

Value/Cost, x 1.8 1.5 1.6 1.5 1.4

Economic PE, x 10.8 15.9 16.9 26.4 30.9

Leverage, % 35.4 45.1 44.4 43.4 43.7

HO

LT

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C

red

it S

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ata

AKER SOLUTIONS ASA (AKSO)

EB

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-2.0% -94% -90% -83% -74%

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0.0% -39% -26% -12% 5%

104%

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2.0% 18% 36% 56% 79%

More than

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downside

Within 10%More than

10% upside

Source: Credit Suisse HOLT®. CFROI and HOLTare trademarks or registered trademarks of Credit Suisse Group AG or its affiliates in the United States and other countries.

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19 September 2016


Figure 116: Summary financials – Aker Solutions

Divisional (NOKm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Subsea Revenue 19293 19101 15281 12225 10269 11039 12419

growth 23% -1% -20% -20% -16% 8% 13%

EBITDA 2058 1778 1406 978 821 993 1180

growth 56% -14% -21% -30% -16% 21% 19%

margin 10.7% 9.3% 9.2% 8.0% 8.0% 9.0% 9.5%

Field Design Revenue 13710 12920 10659 11725 13191 15169 16686

growth 10% -6% -18% 10% 13% 15% 10%

EBITDA 868 543 640 703 818 971 1085

growth -9% -37% 18% 10% 16% 19% 12%

margin 6.3% 4.2% 6.0% 6.0% 6.2% 6.4% 6.5%

Other / Eliminations Revenue -31 -125 -125 -125 -125 -125 -125

EBITDA -252 -480 -200 -200 -200 -200 -200

P&L (NOKm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 32972 31896 25815 23825 23334 26083 28980

growth 13% -3% -19% -8% -2% 12% 11%

EBITDA 2674 1841 1845 1481 1439 1764 2064

growth 29% -31% 0% -20% -3% 23% 17%

margin 8.1% 5.8% 7.1% 6.2% 6.2% 6.8% 7.1%

EBITDA (ex-special items) 2835 2638 1885 1481 1439 1764 2064

D&A -590 -719 -859 -897 -894 -894 -914

EBIT 2084 1122 987 585 545 870 1151

margin 6.3% 3.5% 3.8% 2.5% 2.3% 3.3% 4.0%

EBIT (ex special items) 2243 1918 1076 585 545 870 1151

Net finance expense -149 -272 -225 -225 -230 -224 -216

Other items -277 -961 -90 0 0 0 0

Adj pre-tax profit 1817 685 761 360 315 646 934

Tax -516 -302 -263 -124 -109 -223 -322

Effective tax rate 28% 44% 35% 35% 35% 35% 35%

Minority interests -20 8 8 6 6 8 9

Net profit 1281 391 507 242 213 431 621

Adj net profit 1407 1073 596 242 213 431 621

Diluted shares 272 272 272 272 272 272 272

EPS (CS, Adj) NOK 5.17 3.94 2.19 0.89 0.78 1.58 2.28

EPS (IFRS) 4.71 1.44 1.86 0.89 0.78 1.58 2.28

DPS 1.45 0.00 0.00 0.00 0.00 0.55 0.80


19 September 2016


Figure 117: Cash flow and balance sheet – Aker Solutions

Cash flow (NOKm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Profit for the period 1300 383 499 236 206 423 612

Operating cash flows 733 366 1121 1021 1003 1117 1236

Working capital 536 1022 -2466 -584 35 -236 -229

Net cashflow from operations 2569 1771 -847 672 1244 1304 1619

Capex (net, inc intangible) -1370 -1290 -916 -715 -700 -809 -927

Free Cash Flow 1199 481 -1763 -42 544 496 691

M&A spend (net) -51 -3 0 0 0 0 0

Other investing cash flows 53 -5 0 0 0 0 0

Net cash flow from investing activities -1368 -1298 -916 -715 -700 -809 -927

Change in borrowings 34 98 0 0 0 0 0

DPS cash cost -129 -394 0 0 0 0 -151

Other financing cashflows -2734 -27 0 0 0 0 0

Net cash flow from financing -2829 -323 0 0 0 0 -151

FX 429 211 0 0 0 0 0

Net cash flow -1199 361 -1763 -42 544 496 541

Cash and cash equivalents 3229 3590 1827 1785 2329 2825 3365

Net cash / (debt) -407 164 -1599 -1641 -1097 -601 -61

Balance Sheet (NOKm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Property, plant and equipment 3603 3962 3964 3842 3722 3666 3683

Intangible assets 5763 6207 6262 6203 6129 6099 6095

Other non-current assets 407 368 368 368 368 368 368

Total Non-Current Assets 9773 10537 10595 10413 10218 10132 10146

Current operating assets 12904 11799 11549 11409 11174 12490 13878

Other current assets 1375 1530 1508 1500 1498 1508 1519


Total Current Assets 17618 17191 15156 14966 15273 17096 19034

Total Assets 27391 27728 25751 25378 25492 27228 29180

Pensions 670 572 572 572 572 572 572

Non-current borrowings 3154 3137 3137 3137 3137 3137 3137

Other non-current liabilities 721 310 310 310 310 310 310

Total non-current liabilities 4545 4019 4019 4019 4019 4019 4019

Current operating liabilities 13657 13516 10779 10048 9846 10936 12104

Current borrowings 674 561 561 561 561 561 561

Other Current Liabilities 2622 3001 3254 3371 3473 3689 4003

Total Current Liabilities 16953 17078 14594 13980 13881 15186 16668

Equity 5677 6397 6904 7146 7358 7789 8259

Minority interest 216 234 234 234 234 234 234

Total shareholders equity 5893 6631 7138 7380 7592 8023 8493

Shareholders Equity and Liabilities 27391 27728 25751 25378 25492 27228 29180


19 September 2016


PEERs

PEERs is a global database that captures unique information about companies within the

Credit Suisse coverage universe based on their relationships with other companies – their

customers, suppliers and competitors. The database is built from our research analysts’

insight regarding these relationships. Credit Suisse covers over 3,000 companies globally.

These companies form the core of the PEERs database, but it also includes relationships

on stocks that are not under coverage.

Figure 118: Aker Solutions in PEERs

Source: Credit Suisse PEERs

19 September 2016


Europe/United Kingdom Oil & Gas Equipment & Services

Amec Foster Wheeler (AMFW.L) Rating UNDERPERFORM Price (13 Sep 16, p) 531.00 Target price (p) 450.00 Market Cap (£ m) 2,070.8 Enterprise value (£ m) 3,136.3 *Stock ratings are relative to the coverage universe in each



Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Too much, too soon

■ Initiate with Underperform, TP 450p: New CEO Jon Lewis brings a

welcome new style leadership to AMFW, with swift and effective action thus

far in his three-month tenure, and scope for more to come at the mid-

November CMD. However, investors should not underestimate the scale of

the challenges ahead – topline pressures are significant into 2017, and

changing business mix is dilutive to margins. The restructuring will provide

some cushioning, but business development and system improvement

initiatives will take time to bear fruit. The strategy to grow into lower-margin

construction also dilutes earnings quality.

■ Investment case: Culturally, we expect AMFW to undergo a marked change

– Lewis is likely to instill far greater operational discipline and accountability,

and a more collegiate and commercial organisation should evolve over time.

But AMFW looks unlikely to change fundamentally – its diverse multi-sector

approach will likely remain, and, as in the past, AMFW is likely to be unable

to keep pace with more focused oil & gas peers as cycle conditions improve.

Furthermore, we do not believe the £500m disposal programme alone can

drive AMFW to an optimum capital structure in 2017.

■ Catalysts: The mid-November CMD should deliver a clear strategy,

restructuring plans and financial goals. The disposal of GPG should be an H2

event, with other disposals to follow in H117. Any meaningful contract awards

and commentary from key customers and competitors are key catalysts.

■ Valuation: We value AMFW at 450p using an equally weighted combination

of SOTP and DCF. While we expect the CMD to deliver an extensive

restructuring programme, we think weak top-line trends will be difficult to

reverse and future mix looks dilutive. The non-core asset fire sale is unlikely

to deliver optimum value and does not de-lever the balance sheet sufficiently.

Current EV/EBITDA valuations suggest that too much is priced in too early.



FTSE ALL SHARE INDEX which closed at 3643.4 on

13/09/16

On 13/09/16 the spot exchange rate was £.85/Eu 1.-

Eu.89/US$1

Performance 1M 3M 12M Absolute (%) 2.6 30.4 -31.1 Relative (%) 5.5 18.0 -39.6


Year 12/15A 12/16E 12/17E 12/18E Revenue (£ m) 5,455 5,298 4,928 5,052 EBITDAX (£ m) 400.0 355.5 330.2 360.0 Pre-tax profit adjusted (£ m) 334.0 259.6 235.7 265.2 CS EPS (adj.) (p) 67.74 52.55 47.11 52.99 Prev. EPS (p) ROIC avg (%) 13.1 18.0 11.8 12.7 P/E (adj.) (x) 7.8 10.1 11.3 10.0 P/E rel. (%) 46.4 56.8 73.4 73.6 EV/EBITDAX (x) 7.6 8.9 9.5 8.7

Dividend (12/16E, p) 21.5 Dividend yield (12/16E, %) 4.0 Net debt (12/16E, £ m) 1,100.0 IC (12/16E, £ m) 2,341.4 BV/share (12/16E, £) 3.2 Current WACC (%) EV/GIC (12/15A, (x) 1.2 Number of shares (m) 390.0 Free float (%) 98.2 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Amec Foster Wheeler (AMFW.L)

Price (13 Sep 2016): 531.00p; Rating: UNDERPERFORM; Target Price: 450.00p; Analyst: Phillip Lindsay

Income statement (£ m) 12/15A 12/16E 12/17E 12/18E

Revenue 5,455 5,298 4,928 5,052 EBITDA 400 356 330 360 Depr. & amort. (155) (155) (153) (154) EBIT 374 330 307 336 Net interest exp. (48) (71) (71) (71) Associates 28 6 2 2 PBT 334 260 236 265 Income taxes (18) 89 (25) (32) Profit after tax 316 349 211 233 Minorities 1 1 1 1 Preferred dividends - - - - Associates & other (56) (147) (30) (30) Net profit 261 202 182 204 Other NPAT adjustments (517) (487) (101) (101) Reported net income (256) (285) 81 103

Cash flow (£ m) 12/15A 12/16E 12/17E 12/18E

EBIT 374 330 307 336 Net interest (48) (71) (71) (71) Cash taxes paid (79) (57) (54) (61) Change in working capital (42) 28 11 (25) Other cash and non-cash items (64) (201) (54) (54) Cash flow from operations 141 30 138 125 CAPEX (15) (11) (10) (10) Free cashflow to the firm 129 21 131 117 Acquisitions (6) 0 0 0 Divestments 11 0 0 0 Other investment/(outflows) 57 (36) (19) (19) Cash flow from investments 47 (47) (29) (29) Net share issue/(repurchase) 6 0 0 0 Dividends paid (167) (82) (79) (75) Issuance (retirement) of debt (75) 0 0 0 Cashflow from financing (319) (100) (79) (75) Changes in net cash/debt (159) (117) 31 21 Net debt at start 824 983 1,100 1,069 Change in net debt 159 117 (31) (21) Net debt at end 983 1,100 1,069 1,049

Balance sheet (£ m) 12/15A 12/16E 12/17E 12/18E


Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 385 385 385 385 CS EPS (adj.) (p) 67.74 52.55 47.11 52.99 Prev. EPS (p) Dividend (p) 29.00 21.50 18.84 21.20 Free cash flow per share (p) 32.70 4.93 33.37 29.92

Valuation matrics (%) 12/15A 12/16E 12/17E 12/18E

Dividend yield (%) 5.5 4.0 3.5 4.0 FCF yield (%) 6.3 1.0 6.4 5.7 EV/EBITDAX (x) 7.6 8.9 9.5 8.7 P/E (x) 7.8 10.1 11.3 10.0


ROE (%) 14.6 14.3 14.7 16.4 ROIC (avg.) (%) 13.1 18.0 11.8 12.7


Net debt/equity (%) 61.1 88.6 86.0 82.5 Dividend payout ratio (%) 42.8 40.9 40.0 40.0

Company Background

A UK based provider of engineering, project management, operations and construction services to the oil and gas, clear energy, environment and infrastructure and mining industries.


Our Blue Sky Scenario (p) 687.00

For Americas / NECIS / AMEASE we assume blue sky revenues 5% / 3% / 5% higher than our base case scenario with margins for each division of +1% for 2017 and beyond (2016 impact is diluted). In our SOTP, we assume multiples 1.0 / 1.0 / 1.0 pts higher than our base case for Americas, NECIS and AMEASE respectively. We flex DCF

for long-term growth by +0.25%.

Our Grey Sky Scenario (p) 244.00

For Americas / NECIS / AMEASE we assume grey sky revenues 5% / 3% / 5% lower than our base case scenario with margins for each division of -1% for 2017 and beyond (2016 impact is diluted). In our SOTP, we assume multiples 1.0 / 1.0 / 1.0 pts lower than our base case for Americas, NECIS and AMEASE respectively. We flex DCF for long-term growth by -0.25%.


The price relative chart measures performance against the FTSE ALL SHARE

INDEX which closed at 3643.4 on 13/09/16

On 13/09/16 the spot exchange rate was £.85/Eu 1.- Eu.89/US$1


19 September 2016


AMFW in charts

Figure 119: Revenue vs. trading profit Figure 120: Trading profit overview


Figure 121: Trading cash flow and cash generation Figure 122: AMFW Net Debt to EBITDA evolution


Figure 123: AMFW net debt bridge


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19 September 2016


AMEC Foster Wheeler (AMFW)

Divisional review – Americas. A sharp deterioration within oil & gas triggered a

management change – with John Pearson replacing Simon Naylor as Group President of

Americas - a swift restructuring and a non-cash impairment of £125m. Upstream / offshore

and Canadian oil sands have been particularly weak, reflecting sharp cutbacks in

customer expenditure on high cost-per-barrel projects (this exposure is being addressed

as a part of the strategic review). As a result engineering utilisation is unsustainably low

and the business is being restructured to reflect the weaker outlook. In contrast, Clean

Energy more than doubled revenues yoy in H116, buoyed by a raft of contracts awarded in

H215 ahead of government subsidies drawing to a close. While the regime was ultimately

extended out to 2022, the demand spike from H215 driving H1 volumes does not look

sustainable. Elsewhere, the environmental business is delivering well above historical

trends, whereas Mining may be bottoming out.

Divisional review – Northern Europe & CIS (NECIS). Despite a depressed oil & gas

market, AMFW delivered record revenues in H1 supported by Shah Deniz in Azerbaijan

and hook-up and commissioning work in the North Sea. Shah Deniz volumes should

continue in 2017, but hook-up and commissioning volumes could dry up given sharp

declines in North Sea greenfield capex. The brownfield business should be more resilient,

supported by recent market share gains with Repsol Sinopec. Clean Energy is mixed –

nuclear revenues are currently under pressure (this is unlikely to change in the absence of

any newbuild activity), whereas transmission and distribution is benefiting from current

levels of utility company expenditure.

Divisional review – Asia, Middle East, Africa & S. Europe (AMEASE). The Middle East

has a perception of being a through-cycle spender, but AMFW is suffering from slow

project approvals and delayed project ramp-ups with oil & gas volumes down 15% in H1.

Mining and Environmental business lines are smaller but currently delivering notable

growth, the latter supported by US government work in the region. Encouragingly, margins

are now tracking an improving trend as legacy businesses are integrated.

Backlog development – The order book is trending down from close to record levels at

the end of 2015 as AMFW works through a high volume of solar construction projects

awarded in H215, and oil & gas markets remain soft. Mining should show some recovery,

but overall we expect the downward trend to continue through H216 and into 2017.

Balance sheet and DPS – One of Jon Lewis’s first impressions of AMFW was that “debt

is too high” – we agree – but there was a firm message that an equity injection was not

required. Instead, several disposals are planned that could realise £500m, the largest of

which is Global Power Group. We see net leverage of 3.2x at year-end 2016 – successful

delivery of the disposal programme between now and then could see net leverage below

2x, on our estimates. While this would also improve confidence in DPS sustainability

(yield: ~3.5%, cash cost: £82m), we think it is unlikely to provide AMFW with sufficient

financial flexibility.

Forecasts – Our forecasts are broadly in line with consensus for 2016, but materially

below consensus in 2017/18 on sales / trading profit. There are notable headwinds into

2017 (such as North Sea hook-up and North America clean energy) and insufficient

greenshoots to give us confidence that AMFW can alleviate this pressure. Lower-margin

mix should be offset by restructuring, but we think it could be difficult to grow margins

materially in 2017/18.

Valuation and view – Investors lost confidence in AMFW after the Q415 profit warning

and dividend cut, but we believe sentiment is improving under the leadership of Jon Lewis.

Furthermore, restructuring stories, which is effectively what AMFW is now, often perform

well – and we expect a positive message on costs at the CMD in November. However, we

think the market should also be braced for further backlog deterioration, material revenue

19 September 2016


declines in 2017, and a strategy to chase lower-quality (construction) revenue streams.

The 2017E EV/EBITDA of nearly 10x suggests to us that a lot of the good news is more

than baked into the share price – this is a big premium to peers, and relative to historical

multiples. Disposals would relieve some pressure on the balance sheet, but earnings

dilution associated with this programme indicate the balance sheet will not de-lever to a

sufficiently comfortable positon. We value AMFW using an equally weighted combination

of SOTP and DCF, and initiate with an Underperform rating and a target price of GBp450.


■ For Americas, we assume blue / grey sky revenues +/- 5% from our base-case

scenario with margins +/- 1% for 2017 and beyond (2016 impact is diluted);

■ For NECIS, we assume blue / grey sky revenues +/- 3% and margins +/- 1.0% from our

base-case scenario for 2017 and beyond (diluted impact for 2016);

■ For AMEASE, we assume blue / grey sky revenues +/- 5.0% and margins +/- 1.0%

from our base-case scenario for 2017 and beyond (diluted impact for 2016);

■ In our SOTP, we assume multiples 1.0 / 1.0 / 1.0 pts higher / lower than our base case

for Americas, NECIS and AMEASE, respectively. We flex our DCF for long-term

growth by +/- 0.25%.

19 September 2016


Figure 124: Valuation summary – Amec Foster Wheeler

SOTP (GBPm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV


Americas 124 2272 8.5 0.46 1054 1015

NECIS 107 1342 10.0 0.79 1065 1031

AMEASE 84 1037 9.5 0.77 794 820

GPG 53 364 5.0 0.73 266 254

Investment Services 12 15 5.0 3.88 58 57

Internal revenue -101 0.0 0.00 0 0

Corporate costs -49 7.6 0.00 -371 -345

Total 330 4928 7.6 0.58 2867 2832

Net (debt) / cash -1046 -1026

Asbestos liability -296 -296



Implied value per share (pence) 425 421

DCF (GBPm)


premium

1.41 5.50% 8.69% 2%

EV 3044 3074

Net (debt) / cash -1046 -1026

Asbestos liability -296 -296


MV 1812 1862

Implied value per share, GBp 470 483

Valuation summary (GBp/share) Average 2017E 2018E

SOTP 423 425 421

DCF 477 470 483


Blue Sky / Grey Sky

Blue sky valuation % vs base case Average 2017E 2018E

SOTP 63% 688 686 690

DCF 44% 686 673 700


Grey sky valuation % vs base case Average 2017E 2018E

SOTP -53% 200 205 195

DCF -39% 289 288 290


Source: Credit Suisse estimates

19 September 2016


HOLT



The charts in Figure 125 reflect our forecasts for sales, margins and returns. AMEC Foster

Wheeler has been awarded an eCap (competitive advantage) in HOLT signifying strong

and stable cash generation, whereby the HOLT default fade window extends to 10 years,

thus delaying the mean reversion to long-term observed levels. Based on our

assumptions, HOLT calculates returns to decline from 17.2% in 2016 to 14% by 2021.

Thereafter we capture the next cycle and forecast returns to decline to 10.7% in 2022 and

remain at 10.3% by 2025.




group Wood Group and AMEC Foster Wheeler into an “Engineering, Project Management

& Consultancy” cohort and apply a long term average discount rate of 4.16% to this group

for comparability. Taking into account the relatively higher leverage in AMEC Foster

Wheeler, we add 136 bps to the discount rate and consider a rate of 5.52% for HOLT

based valuation.

The above assumptions suggest a HOLT warranted value of GBp368, compared to our

target price of GBp450. The difference can be explained by a) HOLT using a real discount

rate of 4.16%, which is lower than our nominal 8.69% WACC after an adjustment for

inflation, and b) our methodology also incorporates a multiple-based SOTP.

19 September 2016


Figure 125: AMEC Foster Wheeler in HOLT


Current Price: GBp 531.0 Warranted Price: GBp 367.7 Valuation date: 13-Sep-16


GBP -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % 0.5 36.6 -2.9 -7.0 2.5

EBITDA Mgn, % 7.9 6.6 6.6 6.7 7.1

Asset Turns, x 1.47 2.4 2.2 2.0 1.9

CFROI®, % 13.7 16.8 17.2 14.2 14.0

Disc Rate, % 5.9 6.1 5.5 5.5 5.5

Asset Grth, % 65.9 -17.6 6.5 2.7 5.2

Value/Cost, x 3.0 2.5 2.7 2.5 2.3

Economic PE, x 22.0 15.1 15.7 17.8 16.8

Leverage, % 40.8 49.9 59.0 58.9 59.2

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AMEC FOSTER WHEELER PLC

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19 September 2016


Figure 126: Summary financials – Amec Foster Wheeler

Divisional Forecasts

(GBPm)

2014A 2015A 2016E 2017E 2018E 2019E 2020E

Americas Revenue 2184 2646 2514 2272 2269 2387 2554

growth -3% 21% -5% -10% 0% 5% 7%

Trading profit 212 161 123 118 129 149 172

growth -12% -24% -23% -4% 9% 15% 16%

margin 9.7% 6.1% 4.9% 5.2% 5.7% 6.3% 6.8%

NECIS Revenue 1293 1492 1502 1342 1400 1485 1603

growth 5% 15% 1% -11% 4% 6% 8%

Trading profit 105 134 120 101 108 119 132

growth -24% 172% 12% 2% 10% 12% 11%

margin 8.1% 9.0% 8.0% 7.5% 7.8% 8.0% 8.3%

AMEASE Revenue 516 1050 1012 1037 1099 1187 1288

growth -4% 103% -4% 2% 6% 8% 8%

Trading profit 25 68 76 78 85 95 106

growth -24% 172% 12% 2% 10% 12% 11%

margin 4.8% 6.5% 7.5% 7.5% 7.8% 8.0% 8.2%

GPG Revenue 53 364 364 364 373 392 392

growth 587% 0% 0% 2% 5% 0%

Trading profit 1 51 51 47 50 55 55

growth 5000% 0% -7% 6% 9% 0%

margin 1.9% 14.0% 14.0% 13.0% 13.5% 14.0% 14.0%

Investment Services Revenue 8 15 15 15 15 15 15

Trading profit 9.0 14.0 12.5 11.6 12.6 14.1 15.7

Internal sales -61 -112 -109 -101 -104 -110 -118

Central costs -32 -54 -52 -49 -50 -53 -57

P&L (GBPm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 4054 5567 5407 5029 5156 5467 5851

growth 0% 37% -3% -7% 3% 6% 7%

EBITDA 336.0 400.0 355.5 330.2 360.0 404.5 451.4

Trading profit 320.0 374.0 330.3 306.7 335.9 379.0 424.1

growth -7% 17% -12% -7% 10% 13% 12%

margin 7.9% 6.7% 6.1% 6.1% 6.5% 6.9% 7.2%

PBIT 299.0 334.0 322.3 303.7 332.7 375.3 419.9

Other gains / losses / impairments -156 -559 -644 -130 -130 -130 -117


Share of JV profits 12.0 28.0 5.6 2.1 2.3 2.6 2.9

Adj pre-tax profit 316.0 334.0 259.6 235.7 265.2 308.4 353.8

Pre-tax profit 151.0 -237.0 -386.8 104.8 134.2 177.3 235.5

Tax (pre-exceptional) -70.0 -73.0 -57.1 -54.2 -61.0 -70.9 -81.4


Minority interest 3.0 1.0 1.0 1.0 1.0 1.0 1.0

Adj net profit 249.0 262.0 203.5 182.5 205.2 238.4 273.4

Net Profit 105.0 -254.0 -296.8 80.7 103.0 135.7 180.0

Shares (diluted) 311 385 385 385 385 385 385

EPS (CS, Adj) GBp 80.1 68.0 52.8 47.4 53.3 61.9 71.0

EPS (IFRS) GBp 33.8 -65.9 -77.0 20.9 26.7 35.2 46.7

DPS GBp 43.3 29.0 21.5 18.8 21.2 24.7 28.3


19 September 2016


Figure 127: Cash flow and balance sheet – Amec Foster Wheeler

Cash flow (GBPm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Profit before income taxes 122 -240 -387 105 134 177 236


Working capital -31 -42 28 11 -25 -33 -36

Tax paid -54 -79 -57 -54 -61 -71 -81

Net cash generated from operations 149 141 30 138 125 151 184


Free Cash Flow 118 103 -3 108 94 115 143

M&A spend (net) -782 -6 0 0 0 0 0

Other investing cash flows -15 91 -14 2 2 2 2

Net cash flow from investing

activities

-828 47 -47 -29 -29 -34 -39

DPS cash cost -124 -167 -82 -79 -75 -86 -99

Change in borrowings 1098 -75 0 0 0 0 0

Other financing cash flows -14 -77 -18 0 0 0 0

Net cash flow from financing

activities

960 -319 -100 -79 -75 -86 -99

Net cash flow 281 -131 -117 31 21 31 46


Net cash / (debt) -803 -946 -1077 -1046 -1026 -994 -948

Balance sheet (GBPm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E


Goodwill & intangibles 3443 3025 2673 2560 2449 2336 2221


Non-current assets 4042 3700 3298 3172 3046 2922 2797

Inventories 14 13 13 12 12 13 13

Trade and other receivables 1469 1455 1414 1303 1335 1416 1516



Current assets 2023 1872 1893 1921 2082 2304 2574

Total assets 6065 5572 5191 5092 5128 5226 5371

Bank loans and overdrafts 710 683 683 683 683 683 683

Trade and other payables 1438 1459 1445 1344 1352 1400 1464

Other current liabilities 144 119 119 119 119 119 119

Current liabilities 2292 2261 2247 2146 2154 2202 2266

Bank loans 609 640 640 640 640 640 640

Retirement benefit liabilities 188 168 168 168 168 168 168

Provisions 756 664 664 664 664 664 664


Non-current liabilities 1777 1703 1703 1703 1703 1703 1703

Shareholders equity 1974 1599 1232 1234 1262 1312 1393

Minority interests 22 9 9 9 9 9 9

Total equity 1996 1608 1241 1243 1271 1321 1402



19 September 2016


PEERs







Figure 128: AMEC Foster Wheeler in PEERs


19 September 2016


Europe/France

CGG (GEPH.PA) Rating UNDERPERFORM [V] Price (06 Sep 16, €) 22.22 Target price (€) 17.50 Market Cap (€ m) 491.8 Enterprise value (€ m) 2,489.6 *Stock ratings are relative to the coverage universe in each




Research Analysts

Gregory Brown

44 20 7888 1440

[email protected]

Phillip Lindsay

44 20 7883 1644

[email protected]

Transformed, but at what cost?

■ Initiate with Underperform, TP EUR17.50: The transformation of CGG has

continued exponentially. Gone are the asset-heavy days of a seismic player

looking to dominate the acquisition market with north of 20 vessels. Today,

CGG is an asset-lighter mix of GGR (a cash-generative and profitable

multiclient and processing business), Sercel (the market-leading, but

currently loss-making, equipment franchise) and a much downsized marine

contract business. We applaud the gravitation towards higher-quality

franchises, but we acknowledge CGG’s stretched balance sheet. We are also

concerned about a dwindling client base for Sercel and a possible strategic

misstep in Mexico by not targeting early 2D work.

■ Investment case: CGG is financially stretched. We believe the

transformation of CGG improves its cash flow generation potential, but even

in a recovery cycle, CGG is unlikely to deliver sufficient cash to make a

meaningful dent in its debt pile. This leaves the stock potentially vulnerable if

the downturn in exploration persists, and to future downturns.

■ Catalysts: The licensing rounds in central US Gulf of Mexico, Mexico (round

2), Brazil and Indonesia are important for CGG, but we are concerned about

operator interest. The timing of onshore acquisition campaigns in Russia,

China and the Middle East is uncertain. Q4 late sales could be a positive

trigger, but this will be unknown until Q117. Q316 results: 8 November.

■ Valuation: We derive a target price of EUR17.50 from an equally-weighted

combination of SOTP and DCF. We do not see a sufficiently strong recovery

cycle to enable CGG to delever materially. The transformation has created a

significantly better-quality business mix, but a weak balance sheet and low

recovery potential for the group suggest that CGG is in a higher risk situation.

Against this, the 2017E EV/EBITDA of ~5.5x looks overly demanding relative

to PGS.



CAC 40 INDEX which closed at 4530.0 on 06/09/16

On 06/09/16 the spot exchange rate was €1/Eu 1.-

Eu.89/US$1

Performance 1M 3M 12M Absolute (%) 5.8 -8.6 -64.1 Relative (%) 3.0 -11.7 -62.8


Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ m) 2,103 1,327 1,453 1,635 EBITDAX (US$ m) 661.0 342.1 494.9 637.5 Adjusted net income (US$ m) -1450.2 -427.2 -100.9 -6.2 CS EPS (adj.) (US$) -59.62 -19.30 -4.56 -0.28 Prev. EPS (US$) ROIC avg (%) -27.1 -5.8 0.0 2.7 P/E (adj.) (x) -0.4 -1.3 -5.5 -89.4 P/E rel. (%) -2.9 -8.9 -41.3 -748.3 EV/EBITDAX (x) 4.6 7.7 5.4 4.2

Dividend (12/16E, US$) 0.00 Net debt/equity (12/16E,%) 157.1 Dividend yield (12/16E,%) 0.0 Net debt (12/16E, US$ m) 2,080.2 BV/share (12/16E, US$) 77.4 IC (12/16E, US$ m) 3,404.1 Free float (%) 93.3 EV/IC (12/16E, (x) 0.8 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


CGG (GEPH.PA)

Price (06 Sep 2016): €22.22; Rating: UNDERPERFORM [V]; Target Price: €17.50; Analyst: Gregory Brown

Income statement (US$ m) 12/15A 12/16E 12/17E 12/18E

Revenue 2,103 1,327 1,453 1,635 EBITDA 661 342 495 638 Depr. & amort. (642) (484) (489) (506) EBIT (1,158) (161) 1 128 Net interest exp. (166) (160) (151) (151) Associates 27 0 0 0 PBT (1,391) (337) (167) (38) Income taxes (77) (101) 50 11 Profit after tax (1,468) (438) (117) (27) Minorities (4) -0 -0 -0 Preferred dividends - - - - Associates & other 21 11 16 21 Net profit (1,450) (427) (101) (6) Other NPAT adjustments 0 0 0 0 Reported net income (1,450) (427) (101) (6)

Cash flow (US$ m) 12/15A 12/16E 12/17E 12/18E

EBIT (1,158) (161) 1 128 Net interest (166) (160) (151) (151) Cash taxes paid - - - - Change in working capital (44) 165 (37) (66) Other cash and non-cash items 1,776 377 539 523 Cash flow from operations 408 221 352 433 CAPEX (430) (453) (409) (437) Free cashflow to the firm 282 87 260 320 Acquisitions (19) 0 0 0 Divestments 46 0 0 0 Other investment/(outflows) (20) 0 0 0 Cash flow from investments (423) (453) (409) (437) Net share issue/(repurchase) - 368 0 0 Dividends paid 0 0 0 0 Issuance (retirement) of debt 232 0 0 0 Cashflow from financing 63 368 0 0 Changes in net cash/debt (80) 419 (58) (4) Net debt at start 2,420 2,499 2,080 2,138 Change in net debt 80 (419) 58 4 Net debt at end 2,499 2,080 2,138 2,142

Balance sheet (US$ m) 12/15A 12/16E 12/17E 12/18E


Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 24 22 22 22 CS EPS (adj.) (US$) (59.62) (19.30) (4.56) (0.28) Prev. EPS (US$) Dividend (US$) 0.00 0.00 0.00 0.00 Free cash flow per share (US$) (0.91) (10.45) (2.60) (0.18)

Valuation 12/15A 12/16E 12/17E 12/18E

EV/Sales (x) 1.5 2.0 1.9 1.6 EV/EBITDA (x) 4.6 7.7 5.4 4.2 EV/EBIT (x) (2.6) (16.3) 4821.7 21.1 Dividend yield (%) 0.00 0.00 0.00 0.00 P/E (x) (0.4) (1.3) (5.5) (89.4)


ROE (%) (43.4) (18.9) (6.7) (0.5) ROIC (avg.) (%) (27.1) (5.8) 0.0 2.7


Net debt/equity (%) 184.0 157.1 174.8 176.0 Dividend payout ratio (%) -0.0 -0.0 -0.0 -0.0

Company Background

European based provider of seismic acquisition, seismic equipment, data and processing to the global oil and gas industry.


Our Blue Sky Scenario (€) 34.00

By division, we assume blue sky revenue growth at 7.5% / 5% / 5% above our base case and blue sky margins 4 / 0.5 / 2 ppts above our base case for Contractual Data Acquisition, GGR and Equipment respectively. On valuation, our SOTP, we assume multiples 1.0 / 0.25 / 1.5pts higher than our base case for Acquisition / GGR / Equipment. We flex DCF for long-term growth by +0.25%

Our Grey Sky Scenario (€) 5.00

By division, we assume grey sky revenue decline at 7.5% / 5% / 5% below our base case and grey sky margins 4 / 0.5 / 2 ppts below our base case for Contractual Data Acquisition, GGR and Equipment respectively. On valuation, our SOTP, we assume multiples 1.0 / 0.25 / 1.5pts lower than our base case for Acquisition / GGR / Equipment. We flex DCF for long-term growth by -0.25%.


The price relative chart measures performance against the CAC 40 INDEX

which closed at 4530.0 on 06/09/16

On 06/09/16 the spot exchange rate was €1/Eu 1.- Eu.89/US$1


19 September 2016


CGG in charts

Figure 129: Sercel sales / margin Figure 130: CGG senior debt profile

in USD millions, unless otherwise stated In USD millions, unless otherwise stated

Source: Company data, Credit Suisse Research Source: Company data, Credit Suisse Research

Figure 131: Multiclient net book value by vintage

Figure 132: Onshore/Offshore multiclient net book

value


Figure 133: CGG fleet distribution

Figure 134: CGG group margin vs. fleet on

multiclient


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19 September 2016


CGG (GEPH)

Divisional Review – GGR. CGG’s pivot towards the multiclient and processing

businesses should facilitate stronger through-cycle returns as it dilutes exposure to the

more volatile acquisition sector. Multiclient late-sales is a leading indicator for the overall

market and Q2 was encouraging – there may be pent up demand for data on mature

basins where CGG has extensive library – principally the North Sea and US Gulf of

Mexico. However, at this point, CGG has limited exposure to the re-emerging Mexico

market, while its peers such as PGS, Spectrum and WesternGeco have each committed

to 2D surveys (CGG continues to await permitting for 3D work). That said, we expect CGG

to benefit from upcoming licence rounds in the Central US Gulf of Mexico (although the

Western sale was disappointing) as well as any potential Brazilian activity in 2017. Near

term, we think Q416 has potential to be a strong quarter for late sales, but the strength of

any recovery could be tested in Q1/Q2 2017 if oil prices continue in their current range.

Divisional Review – Equipment. Market conditions remain challenging – there’s an

absence of new marine streamer orders, and timing for onshore orders is uncertain.

Marine headwinds could remain throughout 2017 as seismic vessel operators cannibalise

the last of their existing equipment, but a replacement cycle could commence in 2018/19

(albeit on a structurally smaller fleet). CGG has continually restructured and lowered the

break-even point for Sercel (now below USD375m) but, given the weak outlook, we would

not expect any meaningful contribution until 2018.

Divisional Review – Contractual data acquisition. Marine pricing may have stabilised

as far back as Q4 2015 at or below cash breakeven, but there are few signs of potential

for improvement. Low oil company appetite for contractual acquisition and an oversupply

of streamers restrict recovery potential. The market has restructured with coldstacked and

scrapped vessels, but while some players (eg, Dolphin) are now bankrupt, COSL and

BGP, for example, are internationalising and competing in Northern Europe and

elsewhere. CGG’s marine exposure is now limited to the portion of the fleet not-dedicated

to the multiclient business, but it still has a series of legacy shoots to complete – 65% of

the fleet will be dedicated to contract in Q4 2016. This weighting will have downward

pressure on group margin, but should reverse in 2017 as multiclient takes prominence. We

would, however, expect CGG to lag behind in a recovery as it would need to reactivate

vessels to increase leverage to a recovering market, which management may be hesitant

to do. For land, we see sluggish activity in the Middle East and Northern Africa.

Balance sheet – February’s EUR250m rights issue provided some headroom on revised

covenants. However, the proceeds are to be spent on completing the transformation

programme; the absolute level of debt does not change materially. While the

transformation changes the capital intensity of the business, we do not believe CGG

transforms into a strong, cash-generative business. On our estimates, CGG’s net leverage

should be above 6x at year-end (covenant 5.0x) 2016E, recovering to 4.7x in 2017E –

note this is EBITDA driven, and we do not forecast any material change in the absolute

level of net debt within CGG. Retaining support of banking partners will be key.

Forecasts – we see 2016 as the cyclical and P&L bottom for CGG with material

improvements in both multiclient data and processing through 2017/18. We forecast multi-

client investments broadly in line with the expected market recovery, but lower than the

previous cycle as CGG monetises its existing library. We assume no meaningful recovery

for marine equipment until 2018/19, but see land equipment recovering from Q2 2016’s

historical low. For acquisitions, we factor in a structurally smaller fleet through-cycle

contribution and forecast a cash-flow breakeven in 2017, before a gentle recovery in 2018.

Valuation and view – We initiate on CGG with an Underperform rating and a target price

of EUR17.50. While the exploration cycle may be close to bottoming in 2016, we do not

believe the recovery cycle will be sufficiently strong to enable CGG to de-lever to a more

19 September 2016


comfortable level of gearing. An extended (or future) downturn may require CGG to

undertake further financial restructuring, perhaps at the expense of equity holders. The

transformation has created a substantially better-quality business mix, but a weak balance

sheet and low recovery potential for the group suggest that CGG is a high-risk/high-reward

stock. However, we believe the valuation is not sufficiently attractive – the 2017E

EV/EBITDA of ~5.5x falling to around ~4.5x is in line with historical valuation, but a

material premium to PGS. We derive our target price from equally weighted DCF and

SOTP methodologies, detailed in the below table.


■ In Contractual Data Acquisition, we assume blue / grey sky revenues +/- 7.5% from our

base-case scenario with margins +/- 4% for 2017 and beyond (we dilute the impact for

2016);

■ For GGR, we assume blue / grey sky revenues +/- 5.0% and margins +/- 0.5% from

our base-case scenario for 2017 and beyond (we dilute the impact for 2016);

■ For Equipment, we assume blue / grey sky revenues +/- 5.0% and margins +/- 2.0%

from our base-case scenario for 2017 and beyond (we dilute the impact for 2016);

■ In our SOTP, we assume multiples 1.0 / 0.25 / 1.5pts higher / lower than our base-case

for Acquisition / GGR / Equipment. We flex our DCF for long-term growth by +/- 0.25%.

19 September 2016


Figure 135: Valuation summary – CGG

SOTP (USDm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV


GGR 545 894 4.7 2.9 2563 2273

Equipment 9 325 9.0 0.2 80 329

Contractual data acquisition 0 259 2.0 0.0 0 28

Non-operated resources -25 0 5.0 0.0 -125 -100

Corporate -35 0 5.2 0.0 -183 -147

Eliminations 1 -25 0.0 0.0 1 0

Total 495 1453 5.2 0.0 2335.6 2384

Net (debt) cash -2138 -2142


Implied market value (USD) 416.5 460.6

USD/EUR 1.12 1.12

Implied market value (EUR) 371.9 411.3

Implied value per share 16.8 18.6

DCF (USDm)


Premium

2.50 13.75% 8.83% 2.0%

EV 2275 2430



MV 137 288

USD/EUR 1.12 1.12


Valuation summary (EUR/share) Average 2017E 2018E

SOTP 17.7 16.8 18.6

DCF 17.4 14.3 20.4

Overall average (equally weighted) 17.5

Blue Sky / Grey Sky

Blue sky valuation % diff to base Average 2017e 2018e

SOTP 102% 35.8 31.0 40.7

DCF 86% 32.4 28.5 36.2

Overall average (equally weighted) 94% 34.0

Grey sky valuation

SOTP -79% 3.8 5.8 1.8

DCF -68% 5.8 3.4 8.2

Overall average (equally weighted) -71% 45.0


HOLT



The charts in Figure 136 reflect our forecasts for sales, margins and returns. The extended

10-year forecast allows us to express our view of the near-term recovery and factor in the


improve from -10.1% in 2016 to 6.8% by 2021. Thereafter we capture the next cycle and

forecast returns to decline to 4.2% in 2022 and recover to 9.3% by 2025.

19 September 2016




which causes the CFROI and growth rate to regress to the mean.

HOLT default discount rate for CGG currently is 8.2% and includes a 340bps Leverage

differential. Based on our assumptions and the default discount rate, the HOLT warranted

value is EUR 16.6, very close to our target price of EUR17.5.

Figure 136: CGG in HOLT


Current Price: EUR22.06 Warranted Price: EUR 16.6 Valuation date: 13-Sep-16


USD -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % -17.8 -32.1 -36.9 9.5 12.5

EBITDA Mgn, % 38.4 34.0 25.8 34.1 39.0

Asset Turns, x 0.26 0.2 0.1 0.2 0.2

CFROI®, % -2.9 -6.8 -10.1 -2.7 0.3

Disc Rate, % 7.1 8.0 8.2 8.2 8.2

Asset Grth, % -13.1 -9.5 -12.6 -4.6 -3.5

Value/Cost, x 0.7 0.6 0.6 0.6 0.6

Economic PE, x -23.8 -9.4 -5.9 -23.1 200.8

Leverage, % 69.1 80.9 85.9 86.1 86.4

HO

LT

-

C

red

it S

uis

se A

naly

st

Scen

ari

o D

ata

CGG SA (GEPH)

EB

ITD

A M

arg

in (

para

llel

% p

oin

t ch

an

ge

to f

ore

casts

)

-2.0% -253% -177% -89% 5%

189%

114%

-1.0% -226% -148% -57% 40% 152%

0.0% -198% -118% -25% 74%

264%

1.0% -170% -88% 7% 109% 227%

2.0% -143% -59% 39% 143%

More than

10%

downside

Within 10%More than

10% upside


-40

-20

0

20

40

60

80

100

1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025

Sales Growth (%)

-10

0

10

20

30

40

50

1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025

EBITDA Margin

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025

Asset Turns (x)

-15

-10

-5

0

5

10

15

20



-20

0

20

40

60

80

100

1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025


Asset Growth (in %)

19 September 2016


Figure 137: Summary financials – CGG

Divisionals

(EURm)

2014A 2015A 2016E 2017E 2018E 2019E 2020E

GGR Revenue 1384 1108 803 894 1019 1199 1439

growth 7% -20% -28% 11% 14% 18% 20%

EBIT 328 246 149 215 285 396 532

growth 3% -25% -40% 44% 33% 39% 35%

margin 23.7% 22.2% 18.5% 24.0% 28.0% 33.0% 37.0%

Equipment Revenue 802 437 301 325 362 412 482

growth -23% -46% -31% 8% 11% 14% 17%

EBIT 164 26 -47 -33 0 25 43

growth -44% -84% -279% -28% -100% #DIV/0! 75%

margin 20.4% 5.9% -15.5% -10.3% 0.0% 6.0% 9.0%

Contractual data acquisition Revenue 1057 616 247 259 281 313 360

growth -37% -42% -60% 5% 9% 11% 15%

EBIT -67 -156 -91 -52 -56 -55 -54

growth -297% 133% -41% -43% 9% -3% -1%

margin -6.3% -25.3% -37.0% -20.0% -20.0% -17.5% -15.0%

Non-operated resources -17 -28 -102 -90 -62 -26 0

Corporate -66 -39 -35 -35 -35 -35 -35

Eliminations -100 -30 -16 1 0 0 0

EBIT 242 19 -141 6 132 305 487

P&L 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 3095 2102 1327 1453 1635 1894 2246

growth -18% -32% -37% 10% 13% 16% 19%

EBITDA (adj) 994 661 342 495 638 812 1028

D&A -752 -642 -484 -489 -506 -507 -541

Share of JVs / Associates -82 21 11 16 21 26 33

EBIT 242 19 -141 6 132 305 487

growth -40% -92% -845% -104% 2270% 132% 60%

margin 7.8% 0.9% -10.7% 0.4% 8.1% 16.1% 21.7%



Pre-tax profit -941 -1391 -337 -167 -38 137 320

Tax -124 -77 -101 50 11 -41 -96

Effective Tax rate (underlying) 13% 6% 30% 30% 30% 30% 30%

Minority Interest -90 17 11 16 21 26 33

Net profit -1154 -1450 -427 -101 -6 122 257

Adj Net profit -1154 -1450 -427 -101 -6 122 257

No. Shares (FD) 24 24 22 22 22 22 22

EPS (CS, Adj) -47.48 -59.62 -19.30 -4.56 -0.28 5.53 11.63

EPS (reported) -47.48 -59.62 -19.30 -4.56 -0.28 5.53 11.63

DPS 0.00 0.00 0.00 0.00 0.00 0.00 0.00


19 September 2016


Figure 138: Balance sheet and cash flow – CGG

Balance Sheet (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Property, plant & equipment, net 885 819 764 753 702 665 635

Multiclient 927 989 1012 1012 1012 1012 1046

Goodwill and other intangibles 1588 1562 1514 1457 1483 1570 1620




Trade receivables 813 567 621 699 809 960 913

Inventories 329 202 168 158 164 169 152


Current Assets 1772 1521 1494 1573 1747 1996 2187

Total assets 5513 5199 5092 5102 5253 5552 5797


Borrowings 97 64 64 64 64 64 64

Provisions - current 220 165 165 165 165 165 165


Current Liabilities 1055 1044 1038 1054 1083 1125 1103

Borrowings 2788 2538 2538 2538 2538 2538 2538

Provisions 156 156 156 156 156 156 156


Non-current Liabilities 3099 2831 2831 2831 2831 2831 2831



Total liabilities and shareholders equity 5513 5199 5092 5102 5253 5552 5797

Cash flow 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Net income / (losses) -1147 -1446 -427 -101 -6 122 257


Working cap movement -30 -44 165 -37 -66 -109 -141

Cashflow from operations 864 408 221 352 433 520 657


Capex (multiclient) -583 -285 -307 -306 -304 -332 -398

Free cash flow 7 24 -231 -58 -4 37 66

Other investing cash flows -36 -39 0 0 0 0 0

Cashflow from investing activities -894 -423 -453 -409 -437 -483 -591


Capital increase 0 0 368 0 0 0 0

Other financing activities -197 -172 0 0 0 0 0

Cashflow from financing activities -103 63 368 0 0 0 0

FX / other -39 -21 0 0 0 0 0

Net cash flow -171 26 136 -58 -4 37 66

Net cash / (debt) -2420 -2500 -2080 -2138 -2142 -2104 -2038


19 September 2016


PEERs







Figure 139: CGG in PEERs


19 September 2016


Americas/United States Oil & Gas Equipment & Services

Core Laboratories (CLB) Rating NEUTRAL Price (13-Sep-16,US$) 108.25 Target price (US$) 115.00 52-week price range 133.97 - 89.25 Market cap (US$ m) 4,774.51 Enterprise value (US$ m) 4,980.90 *Stock ratings are relative to the coverage universe in each



Research Analysts

Gregory Lewis, CFA

212 325 6418

[email protected]

Neesha Khanna

212 325 6974

[email protected]

Joseph Nelson

212 538 4894

[email protected]

Phillip Lindsay

44 20 7883 1644

[email protected]

Core a bit hollowed out

We initiated coverage of Core Laboratories on 1 September and we provide the

front page and financial summary here. For the full report, please see CLB: Core a Bit Hollowed Out - Initiating Neutral.

■ Neutral rating, $115 target price. CLB has built a consistent track record of

best-in-class returns and returning cash to shareholders through dividends

(~2.0% yield) and share buybacks. Our call is not on the company, which is a

best-in-class technology and data management service provider to the O&G

sector, but on the stock. We see two headwinds: 1) a lower-for-longer

offshore cycle and 2) frugal customer spending, which is likely to slow the

pace of margin recovery.

■ Onshore recovery to help CLB looks positioned to take advantage of the

North American onshore recovery, with onshore revenues around 50-55%.

Also helping is that ~90% of revenue is tied to production (only ~10% to

exploration). Not surprisingly, CLB has outperformed the OSX by 400bps ytd

and by 1,200bps over the past year. CLB has been a relatively low-risk stock.

■ Curveball. CLB bought back ~USD425m in stock and paid out USD185m in

dividends over the past two years. That is what made the May equity

issuance of ~USD220m (4% dilution) a surprise. Management noted that the

capital injection strengthened the balance sheet, removed any potential debt

covenant breaches, and was accretive to earnings. It also covers the

dividend for the next two years should the recovery stall.

■ Premium valuation. Our $115 TP is ~35x our 2018 EPS estimate, which

looks expensive compared with an industry leader such as SLB (~22x 2018

consensus EPS). However, CLB has generated best-in-class returns on

capital for several years. CLB has posted a ~50% ROC over the past five

years vs. peers in the 10-15% range and more recently a 1H16 ROC of 20%

with its peers around 10%. Bottom line: CLB's returns are best in class OFS.

■ Trough. Earnings look to have bottomed in 2Q16, but while we expect a

recovery, we believe it would be slower than consensus expects. Our

2017/18 EPS estimates of $2.25/$3.25 are 6%/10% below consensus. Share price performance

On 13-Sep-2016 the S&P 500 INDEX closed at 2127.02

Daily Sep16, 2015 - Sep13, 2016, 09/16/15 = US$109.02

Quarterly EPS Q1 Q2 Q3 Q4 2015A 0.86 0.91 0.95 0.62 2016E 0.37 0.35 0.38 0.40 2017E 0.43 0.51 0.59 0.70


Year 12/15A 12/16E 12/17E 12/18E EPS (CS adj.) (US$) 2.37 0.97 -0.19 -1.40 Prev. EPS (US$) - - - - P/E (x) 0.9 2.2 -11.0 -1.5 P/E rel. (%) 4.3 10.8 -59.2 -9.0 Revenue (US$ m) 4,335.0 3,029.2 2,194.3 1,589.9 EBITDA (US$ m) 2,415.0 1,759.5 984.5 262.0 OCFPS (US$) 3.62 2.45 1.69 0.30 P/OCF (x) 0.9 0.9 1.3 7.2 EV/EBITDA (current) 4.1 5.6 10.0 37.6 Net debt (US$ m) 9,499 8,420 9,529 9,766 ROIC (%) 7.23 3.58 0.66 -2.14

Number of shares (m) 508.44 IC (current, US$ m) 19,474.00 BV/share (Next Qtr., US$) 19.4 EV/IC (x) .5 Net debt (Next Qtr., US$ m) 8,787.1 Dividend (current, US$) - Net debt/tot eq (Next Qtr.,%) 84.2 Dividend yield (%) - Source: Company data, Thomson Reuters, Credit Suisse estimates

https://plus.credit-suisse.com/r/kP5M89

https://plus.credit-suisse.com/r/kP5M89

19 September 2016


Core Laboratories (CLB)

Price (13 Sep 2016): US$108.25; Rating: NEUTRAL; Target Price: US$115.00; Analyst: Gregory Lewis

Income Statement 12/15A 12/16E 12/17E 12/18E

Revenue (US$ m) 797.5 604.4 671.3 753.3 EBITDA 211 113 148 196 Depr. & amort. (27) (27) (26) (25) EBIT (US$) 184 87 122 171 Net interest exp (12) (11) (11) (11) Associates - - - - Other adj. (2) 1 0 0 PBT (US$) 170 76 111 161 Income taxes (34) (11) (12) (18) Profit after tax 136 66 99 143 Minorities (0) 0 0 0 Preferred dividends - - - - Associates & other (0) (0) 0 0 Net profit (US$) 136 66 99 144 Other NPAT adjustments 0 0 0 0 Reported net income 136 66 99 144

Cash Flow 12/15A 12/16E 12/17E 12/18E

EBIT 184 87 122 171 Net interest (12) (11) (11) (11) Cash taxes paid - - - - Change in working capital 77 21 (20) (14) Other cash & non-cash items (29) 17 13 7 Cash flow from operations 219 114 105 154 CAPEX (23) (10) (14) (20) Free cashflow to the firm 196 104 92 134 Aquisitions (14) 0 0 0 Divestments 1 1 0 0 Other investment/(outflows) (4) (1) 0 0 Cash flow from investments (40) (11) (14) (20) Net share issue(/repurchase) (160) 196 0 0 Dividends paid (94) (95) (97) (97) Issuance (retirement) of debt (155) (11) (11) (11) Other 154 9 11 11 Cashflow from financing activities (255) 99 (97) (97) Effect of exchange rates 0 0 0 0 Changes in Net Cash/Debt (76) 202 (6) 37 Net debt at start 333 408 206 212 Change in net debt 76 (202) 6 (37) Net debt at end 408 206 212 175

Balance Sheet (US$) 12/15A 12/16E 12/17E 12/18E

Assets Cash & cash equivalents 22 71 55 80 Account receivables 146 122 141 156 Inventory 41 42 45 48 Other current assets 29 30 32 33 Total current assets 239 264 273 318 Total fixed assets 143 127 115 110 Intangible assets and goodwill 188 188 188 188 Investment securities - - - - Other assets 55 54 54 54 Total assets 625 633 629 670 Liabilities Accounts payables 33 35 37 40 Short-term debt 0 0 0 0 Other short term liabilities 87 67 70 73 Total current liabilities 121 102 107 113 Long-term debt 431 278 267 256 Other liabilities 97 101 101 101 Total liabilities 649 480 475 469 Shareholder equity (29) 148 150 196 Minority interests 5 5 5 4 Total liabilities and equity 625 633 629 670 Net debt 408 206 212 175

Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg) 43 44 44 44 CS adj. EPS 3.17 1.51 2.25 3.25 Prev. EPS (US$) - - - - Dividend (US$) 2.20 2.20 2.20 2.20 Dividend payout ratio 69.45 146.04 97.79 67.78 Free cash flow per share 4.58 2.39 2.07 3.03

Earnings 12/15A 12/16E 12/17E 12/18E

Sales growth (%) (26.5) (24.2) 11.1 12.2 EBIT growth (%) (46.9) (52.9) 41.1 40.2 Net profit growth (%) (48.1) (51.7) 51.4 44.3 EPS growth (%) (46.0) (52.4) 49.3 44.3 EBITDA margin (%) 26.5 18.8 22.0 26.0 EBIT margin (%) 23.1 14.3 18.2 22.8 Pretax margin (%) 21.3 12.6 16.6 21.4 Net margin (%) 17.0 10.9 14.8 19.1

Valuation 12/15A 12/16E 12/17E 12/18E

EV/Sales (x) 6.50 8.24 7.43 6.57 EV/EBITDA (x) 24.4 45.5 34.9 26.3 EV/EBIT (x) 28.2 57.5 40.8 28.9 P/E (x) 34.2 71.9 48.1 33.4 Price to book (x) 21.1 12.0 12.1 10.8 Asset turnover 1.3 1.0 1.1 1.1

Returns 12/15A 12/16E 12/17E 12/18E

ROE stated-return on (%) 42.7 21.4 25.1 34.1 ROIC (%) 0.4 0.2 0.3 0.4 Interest burden (%) 0.92 0.88 0.91 0.94 Tax rate (%) 19.9 14.3 11.0 11.0 Financial leverage (%) 1.96 0.70 0.67 0.58

Gearing 12/15A 12/16E 12/17E 12/18E

Net debt/equity (%) (1723.7) 134.9 136.9 87.3 Net Debt to EBITDA (x) 1.9 1.8 1.4 0.9 Interest coverage ratio (X) 14.9 7.8 11.2 16.3

Quarterly EPS Q1 Q2 Q3 Q4

2015A 0.86 0.91 0.95 0.62 2016E 0.37 0.35 0.38 0.40 2017E 0.43 0.51 0.59 0.70



Daily Sep16, 2015 - Sep13, 2016, 09/16/15 = US$109.02

Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016



Hunting Plc (HTG.L) Rating NEUTRAL Price (13 Sep 16, p) 415.50 Target price (p) 500.00 Market Cap (£ m) 619.6 Enterprise value (£ m) 687.3 *Stock ratings are relative to the coverage universe in each




Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Not yet in season

■ Initiate coverage with Neutral, TP GBp500. Despite cutting its workforce by

45% from market peak, management has been unable to cut cost quickly

enough to stay ahead of the drop in activity. While some cost has been

preserved to respond better in a recovery, pricing concessions exacerbate

financial impact on HTG – gross margins in H1 2016 were 22ppts from the

2014 peak (32%), and HTG is loss making at the EBITDA line. HTG is ‘early

cycle’, although traditionally has recovered more slowly than peers and

customers in an upswing. It should perform better in this recovery cycle with

its enlarged Well Completion division.

■ Investment case: Movements in rig count will continue to drive sentiment

around HTG, but well count and, in particular, footage drilled are bigger

drivers of its consumables. Rig efficiency, completion efficiency and acreage

high grading are headwinds to the absolute number of rigs working in the

upcycle. We believe Q216 was the US rig count trough, we could see a

doubling of rig count by 2018, and we believe downhole technologies will

become increasingly relevant in this cycle. From an extremely low base, HTG

looks poised for recovery, but current valuations appear to be insufficiently

attractive to be more positive.

■ Catalysts: Summer 2016 saw the inflection point in North American activity;

continued positive momentum in rig count would be supportive; key customer

/ competitor commentary; FY trading update in December are other key

catalysts.

■ Valuation: We use an equally weighted DCF and SOTP to value HTG,

deriving a target price of GBp500. We think the market will largely ignore

2017 multiples, where HTG is recovering from a loss-making position, and

look towards a more normal P&L in 2018. However, a PE well above 20x and

EV/EBITDA of 9x appear to be pricing in an ample recovery already.



FTSE 100 IDX which closed at 6665.6 on 13/09/16


Eu.89/US$1

Performance 1M 3M 12M Absolute (%) -9.3 18.7 -5.2 Relative (%) -6.0 5.9 -14.5


Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ m) 811 475 596 746 EBITDAX (US$ m) 61.9 -45.7 55.2 106.4 Pre-tax profit adjusted (US$ m) 9.4 -87.7 8.8 58.1 CS EPS (adj.) (US$) 0.03 -0.49 0.04 0.27 Prev. EPS (US$) ROIC avg (%) 0.5 -5.9 0.8 4.0 P/E (adj.) (x) 178.6 -11.2 133.9 20.4 P/E rel. (%) 1058.1 -63.2 872.0 149.7 EV/EBITDAX (x) 15.1 -19.8 15.8 7.7

Dividend (12/16E, US$) 0.00 Net debt/equity (12/16E,%) 8.0 Dividend yield (12/16E,%) 0.0 Net debt (12/16E, US$ m) 84.5 BV/share (12/16E, US$) 5.7 IC (12/16E, US$ m) 1,145.8 Free float (%) 77.8 EV/IC (12/16E, (x) 0.8 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Hunting Plc (HTG.L)

Price (13 Sep 2016): 415.50p; Rating: NEUTRAL; Target Price: 500.00p; Analyst: Phillip Lindsay


Revenue 811 475 596 746 EBITDA 62 (46) 55 106 Depr. & amort. (86) (79) (81) (83) EBIT 16 (85) 12 61 Net interest exp. (3) (3) (4) (3) Associates - - - - PBT 9 (88) 9 58 Income taxes (5) 14 (3) (17) Profit after tax 4 (74) 6 41 Minorities 1 1 1 1 Preferred dividends - - - - Associates & other (1) (1) (1) (1) Net profit 4 (74) 6 41 Other NPAT adjustments (231) (27) (26) (26) Reported net income (227) (101) (20) 15


EBIT 16 (85) 12 61 Net interest (3) (3) (4) (3) Cash taxes paid - - - - Change in working capital - - - - Other cash and non-cash items 128 176 44 20 Cash flow from operations 142 88 52 78 CAPEX (72) (16) (16) (24) Free cashflow to the firm 120 80 44 66 Acquisitions 0 0 0 0 Divestments 1 0 0 0 Other investment/(outflows) (11) (4) (3) (4) Cash flow from investments (82) (19) (19) (28) Net share issue/(repurchase) 1 0 0 0 Dividends paid (40) (6) 0 (5) Issuance (retirement) of debt (29) 0 0 0 Cashflow from financing (79) (6) 0 (5) Changes in net cash/debt 20 31 33 45 Net debt at start 135 115 85 51 Change in net debt (20) (31) (33) (45) Net debt at end 115 85 51 6


Assets Total current assets 564 488 537 625 Total assets 1,496 1,360 1,347 1,380 Liabilities Total current liabilities 177 147 154 178 Total liabilities 328 299 305 329 Total equity and liabilities 1,496 1,360 1,347 1,380

Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 150 151 151 151 CS EPS (adj.) (US$) 0.03 (0.49) 0.04 0.27 Prev. EPS (US$) Dividend (US$) 0.08 0.00 0.00 0.11 Free cash flow per share (US$) 0.47 0.48 0.24 0.36

Valuation 12/15A 12/16E 12/17E 12/18E

EV/Sales (x) 1.2 1.9 1.5 1.1 EV/EBITDA (x) 15.1 (19.8) 15.8 7.7 EV/EBIT (x) 56.9 (10.6) 69.7 13.4 Dividend yield (%) 1.46 0.00 0.00 1.96 P/E (x) 178.6 (11.2) 133.9 20.4


ROE (%) 0.4 (8.0) 0.7 4.8 ROIC (avg.) (%) 0.5 (5.9) 0.8 4.0


Net debt/equity (%) 9.9 8.0 4.9 0.6 Dividend payout ratio (%) 260.7 -0.0 0.0 40.0

Company Background

Hunting PLC is an industrial holding company for a group of companies that manufactures and distributes products that are used in the extraction of oil and gas.



For well construction, completion and intervention blue sky revenues we assume revenues +7.5 / 10.0 / 5.0%. For well construction, completion and intervention blue sky margins 1.5 / 2.0 / 1.0pts higher from our base case for 2017 and beyond (diluted impact for 2016). In our SOTP we assume multiples 1.0 / 2.0 / 0.5pts higher for

well construction, well completion and well intervention respectively. We flex DCF for long-term growth by +0.25%


For well construction, completion and intervention grey sky revenues we assume revenues -7.5 / 10.0 / 5.0%. For well construction, completion and intervention grey sky margins -1.5 / 2.0 / 1.0pts lower from our base case for 2017 and beyond (diluted impact for 2016). In our SOTP we assume multiples 1.0 / 2.0 / 0.5pts lower for well construction, well completion and well intervention respectively. We flex DCF for long-term growth by -0.25%


The price relative chart measures performance against the FTSE 100 IDX




19 September 2016


Hunting in charts

Figure 140: Indexed US rig count vs. previous

cycles Figure 141: CS North American rig count forecast

Source: Baker Hughes International, Credit Suisse Research Source: Baker Hughes International, Credit Suisse Research

Figure 142: Well construction revenue and EBITA

comparison

Figure 143: Well completion revenue and EBITA

comparison


Figure 144: Well intervention revenue and EBITA

comparison

Figure 145: Department incremental / decremental

performance and forecast


0

10

20

30

40

50

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13

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29

33

37

41

45

49

53

57

61

65

69

73

77

81

85

89

93

97

101

1997/98 2001/02 2008/09 2011/12 2014/15

0

100

200

300

400

500

600

700

800

900

1,000

Rig

Count

US Rig Count Canada Rig Count

-25%

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-10%

-5%

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10%

15%

20%

0

50

100

150

200

250

300

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2010 2011 2012 2013 2014 2015 2016e 2017e 2018e

US

Dm

Revenue EBITA margin (RHA)

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2010 2011 2012 2013 2014 2015 2016e 2017e 2018e

US

Dm


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0

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2010 2011 2012 2013 2014 2015 2016e 2017e 2018e

US

Dm


-50%

0%

50%

100%

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2010 2011 2012 2013 2014 2015 2016e 2017e 2018e

Well Construction Well Completion Well Intervention

19 September 2016


Hunting (HTG)

Divisional Review – Well Construction. This traditionally recovers most rapidly in an

upswing, but is likely to lag behind Well Completion due partly to the industry working

through its high inventory of drilled-but-uncompleted wells (DUCs). Improvements in

Premium Connections technology and the 2015 commissioned test facility (accelerating

speed to market) should enable HTG to regain some lost market share. The Advanced

Manufacturing Group can boast structurally shorter lead times and the focus should be on

marketing this capability to gain market share in the recovery. The less differentiated

Drilling Tools and OCTG businesses would effectively follow market activity levels.

Divisional Review – Well Completion. This division is crucial to HTG’s recovery

prospects – it generates over 60% of group revenues at above-average margins – and

should benefit from completion of the market inventory of DUCs. Titan has made good

progress on technology development and internationalising its product range – we expect

the business to play a crucial role in P&L recovery and cash flow generation (Titan was

generating ~USD8m EBITDA/month at the peak). Elsewhere the focus remains on further

market penetration in the Middle East (particularly Saudi Arabia) and Asia Pacific

(although the new campus investment in Singapore needed to improve efficiency and

broaden product range is on hold for now). In Europe, the operations will largely be

dictated by UK North Sea activity with potential for new work in Norway.

Divisional Review – Well Intervention. Hunting Subsea has outperformed market trends

due to its regional focus in the US Gulf and technology development, but we expect

subsea markets generally to remain subdued until 2018. However, demand for pressure

control and rental equipment should benefit from an uptick in field opex and regional

expansion.

Balance sheet / DPS – We forecast an EBITDA loss of USD35m in 2016 but significantly

curtailed capex and reduced working capital should deliver positive FCF of ~USD60m.

This should enable absolute levels of debt to reduce, but EBITDA losses forced HTG to

seek a banking covenant holiday with its lending consortium. The amendment through

mid-2018 should enable Hunting to come through the eye-of-the-storm without needing an

equity injection, but at the cost of 100bps of margin, and restrictions on capex / DPS. HTG

arguably over-invested in the last cycle; this was reflected in poor returns. Management’s

focus for the recovery cycle should be on winning business that maximises facility

utilisation rather than further expansion, in our view. Inventory levels may need to be

rebuilt to support future growth, but we should see a more cash-generative HTG emerge

from this downturn.

Forecasts. Burning through higher-cost inventory would hamper margin expansion initially

in the upswing. That said, HTG is highly operationally geared and looks well placed to

benefit from a recovering North American onshore market. To some extent we think the

market may underestimate this fact – our bottom-line forecasts are considerably above

consensus in 2017/18. Well Completion should recover faster than HTG’s other divisions

as the industry works through its inventory of DUCs, while new well construction would lag

behind before gathering momentum as the recovery phase gathers pace.

Valuation. We initiate on HTG with a Neutral rating and a target price of GBp500. HTG’s

positioning as a short-cycle provider of consumable products should see it as an early and

operationally geared beneficiary in a recovery cycle. 2017 multiples, where HTG is

recovering from a loss-making position, are likely to be largely ignored by the market. A

more normal P&L in 2018 would see the company trading on a PE well above 20x and

EV/EBITDA of ~9x, on our estimates. This is well above typical valuations for HTG, even

in a recovery phase, and a premium to better-quality stocks such as SBO. We think HTG

may have run too far too soon, and a period of consolidation may be necessary before

more material upside can be contemplated.

19 September 2016



■ For Well Construction, we assume blue / grey sky revenues +/- 7.5% from our base-

case scenario with margins +/- 1.5% for 2017 and beyond (diluted impact for 2016);

■ For Well Completion, we assume blue / grey sky revenues +/- 10% and margins +/-

2.0% from our base-case scenario for 2017 and beyond (diluted impact for 2016);

■ For Well Intervention, we assume blue / grey sky revenues +/- 5% and margins +/- 1%

from our base-case scenario for 2017 and beyond (diluted impact for 2016);

■ In our SOTP, we assume multiples 1.0 / 2.0 / 0.5 pts higher / lower than our base-case

for Well Construction, Well Completion and Well Intervention, respectively. We flex our

DCF for long-term growth by +/- 0.25%.

Figure 146: Valuation summary – Hunting Plc

SOTP (GBPm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV


Well Construction 12.9 127 15.0 1.53 193 194

Well Completion 33.4 381 17.0 1.49 568 742

Well Intervention 8.4 86 16.0 1.58 135 113

Hunting Energy Services 54.8 594 16.4 1.51 897 1049

Exploration & Production 0.4 2 5.0 0.87 2 10

Total 55.2 596 16.3 1.51 899 1059

Net (debt) / cash -47 -2



Implied value per share (GBp) 449 553

DCF (GBPm)


premium

1.20 5.00% 7.65% 0.02

EV 952 1001

Net cash / (debt) -47 -2


MV 935 1029

GBP/USD 1.30 1.30

Implied value per share 476 523


SOTP 501 449 553

DCF 499 476 523


Blue Sky / Grey Sky


SOTP 53% 768 665 871

DCF 28% 642 611 672



SOTP -36% 321 295 347

DCF -19% 407 387 427



19 September 2016


HOLT




10 year forecast allows us to express our view of the near term recovery and factor in the



forecast returns to dip to 0.9% in 2022 and recover to 5.8% by 2025.






The above assumptions suggest a HOLT warranted value of GBp 434.6, which is below

our target price of GBp500. The difference can be explained by a) HOLT using a real

discount rate 5.6%, which is below our nominal 7.73% WACC after an adjustment for


19 September 2016


Figure 147: Hunting in HOLT




USD -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % 3.9 -41.5 -41.3 25.3 25.3

EBITDA Mgn, % 19.9 7.1 -9.6 9.3 14.3

Asset Turns, x 0.76 0.5 0.3 0.3 0.4

CFROI®, % 12.1 2.0 -7.2 0.9 3.6

Disc Rate, % 5.4 5.3 5.6 5.6 5.6

Asset Grth, % -1.2 -5.9 -6.2 2.4 4.4

Value/Cost, x 1.2 0.8 1.0 1.0 0.9

Economic PE, x 9.5 38.5 -13.8 104.3 25.2

Leverage, % 18.8 22.2 24.0 25.5 27.3

More than

10%

downside

Within 10%More than

10% upside


66%

1.0% -20% -6% 11% 29% 50%

2.0% -9% 6% 24% 44%

0% 18%

0.0% -31% -18% -3% 14%

HO

LT

-

C

red

it S

uis

se A

naly

st

Scen

ari

o D

ata

HUNTING PLC (HTG)

EB

ITD

A M

arg

in (

para

llel

% p

oin

t ch

an

ge

to f

ore

casts

)

-2.0% -53% -42% -30% -15%

34%

2%

-1.0% -42% -30% -16%

-100

-80

-60

-40

-20

0

20

40

1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025

Sales Growth (%)

-15

-10

-5

0

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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025

EBITDA Margin

0.0

0.5

1.0

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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025

Asset Turns (x)

-10

-5

0

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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025


Asset Growth (in %)

19 September 2016


Figure 148: Summary financials – Hunting Plc

Divisionals (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Well Construction Revenue 378 211 106 127 152 190 209

growth -1% -44% -50% 20% 20% 25% 10%

EBITA 53 2 -21 2 10 20 26

growth -10% -96% -1213% -109% 420% 102% 31%

margin 14.0% 0.9% -20.0% 1.5% 6.5% 10.5% 12.5%

Well Completion Revenue 863 489 293 381 495 619 681

growth 8% -43% -40% 30% 30% 25% 10%

EBITA 141 14 -47 11 47 84 100

growth 13% -90% -430% -124% 312% 78% 20%

margin 16.3% 2.9% -16.0% 3.0% 9.5% 13.5% 14.8%

Well Intervention Revenue 136 106 74 86 96 111 119

growth 25% -22% -30% 15% 13% 15% 8%

EBITA 24 5 -15 1 4 9 12

growth 52% -81% -424% -106% 406% 104% 34%

margin 17.6% 4.3% -20.0% 1.0% 4.5% 8.0% 10.0%

E&P Revenue 10 4 2 2 2 3 3

growth 26% -58% -50% 10% 5% 5% 5%

EBITA 0 -4 -2 -2 0 0 0

growth -83% -2250% -51% -18% -100% n/a n/a

margin 2.0% -102.4% -100.0% -75.0% 0.0% 0.0% 0.0%

P&L (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 1387 811 475 596 746 923 1012

growth 7% -42% -41% 25% 25% 24% 10%

EBITDA 270 62 -46 55 106 163 194

EBITA 218 16 -85 12 61 112 139

growth 9% -92% -618% -115% 392% 83% 23%

margin 15.7% 2.0% -17.9% 2.1% 8.2% 12.2% 13.7%



Share of JV profits -1 0 0 0 0 0 0

Adj pre-tax profit 212 9 -88 9 58 110 136

Pre-tax profit 109 -289 -135 -30 20 73 109

Tax (pre-exceptional) -57 -5 14 -3 -17 -33 -41


Minority interest -4 1 1 1 1 1 1

Adj net profit 151 5 -73 7 41 77 96

Net Profit 69 -227 -101 -20 15 51 76

Shares (diluted) 151 150 151 151 151 151 151

EPS (CS, Adj), USD 1.00 0.03 -0.48 0.04 0.27 0.51 0.64

EPS (IFRS), USD 0.46 -1.51 -0.67 -0.13 0.10 0.34 0.50

DPS, USD 0.31 0.08 0.00 0.00 0.11 0.18 0.22


19 September 2016


Figure 149: Balance sheet and cash flow – Hunting

Cash flow (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

(Loss) / profit from operations* 114 -282 -133 -26 23 76 111


Working capital 4 96 104 -11 -21 -16 -14

Net cash flow from operating activities 229 142 88 52 78 122 143


Free Cash Flow 130 64 69 33 50 75 89

M&A spend (net) -3 0 0 0 0 0 0

Other investing cash flows 9 -3 0 0 0 0 0


Change in borrowings -86 -29 0 0 0 0 0

DPS cash cost -44 -40 -6 0 -5 -19 -28

Other financing cash flows -16 -10 0 0 0 0 0

Net cash flow from financing activities -146 -79 -6 0 -5 -19 -28

Net cash flow -9 -18 63 33 45 55 60


Net cash / (debt) -131 -111 -80 -47 -2 54 114



Goodwill and intangibles 665 411 375 339 305 273 251


Non-Current Assets 1187 932 872 810 755 715 687

Inventories 382 331 243 245 277 313 332



Cash and Cash equivalents 89 54 85 118 163 219 279

Current Assets 782 564 488 537 625 726 812

Total Assets 1969 1496 1360 1347 1380 1441 1499


Borrowings 65 52 52 52 52 52 52



Borrowings 158 117 117 117 117 117 117


Non-Current Liabilities 220 151 151 151 151 151 151


Non-controlling interests 30 26 26 26 26 26 26

Total equity 1438 1168 1061 1041 1050 1082 1130


Source: Company data, Credit Suisse estimates. *(loss) / profit from operations is derived from EBITA less other gains, losses and impairments

19 September 2016


PEERs







Figure 150: Hunting in PEERs


19 September 2016



Petrofac (PFC.L) Rating OUTPERFORM [V] Price (13 Sep 16, p) 808.00 Target price (p) 1100.00 Market Cap (£ m) 2,795.0 Enterprise value (£ m) 3,363.2 *Stock ratings are relative to the coverage universe in each




Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Back to core business

■ Initiate coverage at Outperform, GBp1100 TP. Balance sheet deleveraging

and an improving and more stable P&L should give investors comfort around

DPS sustainability (yield ~6.5%). Diversification has not worked - a refocused

Petrofac with a well-managed E&C unit (which we view as best-in-class) at its

core should be a far more attractive proposition for investors. PFC cannot

simply make a clean break from its non-core activities, but the direction of

travel should support multiple expansion.

■ Investment case: The market correctly penalized PFC for poor strategic

decisions and bad execution on Laggan Tormore. However PFC still looks

like a stock being punished for past mistakes. In the past PFC was premium

rated for its best-in-class onshore E&C business – current multiples are about

half of what PFC has achieved in the past. The margin profile is less

attractive versus its own rich history but remains considerably above peers.

■ Catalysts: A healthy pipeline underpins improving book-to-bill momentum in

H216, and we expect the market to respond positively to IES disposals. Next

scheduled news flow is FY16 trading update: 15 December.

■ Valuation: The stock looks particularly compelling on a SOTP-basis. Valuing

E&C in line with TRE’s current valuation would imply negative value for non-

core assets. These assets have a book value of over GBP4.00/share, which

PFC plans to monetize in the coming years. This gives the stock a lot of

option value. We value the stock using an equally weighted SOTP and DCF.

We see material upside; PFC is one of our top picks in the sector. Share price performance



13/09/16


Eu.89/US$1



Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ m) 6,844 7,543 7,316 7,408 EBITDAX (US$ m) 312.0 648.5 836.8 818.0 Pre-tax profit adjusted (US$ m) 20.0 384.9 584.0 579.8 CS EPS (adj.) (US$) 0.03 0.94 1.36 1.41 Prev. EPS (US$) ROIC avg (%) 3.2 19.7 24.5 23.4 P/E (adj.) (x) 402.7 11.4 7.8 7.5 P/E rel. (%) 2385.3 64.0 51.0 55.3 EV/EBITDAX (x) 14.0 6.9 5.3 5.4


19 September 2016


Petrofac (PFC.L)

Price (13 Sep 2016): 808.00p; Rating: OUTPERFORM [V]; Target Price: 1100.00p; Analyst: Phillip Lindsay


Revenue 6,844 7,543 7,316 7,408 EBITDA 312 649 837 818 Depr. & amort. (200) (187) (189) (174) EBIT 102 462 648 644 Net interest exp. (47) (87) (78) (78) Associates 10 10 14 14 PBT 20 385 584 580 Income taxes (6) (62) (116) (94) Profit after tax 14 322 468 486 Minorities (5) (4) (5) (5) Preferred dividends - - - - Associates & other 0 (0) 0 0 Net profit 9 319 463 481 Other NPAT adjustments (358) (129) 0 0 Reported net income (349) 190 463 481


EBIT 102 462 648 644 Net interest (47) (87) (78) (78) Cash taxes paid - - - - Change in working capital 602 (58) (180) (190) Other cash and non-cash items 12 132 84 92 Cash flow from operations 669 448 474 468 CAPEX (169) (279) (180) (128) Free cashflow to the firm 585 365 384 378 Acquisitions - - - - Divestments 43 5 0 0 Other investment/(outflows) (192) (79) (38) (38) Cash flow from investments (318) (352) (218) (166) Net share issue/(repurchase) - - - - Dividends paid (223) (223) (224) (229) Issuance (retirement) of debt 42 0 0 0 Cashflow from financing (220) (223) (224) (229) Changes in net cash/debt 47 (130) 33 72 Net debt at start 733 686 816 784 Change in net debt (47) 130 (33) (72) Net debt at end 686 816 784 711



Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 340 340 340 340 CS EPS (adj.) (US$) 0.03 0.94 1.36 1.41 Prev. EPS (US$) Dividend (US$) 0.66 0.66 0.66 0.71 Free cash flow per share (US$) 1.47 0.50 0.86 1.00

Valuation 12/15A 12/16E 12/17E 12/18E



ROE (%) 0.5 24.1 32.4 28.8 ROIC (avg.) (%) 3.2 19.7 24.5 23.4



Company Background

Petrofac designs, builds, operates and maintains oil and gas facilities. It has a large onshore engineering and construction business operating primarily in the Middle East and North Africa as well as a large operations business in the North Sea.



In E&C we assume blue sky revenues +7.5% from base with margins +1% for 2017 and beyond (diluted impact for 2016). For EPS we assume blue sky revenues +5% and margins +0.5% from our base case from 2017. For IES we assume revenues +7.5% from

our base case and margins +2.0% from our base case. In our SOTP we assume multiples +1.5/1.0pts higher than base in E&C and EPS. For IES we assume 75% of book value. We flex DCF for LT growth by +0.25%


In E&C we assume grey sky revenues -7.5% from base with margins -1% for 2017 and beyond (diluted impact for 2016). For EPS we assume blue sky revenues -5% and margins -0.5% from our base case from 2017. For IES we assume revenues -7.5% from our base case and margins -2.0% from our base case. In our SOTP we assume multiples +1.5/1.0pts higher than base in E&C and EPS. For IES we assume 25% of book value. We flex DCF for LT growth by -0.25%






19 September 2016


Petrofac in charts

Figure 151: PFC backlog ageing Figure 152: Active E&C bids by region


Figure 153: Key projects being bid Figure 154: Bid book by country


Figure 155: Key E&C project progression

Source: Company data

2.6

5.2

2.9

0.9

1.1

1.90.4

0.5

1.9

0

1

2

3

4

5

6

7

8

H216 2017 2018+

US

Dm

E&C EPS IES

Middle East

Africa

Other

0500

100015002000250030003500400045005000

US

Dm

0

1000

2000

3000

4000

5000

6000

7000

US

Dm

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3

Salah southern fields USD1200m

Petro Rabigh Undisclosed

Jazan USD1400m

SARB3 USD500m

Upper Zakum USD2900m

Alrar USD450m

Sohar Refinery USD1050m

Clean Fuels Kuwait USD1700m

Khazzan CPF USD1200m

Rabab Haweel >USD1000m

BorWin3 Undisclosed

Reggan North USD970m

GC29 USD700m

RAPID >USD500m

Lower Fars >USD3000m

Yibal Khuff USD900m

Manifold Group Trunkline USD780m

Fadhili Sulhur Recovery Undisclosed

Joint NOC/IOC led

2019

IOC/NOC led NOC led

2013 2014 2015 2016 2017 2018

19 September 2016


Petrofac (PFC)

Divisional review – Engineering & Construction (E&C). Positive book-to-bill averaging

above 1.5x in 2014/15 more than compensates for a weaker H116. Visibility is excellent in

2017 (>90% of CS forecasts secure) and supply chain deflation underpins contract

profitability (embedded margins 7-8%). With the problematic Laggan Tormore now behind

it, PFC focus now turns to executing backlog in core Middle East markets and business

development. On the former, Upper Zakum in Abu Dhabi and Clean Fuels in Kuwait

represent the most challenging of projects in the execution phase, but so far so good here,

while the remainder of the portfolio appears to be performing well. In terms of business

development, the projects market was slow in H116 but a number of live bid situations

should deliver a marked improvement in H216 / H117. We do not believe the competitive

environment has intensified materially thus far in the downturn, nor would we expect it to –

contractor losses (for Korean E&C in particular) are still fresh in the memory. Cash

advances and milestone payments are increasingly less generous for contractors, while

variation order are often dilutive and commercial close-out discussions remain challenging.

Divisional review – Engineering & Production Services (E&PS). The reimbursable

business looks to have gained market share ytd in the North Sea (we note contract wins

with Anasuria Operating Company, BP and Repsol Sinopec) and activity is ramping up

well on Middle East EPCM projects. Margins have improved materially on operational

performance and restructuring.

Divisional review – Integrated Energy Services (IES). The de-emphasizing of the

capital intensive IES is welcome, but monetizing the portfolio may take several years. All

eyes are on Mexico as the market awaits contract migration of Santuario from a production

enhancement contract to a production-sharing contract (should be H216) with farm-out

(and cash inflow) potential in 2017. We think a joint deal with Magallanus is likely (the two

fields were awarded in combination originally) – together the two fields account for about

75% of the USD600m book value. GSA is now de-risked and should be next in line for

disposal – recent updates around access to export pipeline support valuation.

Backlog development. H1 order intake was disappointing but reflects a shortage of

opportunities, not a poor win rate. There are several large live bid situations (in aggregate

worth in excess of USD20bn) across several Middle East markets - Bahrain, UAE, Oman,

Kuwait and Saudi Arabia. The medium-term pipeline is populated with more non-Middle

East projects (North Africa, Russia and CIS), which should be supportive of medium-term

margins.

Balance sheet and DPS – PFC should receive USD300m-plus in H216 / H117 from the

Berantai contract termination, while Mexican PEC contract migration / farm-outs provide

more opportunities for cash-in. Realising value from the JSD6000 (‘the boat’) and PM304

(Malaysian PSC) may not be possible before 2018 due to subsea market conditions and a

possible contract extension respectively. PFC has bucked the market trend and preserved

dividend in the downturn (yield: ~6%). We believe this can continue but requires an

increase to official payout policy, supported by a more conservative capital structure.

Forecasts – Our forecasts are in line with company guidance for 2016 where Laggan

Tormore losses depress earnings. Underpinned by strong visibility and a more stable

margin outlook, we see a material step-up in net profit in 2017 and further improvements in

2018 (we expect improving order intake in H216 / H117 to support this). Our EPS

forecasts are 6%/13% ahead of consensus in 2017/18.

Valuation and view - We value PFC using an equally weighted SOTP and DCF; it looks

particularly compelling on the former, in our view. Valuing OEC in line with TRE’s current

valuation would imply negative value for non-core assets. These assets have a book value

of over GBP4.00/share, which PFC plans to monetize in the coming years - our SOTP,

however, values IES assets conservatively at 50% of book value (with zero value

19 September 2016


assumed for the JSD6000). Given relatively low earnings for IES in 2017, any disposals

would not be materially dilutive to EPS, but the implied PE would be even more attractive

(6-7x in 2017 assuming 50% of book value is realised). We see option value and potential

for material upside. As such PFC is one of our top picks.


■ In Engineering & Construction, we assume blue / grey sky revenues +/- 7.5% from our

base case scenario with margins +/- 1% for 2017 and beyond (diluted impact for 2016)

■ For Engineering & Production Services, we assume blue / grey sky revenues +/- 5.0%

and margins +/- 0.5% from our base case scenario for 2017 and beyond (diluted

impact for 2016)

■ For Integrated Energy Services, we assume blue / grey sky revenues +/- 7.5% and

margins +/- 2.0% from our base case scenario for 2017 and beyond (diluted impact for

2016)

■ In our SOTP, we assume multiples 1.5 / 1.0 pts higher / lower than our base case for

Engineering & Construction and Engineering & Production Services respectively. For

Integrated Energy Services we assume 75% / 25% of book value in our blue / grey sky

scenario. We flex DCF for long-term growth by +/- 0.25%.

19 September 2016


Figure 156: Valuation summary - Petrofac



Engineering & Construction 423 5641 11.0 0.83 4653 4553

Engineering & Production Services 70 1404 7.0 0.35 491 479

Integrated Energy Services 18 358 44.3 2.21 793 793

Corporate & others -48 0 9.0 0.00 -436 -417

Consolidation adj & elimination 0 -87 0.0 0.00 0 0

Total 463 7316 9.0 0.75 5502 5408





DCF (USDm)


premium

1.25 5.00% 9.58% 2.0%

EV 5572 5807


Associates / minorities

MV 4788 5096

GBP / USD 1.30 1.30



SOTP 1082 1085 1080

DCF 1118 1083 1153


Blue Sky / Grey Sky


SOTP 60% 1736 1668 1804

DCF 59% 1777 1697 1856



SOTP -47% 577 617 537

DCF -39% 684 681 687



19 September 2016


HOLT



The charts below reflect our forecasts for sales, margins and returns. The extended 10

year forecast allows us to express our view of the near term recovery and factor in the


improve from 6.7% in 2016 to 8.6% by 2022. Thereafter we capture the next cycle and

forecast returns to decline to 7.3% in 2023 and recover to 9.9% by 2025 – highest level

achieved across 2016 to 2025.




group Tecnicas Reunidas, Petrofac, Saipem, Technip SA and Subsea 7 into an

“Engineering and Construction” cohort and apply a long term average discount rate of

5.15% for each.

The above assumptions suggest a HOLT warranted value of GBp 879.5, below our

GBp1100 target price. The difference can be explained by a) HOLT using a real discount

rate 5.15%, which is below our nominal 9.61% WACC after an adjustment for inflation, and

b) our methodology also incorporates a multiple-based SOTP.

19 September 2016


Figure 157: Petrofac in HOLT

Source: HOLT®

Current Price: GBp 808.0 Warranted Price: GBp 879.5 Valuation date: 13-Sept-16


USD -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % -1.4 9.7 10.2 -3.0 1.3

EBITDA Mgn, % 14.0 4.4 8.6 11.4 11.0

Asset Turns, x 1.03 1.2 1.3 1.2 1.1

CFROI®, % 12.4 0.4 6.7 8.8 8.3

Disc Rate, % 5.6 5.7 5.2 5.2 5.2

Asset Grth, % 34.7 -6.9 2.1 3.4 2.9

Value/Cost, x 1.3 1.5 1.4 1.3 1.2

Economic PE, x 10.3 339.8 20.9 15.0 15.1

Leverage, % 33.8 41.4 46.8 46.6 46.5

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PETROFAC LIMITED (PFC)

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-2.0% -66% -56% -44% -31%

44%

-17%

-1.0% -44% -32% -19% -3% 13%

0.0% -22% -8% 7% 25%

104%

1.0% 0% 16% 33% 52% 74%

2.0% 22% 40% 59% 80%

More than

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Within 10%More than

10% upside


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2002 2005 2008 2011 2014 2017 2020 2023

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EBITDA Margin

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Asset Turns (x)

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2002 2005 2008 2011 2014 2017 2020 2023Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate


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2002 2005 2008 2011 2014 2017 2020 2023


Asset Growth (in %)

19 September 2016


Figure 158: Summary financials – Petrofac

Divisional Analysis (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Engineering & Construction Revenue 3587 4821 5641 5641 5782 6071 6526

growth -5% 34% 17% 0% 3% 5% 8%

Net profit 438 -1 322 423 434 470 522

growth -9% -100% -32276% 31% 2% 9% 11%

margin 12.2% 0.0% 5.7% 7.5% 7.5% 7.8% 8.0%

Engineering & Production Services Revenue 2180 1739 1652 1404 1404 1439 1476

growth 19% -20% -5% -15% 0% 3% 3%

Net profit 55 58 78 70 74 79 81

growth 0% 5% 34% -10% 5% 7% 3%

margin 2.5% 3.3% 4.7% 5.0% 5.3% 5.5% 5.5%

Integrated Energy Services Revenue 591 379 341 358 304 244 195

growth -22% -36% -10% 5% -15% -20% -20%

Net profit 138 7 -31 18 23 21 17

growth 11% -95% -539% -158% 28% -9% -20%

margin 58.2% 43.5% 30.5% 46.5% 51.4% 56.8% 62.0%

Corporate & Others Net profit -61 -54 -50 -48 -49 -51 -54

Consolidation adjustments &

eliminations

Revenue -117 -95 -91 -87 -82 -77 -72

Group Revenue 6241 6844 7543 7316 7408 7677 8124

growth -1% 10% 10% -3% 1% 4% 6%

Net profit 588 19 319 463 481 519 566

margin 9.4% 0.3% 4.2% 6.3% 6.5% 6.8% 7.0%

Profit & Loss (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 6241 6844 7543 7316 7408 7677 8124

growth -1% 10% 10% -3% 1% 4% 6%

EBITDA 935 312 649 837 818 848 892

D&A -244 -200 -187 -189 -174 -160 -151

Operating profit 691 112 462 648 644 688 742

Other gains / losses / impairments -463 -355 -129 0 0 0 0


Share of JV profits 7 10 10 14 14 15 16

Pre-tax profit (adjusted) 641 30 385 584 580 626 681

Pre-tax profit (IFRS) 178 -325 256 584 580 626 681

Tax (pre-exceptional) -33 -6 -62 -116 -94 -101 -109


Tax (exceptional items) 2 -3 0 0 0 0 0

Minority interest -20 -5 -4 -5 -5 -5 -6

Adj net profit 588 19 319 463 481 519 566

Net Profit 127 -339 190 463 481 519 566

Shares (diluted) 344 340 340 340 340 340 340

EPS (CS, Adj) 1.71 0.06 0.94 1.36 1.41 1.53 1.66

EPS (IFRS) 0.37 -1.00 0.56 1.36 1.41 1.53 1.66

DPS 0.66 0.66 0.66 0.66 0.71 0.76 0.83


19 September 2016


Figure 159: Cash flow and balance sheet – Petrofac


Profit before tax and exceptional items 634 20 385 584 580 626 681


Working capital -60 602 -58 -180 -190 -52 -2

Net cash flow from operating activities 648 669 448 474 468 629 717


Free Cash Flow 59 483 131 256 302 467 554

M&A 0 0 -12 0 0 0 0

Other investing cash flows 61 -132 -23 0 0 0 0



DPS cash cost -225 -223 -223 -224 -229 -247 -267


Net cash flow from financing activities 274 -220 -223 -224 -229 -247 -267

Net cash flow 394 131 -128 33 72 220 287


Net cash / (debt) -733 -686 -816 -784 -711 -491 -204

Balance sheet (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E


Goodwill & intangibles 301 187 187 187 187 187 187

Other Non-Current Assets 1089 1083 1083 1083 1083 1083 1083

Non-Current Assets 3088 3045 3141 3136 3093 3060 3033

Work in progress 1602 1794 1890 1833 1856 1923 2035

Trade & Other receivables 2783 2124 2306 2232 2412 2500 2645

Other Current Assets 471 480 523 508 514 532 563

Cash and ST deposits 986 1104 980 1012 1085 1305 1592

Current Assets 5842 5502 5699 5585 5867 6260 6836

Total Assets 8930 8547 8840 8721 8960 9320 9869


Accrued contract expenses 800 1233 1127 1061 1076 1112 1174




Bank loans 1710 1270 1270 1270 1270 1270 1270

Provisions 273 331 331 331 331 331 331

Other Non-Current Liabilities 907 800 857 837 815 821 847

Non-Current Liabilities 2890 2401 2458 2438 2416 2422 2448


Minority interests 10 2 2 2 2 2 2

Total equity 1871 1232 1198 1437 1689 1961 2260



19 September 2016


PEERs







Figure 160: Petrofac in PEERs

Source: Credit Suisse PEER

19 September 2016



Petroleum Geo Services (PGS.OL) Rating OUTPERFORM [V] Price (13 Sep 16, Nkr) 16.60 Target price (Nkr) 27.00 Market Cap (Nkr m) 3,977.0 Enterprise value (Nkr m) 13,311.8 *Stock ratings are relative to the coverage universe in each




Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Perfectly geared seismic

■ Initiate at Outperform, TP NOK27: Of the asset heavy marine-seismic

players, PGS has the best quality fleet and lowest cost structure. Its balance

sheet is also relatively stronger and should de-lever faster in the recovery

cycle (our model shows net leverage falling from 3.9x in 2016E to 2.0x in

2018E). We do not expect ‘the seismic’ trade to work as well coming out of

this cycle versus the last (PGS more than doubled in 2009) – exploration

spend will take a back seat to development expenditure in the initial recovery

phase. However, PGS’s new cost structure should provide good leverage to

even a modest recovery. We think the market underestimates this.

■ Not without risk but high rewards on offer: The 2017E multiple of about 4x

recovering (but still very depressed EBITDA) implies the market is not yet

convinced of recovery. We think the market may be underestimating the level

of pent-up demand for multi-client data and production seismic, plus the pace

at which the contract market could rebalance. At near a market trough for

exploration spend and seismic demand, the upside potential looks significant

to us but PGS should be considered a higher risk / reward play within OFS.

■ Catalysts: Operator interest in key licensing rounds in Europe, Mexico,

Canada, and to a lesser extent, the Central US Gulf; the allocation to

exploration within 2017 oil company E&P budgets; Q316 results on 27

October and the Q416 trend for late sales.

■ Valuation: Our target price of NOK27 is derived from an equally-weighted

combination of SOTP and DCF. A bottoming exploration cycle is usually a

good time to buy seismic stocks but the situation is less clear cut today with

less operator focus on exploration. However, the 2017 multiple of about 4x

recovery EBITDA implies a far more pessimistic view than we currently see.

For us, the market underestimates pent-up demand and how quickly the

contract market could rebalance.





Eu.89/US$1

Performance 1M 3M 12M Absolute (%) -10.0 -15.9 -48.4 Relative (%) -7.4 -20.2 -52.1


Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ m) 962 795 891 1,032 EBITDAX (US$ m) 484.4 299.6 414.8 540.6 Adjusted net income (US$ m) -202.0 -214.9 -133.3 -13.7 CS EPS (adj.) (US$) -0.92 -0.90 -0.56 -0.06 Prev. EPS (US$) ROIC avg (%) -16.7 -6.6 -2.6 0.7 P/E (adj.) (x) -2.2 -2.2 -3.6 -35.1 P/E rel. (%) -17.1 -13.9 -27.5 -316.4 EV/EBITDAX (x) 3.0 5.5 4.1 2.9

Dividend (12/16E, US$) 0.00 Net debt/equity (12/16E,%) 87.4 Dividend yield (12/16E,%) 0.0 Net debt (12/16E, US$ m) 1,179.8 BV/share (12/16E, US$) 6.0 IC (12/16E, US$ m) 2,530.1 Free float (%) 99.4 EV/IC (12/16E, (x) 0.7 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Petroleum Geo Services (PGS.OL)

Price (13 Sep 2016): Nkr16.6; Rating: OUTPERFORM [V]; Target Price: Nkr27.00; Analyst: Phillip Lindsay


Revenue 962 795 891 1,032 EBITDA 484 300 415 541 Depr. & amort. (469) (440) (470) (507) EBIT (430) (150) (55) 34 Net interest exp. (56) (36) (41) (40) Associates (16) (16) (19) (21) PBT (505) (202) (116) (27) Income taxes (22) (20) (17) 14 Profit after tax (528) (222) (133) (14) Minorities - - - - Preferred dividends - - - - Associates & other 326 7 0 0 Net profit (202) (215) (133) (14) Other NPAT adjustments (326) (7) 0 0 Reported net income (528) (222) (133) (14)


EBIT (430) (150) (55) 34 Net interest 58 0 0 0 Cash taxes paid (25) 0 0 0 Change in working capital 115 14 (13) (16) Other cash and non-cash items 770 388 412 480 Cash flow from operations 488 252 343 498 CAPEX (469) (450) (383) (369) Free cashflow to the firm 447 192 280 420 Acquisitions - - - - Divestments 89 0 0 0 Other investment/(outflows) (47) 0 0 0 Cash flow from investments (427) (450) (383) (369) Net share issue/(repurchase) - - - - Dividends paid (20) 0 0 0 Issuance (retirement) of debt (64) 193 0 0 Cashflow from financing (34) 193 0 0 Changes in net cash/debt 66 (208) (40) 129 Net debt at start 1,038 972 1,180 1,219 Change in net debt (66) 208 40 (129) Net debt at end 972 1,180 1,219 1,091


Assets Total current assets 470 588 562 710 Total assets 2,914 3,042 2,929 2,939 Liabilities Total current liabilities 298 349 369 393 Total liabilities 1,450 1,692 1,712 1,736 Total equity and liabilities 2,914 3,042 2,929 2,939

Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 218 239 239 239 CS EPS (adj.) (US$) (0.92) (0.90) (0.56) (0.06) Prev. EPS (US$) Dividend (US$) 0.00 0.00 0.00 0.00 Free cash flow per share (US$) 0.09 (0.83) (0.17) 0.54

Valuation 12/15A 12/16E 12/17E 12/18E

EV/Sales (x) 1.5 2.1 1.9 1.5 EV/EBITDA (x) 3.0 5.5 4.1 2.9 EV/EBIT (x) (3.4) (11.1) (30.7) 46.5 Dividend yield (%) 0.00 0.00 0.00 0.00 P/E (x) (2.2) (2.2) (3.6) (35.1)


ROE (%) (11.6) (14.6) (9.8) (1.1) ROIC (avg.) (%) (16.7) (6.6) (2.6) 0.7


Net debt/equity (%) 66.4 87.4 100.2 90.6 Dividend payout ratio (%) -0.0 -0.0 -0.0 -0.0

Company Background

Norwegian based provider of seismic services to the global oil and gas industry.



In Marine Contract, we assume blue sky revenues +10% from our base case scenario with margins +2% for 2017 and beyond For Multi-Client Pre-funding, Late-Sales, and Imaging we assume blue sky revenues +5.0% and margins +0.5% from our base case scenario for 2017 and beyond (diluted impact for 2016). In our SOTP, we assume multiples 1.0 pt higher than our base case for

Marine Contract / Multi-Client and flex long term growth by +.25% in our DCF


In Marine Contract, we assume grey sky revenues -10% from our base case with margins -2% for 2017 and beyond (diluted impact for 2016). For Multi-Client Pre-funding, Late-Sales and Imaging we assume grey sky revenues -5.0% and margins -0.5% from our base case for 2017 and beyond. In our SOTP, we assume multiples 0.25 pts lower than our base case for Marine Contract / Multi-Client and flex long term growth by -.25% in our DCF



closed at 532.5 on 13/09/16



19 September 2016


PGS in charts

Figure 161: Cash investment vs. prefunding rate for

multiclient Figure 162: Multiclient book value and vintage

In US $ millions


Figure 163: Annual fleet distribution

Figure 164: Onshore/Offshore multiclient NBV as at

Q2 2016


Figure 165: PGS cost profile (USDm) Figure 166: PGS capex profile (USDm)


1% 2%4%

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Q1 Q2 Q1 Q2 Q1 Q2 Q1 Q2 Q1 Q2 Q1 Q2 Q1 Q2 Q1

2009 2010 2011 2012 2013 2014 2015 2016

Cash investment in Multiclient Prefunding rate (RHA)

0%

10%

20%

30%

40%

50%

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2010 2011 2012 2013 2014 2015 2016e 2017e 2018e

Multiclient Marine and Other

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274 269288 281

190208 209

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19 September 2016


PGS (PGS)

Divisional Review – Marine Contract. A shift towards higher multi-client volumes should

be more pronounced in a recovery – this is structural. Oil companies view seismic data as

a commodity, particularly so in a downturn, but we expect technology differentiation and

data quality to become more important as the recovery cycle develops, given a more

returns-focused customer base. In 2016, contract revenues will be the lowest they’ve been

this century, and we model a recovery to our view of cycle peak (in 2020) that is about half

the level of the last cycle. Seismic vessel and streamer supply/demand has improved

markedly; we think the market could rebalance quickly in an upcycle. We would expect

vessel reactivations as market conditions improve but we believe only 30-40% of the

industry’s lost capacity could come back. There are encouraging signs that the worst of

this cycle is behind us – customer behavior around survey planning has become more

predictable, and we believe there is pent-up demand for production seismic in particular.

This all bodes well for this segment in 2017, and particularly 2018.

Divisional Review – Multi-client and Imaging. Traditionally multi-client is a lead indicator

for the overall seismic industry – it recovers faster than contract in an upswing as the

clamour for data drives late sales. Q216 was very encouraging for PGS (and multi-client

peers), and we believe there is pent-up demand for multi-client data because oil

companies that were awarded licenses have been deferring data purchases through the

downturn. Investors should continue to expect quarterly turbulence in regional demand.

Q4 is seasonally the strongest quarter for late sales, and with oil companies beginning to

focus more on development of new reserves, we think Q4 2016 could be a particularly

strong quarter and one that could surprise on the upside. We expect PGS to benefit from

upcoming license rounds, particularly in the North Sea, East Canada and Mexico, where it

has considerable exposure, bolstered by the joint acquisition (with TGS) of Dolphin’s

multiclient library. The imaging and processing business typically tracks the recovery in the

broader market, but a more-returns focused customer base may drive demand higher than

this.

Balance sheet – Our model sees net leverage at below 4x (covenant: 5.5x) in 2016,

below 3x (covenant 4.0x) in 2017 and below 2x in 2018 (covenant 4.0x). The market

moving forward would need to be worse than we’ve seen in 2016 for PGS to be at risk of

breaching covenants but the absolute level of debt is unlikely to peak until 2017. We do

not rule out the need for an equity injection but an improving outlook makes this less likely

in our view – the company has no significant debt maturities until y/e 2018. Its USD450m

bond currently trades well below par value.

Forecasts – We see 2016 as the cyclical and P&L bottom for PGS with material

improvements in multi-client in 2017/18 with Marine Contract lagging. We are broadly in

line with the street for 2016 but our 2017/18 EBITDA is 8% / 11% ahead of consensus –

we think the market underestimates a) the recovery potential, and b) the leverage to a

recovery given its improved cost structure. On capex, we assume no further newbuilds

expenditure beyond existing commitments, whereas we forecast multi-client investments

broadly in line with the expected market recovery.

Valuation and view - We initiate on PGS at Outperform with a target price of NOK27. We

believe the exploration cycle is close to bottoming in 2016. While the rebound in

exploration spending could well underperform the last cycle, we believe PGS is poised to

outperform seismic peers. The 2017 multiple of about 4x recovering (but still very

depressed) EBITDA implies the market is far from convinced of recovery for PGS. We

think the market may be underestimating the level of pent-up demand for multi-client data

and production seismic, plus the pace at which the contract market could rebalance (and

PGS is the most geared play on the latter). Furthermore, the current valuation discount to

CGG looks unwarranted – PGS appears far better placed for P&L recovery and balance

sheet deleveraging. We would give PGS a ‘higher risk / higher reward’ badge, but at close

19 September 2016


to market trough for exploration spend/seismic demand, we think the stock should warrant

investor attention. There are not many stocks across our coverage that provide as much

upside potential as PGS, in our view. We derive our target price from an equally-weighted

DCF and SOTP, detailed in the below table.


■ In Marine Contract, we assume blue / grey sky revenues +/- 10% from our base case

scenario with margins +/- 2% for 2017 and beyond (diluted impact for 2016)

■ For Multi-Client Pre-funding, Late-Sales, and Imaging we assume blue / grey sky

revenues +/- 5.0% and margins +/- 0.5% from our base case scenario for 2017 and

beyond (diluted impact for 2016)


Marine Contract / Multi-Client Pre-funding, Late-Sales, and Imaging. We flex DCF for

long-term growth by +/- 0.25%.

19 September 2016


Figure 167: Valuation summary - PGS

SOTP (USD) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV


Marine contract 30 249 2.5 0.3 75 96

Multi-client, imaging & other 385 642 4.75 2.9 1828 1847

Total 415 891 4.6 3.6 1903 1943

Net (debt) / cash -1219 -1091


Implied market value (USD) 734 903

NOK/USD 8.21 8.21

Implied market value (NOK) 6032 7419


DCF (USDm)

Assumptions Beta Risk Premium WACC LT Growth 2017E 2018E

2.00 5.5% 8.6% 2.0%

EV 1756 1896

Net (debt) / cash -1219 -1091


MV 587 856

NOK/USD 8.21 8.21


Valuation Summary (NOK/share) Average 2017E 2018E

SOTP 28 25 31

DCF 25 21 30


Blue Sky / Grey Sky


SOTP 53% 43 37 49

DCF 126% 58 52 64


Grey sky valuation

SOTP -45% 16 15 16

DCF -83% 4 0 8



19 September 2016


HOLT






improve from -5.5% in 2016 to 4% by 2020. Thereafter we capture the next cycle and

forecast returns to dip to 0.2% in 2021 and recover to 3.6% by 2025 – driven by 1100 bps

margin expansion - reflecting PGS’s recovery potential.



which causes the CFROI and growth rate to regress to the mean.

HOLT default discount rate for PGS currently is 7.8% and includes a 300bps Leverage

differential. Based on our assumptions and the default discount rate, the HOLT warranted

value would be NOK -55 (see Figure 168). With the expected deleveraging, given the

improved cost structure and asset disposals, we use a credit-risk free discount rate of

4.4% for PGS, resulting in a warranted price of NOK 25.1, 34% upside to the current

market price. This is our higher risk/higher reward play and to express this we offer a

range of valuations around a rising discount rate using the HOLT framework in the table

below:

Figure 168: PGS HOLT valuation based on rising discount rate

Discount rate 4.4%

4.4% 5.4% 6.4% 7.4% 8.4%

Warranted Price 25.0 -5.4 -29.2 -47.8 -62.2

% up/down 33.9% -129% -256% -356% -433%


19 September 2016


Figure 169: PGS in HOLT




USD -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % -3.2 -33.8 -17.4 12.1 15.9

EBITDA Mgn, % 47.3 49.9 37.7 46.6 52.4

Asset Turns, x 0.18 0.1 0.1 0.1 0.1

CFROI®, % 1.6 -1.7 -5.5 -1.9 2.2

Disc Rate, % 6.7 6.9 4.4 4.4 4.4

Asset Grth, % 5.4 -13.1 3.9 1.6 4.6

Value/Cost, x 0.7 0.7 0.6 0.7 0.7

Economic PE, x 42.0 -42.0 -11.8 -34.8 29.7

Leverage, % 58.6 63.1 80.7 81.8 83.1

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-2.0% -291% -174% -41% 110%

370%

281%

-1.0% -260% -140% -4% 151% 326%

0.0% -228% -105% 34% 192%

459%

1.0% -197% -71% 71% 233% 415%

2.0% -165% -37% 109% 273%

More than

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Within 10%More than

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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025

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EBITDA Margin

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Asset Growth (in %)

19 September 2016


Figure 170: Summary financials – PGS

Divisionals 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Marine contract Revenue 698 274 233 249 274 308 355

growth 3% -61% -15% 7% 10% 13% 15%

Multiclient Revenue 600 575 481 554 659 791 852

growth -11% -4% -16% 15% 19% 20% 8%

Pre-funding Revenue 291 380 228 257 295 354 372

growth -19% 31% -40% 13% 15% 20% 5%

Late sales Revenue 309 194 253 297 364 436 480

growth -1% -37% 30% 18% 23% 20% 10%

Imaging Revenue 119 94 61 67 77 91 109

growth -3% -21% -35% 10% 15% 18% 20%

Other Revenue 37 20 20 21 22 23 24

growth 25% -47% 2% 5% 5% 5% 5%

Group EBIT 177 16 -140 -55 34 147 248

growth -55% -91% -981% -60% -161% 334% 69%

margin 12.2% 1.7% -17.6% -6.2% 3.3% 12.1% 18.5%

P&L 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 1454 962 795 891 1032 1213 1340

growth -3% -34% -17% 12% 16% 18% 10%

EBITDA (adj) 703 484 300 415 541 687 796

D&A -598 -915 -449 -470 -507 -541 -548

Share of JVs / Associates -31 -16 -16 -19 -21 -18 -19

Other gains / losses / impairments -73.1 -446.1 -9.8 0 0 0 0

EBIT 177 16 -140 -55 34 147 248

growth -15% -31% -38% 38% 30% 27% 16%

margin 12.2% 1.7% -17.6% -6.2% 3.3% 12.1% 18.5%


Pre-tax profit 17 -505 -202 -116 -27 90 194

Tax -68 -22 -20 -17 14 -23 -48

Effective Tax rate (underlying) 405% -4% -10% -15% 50% 25% 25%

Net profit -51 -528 -222 -133 -14 68 145

Adj Net profit 2 -202 -215 -133 -14 68 145

No. Shares (FD) 215 218 239 239 239 239 239

EPS (CS, Adj) 0.01 -0.92 -0.90 -0.56 -0.06 0.28 0.61

EPS (IFRS) -0.24 -2.42 -0.93 -0.56 -0.06 0.28 0.61

DPS 0.11 0.00 0.00 0.00 0.00 0.14 0.30


19 September 2016


Figure 171: Cash flow and balance sheet – PGS

Cash Flow 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Net profit (loss) for the year -51 -528 -222 -133 -14 68 145

Operating cash adjustments 663 901 460 490 528 559 566

Change in working capital -28 115 14 -13 -16 -21 -16

Net cash provided by operating activities 584 488 252 343 498 606 696

Capex (inc intangible) -442 -207 -225 -129 -77 -97 -115

Capex (multi-client) -344 -303 -225 -254 -292 -350 -368

Free cash flow -202 -23 -198 -40 129 159 213

Other investing cash flows 0 84 0 0 0 0 0

Net cash used in investing activities -786 -427 -450 -383 -369 -447 -483

Change in borrowings 149 -64 193 0 0 0 0

Dividend -84 -20 0 0 0 0 -34

Other financing cash flows -72 50 0 0 0 0 0

Net cash used in financing activities -7 -34 193 0 0 0 -34

Net cash flow -209 27 -5 -40 129 159 179


Net cash / (debt) -1038 -972 -1180 -1219 -1091 -932 -752

Balance Sheet 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Property and equipment 1664 1398 1495 1486 1419 1371 1339

Multiclient Library 695 695 607 529 458 413 380

Goodwill & Intangibles 324 162 162 162 162 162 162

Restricted Cash 72 53 53 53 53 53 53

Other Non-current assets 151 137 137 137 137 137 137

Total non-current assets 2906 2444 2454 2367 2229 2135 2070

Accounts receivable 266 113 111 124 144 169 187

Accrued revenues and other

receivables

181 158 158 158 158 158 158


Restricted Cash 20 19 19 19 19 19 19


Total current assets 657 470 588 562 710 895 1092

Total assets 3563 2914 3042 2929 2939 3030 3162

Short-term debt and current portion of

long-term debt

25 25 38 38 38 38 38

Accounts payable 75 53 65 65 68 73 75

Accrued expenses 272 197 197 197 197 197 197


Total current liabilities 410 298 349 369 393 416 436

Long-term debt 1160 1100 1291 1291 1291 1291 1291

Other long-term liabilities 92 52 52 52 52 52 52






19 September 2016


PEERs







Figure 172: PGS in PEERs


19 September 2016


Europe/Italy Oil & Gas Equipment & Services

Saipem (SPMI.MI) Rating NEUTRAL [V] Price (13 Sep 16, €) 0.38 Target price (€) 0.45 Market Cap (€ m) 3,805.3 Enterprise value (€ m) 6,601.6 *Stock ratings are relative to the coverage universe in each




Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Rehabilitation requires patience

■ Initiate at Neutral, TP EUR0.45: The rehabilitation of SPM is far from

complete, but this long cycle business is slowly moving in the right direction,

buoyed by recent contract wins that support further progress. However,

significant risks remain, particularly around pending revenues, arbitration/

litigation (notably in Algeria), Offshore Drilling re-contracting, and net debt/

financing. The turbulence of recent years looks likely to continue, although

the bumps may be easier to withstand.

■ Better positioned for new orders than most. The SPM equity story relies

on sustained strong momentum in Offshore E&C more than compensating for

growing headwinds in Offshore Drilling as positive cycle contracts roll-over. A

EUR35bn pipeline shows SPM is not short of opportunities to bolster ytd

momentum. Its early positioning in Iran is also differentiated. However we do

not think the 2016/17 outlook is supportive enough for SPM to meet medium-

term targets.

■ Catalysts: SPM is chasing major contract awards; perceived to be good

quality orders should be well received; resolution to outstanding litigation,

progress on financing; Q316 results on 26 October should provide 2017

guidance.

■ Valuation: We value SPM on an equally weighted SOTP / DCF, deriving a

EUR0.45 target price. Post the capital raise, Saipem appears to be good

value on EV/EBITDA metrics (less so on PE) relative to peers/history.

However, we believe medium-term financial targets are unrealistic

(downgrades possible at Q3 results), and there are several risk items

(including legal situations, investigations, disputes, working capital issues),

which are hard to price. We’d like to see many of these issues resolved.



FTSEUROFIRST 300 INDEX which closed at 1332.9 on

13/09/16


Eu.89/US$1



Year 12/15A 12/16E 12/17E 12/18E Revenue (€ m) 11,507 10,440 9,407 9,021 EBITDAX (€ m) 487.0 1296.8 1226.2 1168.2 Adjusted net income (€ m) -608.0 253.4 268.3 261.2 CS EPS (adj.) (€) -0.06 0.03 0.03 0.03 Prev. EPS (€) ROIC avg (%) -3.7 3.9 4.0 3.9 P/E (adj.) (x) -6.3 15.0 14.2 14.6 P/E rel. (%) -37.9 103.7 132.3 155.2 EV/EBITDAX (x) 19.0 4.2 4.2 4.1

Dividend (12/16E, €) 0.00 Net debt/equity (12/16E,%) 23.4 Dividend yield (12/16E,%) 0.0 Net debt (12/16E, € m) 1,686.8 BV/share (12/16E, €) 0.7 IC (12/16E, € m) 8,895.2 Free float (%) 55.0 EV/IC (12/16E, (x) 0.6 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Saipem (SPMI.MI)

Price (13 Sep 2016): €0.3764; Rating: NEUTRAL [V]; Target Price: €0.45; Analyst: Phillip Lindsay

Income statement (€ m) 12/15A 12/16E 12/17E 12/18E

Revenue 11,507 10,440 9,407 9,021 EBITDA 487 1,297 1,226 1,168 Depr. & amort. (741) (694) (689) (643) EBIT (254) 603 537 525 Net interest exp. (244) (163) (126) (124) Associates 16 13 13 13 PBT (464) 464 434 422 Income taxes (127) (195) (152) (148) Profit after tax (591) 269 282 275 Minorities (17) (15) (14) (13) Preferred dividends - - - - Associates & other 0 0 0 0 Net profit (608) 253 268 261 Other NPAT adjustments (198) (100) (13) (13) Reported net income (806) 154 256 249

Cash flow (€ m) 12/15A 12/16E 12/17E 12/18E

EBIT (254) 603 537 525 Net interest 191 0 0 0 Cash taxes paid 127 0 0 0 Change in working capital 322 485 485 485 Other cash and non-cash items (893) (348) (216) (190) Cash flow from operations (507) 740 806 820 CAPEX (550) (403) (407) (506) Free cashflow to the firm (1,002) 337 440 415 Acquisitions - - - - Divestments 185 0 0 0 Other investment/(outflows) (30) (13) (12) (12) Cash flow from investments (395) (416) (419) (518) Net share issue/(repurchase) - 3,436 - - Dividends paid (17) 0 0 0 Issuance (retirement) of debt 818 0 0 0 Cashflow from financing 354 436 0 0 Changes in net cash/debt (955) 3,760 387 302 Net debt at start 4,492 5,447 1,687 1,299 Change in net debt 955 (3,760) (387) (302) Net debt at end 5,447 1,687 1,299 997

Balance sheet (€ m) 12/15A 12/16E 12/17E 12/18E


Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 10,110 10,110 10,110 10,110 CS EPS (adj.) (€) (0.06) 0.03 0.03 0.03 Prev. EPS (€) Dividend (€) 0.00 0.00 0.00 0.00 Free cash flow per share (€) (0.10) 0.03 0.04 0.03

Valuation 12/15A 12/16E 12/17E 12/18E

EV/Sales (x) 0.8 0.5 0.5 0.5 EV/EBITDA (x) 19.0 4.2 4.2 4.1 EV/EBIT (x) (36.4) 9.1 9.5 9.1 Dividend yield (%) 0.00 0.00 0.00 0.00 P/E (x) (6.3) 15.0 14.2 14.6


ROE (%) (13.9) 4.5 3.8 3.6 ROIC (avg.) (%) (3.7) 3.9 4.0 3.9


Net debt/equity (%) 154.8 23.4 17.4 12.9 Dividend payout ratio (%) -0.0 0.0 0.0 0.0

Company Background

Saipem is an integrated engineering, construction and drilling company with operations both on and offshore



For blue sky we assume revenues +7.5 / 5.0 / 5.0 / 5.0% higher from our base case for offshore E&C, Onshore E&C, Offshore Drilling and Onshore Drilling, respectively. For blue sky margin we assume multiples +2.0 / 1.0 / 1.5 / 1.0% higher from our base scenario for 2017 (diluted impact in 2017). In our SOTP we assume multiples 2.0 / 1.5 / 1.0 / 1.5pts higher than our base case and flex DCF for long

term growth by +.25%


For grey sky we assume revenues -7.5 / 5.0 / 5.0 / 5.0% higher from our base case for offshore E&C, Onshore E&C, Offshore Drilling and Onshore Drilling, respectively. For grey sky margin we assume multiples -2.0 / 1.0 / 1.5 / 1.0% higher from our base scenario for 2017 (diluted impact in 2017). In our SOTP we assume multiples 2.0 / 1.5 / 1.0 / 1.5pts lower than our base case and flex DCF for long term growth by -.25%


The price relative chart measures performance against the FTSEUROFIRST

300 INDEX which closed at 1332.9 on 13/09/16



19 September 2016


Saipem in charts

Figure 173: New orders and book-to-bill Figure 174: Backlog evolution


Figure 175: Key contracts being bid (USDm) Figure 176: Current bids by region (USDm)

Source: MEED, Upstream, Credit Suisse Research, data correct as of September 7th 2016 Source: MEED, Upstream, Credit Suisse Research, data correct as of September 7

th 2016

Figure 177: Offshore drilling commitments


0.99 1.02

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Offshore Onshore Drilling: Offshore

Drilling: Onshore Book to bill

7518

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Eni Portugal

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Eni Angola

Eni North Sea

Eni Indonesia

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Statoil North Sea

Perro Negro 8 NDC Abu Dhabi

Perro Negro 7 Saudi Aramco Saudi Arabia

Perro Negro 5 Saudi Aramco Saudi Arabia

Perro Negro 4 Petrobel Egypt

Perro Negro 3 -

Perro Negro 2 NDC Abu Dhabi

TAD Eni Congo

New contract

Hi Spec

Saipem 12000

Saipem 10000

Scarabeo 9

Scarabeo 8

Scarabeo 7

2016 2017 2018 2019 2020

Contracted to 2024

Committed Standby Termination fee

Scarabeo 6

Scarabeo 5

Sta

ndard

19 September 2016


Saipem (SPM)

Divisional review – Offshore E&C. 2017 appears to be a critical year – the vessel

intensive offshore campaign on Zohr has filled scheduling gaps for key vessels including

Castorone but others (Saipem7000 for example) are still at risk of idleness. This is a

headwind to margin accretion although we think the underlying quality of backlog is the

best it’s been in several years, and this should be sufficient to drive margins forward in

2017.

Divisional review – Onshore E&C. The overall business is tracking a recovery trend

having been above break-even for the last 12 months, and recent contract wins should

support further margin improvement in the medium term despite top-line pressures as the

backlog erodes. There are significant medium-term opportunities for new orders with

several prospects in the Middle East and Africa.

Divisional review – Offshore Drilling. While more resilient than offshore drilling peers to

date, several assets continue to operate on inflated day rates from pre-downturn contract

signatures. However, half the active deepwater fleet (Scarabeo units 5 with Statoil, and 8

and 9 with ENI) have contract expiries in 2017 (with Scarabeo 7 with ENI expiring early in

2018) and Saipem 12000 has limited visibility. Our forecasts of operator production

profiles suggest re-contracting with existing customers in current locations could be

challenging, potentially leaving several assets fighting for work in a heavily oversupplied

market. At best, in our view, SPM will likely secure work for these assets at materially

lower prevailing spot rates.

Divisional review – Onshore drilling. Middle East operations have been stable but over-

exposure to a savage downturn in Latin America (Venezuela in particular) is hurting this

business; it has been marginally loss making for the last three quarters cumulative.

Onshore Drilling could be a potential disposal candidate although a sale in the current

market may be suboptimal.

Balance sheet – The Q1 2016 EUR3.5bn capital raise improved Saipem’s financial

position. However meeting net debt targets is not easy given the downturn; quarterly

working capital swings can be volatile and receiving timely payments from customers is

challenging. Recent progress replacing the EUR1.5bn bridge-to-bond, which expires mid-

2017, has been positive with the EUR1bn bond issuance, despite S&P’s downgrade to

sub-investment grade in May 2016. The residual EUR400m is less of a concern now.

Backlog development – In line with previous cycles, SPM has outperformed the wider

market on order intake through the downturn, notably in Offshore E&C, where the run-rate

book-to-bill of 0.7x for last six quarters should be improved upon in Q3 based on secured

work. The pipeline, which Saipem values at around EUR35bn, remains healthy with ENI’s

West Hub and various contracts through Saudi Aramco’s LTAs looking promising for near-

term awards. If Turkish Stream goes ahead we believe Saipem would be well placed.

Forecasts – we are in line with company guidance for 2016 (but above consensus), but

we are materially above consensus in 2017, where we believe the market underestimates

the underlying quality of Saipem’s backlog (our revenues are in line with the street, but we

assume higher margins). Our forecasts in 2018/19 see Saipem underachieving relative to

financial targets. The overarching theme across our forecasts is one of revenue pressures

but gradual margin improvement.

Valuation – we value SPM on an equally-weighted SOTP and DCF. SPM may look good

value on EV/EBITDA metrics versus peers and historical valuations. If SPM can

successfully navigate the next several years and drive significant improvement in line with

its financial plan, we think the stock could perform well. However, we do not believe

market conditions are supportive enough to deliver on its aspiration. Furthermore there are

notable risks around pending revenues, arbitration / litigation (notably in Algeria), Offshore

19 September 2016


Drilling re-contracting, and net debt / financing. We do not attempt to quantify legal and

other situations that could result in a meaningful charge, but investors should be aware of

these “known unknowns”. In essence, we see a balanced risk / reward.


■ For Offshore E&C, we assume blue / grey sky revenues +/- 7.5% from our base case

scenario with margins +/- 2.0% for 2017 and beyond (diluted impact for 2016)

■ For Onshore E&C we assume blue / grey sky revenues +/- 5% and margins +/- 1.0%

from our base case scenario for 2017 and beyond (diluted impact for 2016)

■ For Offshore Drilling, we assume blue / grey sky revenues +/- 5% and margins +/-

1.5% from our base case scenario for 2017 and beyond (diluted impact for 2016)

■ For Onshore Drilling, we assume blue / grey sky revenues +/- 5% and margins +/-

1.0% from our base case scenario for 2017 and beyond (diluted impact for 2016)

■ In our SOTP, we assume multiples 2.0 / 1.5 / 1.0 / 1.5 pts higher / lower than our base

case for Offshore E&C, Onshore E&C, Offshore Drilling and Onshore Drilling

respectively. We flex DCF for long-term growth by +/- 0.25%.

19 September 2016


Figure 178: Summary financials – Saipem

SOTP (EURm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV


Offshore 695 5643 6 0.7 4168 3777

Onshore 59 2543 4.0 0.1 236 251

Drilling - Offshore 368 768 3 1.4 1103 1025

Drilling - Onshore 105 453 4 0.9 419 467

Total 1226 9407 5 0.6 5927 5521

Net cash / (debt) -1299 -997


Implied market value (EURm) 4807 4703


DCF (EURm)


premium

1.25 5.50% 8.1% 2.00%

EV 5270 5205

Net (debt) / cash -1299 -997


MV 4151 4387



SOTP 0.47 0.48 0.47

DCF 0.42 0.41 0.44

Overall average (equally weighted) 0.45

Blue Sky / Grey Sky


SOTP 75% 0.82 0.89 0.75

DCF 90% 0.81 0.78 0.84

Overall average (equally weighted) 82% 0.82


SOTP -54% 0.21 0.18 0.25

DCF -56% 0.19 0.19 0.19

Overall average (equally weighted) -55% 0.20


19 September 2016


HOLT







forecast returns to decline to 1.8% in 2023 and recover to 2.2% by 2025.






5.15% for each.

The above assumptions suggest a HOLT warranted value of EUR 0.55 versus our target

price of EUR0.45.

19 September 2016


Figure 179: Saipem in HOLT

Source: HOLT®

Current Price: EUR 0.38 Warranted Price: EUR 0.55 Valuation date: 13-Sep-16


EUR -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % 5.0 -10.6 -9.3 -9.9 -4.1

EBITDA Mgn, % 9.4 4.4 12.4 13.0 12.9

Asset Turns, x 0.37 0.3 0.3 0.3 0.3

CFROI®, % 3.4 -0.4 2.9 2.0 1.4

Disc Rate, % 7.0 7.7 5.2 5.2 5.2

Asset Grth, % 16.8 0.9 -0.2 -2.1 -0.3

Value/Cost, x 0.9 0.9 0.7 0.6 0.6

Economic PE, x 26.9 -209.5 22.8 31.2 42.9

Leverage, % 73.5 81.0 79.0 78.2 78.1

More than

10%

downside

Within 10%More than

10% upside

Source: Credit Suisse HOLT®. CFROI and HOLTare trademarks or registered trademarks of Credit Suisse Group AG or its affiliates in the United States and other countries .

193%

1.0% 9% 38% 71% 108% 149%

2.0% 41% 72% 108% 148%

27% 61%

0.0% -22% 4% 33% 67%

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LT

-

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it S

uis

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naly

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ata

SAIPEM SPA (SPMI)

EB

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A M

arg

in (

para

llel

% p

oin

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an

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ore

casts

)

-2.0% -86% -65% -41% -14%

105%

17%

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Asset Turns (x)

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-20

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1996 1999 2002 2005 2008 2011 2014 2017 2020 2023


Asset Growth (in %)

19 September 2016


Figure 180: Summary financials – Saipem

Divisionals (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Offshore Revenue 7202 6890 6270 5643 5361 5763 6339

growth 40% -4% -9% -10% -5% 8% 10%

EBIT 435 192 332 327 338 406 479

growth 378% -56% 73% -2% 3% 20% 18%

margin 6.0% 2.8% 5.3% 5.8% 6.3% 7.1% 7.6%

Onshore Revenue 3765 2788 2676 2543 2543 2797 3356

growth -22% -26% -4% -5% 0% 10% 20%

EBIT -411 -693 20 32 44 63 92

growth 2% 69% -103% 58% 40% 41% 47%

margin -10.9% -24.9% 0.8% 1.3% 1.8% 2.3% 2.8%

Drilling: Offshore Revenue 1192 1067 960 768 653 653 669

growth 1% -10% -10% -20% -15% 0% 3%

EBIT 350 295 245 169 124 124 131

growth -16% -17% -31% -27% 0% 5% 10%

margin 29.4% 27.6% 25.5% 22.0% 19.0% 19.0% 19.5%

Drilling: Onshore Revenue 714 762 533 453 465 488 525

growth -1% 7% -30% -15% 3% 5% 8%

EBIT 91 -48 5 9 19 29 42

growth 0% -153% -111% 70% 105% 58% 43%

margin 12.7% -6.3% 1.0% 2.0% 4.0% 6.0% 8.0%

P&L 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 12873 11507 10440 9407 9021 9701 10889

growth 9% -11% -9% -10% -4% 8% 12%

EBITDA (adj) 1212 508 1297 1226 1168 1300 1476

D&A -747 -762 -694 -689 -643 -677 -733

EBIT 465 -254 603 537 525 623 743

growth 196% -155% -337% -11% -2% 19% 19%

margin 3.6% -2.2% 5.8% 5.7% 5.8% 6.4% 6.8%


Other gains / losses / impairments 4 18 11 10 9 10 12

Exceptionals -410 -198 -87 0 0 0 0

Pre-tax profit (Adj) 270 -480 451 421 410 510 632

Pre-tax profit -140 -678 364 421 410 510 632

Tax -118 -127 -195 -152 -148 -184 -226

Effective Tax rate (underlying) 41% -27% 42% 35% 35% 35% 35%

Minority Interest 8 -17 -15 -14 -13 -14 -16

Adj Net profit 160 -624 241 256 249 312 390

Net profit -250 -822 154 256 249 312 390

No. Shares (FD) 10110 10110 10110 10110 10110 10110 10110

EPS (CS, Adj) 0.02 -0.06 0.02 0.03 0.02 0.03 0.04

EPS (IFRS) -0.02 -0.08 0.02 0.03 0.02 0.03 0.04

DPS 0.00 0.00 0.00 0.00 0.00 0.00 0.00


19 September 2016


Figure 181: Cash flow and balance sheet – Saipem

Cash flow (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Net income / (losses) -230 -806 154 256 249 312 390


Working cap movement 569 -468 -108 -139 -72 -310 -342

Net cash flow from operations 1198 -507 740 806 820 679 781


Free cash flow 504 -1068 324 387 302 1 -97

Other investing cash flows -4 166 0 0 0 0 0


Change in borrowings -170 370 -3000 0 0 0 0

DPS cash cost -45 -17 0 0 0 0 0

Capital increase 0 0 3436 0 0 0 0

Other financing cash flows 18 13 0 0 0 0 0

Net cash flow from financing activities -197 366 436 0 0 0 0

Net cash flow 303 -536 760 387 302 1 -97


Net cash / (debt) -4424 -5390 -1687 -1299 -997 -996 -1093

Balance Sheet (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E


Intangible assets, net 760 758 760 761 761 763 764




Inventories 2485 2286 1738 1584 1515 1676 1947




Total assets 17594 16319 15908 15620 15642 16126 16928


ST borrowings 2780 3672 972 972 972 972 972



Long-term debts 3314 2841 2541 2541 2541 2541 2541

Provisions for contingencies 218 238 238 238 238 238 238


Total Non-Current Liabilities 3811 3342 3042 3042 3042 3042 3042



Total Shareholders equity 4178 3519 7208 7477 7738 8065 8468



19 September 2016


PEERs







Figure 182: Saipem in PEERs


19 September 2016


Europe/Austria Oil & Gas Equipment & Services

Schoeller Bleckmann Oilfield

Equipment (SBOE.VI) Rating OUTPERFORM Price (13 Sep 16, €) 52.65 Target price (€) 70.00 Market Cap (€ m) 842.4 Enterprise value (€ m) 866.7 *Stock ratings are relative to the coverage universe in each



Research Analysts

Gregory Brown

44 20 7888 1440

[email protected]

Phillip Lindsay

44 20 7883 1644

[email protected]

Best EU play on US unconventionals

■ Initiate at Outperform, TP EUR70: SBO’s build out of the completions

business line gives it faster growth potential (completion of the industry’s

inventory of DUCs would be positive) in a recovery plus greater balance over

the cycle. An uptick in drilling activity is a promising lead indicator for

rebuilding High Precision Components’ backlog, where customer inventory

levels are currently low. Oilfield Equipment (drilling motors / circulation tools)

is also poised to benefit from growth in drilling activity.

■ Rig count expectation vs underlying trends: Rig count has become less

important as an indicator of overall demand for SBO’s product lines.

Underlying trends in directional drilling and downhole completions are more

prominent factors. Well count, lateral size and frac stage count data are less

readily available versus the rig count data, but these underlying trends have

remained positive through this downturn. SBO’s products enable more

effective oil production; such technologies should achieve above average

growth in the recovery cycle and customers chase returns over growth.

■ Catalysts: Further rig count momentum would be positive; key customer /

competitor commentary; further M&A activity, Q3 results: 23 November.

■ Valuation: SBO has made good acquisitions during the downturn, utilizing

the strong balance sheet it built up through last cycle. SBO today provides

more leverage to the recovery cycle than SBO of the last cycle, and we

expect sharp increases in US Unconventional activity in 2017/18. We believe

investors should look through recovery-type multiples in 2017 into 2018

where a low 20s PE and EV/EBITDA of 8x are in line with historical averages.

However we think the earnings capacity of the business is more than double

2018 forecasts. We therefore see an attractive risk / reward – in our

European coverage, we believe SBO is the best way to play the recovery in

US Unconventionals.



VIENNA SE AUSTRIAN TRADED IDX Index which closed

at 2356.4 on 13/09/16


Eu.89/US$1

Performance 1M 3M 12M Absolute (%) -11.0 1.6 6.6 Relative (%) -13.9 -10.8 3.2


Year 12/15A 12/16E 12/17E 12/18E Revenue (€ m) 314 180 260 343 EBITDAX (€ m) 55.1 3.0 73.8 115.4 Adjusted net income (€ m) -19.0 -30.6 16.2 42.2 CS EPS (adj.) (€) -1.19 -1.92 1.02 2.65 Prev. EPS (€) ROIC avg (%) 0.8 -6.4 4.2 10.0 P/E (adj.) (x) -44.3 -27.5 51.8 19.9 P/E rel. (%) -362.0 -223.3 466.3 196.3 EV/EBITDAX (x) 14.8 296.9 11.7 7.3

Dividend (12/16E, €) 0.50 Net debt/equity (12/16E,%) 11.0 Dividend yield (12/16E,%) 0.9 Net debt (12/16E, € m) 45.4 BV/share (12/16E, €) 25.8 IC (12/16E, € m) 457.2 Free float (%) 66.5 EV/IC (12/16E, (x) 1.9 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Schoeller Bleckmann Oilfield Equipment (SBOE.VI)

Price (13 Sep 2016): €52.65; Rating: OUTPERFORM; Target Price: €70.00; Analyst: Gregory Brown


Revenue 314 180 260 343 EBITDA 55 3 74 115 Depr. & amort. (51) (41) (47) (51) EBIT 4 (38) 27 64 Net interest exp. (3) (3) (4) (4) Associates 0 0 0 0 PBT (20) (41) 23 60 Income taxes 1 10 (7) (18) Profit after tax (19) (31) 16 42 Minorities - - - - Preferred dividends - - - - Associates & other 0 0 0 0 Net profit (19) (31) 16 42 Other NPAT adjustments 0 0 0 0 Reported net income (19) (31) 16 42

Cash flow (€ m) 12/15A 12/16E 12/17E 12/18E

EBIT 4 (38) 27 64 Net interest (4) (3) (4) (4) Cash taxes paid - - - - Change in working capital 57 60 (2) (23) Other cash and non-cash items 46 51 40 33 Cash flow from operations 103 70 61 70 CAPEX (23) (11) (22) (33) Free cashflow to the firm 81 59 39 37 Acquisitions - - - - Divestments 5 0 0 0 Other investment/(outflows) (0) (95) (7) (10) Cash flow from investments (18) (106) (29) (42) Net share issue/(repurchase) - - - - Dividends paid (24) (8) (8) (8) Issuance (retirement) of debt - - - - Cashflow from financing (25) (8) (8) (8) Changes in net cash/debt 62 (72) 24 20 Net debt at start 36 (26) 45 22 Change in net debt (62) 72 (24) (20) Net debt at end (26) 45 22 2


Assets Total current assets 391 280 313 366 Total assets 741 693 709 753 Liabilities Total current liabilities 87 86 87 90 Total liabilities 290 282 289 299 Total equity and liabilities 741 693 709 753

Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 16 16 16 16 CS EPS (adj.) (€) (1.19) (1.92) 1.02 2.65 Prev. EPS (€) Dividend (€) 0.50 0.50 0.50 0.50 Free cash flow per share (€) 5.05 3.70 2.45 2.34

Valuation 12/15A 12/16E 12/17E 12/18E

EV/Sales (x) 2.6 4.9 3.3 2.5 EV/EBITDA (x) 14.8 296.9 11.7 7.3 EV/EBIT (x) 217.9 (23.7) 32.0 13.2 Dividend yield (%) 0.95 0.95 0.95 0.95 P/E (x) (44.3) (27.5) 51.8 19.9


ROE (%) (4.2) (7.1) 3.9 9.7 ROIC (avg.) (%) 0.8 (6.4) 4.2 10.0


Net debt/equity (%) (5.8) 11.0 5.1 0.4 Dividend payout ratio (%) (42.0) (26.1) 49.1 18.9

Company Background

Schoeller-Bleckmann Oilfield Equipment AG (SBO) is the global market leader for high-precision components for the oil service industry. The group manufactures drilling motors and drilling tools and offers to its customers full-scale repair.



For High Precision Components, we assume blue sky revenues +5% from our base case scenario with margins +1% for 2017 and beyond (diluted impact for 2016). For Oilfield Equipment/Well Completion, we assume blue sky revenues +7.5% and margins

+2.0% from our base case scenario for 2017 and beyond (diluted impact for 2016). In our SOTP, we assume multiples 1.5 pts higher than our base case for HPC. We flex DCF long-term growth by +0.25%


For High Precision Components, we assume grey sky revenues -5% from our base case scenario with margins -1% for 2017 and beyond (diluted impact for 2016). For Oilfield Equipment/Well Completion, we assume grey sky revenues -7.5% and margins -2.0% from our base case scenario for 2017 and beyond (diluted impact for 2016). In our SOTP, we assume multiples 1.5 pts lower than our base case for HPC. We flex DCF long-term growth by -0.25%


The price relative chart measures performance against the VIENNA SE

AUSTRIAN TRADED IDX Index which closed at 2356.4 on 13/09/16


Source: Company data, Thomson Reuters, Credit Suisse estimates.

19 September 2016


Schoeller Bleckmann in charts

Figure 183: Indexed US rig count vs. previous

cycles Figure 184: CS North American rig count forecast

Source: Baker Hughes International, Credit Suisse Research Source: Baker Hughes International, Credit Suisse estimates

Figure 185: Group incremental / decremental margin Figure 186: EBITDA/EBIT and gearing


Figure 187: HPC revenue / EBIT vs. rig count Figure 188: OE revenue / EBIT vs. rig count


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19 September 2016


Schoeller Bleckmann (SBO)

Divisional review – Oilfield Equipment: The downhole tools (drilling motors, circulation

tools) business line has used the sharp downturn in US unconventionals to internationalise

the business through directing tools into new markets - with decent market penetration in

the Middle East (Dubai/Saudi, plus Iran has medium-term promise) and parts of Asia (Iran

and China could also be attractive medium-term targets) and Russia. Market acceptance

of SBO’s high performance fleet has been good as several of these markets take to

geologically more challenging drilling and use of directional drilling.

Divisional review – High Precision Components: We have seen two smaller

competitors go out of business thus far in the downturn. This business benefited from

record bookings in 2014, giving some cushion to 2015 numbers, but current run-rates are

not enough to support profitable operations. The customer base is likely to have

consumed significant inventory through the downturn, which could drive a sharp uptick in

orders once business confidence and activity rebound, although we believe its customers

will look to operate with lower inventory in a recovery cycle. The ability to shorten lead

times therefore is crucial to the longer-term success of HPC. This business is usually the

last of SBO’s business units to recover in a downturn, however the recovery cycle could

yield positive results as SBO defended gross margin as much as possible thus far in the

downturn - single digit concessions in 2015, double digit from the peak now in 2016 –

compared to more commoditized product lines, we view this as defensive.

Divisional review – Well Completion: The USD103m acquisition of 68% of Downhole

Technologies is the largest in SBO’s history. Downhole expands SBO’s product line of

niche, highly specialized products. The business’ main product line is ‘composite frac

plugs’ – or the ‘plug’ in ‘plug and perf’ which is the dominant well completion technology for

unconventionals. This is SBO’s second acquisition, after 2014’s investment in Resource (a

sliding sleeve technology provider), as it builds a Well Completion product line. There may

be more to come – obvious gaps would include the actual perforating guns/charges

(similar to Hunting and Core Labs). Synergies in terms of cost are somewhat limited (some

economies of scale in procurement) but business development teams have a far broader

portfolio of products to cross sell.

Balance sheet and DPS: SBO’s balance sheet currently would be unlikely to support

another acquisition of the scale of Downhole. Small technology bolt-ons and distressed

situations are more likely candidates near term with potential for bigger deals in the

medium term as liquidity improves. SBO also increased debt by EUR27m to provide more

flexibility (not used for the acquisition of Downhole but could be earmarked for a bolt-on) –

and secured a favorable interest rate of 2%. Like the last cycle, SBO has again rebased

dividend back to EUR0.50 but it would look to increase it as market conditions improve.

Forecasts: Schoeller Bleckmann is highly geared into a recovery in global drilling activity,

particularly for US Unconventionals after the two Well Completion acquisitions. We see

2016 as the bottom, and a loss making year for SBO, but expect a significant recovery in

2017/18e. We are materially below consensus forecasts for 2017/18 although we believe

consensus to be unreliable with several stale numbers.

Valuation and view: We initiate on SBO at Outperform with a target price of EUR70.

Manufacturing of short-cycle consumable products should see a very strong and early

recovery, and we expect a more returns-focused industry will lean towards higher-end

technology rather than low-cost provider. We think SBO has made a number of good

acquisitions during the downturn, utilizing the strong balance sheet it built up through the

last cycle. As such, SBO today provides more leverage to the recovery cycle than the SBO

of last cycle. Rig count trends have bottomed and are beginning to demonstrate positive

trends – we expect sharp increases in US Unconventional activity in 2017/18e. We believe

the market should largely ignore the recovery-type multiples SBO is trading on in 2017E (a

19 September 2016


PE > 50x, EV/EBITDA 13x). The multiples fall sharply in 2018 to a low 20s PE and

EV/EBITDA of 8x – these are more in line with historical averages. However, we think the

earnings capacity of the business is more than double our 2018 forecasts. We therefore

see an attractive risk / reward – in our coverage, SBO is the most attractive way to play

the recovery in US Unconventionals, in our opinion.


■ For High Precision Components, we assume blue / grey sky revenues +/- 5% from our

base case scenario with margins +/- 1% for 2017 and beyond (diluted impact for 2016)

■ For Oilfield Equipment / Well Completion, we assume blue / grey sky revenues +/-

7.5% and margins +/- 2.0% from our base case scenario for 2017 and beyond (diluted

impact for 2016)


High Precision Components / Oilfield Equipment and Well Completion. We flex DCF for

long-term growth by +/- 0.25%.

Figure 189: Valuation summary - Schoeller Bleckmann

2017E 2017E EV/EBITA EV/Sales Implied EV Implied EV


High Precision Components 24 110 15.0 3.3 363 375

Oilfield Equipment 51 243 14.0 3.0 716 800

Corporate -2 0 7.5 0.0 -12 -15

Total 500 1497 4.0 0.0 1068 1160



Implied market value (EUR) 1046 1159


DCF (EURm)

Assumptions: Beta Risk Premium WACC LT Growth 2017E 2018E

0.90 5.50% 6.9% 2.0%

EV 1125 1160


MV 1103 1158



SOTP 69 66 73

DCF 71 69 72


Blue Sky / Grey Sky


SOTP 35% 95 87 102

DCF 46% 102 99 106


Grey sky valuation

SOTP -28% 51 50 52

DCF -30% 49 48 50



19 September 2016


HOLT







forecast returns to dip to 3.4% in 2022 and recover to 11% by 2025 - driven by significant

margin expansion and double digit top line growth.






The above assumptions suggest a HOLT warranted value of EUR 78.88, close to our EUR

70 target price.

19 September 2016


Figure 190: Schoeller Bleckmann in HOLT




EUR -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % 6.6 -35.8 -42.6 44.4 31.8

EBITDA Mgn, % 43.4 17.0 1.7 28.4 33.7

Asset Turns, x 0.55 0.3 0.2 0.3 0.4

CFROI®, % 19.1 3.1 -5.7 3.7 7.5

Disc Rate, % 4.8 4.5 5.6 5.6 5.6

Asset Grth, % 13.2 3.5 -14.7 3.7 6.1

Value/Cost, x 1.7 1.4 1.7 1.6 1.5

Economic PE, x 8.8 44.8 -30.2 44.1 20.2

Leverage, % 17.0 21.2 19.7 20.4 21.1

More than

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1.0% 3% 30% 61% 97% 140%

2.0% 12% 40% 72% 110%

71% 111%

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OILFIELD EQUIP. AG (SBOE)

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19 September 2016


Figure 191: Summary financials - Schoeller Bleckmann


High Precision Components Revenue 281 184 92 110 135 169 203

growth -1% -35% -50% 20% 23% 25% 20%

EBIT 37 -6 -18 6 14 26 39

growth 19% -116% 211% -130% 145% 94% 47%

margin 13.3% -3.2% -20.0% 5.0% 10.0% 15.5% 19.0%

Oilfield Equipment Revenue 333 223 167 243 322 402 462

growth 15% -33% -25% 45% 33% 25% 15%

EBIT 72 13 -17 24 55 80 99

growth 3% -81.4% n/a n/a 125.3% 47.1% 23.6%

margin 21.5% 6.0% -10.0% 10.0% 17.0% 20.0% 21.5%

Intersegment Revenue -126 -93 -79 -93 -114 -143 -169

Corporate EBIT -2 -4 -2 -3 -4 -4 -4

P&L 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 489 314 180 260 343 428 497

growth 7% -36% -43% 44% 32% 25% 16%

EBITDA (adj) 189 79 3 74 115 156 188

D&A -82 -75 -41 -47 -51 -54 -55

Other gains / losses / impairments -39 -26 0 0 0 0 0

EBIT 67 -22 -38 27 64 102 134

growth 9% -96% -1095% -172% 137% 60% 31%

margin 13.8% -7.0% -20.8% 10.4% 18.7% 23.9% 26.9%

Net finance expense 13 2 -3 -4 -4 -3 -3

Pre-tax profit 80 -20 -41 23 60 99 131

Tax -26 1 10 -7 -18 -30 -39


Minority Interest 0 0 0 0 0 0 0

Net profit 54 -19 -31 16 42 69 91

Adj Net profit 54 -19 -31 16 42 69 91

No. Shares (FD) 16 16 16 16 16 16 16

EPS (CS, Adj) 3.38 -1.19 -1.92 1.02 2.65 4.34 5.73

EPS (IFRS) 3.38 -1.19 -1.92 1.02 2.65 4.34 5.73

DPS 1.50 0.50 0.50 0.50 0.50 0.50 0.50


19 September 2016


Figure 192: Cash flow and balance sheet - Schoeller Bleckmann


Net income / (losses) 54.0 -19.0 -30.6 16.2 42.2 69.3 91.5

Operating cash flows 84.9 65.3 40.5 46.8 51.4 53.5 54.6

Working cap movement -71 57 60 -2 -23 -25 -20

Cashflow from operating activities 68 103 70 61 70 98 126


Free cash flow 23 80 54 32 28 47 68

M&A -23 0 -90 0 0 0 0



Change in borrowings -12 4 0 0 0 0 0

Dividend -24 -24 -8 -8 -8 -8 -8


Cashflow from financing activities -39 -25 -8 -8 -8 -8 -8

Effect of forex differences 8 6 0 0 0 0 0

Net cash flow -28 66 -44 24 20 39 60

Net cash / (debt) -35 26 -45 -22 -2 38 97






Trade accounts receivable 107 49 31 45 59 74 86

Inventories 165 134 87 82 100 119 135




Total assets 800 741 693 709 753 825 917

Trade accounts payable 24 11 16 16 20 24 27




Long-term loans 98 125 158 158 158 158 158







19 September 2016


PEERs







Figure 193: Schoeller Bleckmann in PEERs


19 September 2016


Americas/United States Oil & Gas Equipment & Services

Seadrill (SDRL) Rating UNDERPERFORM [V] Price (13-Sep-16,US$) 2.15 Target price (US$) 1.00 52-week price range 7.72 - 1.63 Market cap (US$ m) 1,093.16 Enterprise value (US$ m) 9,512.77 *Stock ratings are relative to the coverage universe in each




Research Analysts

Gregory Lewis, CFA

212 325 6418

[email protected]

Neesha Khanna

212 325 6974

[email protected]

James Wicklund

214 979 4111

[email protected]

Joseph Nelson

212 538 4894

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Phillip Lindsay

44 20 7883 1644

[email protected]

All drilled out

■ Reiterate Underperform, TP U$1: Like most drillers, SDRL has suffered a

series of contract cancellations and day-rate concessions during this

downturn. Operationally, the company has performed well – aggressive

action on costs and historically high utlisation of floaters and jack-ups have

helped SDRL exceed market expectations on several occasions. However

the fundamentals for offshore drilling appear weak, potentially through to the

end of the decade.

■ Stretched balance sheet: SDRL is working on evaluating financing

alternatives by issuing equity and working with banks to amend near-term

credit facilities. However, at this point, there is no long-term solution in place

that will bridge the company to a potential recovery in offshore drilling. At

Q216, the net debt position stood at USD9.1bn – nearly 95% of SDRL’s EV –

and there is USD4.8bn reaching maturity through 2018.

■ Catalysts: management seems more optimistic than most noting at Q216

that the floater market is showing some signs of a pick-up in short-term

tendering and a bottoming floater count. We are more cautious, but any new

awards could be positive for sentiment. The debt restructuring is the main

event on the horizon – our concern is that equity holders are diluted. SDRL

converted USD55m of its 2017 senior notes for around 8m shares in May.

■ Valuation: SDRL continues to pay down debt (organically), and amend

covenants as part of its restructuring efforts, but there is a lot to do, and

management is trying to complete a restructuring by year end. The sense of

urgency is best illustrated by its net leverage position that we expect it to

increase to ~10x late 2017. We value SDRL on 10x 2017 EBITDA where we

are >10% below consensus.



Daily Sep16, 2015 - Sep13, 2016, 09/16/15 = US$7.51

Quarterly EPS Q1 Q2 Q3 Q4 2015A 0.85 0.77 0.21 0.54 2016E 0.26 0.37 0.19 0.15 2017E 0.06 0.01 -0.09 -0.17


Year 12/15A 12/16E 12/17E 12/18E EPS (CS adj.) (US$) 2.37 0.97 -0.19 -1.40 Prev. EPS (US$) - - - - P/E (x) 0.9 2.2 -11.0 -1.5 P/E rel. (%) 4.3 10.8 -59.2 -9.0 Revenue (US$ m) 4,335.0 3,029.2 2,194.3 1,589.9 EBITDA (US$ m) 2,415.0 1,759.5 984.5 262.0 OCFPS (US$) 3.62 2.45 1.69 0.30 P/OCF (x) 0.9 0.9 1.3 7.2 EV/EBITDA (current) 4.1 5.6 10.0 37.6 Net debt (US$ m) 9,499 8,420 9,529 9,766 ROIC (%) 7.23 3.58 0.66 -2.14

Number of shares (m) 508.44 IC (current, US$ m) 19,474.00 BV/share (Next Qtr., US$) 19.4 EV/IC (x) .5 Net debt (Next Qtr., US$ m) 8,787.1 Dividend (current, US$) - Net debt/tot eq (Next Qtr.,%) 84.2 Dividend yield (%) - Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Seadrill (SDRL)

Price (13 Sep 2016): US$2.15; Rating: UNDERPERFORM [V]; Target Price: US$1.00; Analyst: Gregory Lewis

Income Statement 12/15A 12/16E 12/17E 12/18E

Revenue (US$ m) 4,335.0 3,029.2 2,194.3 1,589.9 EBITDA 2,415 1,760 984 262 Depr. & amort. (779) (787) (815) (800) EBIT (US$) 1,636 973 169 (538) Net interest exp (348) (302) (305) (387) Associates - - - - Other adj. 203 140 85 89 PBT (US$) 1,491 811 (51) (835) Income taxes (208) (246) 11 183 Profit after tax 1,283 565 (40) (652) Minorities - - - (59) Preferred dividends - - - - Associates & other 0 0 0 0 Net profit (US$) 1,283 565 (40) (711) Other NPAT adjustments 0 0 0 0 Reported net income 1,283 565 (40) (711)

Cash Flow 12/15A 12/16E 12/17E 12/18E

EBIT 1,636 973 169 (538) Net interest (348) (302) (305) (387) Cash taxes paid - - - - Change in working capital (2,963) (3,061) (2,717) (2,378) Other cash & non-cash items 3,463 3,619 3,712 3,454 Cash flow from operations 1,788 1,229 860 152 CAPEX (935) (701) (2,369) (1,189) Free cashflow to the firm 853 528 (1,509) (1,037) Aquisitions - - - - Divestments - - - - Other investment/(outflows) 745 483 0 0 Cash flow from investments (190) (218) (2,369) (1,189) Net share issue(/repurchase) 0 0 0 0 Dividends paid 0 0 0 0 Issuance (retirement) of debt (1,340) 95 228 568 Other 2,651 (35) 172 232 Cashflow from financing activities 1,311 60 400 800 Effect of exchange rates (15) 8 0 0 Changes in Net Cash/Debt 2,894 1,079 (1,109) (237) Net debt at start 12,393 9,499 8,420 9,529 Change in net debt (2,894) (1,079) 1,109 237 Net debt at end 9,499 8,420 9,529 9,766

Balance Sheet (US$) 12/15A 12/16E 12/17E 12/18E

Assets Cash & cash equivalents 1,044 2,081 800 331 Account receivables 718 582 452 311 Inventory 0 0 0 0 Other current assets 1,180 1,042 1,042 1,042 Total current assets 2,942 3,705 2,294 1,685 Total fixed assets 14,930 13,893 12,678 11,078 Intangible assets and goodwill 0 0 0 0 Investment securities - - - - Other assets 5,598 5,946 8,365 9,692 Total assets 23,470 23,545 23,336 22,455 Liabilities Accounts payables 141 37 41 43 Short-term debt 1,489 2,347 2,347 2,347 Other short term liabilities 1,836 1,810 1,810 1,810 Total current liabilities 3,466 4,194 4,198 4,200 Long-term debt 9,054 8,154 7,982 7,750 Other liabilities 975 663 663 663 Total liabilities 13,495 13,011 12,843 12,613 Shareholder equity 9,371 9,955 9,856 9,145 Minority interests 604 578 637 696 Total liabilities and equity 23,470 23,545 23,336 22,455 Net debt 9,499 8,420 9,529 9,766

Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg) 494 502 508 508 CS adj. EPS 2.37 0.97 (0.19) (1.40) Prev. EPS (US$) - - - - Dividend (US$) 0.00 0.00 0.00 0.00 Dividend payout ratio 0.00 0.00 -0.00 -0.00 Free cash flow per share 1.73 1.05 (2.97) (2.04)

Earnings 12/15A 12/16E 12/17E 12/18E

Sales growth (%) (13.2) (30.1) (27.6) (27.5) EBIT growth (%) (12.9) (40.5) (82.6) (418.2) Net profit growth (%) 2.4 (56.0) (107.1) (1673.3) EPS growth (%) 0.4 (59.2) (120.1) (619.5) EBITDA margin (%) 55.7 58.1 44.9 16.5 EBIT margin (%) 37.7 32.1 7.7 (33.8) Pretax margin (%) 34.4 26.8 (2.3) (52.5) Net margin (%) 29.6 18.7 (1.8) (44.7)

Valuation 12/15A 12/16E 12/17E 12/18E

EV/Sales (x) 2.44 3.14 4.84 6.83 EV/EBITDA (x) 4.1 5.6 10.0 37.7 EV/EBIT (x) 6.5 9.8 62.8 (20.2) P/E (x) 0.9 2.2 (11.1) (1.5) Price to book (x) 0.1 0.1 0.1 0.1 Asset turnover 0.2 0.1 0.1 0.1

Returns 12/15A 12/16E 12/17E 12/18E

ROE stated-return on (%) 13.4 5.8 (0.4) (7.5) ROIC (%) 0.1 0.0 0.0 (0.0) Interest burden (%) 0.91 0.83 (0.30) 1.55 Tax rate (%) 14.0 30.3 21.9 21.9 Financial leverage (%) 1.13 1.05 1.05 1.10

Gearing 12/15A 12/16E 12/17E 12/18E

Net debt/equity (%) 95.2 79.9 90.8 99.2 Net Debt to EBITDA (x) 3.9 4.8 9.7 37.3 Interest coverage ratio (X) 4.7 3.2 0.6 (1.4)

Quarterly EPS Q1 Q2 Q3 Q4

2015A 0.85 0.77 0.21 0.54 2016E 0.26 0.37 0.19 0.15 2017E 0.06 0.01 -0.09 -0.17



Daily Sep16, 2015 - Sep13, 2016, 09/16/15 = US$7.51

Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016



Subsea 7 S.A. (SUBC.OL) Rating UNDERPERFORM Price (13 Sep 16, Nkr) 84.70 Target price (Nkr) 75.00 Market Cap (Nkr m) 27,728.0 Enterprise value (Nkr m) 25,257.6 *Stock ratings are relative to the coverage universe in each



Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Reality bites

■ Initiate with Underperform, TP NOK75: Backlog awarded in positive market

conditions in the last cycle is about to run out. This leaves SUBC exposed to

the impact of the worst cycle in a generation and needing to secure work –

and we do not expect deepwater markets to improve materially until at least

2018. Furthermore, a significant cash call from working capital, debt

maturities and committed capex could weaken the balance sheet.

■ Early outperformance from a late-cycle play: SUBC has been the best-

performing OFS stock in our coverage ytd by far on significant margin

outperformance, consensus EPS upgrades, and sector-leading book-to-bill.

So what's next? We believe SUBC is well positioned for awards in West /

North Africa and the Gulf of Mexico, there’s further potential in the

renewables sector, and SUBC should benefit from an uptick in marginal field

and tieback development. However, we are concerned about pricing on

current awards, future mix, and an extended period of depressed earnings.

■ Catalysts: Investors should be mindful of positive book-to-bill at the bottom

of the cycle – we think SUBC is well placed for further awards, but embedded

margin concern us. We are seeing consolidation in the subsea sector

(TEC/FMC) – we don’t view SUBC as a potential target, but it could be active

moving into more asset-light service lines. Q3 results on 10 November should

see the last of the good cycle work flowing through the P&L – weak margins /

returns are likely to be the new trends in 2017/18.

■ Valuation: We value SUBC using an equally weighted combination of SOTP

and DCF, deriving a target price of NOK75. In the past SUBC has delivered

poor financial returns, often below WACC and peers. Despite fleet

rationalisation and reorganisation, SUBC remains an inherently capital-

intensive business. We view it as an excellent project manager, but vessel

ownership could be value destructive in a recovery cycle.





Eu.89/US$1

Performance 1M 3M 12M Absolute (%) -8.4 14.5 26.5 Relative (%) -5.8 10.2 22.7


Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ m) 4,758 3,555 3,537 3,354 EBITDAX (US$ m) 1216.9 909.5 474.6 513.9 Adjusted net income (US$ m) 503.9 360.4 69.9 108.0 CS EPS (adj.) (US$) 1.45 1.04 0.20 0.31 Prev. EPS (US$) ROIC avg (%) -2.3 6.1 0.5 1.0 P/E (adj.) (x) 7.0 9.9 50.8 32.9 P/E rel. (%) 55.5 61.4 389.0 296.9 EV/EBITDAX (x) 2.4 3.4 6.4 5.8

Dividend (12/16E, US$) 0.00 Net debt/equity (12/16E,%) -4.1 Dividend yield (12/16E,%) 0.0 Net debt (12/16E, US$ m) -234.1 BV/share (12/16E, US$) 17.6 IC (12/16E, US$ m) 5,472.5 Free float (%) 77.2 EV/IC (12/16E, (x) 0.6 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Subsea 7 S.A. (SUBC.OL)

Price (13 Sep 2016): Nkr84.7; Rating: UNDERPERFORM; Target Price: Nkr75.00; Analyst: Phillip Lindsay


Revenue 4,758 3,555 3,537 3,354 EBITDA 1,217 909 475 514 Depr. & amort. (394) (396) (381) (368) EBIT 601 462 38 77 Net interest exp. (9) (2) (3) (2) Associates 63 41 55 69 PBT 185 501 90 144 Income taxes (222) (155) (28) (45) Profit after tax (37) 345 62 100 Minorities 20 15 8 8 Preferred dividends - - - - Associates & other 521 0 0 0 Net profit 504 360 70 108 Other NPAT adjustments (521) 0 0 0 Reported net income (17) 360 70 108


EBIT 601 462 38 77 Net interest (9) (2) (3) (2) Cash taxes paid (208) (155) (28) (45) Change in working capital 64 (348) (32) (26) Other cash and non-cash items 601 258 365 333 Cash flow from operations 1,049 215 339 338 CAPEX (639) (400) (250) (268) Free cashflow to the firm 899 85 209 195 Acquisitions - - - - Divestments 4 0 0 0 Other investment/(outflows) 81 (4) (4) (4) Cash flow from investments (554) (404) (254) (272) Net share issue/(repurchase) (16) 0 0 0 Dividends paid 0 0 0 0 Issuance (retirement) of debt (1) 0 0 0 Cashflow from financing (96) 0 0 0 Changes in net cash/debt 428 (189) 85 66 Net debt at start 6 (423) (234) (319) Change in net debt (428) 189 (85) (66) Net debt at end (423) (234) (319) (385)



Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 347 347 347 347 CS EPS (adj.) (US$) 1.45 1.04 0.20 0.31 Prev. EPS (US$) Dividend (US$) 0.00 0.00 0.00 0.00 Free cash flow per share (US$) 1.18 (0.53) 0.26 0.20

Valuation 12/15A 12/16E 12/17E 12/18E



ROE (%) 9.2 6.5 1.2 1.8 ROIC (avg.) (%) (2.3) 6.1 0.5 1.0


Net debt/equity (%) (7.9) (4.1) (5.5) (6.5) Dividend payout ratio (%) 0.0 0.0 0.0 0.0

Company Background

Subsea 7 is a provider of subsea to surface engineering and construction services, primarily to the offshore oil and gas industries using its fleet of offshore construction and support vessels.



For SURF & Conventional we assume blue sky revenues +5% from our base case scenario with margins +1.5% for 2017 and beyond (diluted impact for 2016). For i-tech services, we assume blue sky revenues +2.5% and margins +1.0% from our base case for 2017 and beyond (diluted impact for 2016). In our SOTP, we assume

multiples 1.5 / 1.0 higher than our base case for SURF & Conventional/ i-tech services. We flex DCF for long-term growth by +.25%


For SURF & Conventional we assume grey sky revenues -5% from our base case scenario with margins -1.5% for 2017 and beyond (diluted impact for 2016). For i-tech services, we assume grey sky revenues -2.5% and margins -1.0% from our base case for 2017 and beyond (diluted impact for 2016). In our SOTP, we assume multiples 1.5 / 1.0 lower than our base case for SURF & Conventional/ i-tech services. We flex DCF for long-term growth by -.25%



closed at 532.5 on 13/09/16



19 September 2016


Subsea 7 in charts

Figure 194: Backlog by division as of Q2 2016 Figure 195: Backlog scheduling as of Q2 2016

Source: Company data, Credit Suisse research Source: Credit Suisse research

Figure 196: Key contracts being bid (USDm) Figure 197: Capital expenditure (USDm)

Source: MEED, Upstream, Credit Suisse Research Source: Company data

Figure 198: Major project progress

Source: Company data, Credit Suisse research

SURF and

Conventional

71%

LOF and i-tech

11%

Corporate

18%

2016

27%

2017

35%

2018+

38%

0

500

1000

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557 544 499 162

108

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200

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2013 2014 2015 2016e 2017e

Actual Forecast

Major (over USD750m)

Very Large (USD500-700m)

Large (USD300-500m)

Substantial (USD150-300m)

Sizeable (USD50-150m)

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Ten

Lianzi Topside

Martin Linge

Clair Ridge

Mariner

Persephone Ph 2

SLMP

Catcher

Aasta Hansteen

Western Isles

Sonamet

Maria

Stampede

West Nile Delta P1

Culzean

19 September 2016


Subsea 7 (SUBC)

Divisional review – SURF & Conventional. Recent margin outperformance looks

unsustainable; company guidance for lower EBITDA margins yoy (which we view as

conservative) implies H2 declines by at least 13-14ppts and management has

acknowledged Q3 margins would continue to benefit from close-outs of high-margin

contracts (which we think has had a significantly greater bearing on outperformance than

cost-cutting initiatives). These factors suggest that the Q4 sequential decline could be

sharp. In Brazil, management is standing firm on the strength of its contractual position on

the PLSVs, and now sees little risk of further ‘blocking’. However, we would expect some

renegotiation of delivery, start-up and rates, and see risks associated with the renewal of

the Seven Mar and Seven Phoenix contracts in an oversupplied PLSV market in Brazil.

Divisional review – i-Tech Services & Corporate. The Corporate line is likely to see the

most material change in financials as the Beatrice windfarm contract is included within this

line. We assume the contract is worth USD1.3bn with the bulk of revenues being booked

in 2017/18. The award of this work to Subsea 7 (with JV partner SHL) took the market by

surprise, but it represents a deliberate strategy to diversify into adjacent sectors. We have

some concerns about SUBC’s ability to execute such large renewables sector projects (we

take some comfort in the track record of SHL) but are more concerned about the value it

can extract from what we view as low-end T&I work. We model the contract as a ‘one-off’.

Within i-Tech, deferred maintenance spending is morphing gradually into demand and

there’s been an uptick in ‘break and fix’ in markets such as Nigeria. The SapuraAcergy JV,

however, has little work in the near-to-medium term.

Backlog development – Of its main peers, SUBC’s backlog suffered the most in this

downturn, almost halving in 2013-2015 (peers down 25-30%). However, ytd trends have

been strong with book-to-bill above 1.5, buoyed by the awards of Beatrice and West Nile

Delta Phase 2. There are ongoing traditional SURF tenders across several regions, but

notably in the US Gulf and East / West / North Africa, plus its alliance with Schlumberger is

targeting integrated SURF / SPS solutions with 10-12 “good” prospects. Timing for large

awards is difficult to predict (and projects tend to shift to the right), but we note more client

interest around sustaining current production and marginal field development, particularly

in the North Sea and Gulf of Mexico. In addition, SUBC is actively chasing further EPIC

renewables contracts, while SHL is actively bidding T&I work independently.

Balance sheet – SUBC’s balance sheet has been managed prudently ahead of a

significant cash call – USD466m outstanding on a bond maturing in 2017, a working

capital outflow (we model near the upper end of the guided USD250-350m range), and the

completion of the newbuild programme (around USD160m in 2016/17).

Forecasts – We are below consensus in 2017, and materially so in 2018. For SURF &

Conventional, we forecast a sharp fall in profitability in 2017 as contracts awarded in

positive cycle conditions roll off. We see the business stabilising in 2018 with offshore and

deepwater momentum gathering pace and returning the business to growth in 2019. The

performance of i-Tech services is significantly less volatile throughout our forecasts. We

model capex at below depreciation for several years. We do not forecast repayment of the

bond (we assume it is refinanced), but note that this could have an impact on our net debt

forecasts.

Valuation – We value SUBC using an equally weighted combination of SOTP and DCF,

deriving a target price of NOK75. EV/EBITDA multiples of 6-7x for 2017E/18E do not look

overly demanding relative to the cycle and peers. However, SUBC’s high capital intensity

(high D&A) model has a material impact on earnings near the bottom of the cycle.

Therefore, the 2018E PE looks high. In the past SUBC has delivered poor financial

returns, often below both WACC and peers. Despite fleet rationalisation and

reorganisation, SUBC remains an inherently capital-intensive business. We view SUBC as

19 September 2016


an excellent project manager, but vessel ownership could be value destructive in a

recovery cycle – our model shows suboptimal (below WACC) returns persisting through

2020E. SUBC has outperformed the sector materially ytd; we believe the stock is

overvalued.


■ For SURF & Conventional, we assume blue / grey sky revenues +/- 5% from our base-

case scenario with margins +/- 1.5% for 2017 and beyond (diluted impact for 2016);

■ For i-Tech services, we assume blue / grey sky revenues +/- 2.5% and margins +/-


■ In our SOTP, we assume multiples 1.5 / 1.0 higher / lower than our base case for

SURF & Conventional/ i-Tech services. We flex our DCF for long-term growth by +/-

0.25%.

Figure 199: Valuation summary – Subsea 7



SURF & Conventional 319 2548 6.5 0.81 2071 1848

i-Tech Services 66 339 7.0 1.37 463 451

Corporate 90 650 3.0 0.42 270 263

Total 475 3537 5.9 2803 2561

Net cash / (debt) 319 385


Implied market value (USDm) 3460 3284

Implied market value (NOKm) 28685 27224


DCF (USDm)


premium

1.45 5.50% 9.70% 2%

EV 2155 2238

Net (debt) / cash 319 385


MV 2812 2961

NOK / USD 8.29 8.29

Implied value per share (NOK) 67.2 70.7

Valuation summary (NOK/share) Average 2017E 2018E

SOTP 81 83 78

DCF 69 67 71


Blue Sky / Grey Sky


SOTP 26% 101 89 114

DCF 97% 135 131 140



SOTP -37% 51 49 52

DCF -69% 21 22 21



19 September 2016


HOLT






decline from 3.7% in 2016 to 2.9% by 2022. Thereafter we capture the next cycle and

forecast returns to dip to -0.05% in 2023 and recover to 0.37% by 2025 – much lower than

returns achieved in the past 11 years.




group Tecnicas Reunidas, Petrofac, Saipem, Technip SA and Subsea 7 into “Engineering

and Construction” and apply a long term average discount rate of 5.15% for each.

The above assumptions suggest a HOLT warranted value of NOK 41.1, versus our target

price of NOL75. The difference can be explained by a) HOLT using a real discount rate

5.15%, which is below our nominal 9.71% WACC after an adjustment for inflation, and b)

our methodology also incorporates a multiple-based SOTP.

19 September 2016


Figure 200: Subsea 7 in HOLT




USD -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % 9.1 -30.7 -25.3 -0.5 -5.2

EBITDA Mgn, % 19.7 24.5 24.4 11.9 13.3

Asset Turns, x 0.60 0.4 0.3 0.3 0.3

CFROI®, % 11.0 8.2 3.7 -1.5 -1.5

Disc Rate, % 5.7 5.9 5.2 5.2 5.2

Asset Grth, % 3.6 -3.1 -2.7 0.8 -0.4

Value/Cost, x 0.8 0.7 0.8 0.7 0.7

Economic PE, x 7.1 8.0 20.3 -47.9 -46.4

Leverage, % 42.0 48.9 39.3 39.7 39.3

HO

LT

-

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red

it S

uis

se A

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st

Scen

ari

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ata

SUBSEA 7 S.A. (SUBC)

EB

ITD

A M

arg

in (

para

llel

% p

oin

t ch

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to f

ore

casts

)

-2.0% -103% -95% -85% -73%

-22%

-59%

-1.0% -91% -81% -69% -56% -40%

0.0% -78% -67% -54% -39%

14%

1.0% -65% -53% -39% -22% -4%

2.0% -53% -39% -24% -6%

More than

10%

downside

Within 10%More than

10% upside


-40

-30

-20

-10

0

10

20

30

40

1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

Sales Growth (%)

-10

-5

0

5

10

15

20

25

30

1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

EBITDA Margin

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

Asset Turns (x)

-10

-5

0

5

10

15

1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

Historical CFROI Forecast CFROI Forecast CFROI CFROI Discount Rate


-20

-10

0

10

20

30

40

1996 1999 2002 2005 2008 2011 2014 2017 2020 2023


Asset Growth (in %)

19 September 2016


Figure 201: Summary financials – Subsea 7

Divisionals (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

SURF & Conventional Revenue 4283 2998 2548 2548 2931 3444

growth -30% -15% 0% 15% 18%

EBIT 840 510 51 115 234 379

growth -39% -90% 125% 104% 62%

margin 19.6% 17.0% 2.0% 4.5% 8.0% 11.0%

i-tech services Revenue 446 357 339 356 391 440

growth -20% -5% 5% 10% 13%

EBIT 22 48 42 46 53 62

growth 118.9% -12.0% 9.2% 14.2% 16.7%

margin 4.9% 13.5% 12.5% 13.0% 13.5% 14.0%

Corporate Revenue 29 200 650 450 50 50

EBIT -197.4 -55 0 -15 -80 -80

P&L (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 6870 4758 3555 3537 3354 3372 3934

growth 9% -31% -25% 0% -5% 1% 17%

EBITDA (adj) 1439 1217 909 475 514 587 755

D&A -404 -394 -396 -381 -368 -379 -394

Share of JVs / Associates 69 63 41 55 69 69 76

EBIT 930 665 503 93 146 207 360

growth 64% -28% -24% -81% 56% 42% 74%

margin 13.5% 14.0% 14.1% 2.6% 4.4% 6.1% 9.2%

Net finance expense -22 -9 -2 -3 -2 0 1


Pre-tax profit -252 167 501 90 144 207 362

Tax -152 -222 -155 -28 -45 -64 -112


Minority Interest 43 20 15 8 8 10 12

Net profit -360 -35 360 70 108 153 262

Adj Net profit 856 504 360 70 108 153 262

No. Shares (FD) 369 347 347 347 347 347 347

EPS (CS, Adj) 2.32 1.45 1.04 0.20 0.31 0.44 0.75

EPS (IFRS) -0.98 -0.10 1.04 0.20 0.31 0.44 0.75

DPS 0.60 0.00 0.00 0.00 0.00 0.14 0.24


19 September 2016


Figure 202: Cash flow and balance sheet – Subsea 7


Net income / (losses) before taxes -230 185 360 70 108 153 262


Working cap movement 269 64 -348 -32 -26 -20 -3

Cashflow from operations 1450 1049 215 339 338 379 463


Free cash flow 582 404 -189 85 66 68 111



Change in borrowings -337 -65 0 0 0 0 0

DPS / Buyback cash cost -360 -8 0 0 0 0 -46


Cash flow from financing activities -720 -96 0 0 0 0 -46

Net cash flow -98 399 -189 85 66 68 65


Net cash / (debt) -6 423 234 319 385 453 518


Property, plant & equipment 4565 4559 4580 4456 4363 4298 4259

Goodwill and intangible assets 1344 785 782 779 777 773 771

Other Non-Current Assets 554 484 667 746 858 991 1181



Construction contracts - assets 378 278 278 278 278 278 278

Other accrued income and prepaid

expenses

283 152 152 152 152 152 152




Total Assets 8624 7854 7813 7951 7997 8132 8451

ST borrowing 2 0 0 0 0 0 0

Trade & other liabilities 1674 1124 722 790 728 711 814

Construction contracts - liabilities 426 459 459 459 459 459 459


Total Current Liabilities 2203 1774 1373 1440 1378 1361 1464

LT borrowings 576 524 524 524 524 524 524

Other Non-Current Liabilities 283 210 210 210 210 210 210

Total Non-Current Liabilities 860 734 734 734 734 734 734


Minority interest -25 -31 -31 -31 -31 -31 -31

Total Shareholders Equity 5562 5346 5707 5776 5884 6037 6253



19 September 2016


PEERs







Figure 203: Subsea 7 in PEERs


19 September 2016


Europe/France Oil & Gas Equipment & Services

Technip (TECF.PA) Rating OUTPERFORM Price (13 Sep 16, €) 51.30 Target price (€) 65.00 Market Cap (€ m) 6,275.9 Enterprise value (€ m) 4,159.9 *Stock ratings are relative to the coverage universe in each



Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

More than just a deepwater play

■ Initiate with Outperform, TP EUR65. The warm industry response to the

creation of Forsys was a key driver behind the decision to merge Technip

with FMC Technologies. While the deal timing also speaks to the expected

duration of continued weakness in deepwater spending, consolidating

through 2017 should enable Technip/FMC to outperform in a deepwater

cyclical recovery in 2018+. Between now and then, improving financial

performances from Technip’s Onshore/Offshore business and FMC’s Surface

division provide some cushion to pressured financials in both companies'

Subsea divisions.

■ More resilient than many think. We believe the market underappreciates

the breadth of TEC’s business mix and capabilities. Deepwater is important –

it represents TEC’s highest-margin work – but there are several other drivers

to the business – shallow water, downstream, and gas (including LNG and

FLNG). Furthermore, TEC continues to migrate to a higher-quality mix of

lower-risk services lines and a lower capital-intensity business model.

■ Catalysts: An active bidding pipeline is likely to deliver contract awards to

TEC that should improve on recent book-to-bill trends; shareholder approval

and completion of the FMC deal (indicated Q117); Q316 results 27 October.

■ Valuation: A 2018E PE of 18x and EV/EBITDA of ~6x do not represent

demanding multiples for what we consider to be trough earnings. Investors

may need to be patient for book-to-bill trends to recover, but we’d expect an

inflection point to be reached in 2017. TEC is the EU bellwether stock and

should be a natural beneficiary of inflows as investor sentiment turns more

positive towards the OFS sector.



CAC 40 INDEX which closed at 4387.2 on 13/09/16


Eu.89/US$1

Performance 1M 3M 12M Absolute (%) 0.6 11.5 17.2 Relative (%) 2.9 5.7 21.0


Year 12/15A 12/16E 12/17E 12/18E Revenue (€ m) 12,209 10,567 8,233 7,883 EBITDAX (€ m) 1108.0 1119.0 860.7 788.4 Adjusted net income (€ m) 586.8 550.5 384.1 333.8 CS EPS (adj.) (€) 5.11 4.69 3.27 2.84 Prev. EPS (€) ROIC avg (%) 22.8 23.1 14.0 10.7 P/E (adj.) (x) 10.0 10.9 15.7 18.0 P/E rel. (%) 69.1 75.0 118.1 151.0 EV/EBITDAX (x) 3.9 3.7 5.7 6.2

Dividend (12/16E, €) 2.00 Net debt/equity (12/16E,%) -45.0 Dividend yield (12/16E,%) 3.9 Net debt (12/16E, € m) -2,190.3 BV/share (12/16E, €) 36.7 IC (12/16E, € m) 2,675.3 Free float (%) 94.5 EV/IC (12/16E, (x) 1.5 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Technip (TECF.PA)

Price (13 Sep 2016): €51.3; Rating: OUTPERFORM; Target Price: €65.00; Analyst: Phillip Lindsay


Revenue 12,209 10,567 8,233 7,883 EBITDA 1,108 1,119 861 788 Depr. & amort. (306) (268) (242) (237) EBIT 802 873 634 566 Net interest exp. (157) (71) (73) (78) Associates 20 22 16 14 PBT 707 802 561 488 Income taxes (119) (241) (168) (146) Profit after tax 588 562 393 342 Minorities (11) (11) (9) (8) Preferred dividends - - - - Associates & other 10 0 0 0 Net profit 587 551 384 334 Other NPAT adjustments (542) 0 0 0 Reported net income 45 551 384 334

Cash flow (€ m) 12/15A 12/16E 12/17E 12/18E

EBIT 802 873 634 566 Net interest (157) (71) (73) (78) Cash taxes paid - - - - Change in working capital 562 (62) (965) (57) Other cash and non-cash items (164) (6) 49 68 Cash flow from operations 1,043 734 (355) 499 CAPEX (282) (241) (230) (237) Free cashflow to the firm 846 541 (539) 310 Acquisitions (2) 0 0 0 Divestments 24 0 0 0 Other investment/(outflows) (44) (11) (9) (8) Cash flow from investments (303) (252) (239) (245) Net share issue/(repurchase) 94 0 0 0 Dividends paid (95) (230) (235) (235) Issuance (retirement) of debt (113) 0 0 0 Cashflow from financing (114) (230) (235) (235) Changes in net cash/debt 813 252 (829) 19 Net debt at start (1,125) (1,938) (2,190) (1,362) Change in net debt (813) (252) 829 (19) Net debt at end (1,938) (2,190) (1,362) (1,381)



Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 115 117 117 117 CS EPS (adj.) (€) 5.11 4.69 3.27 2.84 Prev. EPS (€) Dividend (€) 2.00 2.00 2.00 2.00 Free cash flow per share (€) 6.63 4.20 (4.98) 2.24

Valuation 12/15A 12/16E 12/17E 12/18E



ROE (%) 13.9 12.5 8.6 7.1 ROIC (avg.) (%) 22.8 23.1 14.0 10.7



Company Background

Technip is a broad based services provider of project management, engineering and construction for the energy industry. It has notable positions in subsea, offshore and onshore sectors.



For Subsea, we assume blue sky revenues +7.5% from our base case scenario with margins +2% for 2017 and beyond (diluted impact for 2016). For Onshore / Offshore, we assume blue sky revenues +2.5% and margins +1.0% from our base case scenario for 2017 and beyond (diluted impact for 2016). In our SOTP, we

assume multiples 1.0pt higher than our base case for Subsea and Onshore / Offshore respectively. For DCF we flex long-term growth by +0.25%


For Subsea, we assume grey sky revenues -7.5% from our base case scenario with margins -2% for 2017 and beyond (diluted impact for 2016). For Onshore / Offshore, we assume grey sky revenues -2.5% and margins -1.0% from our base case scenario for 2017 and beyond (diluted impact for 2016). In our SOTP, we assume multiples 1.0pt lower than our base case for Subsea and Onshore / Offshore respectively. For DCF we flex long-term growth by -0.25%


The price relative chart measures performance against the CAC 40 INDEX




19 September 2016


Technip in charts

Figure 204: Q2 2016 backlog profile Figure 205: Group order intake and book-to-bill

Source: Company data, Credit Suisse research Source: Company data, Credit Suisse research

Figure 206: Cost profile Figure 207: Fleet profile


Figure 208: Key contracts being bid Figure 209: Key tendering regions

Source: Company data, Credit Suisse Research, data correct as of 7th September 2016 Source: Company data, Credit Suisse Research, data correct as of 7

th September 2016

Deepwater

25%

Shallow Water

25%

Gas / LNGL /

FLNG

36%

Refining /

Heavy Oil /

Petrochems

13%

Others

1%

1.82

0.89 0.910.75

1.11 1.14 1.17

1.421.29

1.43

0.63 0.57

0.0

0.2

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0.6

0.8

1.0

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8000

10000

12000

14000

16000

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Book t

o b

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EU

Rm

Subsea Onshore / Offshore Book to bill

4.523.89 3.79

4.79

0.27

0.63

0.1

0

0.5

1

1.5

2

2.5

3

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4

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36

27

24 23

20

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2013 2014 2015 1H 2016 2017e

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19 September 2016


Technip (TEC)

Divisional review – Subsea. TEC is managing Subsea for utilisation - focusing on

winning projects that plug obvious gaps in vessel schedules and manufacturing plant

throughput. The current business development pipeline is increasingly populated with

smaller projects with shorter award-to-execution timeframes – many projects currently

being bid, notably in the North Sea (Norwegian sector) and Gulf of Mexico, benefit from

2017 offshore campaigns. West Africa and Australia are also growing in importance for

tieback work as these regions mature – average project sizes should be more material in

these regions.

Divisional review – Onshore / Offshore. Larger project award opportunities currently sit

within its Onshore/Offshore division – the market for downstream/petrochemical projects

remains robust in North America, the Middle East and Asia. We believe TEC has the right

cost structure and offering (technology/licensing, equipment, EPCM, EPC) to compete

effectively in this market and build quality backlog. Furthermore, existing backlog

underpins improving financial performance in 2017 (we think the market is underestimating

this potential) as profit recognition kicks in on major projects like Yamal.

Outlook improving. TEC delivered a clear change of tone regarding outlook with its

consensus-beating Q2 2016 results. Oil companies appear more satisfied around supply

chain costs and are now more willing to embrace supply chain initiatives to drive structural

improvements. In addition, there’s growing concern over sustaining current production,

which we expect to deliver higher marginal field development and tiebacks activity. Larger

greenfield projects will come later, and will be more phased with greater focus on schedule

delivery and early cash flow.

Backlog development. Technip entered the downturn with the strongest visibility in its

history, but book-to-bill has averaged about 0.6 (0.5 in Subsea) for the past six quarters.

Backlog is now 35% off the peak, and TEC’s forward visibility has diminished – it has

about 60% revenue visibility in 2017 (based on consensus revenues, 66% on CS

forecasts), compared with almost 80% one-year forward at Q2 2015. We note the more

upbeat tone in the company’s outlook, but consensus revenues may be too optimistic, in

our view.

Balance sheet and dividend. TEC’s balance sheet is robust – the group is strongly net

cash (even adjusting for net construction contracts, ie client cash) –Q216 saw record

levels of cash. Capex is running at levels well below depreciation and we do not envisage

any material new investments in the coming years. TEC has preserved DPS through the

downturn thus far, and while EPS cover may run thin through 2018 (our view of trough),

we believe the board will maintain it.

Forecasts (TEC standalone). We typically see lower-than-consensus revenues but better

margins in 2016-18 – our forecasts are not materially out of line with consensus. TEC is a

long-cycle business; we believe 2016 financials reflect the 'good' part of the last cycle

rather than current market conditions. We see declining financials yoy in 2017 and 2018

with recovery from 2019. We expect the performance of Onshore/Offshore to be

significantly more resilient than Subsea in 2016-18.

Valuation and view (TEC standalone). We believe the market considers TEC to be a

play on deepwater markets. However, only 25% of TEC’s Q216 backlog was deepwater

(classed as >1,000 metres) – we think the market underappreciates the breadth of TEC’s

business mix and capabilities. Deepwater is important –it represents TEC’s highest-margin

work – but there are several other drivers to the business – shallow water, downstream,

and gas (including LNG and FLNG). Furthermore, TEC continues to migrate to a higher-

quality mix of lower-risk services and a lower-capital-intensity business model. EPC and

EPIC will continue to account for the bulk of group revenues, but TEC is only targeting

projects where it has front-end involvement – the growth of Genesis through the last cycle,

19 September 2016


plus more recent success with Forsys (its JV with FMC) confirm this. A 2018E PE of 18x

and EV/EBITDA of ~6x do not represent demanding multiples for what we consider to be

trough earnings. Investors may need to be patient for book-to-bill trends to recover, but

we’d expect an inflection point to be reached in 2017. TEC is the bellwether stock in

European OFS and a name we expect investors to warm to as they gain more confidence

in the cyclical recovery. We value TEC using equally weighted SOTP and DCF metrics,

deriving a EUR65 TP.


■ For Subsea, we assume blue / grey sky revenues +/- 7.5% from our base-case

scenario with margins +/- 2% for 2017 and beyond (diluted impact for 2016);

■ For Onshore / Offshore, we assume blue / grey sky revenues +/- 2.5% and margins +/-



Subsea and Onshore / Offshore, respectively. For our DCF we flex long-term growth by

+/- 0.25%.

19 September 2016


Figure 210: Valuation summary – Technip



Subsea 654 3496 9.0 1.68 5887 5730

Onshore / Offshore 288 4737 6.0 0.36 1727 1727

Corporate -65 0 7.5 0.00 -490 -466

Total 877 8233 7.5 0.00 7125 6991


Net construction contracts -1117 -1069




DCF (EURm)


premium

1.20 6.60% 7.91% 2%

EV 6843 7904

Net cash / (debt) -1361 -1381

Net construction contracts 1117 1069


MV 7194 8322



SOTP 63.40 63.69 63.12

DCF 66.09 61.28 70.90


Blue Sky / Grey Sky


SOTP 45% 91.84 88.98 94.71

DCF 88% 124.45 117.57 131.34



SOTP -34% 41.87 43.84 39.91

DCF -54% 30.28 26.66 33.91



19 September 2016


HOLT






decline from 10% in 2016 to 8.1% by 2022. Thereafter we capture the next cycle and

forecast returns to average at 6.1% over 2023-2025.






5.15% for each.

The above assumptions suggest a HOLT warranted value of EUR 58.33, slightly below our

target price of EUR 65. The difference can be explained by a) HOLT using a real discount

rate 5.15%, which is below our nominal 7.91% WACC after an adjustment for inflation, and

b) our methodology also incorporates a multiple-based SOTP.

19 September 2016


Figure 211: Technip in HOLT




EUR -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % 7.9 2.6 -13.4 -22.1 -4.2

EBITDA Mgn, % 9.1 10.1 12.5 12.3 11.8

Asset Turns, x 0.93 0.9 0.8 0.6 0.6

CFROI®, % 8.7 7.0 10.1 7.2 6.0

Disc Rate, % 5.6 5.7 5.2 5.2 5.2

Asset Grth, % 4.2 9.6 -8.1 -2.3 1.0

Value/Cost, x 1.4 1.3 1.3 1.3 1.2

Economic PE, x 15.8 18.3 13.4 17.7 20.3

Leverage, % 42.3 47.9 45.8 43.0 42.6

More than

10%

downside

Within 10%More than

10% upside


92%

1.0% -2% 12% 29% 49% 70%

2.0% 14% 30% 48% 69%

7% 24%

0.0% -18% -5% 10% 28%

HO

LT

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Asset Growth (in %)

19 September 2016


Figure 212: Summary financials – Technip


Subsea Revenue 4880 5876 4995 3496 3147 3540 4071

growth 20% -15% -30% -10% 13% 15%

OIFRA 635 851 684 444 368 432 517

growth 34% -20% -35% -17% 17% 20%

margin 13.0% 14.5% 13.7% 12.7% 11.7% 12.2% 12.7%

Onshore / Offshore Revenue 5844 6333 5573 4737 4737 5211 6253

growth 8% -12% -15% 0% 10% 20%

OIFRA 276 34 279 256 256 266 319

growth -87.7% 721.9% -8.2% 0.0% 3.9% 20.0%

margin 4.7% 0.5% 5.0% 5.4% 5.4% 5.1% 5.1%

Corporate EBIT -87 -83 -90 -65 -58 -65 -78

P&L 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 10725 12209 10567 8233 7883 8750 10324

growth 16% 14% -13% -22% -4% 11% 18%

EBITDA 1108 1108 1119 861 788 865 1005

D&A -283 -306 -268 -242 -237 -248 -267

OIFRA 825 802 851 619 551 617 739

growth -1% -3% 9% -27% -11% 12% 20%

margin 7.7% 6.6% 8.1% 7.5% 7.0% 7.0% 7.2%



Pre-tax profit 623 175 781 545 474 540 666

Tax -180 -119 -241 -168 -146 -167 -206


Minority Interest -6 -11 -11 -9 -8 -9 -10

Net profit 437 45 529 368 320 365 451

Adj Net profit 457 587 551 384 334 381 470

No. Shares (FD) 125 115 117 117 117 117 117

EPS (CS, Adj) 3.65 5.11 4.69 3.27 2.84 3.24 4.00

EPS (IFRS) 3.49 0.39 4.50 3.14 2.72 3.11 3.84

DPS 2.00 2.00 2.00 2.00 2.00 2.00 2.00


19 September 2016


Figure 213: Cash flow and balance sheet – Technip


Net income / (losses) 442 56 551 384 334 381 470


Working cap movement 105 562 -62 -965 -57 170 308

Cashflow from operations 868 1043 734 -355 499 783 1026


Free cash flow 492 748 482 -594 254 501 695

M&A -59 -31 0 0 0 0 0



Change in borrowings 80 -113.4 0 0 0 0 0

Dividend -207 -89 -230 -235 -235 -235 -235

Other financing cash flows -33 89 0 0 0 0 0

Cash flow from financing activities -159 -114 -230 -235 -235 -235 -235

Effect of FX 211 138 0 0 0 0 0

Net cash flow 534 764 252 -829 19 266 460


Net cash / (debt) 1125 1938 2190 1362 1381 1647 2107



Intangible assets, net 3497 3583 3564 3540 3517 3497 3478



Construction contracts - assets 756 652 564 440 421 467 551

Advances paid to suppliers 554 479 415 323 309 344 405





Total assets 14600 15536 15670 14359 14246 14791 15784

Trade payables 2445 2891 2816 2010 1934 2152 2548

Construction contracts - liabilities 2258 2308 1998 1557 1490 1654 1952

Provisions 328 436 377 294 281 312 368

Current financial debt 256 937 937 937 937 937 937



Non-current financial debts 2357 1626 1626 1626 1626 1626 1626







19 September 2016


Technip FMC – a marriage of convenience

The background – The origins of the deal can be traced back several years to when oil

prices were materially higher than current spot prices – senior management (Thierry

Pilenko and Doug Pferdehirt) had a shared vision of how to create more value from

offshore and deepwater field development. This culminated in the creation of the Forsys

Subsea JV in March 2015, set up to target front-end involvement in projects and drive

greater standardisation and simplification through reducing the interfaces between SURF

and SPS systems. Interest levels grew materially post launch and in May 2016, Technip

and FMC announced plans to merge.

Figure 214: Timeline of merger plans

Deal Mechanics

Deal: All stock merger, TEC shareholders to receive two NewCo shares for every one, FTI ratio is 1:1

Each company's shareholders to own c50% of NewCo

Company name: TechnipFMC

Listing: NYSE and Paris, seeking inclusion in S&P 500 and CAC40

Synergies: >USD400m pre-tax cost synergies

Equity value: USD13bn, based on pre-announcement closing prices on 18 May 2016

Headquarters: Paris, France and Houston, Texas, USA

Domicile: London, UK

Management and

Governance:

Executive Chairman - Thierry Pilenko

Chief Executive Officer - Doug Pferdehirt

Chief Operating Officer - Julien Waldron

Chief Financial Officer - Maryann Seaman

Progress: US antitrust cleared

Business Combination Agreement executed

Prospectus timing - TBC

Shareholder approval - TBC

Timing: Deal close early 2017, subject to regulatory and shareholder approval


The rationale – Demand exceeded supply for Forsys, particularly after initial studies

appeared to prove the concept. But to be truly effective in the project execution phase, a

combination was necessary. The deal appears defensive in the short term to a lacklustre

deepwater market, but should position the combined entity to outperform in the medium-

to-long term, particularly as deepwater markets eventually recover. We note the rationale

is much broader than merely improving greenfield prospects in subsea – life-of-field is a

significant opportunity, and there are less obvious synergies between FTI’s Surface

business with key elements of TEC’s Onshore / Offshore division.

The merits – the deal is client-led – oil companies can see the value creation in an

integrated SPS/SURF approach through structurally lower costs and accelerated

development times. It enables more clients to take projects off the shelf and into the

hopper of realistic development candidates – TEC/FTI can become more embedded with

oil company clients and take ‘a larger slice of a smaller deepwater pie’. Future R&D should

create greater opportunities around longer tie-backs, life-of-field offerings and within land

operations. Contracting with a single entity is simpler than awarding work to an alliance

where risk apportionment can be complex and ill-defined. Crucially, the combination does

not limit an operator’s choice – it can still procure SPS/SURF independently. The bottom

line may not benefit fully from the USD400m cost synergies; at worst it improves their

competitiveness and at best it could be accretive to margins. Also, any tax benefit from

being UK domiciled is likely to be marginal.

19 September 2016


The pushback – Although support for the integrated approach has grown, not all oil

companies will want to pursue subsea projects in this way; we should question the

revenue synergy potential if the industry reverts to a more traditional procurement

approach as oil prices improve. TEC investors are typically more enthusiastic about merits

of the combination, whereas FTI investors have been more sceptical – this is best

illustrated by the 10% performance spread in the stocks on the day of the deal

announcement, despite being pitched as a “merger of equals”. Many FTI investors prefer

its pureplay, asset-light, high-tech, high-margin, high-ROIC business model relative to

TEC’s more capital-intensive, higher-risk/lower-return and broader-based business model.

The historical spread in multiples is stark – where FTI has enjoyed a 70% premium (on

EV/EBITDA).

Our view – The level and depth of management capability is impressive and the

combination of product offerings, technologies and solutions should create a potential

industry powerhouse. Through merging, the new entity can defend against a lacklustre

deepwater market in the short term, but could benefit disproportionately from its eventual

recovery. The question is when does this recovery take place – other than perhaps a

series of smaller subsea tiebacks and a small number of larger greenfield opportunities

(for which competition could be fierce), we think deepwater activity will continue to decline

through 2018.

The deal has already received US anti-trust clearance and we foresee few antitrust issues.

It is a vertical integration combination rather than like-for-like consolidation. The majority of

customers appear to see the benefit of the integrated business model – the concept is not

proven in terms of a working subsea system on the seabed, but studies to date appear to

validate the claims about the improvement in project economics. Management believes it

will secure its first EPIC award in H2 2016.

We believe a longer-term development goal will see the combination develop (organically

or through acquisition) subsurface capability. After the failed acquisition of CGG, TEC

began an organic recruitment programme to recruit experienced subsurface personnel into

Genesis, its engineering division, and also formed an alliance with UK-listed RPS Group–

enabling more effective competition to OneSubsea.

Both TEC and FTI are facing potential revenue and margin declines and both will likely

have increased valuation headwinds as lower-multiple businesses (Onshore/Offshore for

TEC, Surface for FTI) to account for a higher proportion of group profits in 2017 versus

2015/16. Given the relative outlooks, these headwinds may be sustained into 2018,

although Subsea order intake should be gathering momentum by then.

See ‘Fishing where the fish are’ for key projects where TEC and FTI are currently bidding

for work.

19 September 2016


Figure 215: Combined FMC / Technip scope

Source: Company data, Credit Suisse Research, Technip

Figure 216: Combined FMC / Technip overview

Source: Company data, Credit Suisse Research, Technip

FEED Execution

Seismic & Information Gathering

Reservoir & DownholeCapabilities

Concept Selection

Tender Preparation

Subsea field development

SURF field development

Topsides & Facilities

Reservoir Development

Subsea Production Systems

SURF

Topsides & Facilities

Drilling & Downhole Completion

Reservoir Development

Forsys Subsea JV scope

Combined Entity Scope

Subsea Surface Onshore / Offshore

• Products: trees, manifolds,

control, templates, flowline systems, umbilicals and flexibles

• Subsea processing• ROV’s and manipulator systems• Subsea services

− Drilling systems− Installation− Asset management and

production optimisation− Field IMR and well services

• Drilling, completion and

production wellheads:− Surface integrated services− Frac stacks, arm manifold− Frac flowback services− Separation systems

− Metering systems• Fluid control

− Treating iron, temporary pipe restrains, pumps, fluid ends

− Water processing,

advanced separation

• Offshore productions, technologies and services− Fixed facilities:

Conventional platforms, self-elevating platforms, GBS, artificial islands

− Floating facilities: FPSO, semi submersibles, Spar, TLP, FLNG

− Services: Floatoverinstallation, HUC modifications

• Onshore products, technologies and services− Gas monetisation, refining,

petrochemicals, onshore pipelines, etc

•Backlog: USD10.6bn

•Revenue contribution:56%

• Backlog: USD0.4bn

• Revenue contribution:

• Backlog: USD9.8bn

• Revenue contribution:

9%

35%

19 September 2016


Figure 217: Technip / FMC Pro-forma P&L and Valuation Metrics

Pro-forma P&L 2016E 2017E 2018E 2019E 2020E

Revenues 16494 13905 13865 15249 17697

EBITDA pre-synergies 1884 1575 1569 1726 2005

EBITDA pre-synergies % 11.4% 11.3% 11.3% 11.3% 11.3%

Synergies 0 0 200 400 400

EBITDA inc-synergies 1884 1575 1769 2126 2405

D&A -508.5 -449.5 -430.7 -435.3 -452.3

Incremental deal amortisation -127.1 -112.4 -107.7 -108.8 -113.1

Total D&A -635.6 -561.9 -538.4 -544.1 -565.4

EBIT pre-synergies 1248.3 1012.8 1031.0 1182.0 1439.3

EBIT pre-synergies % 7.6% 7.3% 7.4% 7.8% 8.1%

EBIT inc-synergies 1248.3 1012.8 1231.0 1582.0 1839.3

EBIT inc-synergies % 7.6% 7.3% 8.9% 10.4% 10.4%

Interest -108.9 -110.0 -110.1 -107.8 -103.1

Other -29.9 -27.8 -23.3 -22.6 -21.9

Incremental interest and other

PTP pre-synergies 1109.5 875.0 897.6 1051.6 1314.3

PTP inc-synergies 1109.5 875.0 1097.6 1451.6 1714.3

Tax pre-synergies -335.7 -244.5 -245.8 -287.4 -359.0

Tax inc-synergies -335.7 -244.5 -300.6 -396.7 -468.3

Tax rate 30.3% 27.9% 27.4% 27.3% 27.3%

Net income pre-synergies 773.8 630.5 651.8 764.2 955.3

Net income inc-synergies 773.8 630.5 797.0 1054.9 1246.0

Diluted shares 462.4 461.6 461.6 461.6 461.6

EPS pre-synergies 1.67 1.37 1.41 1.66 2.07

EPS inc-synergies 1.67 1.37 1.73 2.29 2.70

Net cash / (debt) 2339 1724 1918 2464 3316

Prepayments adj

Adj net cash 1603 1267 1454 1911 2608

Equity value 13435 13412 13412 13412 13412

Enterprise value 11096 11688 11494 10948 10096

Enterprise value adj 11832 12145 11958 11501 10803

Pro-forma valuation data 2016E 2017E 2018E 2019E 2020E

PE pre-synergies 17.4 21.3 20.6 17.6 14.0

PE inc-synergies 17.4 21.3 16.8 12.7 10.8

EV/EBITDA pre-synergies 5.89 7.42 7.32 6.34 5.04

EV/EBITDA inc-synergies 5.89 7.42 6.50 5.15 4.20

Adj EV/EBITDA pre-synergies 6.28 7.71 7.62 6.66 5.39

Adj EV/EBITDA inc-synergies 6.28 7.71 6.76 5.41 4.49

EV/Sales 0.67 0.84 0.83 0.72 0.57

Adj EV/Sales 0.72 0.87 0.86 0.75 0.61


19 September 2016


Figure 218: Forsys Subsea FEED Study Overview


Figure 219: Cumulative Integrated FEED Study Awards

Source: Technip

16

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Months after Establishing JV/Alliance

19 September 2016


PEERs







Figure 220: Technip in PEERs


19 September 2016


Europe/Spain Oil & Gas Equipment & Services

Tecnicas Reunidas (TRE.MC) Rating UNDERPERFORM Price (13 Sep 16, €) 32.50 Target price (€) 28.00 Market Cap (€ m) 1,816.3 Enterprise value (€ m) 1,319.1 *Stock ratings are relative to the coverage universe in each



Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Pressured premium

■ Initiate with Underperform, TP EUR28: TRE has come a long way since its

IPO a decade ago, building a strong, well-managed and broad-based

contracting business. Until 2016, TRE had a near-perfect track record of

executing EPC contracts, with EBIT margins consistently in the 4-6% range.

Problem contracts can be exceptionally painful for contractors, particularly in

regions with expensive man-hours, but strong management action has

isolated the adverse impact to a single charge on the Upgrader Project in

Canada. However, liquidated damages cannot be ruled out on commercial

close-out.

■ Investment case: Margins are trending towards the bottom of TRE’s

historical 4-6% range, reflecting tougher market conditions (over half the

current backlog was awarded in a downturn), mix (both geographical, and the

proportion of early-stage work flowing through its books), and higher

contingencies assumed across secured and future backlog. TRE has

benefited from lower supply chain costs, but headwinds have been too

strong.

■ Catalysts: Our in-house projects tracker sees TRE bidding for several

medium-to-large EPC contracts; key competitor/customer commentary,

commercial close-out in Canada; Q3 results on 10 November.

■ Valuation: We value TRE on an equally weighted combination of SOTP and

DCF, deriving a EUR28 TP. TRE is a solid company with a largely robust

execution track record, but we think this is more than reflected in the current

valuation. The premium to its closest peer (in our coverage), Petrofac, is

significant; yet margins are lower and there is less scope for improvement.

We also think the market underestimates the risks with the current backlog, in

terms of both margin and cash flow.



MADRID SE INDEX which closed at 879.2 on 13/09/16


Eu.89/US$1

Performance 1M 3M 12M Absolute (%) 1.5 31.2 -21.3 Relative (%) 1.2 24.5 -10.2


Year 12/15A 12/16E 12/17E 12/18E Revenue (€ m) 4,188 4,518 4,413 4,533 EBITDAX (€ m) 100.1 202.9 199.0 209.5 Adjusted net income (€ m) 60.2 137.0 134.4 141.7 CS EPS (adj.) (€) 1.11 2.55 2.50 2.64 Prev. EPS (€) ROIC avg (%) -58.0 -225.3 6555.2 132.7 P/E (adj.) (x) 29.4 12.7 13.0 12.3 P/E rel. (%) 192.9 77.4 96.0 100.9 EV/EBITDAX (x) 13.5 6.4 6.8 6.6

Dividend (12/16E, €) 1.39 Net debt/equity (12/16E,%) -110.7 Dividend yield (12/16E,%) 4.3 Net debt (12/16E, € m) -508.9 BV/share (12/16E, €) 9.2 IC (12/16E, € m) -49.1 Free float (%) 58.9 EV/IC (12/16E, (x) -26.6 Source: Company data, Thomson Reuters, Credit Suisse estimates

19 September 2016


Tecnicas Reunidas (TRE.MC)

Price (13 Sep 2016): €32.495; Rating: UNDERPERFORM; Target Price: €28.00; Analyst: Phillip Lindsay


Revenue 4,188 4,518 4,413 4,533 EBITDA 100 203 199 210 Depr. & amort. (19) (20) (19) (20) EBIT 86 182 177 187 Net interest exp. 2 (1) (1) (1) Associates (5) 2 3 3 PBT 82 183 179 189 Income taxes (22) (46) (45) (47) Profit after tax 60 137 134 142 Minorities - - - - Preferred dividends - - - - Associates & other 0 0 0 0 Net profit 60 137 134 142 Other NPAT adjustments (1) 0 0 0 Reported net income 59 137 134 142

Cash flow (€ m) 12/15A 12/16E 12/17E 12/18E

EBIT 86 182 177 187 Net interest 2 (1) (1) (1) Cash taxes paid - - - - Change in working capital (111) (11) (89) (91) Other cash and non-cash items 5 (29) (29) (31) Cash flow from operations (18) 141 58 64 CAPEX (30) (25) (24) (25) Free cashflow to the firm (33) 122 40 45 Acquisitions (2) 0 0 0 Divestments 2 0 0 0 Other investment/(outflows) (8) (2) (2) (2) Cash flow from investments (38) (27) (26) (27) Net share issue/(repurchase) (1) 0 0 0 Dividends paid (75) (75) (75) (75) Issuance (retirement) of debt 0 0 0 0 Cashflow from financing 136 (75) (75) (75) Changes in net cash/debt (132) 40 (42) (38) Net debt at start (601) (469) (509) (467) Change in net debt 132 (40) 42 38 Net debt at end (469) (509) (467) (429)



Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 54 54 54 54 CS EPS (adj.) (€) 1.11 2.55 2.50 2.64 Prev. EPS (€) Dividend (€) 1.39 1.39 1.39 1.39 Free cash flow per share (€) (0.89) 2.16 0.64 0.72

Valuation 12/15A 12/16E 12/17E 12/18E



ROE (%) 12.8 29.5 25.6 24.0 ROIC (avg.) (%) (58.0) (225.3) 6555.2 132.7



Company Background

A Spainish contractor providing engineering, procurement, and construction of industrial and power facilities with a principal focus on the onshore oil and gas market.



For O&G, we assume blue sky revenues +7.5% from our base case with margins +1.5% for 2017 and beyond (diluted impact for 2016). For Power, and for Infrastructure, we assume blue sky revenues +5% and margins +0.5% from our base case for 2017 and beyond (diluted impact for 2016). In our SOTP, we assume multiples 1.0 /

0.5 / 0.5 higher than our base case for Oil & Gas, Power and Infrastructure. We flex DCF for long-term growth by +0.25%


For O&G, we assume grey sky revenues -7.5% from our base case with margins -1.5% for 2017 and beyond (diluted impact for 2016). For Power, and for Infrastructure, we assume grey sky revenues -5% and margins -0.5% from our base case for 2017 and beyond (diluted impact for 2016). In our SOTP, we assume multiples 1.0 / 0.5 / 0.5 lower than our base case for Oil & Gas, Power and Infrastructure. We flex DCF for long-term growth by -0.25%


The price relative chart measures performance against the MADRID SE INDEX




19 September 2016


Tecnicas Reunidas in charts

Figure 221: Regional backlog evolution

Figure 222: Backlog distribution by region as of Q2

2016

Source: Company data, Credit Suisse research Source: Company data

Figure 223: Backlog and book-to-bill evolution Figure 224: New order and book-to-bill evolution

Source: Company data, Credit Suisse research Source: Company data, Credit Suisse research

Figure 225: Key contracts being bid Figure 226: Current bids by region

*Bab has been deferred Source: MEED, Upstream, Credit Suisse Research

Source: MEED, Upstream, Credit Suisse Research

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19 September 2016


Tecnicas Reunidas (TRE)

Divisional review – Oil & Gas. TRE has recovered well from its February 2015 profit

warning – we applaud management action to the problems on its Upgrader Project in

Alberta, Canada. OFS contractors have a mixed track record in managing projects in crisis

but this looks like an isolated event under exceptional circumstances, which management

has resolved swiftly and efficiently and at no more cost to shareholders than was

provisioned at the time. The project is now delivered, but there remains a risk the client

could apply liquidated damages – there remains financial exposure in Alberta. As

demonstrated at its June capital markets event in Madrid, TRE’s planning and project

management approach is meticulous – the largely unblemished track record before this

project underlines this – the business is run conservatively, we think even more so after

Alberta. We are not aware of any other ‘problem contracts’ in TRE’s portfolio – however,

we would highlight exposure to Kuwait (Al Zour, which accounts for almost 20% of current

backlog) as one to watch as we see risks that the local construction market could

overheat.

Divisional review – Power & Infrastructure. The power market is a difficult market in

which to deliver stable margins consistently. TRE management appears to be aware this

and therefore operates a highly selective approach on projects for which it bids to win. The

Infrastructure sector is not strategic – TRE has capability and reference points (notably

Madrid airport) but this is not an area of business development focus.

Backlog development – As flagged by the company, order momentum has stalled in

2016 after a record 2015 intake of EUR6.7bn. Consequently, backlog fell 12% sequentially

in H1 2016 to EUR10.7bn, but visibility remains strong at about 2.4x our 2016E revenues.

The mix has gravitated to the Middle East – largely because of the Al Zour new refinery

contract worth USD2bn-plus awarded in Q4 2015, but momentum here has slowed. In

addition, prospects in other regions, Europe, North Africa, North and South America, and

Asia, have seen delays, although commentary on the Q2 call was more positive that

management’s EUR3bn order intake target remains realistic.

Balance sheet – project terms and conditions are less favourable than the past,

particularly around cash flow profile, DSOs are increasing, and realising variation orders is

becoming progressively difficult. Consequently, TRE is consuming more of its own cash

executing projects, and this requires greater debt facilities to sustain effective project

management (TRE typically advances and pays suppliers on time to minimise schedule

disruption). While quarterly trends can be lumpy, over time this would likely drive net cash

down (about EUR140m of cash on the balance sheet is client cash). All that said, the

dividend (yield 4.2%) appears largely supported.

Forecasts. We are slightly below consensus in 2017, but more in line in 2018. We see no

real variability in revenues and margins in 2017/18. Greater contingencies assumed

across the existing and any new backlog is sensible in a downturn where contractors are

exposed to greater risks. We believe a 4% EBIT margin should be sustainable. We think

the market underappreciates less favorable payment schedules on existing and new work

– TRE could underperform market expectations for FCF.

Valuation. We value TRE on an equally weighted combination of SOTP and DCF,

deriving a EUR28 TP. We view TRE as a solid company with a largely robust execution

track record, but believe this is more than reflected in the current valuation. The premium

to its closest peer (in our coverage), Petrofac, is significant; yet margins/returns are lower

and there is less scope for improvement, in our view. We also think the market

underestimates the risks with the current backlog, in terms of both margin and cash flow.

We initiate coverage on TRE with Underperform.

19 September 2016



■ For Oil & Gas, we assume blue / grey sky revenues +/- 7.5% from our base-case

scenario with margins +/- 1.5% for 2017 and beyond (diluted impact for 2016);

■ For Power, and for Infrastructure & Industries, we assume blue / grey sky revenues +/-

5% and margins +/- 0.5% from our base-case scenario for 2017 and beyond (diluted

impact for 2016)

■ In our SOTP, we assume multiples 1.0 / 0.5 / 0.5 higher / lower than our base case for

Oil & Gas, Power and Infrastructure & Industries. We flex our DCF for long-term growth

by +/- 0.25%.

Figure 227: Valuation summary – Tecnicas Reunidas



Oil and gas 266 4016 5.0 0.3 1332 1426

Power 13 303 4.5 0.2 60 63

Infrastructure and industries 4 94 4.0 0.2 17 17

Corporate -88 4.8 0.0 -419 -463

Total 196 4413 5.0 0.2 989 1044





DCF (EURm)


premium

1.25 6.25% 9.17% 2%

EV 974 1028

Net (debt) / cash 467 429


MV 1444 1636



SOTP 27.33 27.17 27.49

DCF 28.68 26.89 30.46


Blue Sky / Grey Sky


SOTP 53% 41.9 39.7 44.1

DCF 65% 47.2 44.5 49.9


Grey sky valuation

SOTP -37% 17.1 18.1 16.2

DCF -41% 16.9 15.7 18.2



19 September 2016


HOLT






decline from 14% in 2016 to 10.2% by 2022. Thereafter we capture the next cycle and

forecast returns to decline to 7.5% in 2023 and move to 7.8% by 2025.




group Tecnicas Reunidas, Petrofac, Saipem, Technip and Subsea 7 into “Engineering and

Construction” and apply a long term average discount rate of 5.15% for each.

These assumptions suggest a HOLT warranted value of EUR 28.88 in line with our target

price of EUR 28.00.

19 September 2016


Figure 228: Tecnicas Reunidas in HOLT




EUR -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % 10.6 33.0 7.9 -2.3 2.7

EBITDA Mgn, % 5.4 2.5 4.5 4.4 4.6

Asset Turns, x 3.07 3.4 3.5 3.2 3.1

CFROI®, % 17.1 8.2 14.0 12.4 11.7

Disc Rate, % 4.6 4.4 5.2 5.2 5.2

Asset Grth, % 11.4 19.7 4.3 4.2 5.5

Value/Cost, x 2.8 2.6 2.3 2.2 2.0

Economic PE, x 16.5 31.3 16.5 17.5 17.3

Leverage, % 14.2 21.8 27.6 27.6 28.1

More than

10%

downside

Within 10%More than

10% upside


87%

1.0% 0% 10% 21% 33% 47%

2.0% 29% 41% 55% 70%

-39% -32%

0.0% -29% -21% -13% -3%

HO

LT

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TECNICAS REUNIDAS S.A. (TRE)

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casts

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19 September 2016


Figure 229: Summary financials – Tecnicas Reunidas


Oil and gas Revenue 2922 3744 4119 4016 4116 4322 4646

growth 12% 28% 10% -3% 2% 5% 8%

EBIT 239 157 255 249 268 290 321

growth 8% -34% 63% -3% 7% 8% 11%

margin 8.2% 4.2% 6.2% 6.2% 6.5% 6.7% 6.9%

Power Revenue 140 321 289 303 318 318 286

growth 76% 130% -10% 5% 5% 0% -10%

EBIT -2 15 14 12 13 13 11

growth -50% -793% -1% -16% 5% 0% -10%

margin -1.5% 4.5% 5.0% 4.0% 4.0% 4.0% 4.0%

Infrastructure Revenue 88 123 110 94 99 99 89

industries growth -42.6% 139% 90% 85% 105% 100% 90%

EBIT -3 -4 2 4 4 4 4

growth 268.6% 27% -152% 70% 5% 0% -10%

margin -3.8% -3.5% 2.0% 4.0% 4.0% 4.0% 4.0%

Corporate EBIT -76 -81 -90 -88 -97 -95 -100

P&L (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 3149 4188 4518 4413 4533 4739 5021

growth 11% 33% 8% -2% 3% 5% 6%

EBITDA (adj) 170 104 198 193 203 229 254

D&A -12 -17 -20 -19 -20 -20 -22

Share of JVs / Associates 0 -5 2 3 3 5 5

EBIT 157 80.85 183.40 180 190 216 240

growth 6% -45% 111% -3% 6% 13% 11%

margin 5.0% 1.9% 4.1% 4.1% 4.2% 4.6% 4.8%

Net finance expense 9 1 -1 -1 -1 -1 -1

Other gains / losses / impairments 0 -3 0 0 0 0 0

Pre-tax profit 166 82 183 179 189 215 239

Tax -31 -22 -46 -45 -47 -54 -60


Minority Interest -1 1 0 0 0 0 0

Net profit 133 61 137 134 142 161 179

Adj Net profit 134 60 137 134 142 161 179

No. Shares (FD) 54 54 54 54 54 54 54

EPS (CS, Adj) 2.50 1.12 2.55 2.50 2.64 3.00 3.33

EPS (IFRS) 2.48 1.14 2.55 2.50 2.64 3.00 3.33

DPS 1.39 1.39 1.39 1.39 1.39 1.39 1.39


19 September 2016


Figure 230: Cash flow and balance sheet – Tecnicas Reunidas

Cash flow (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Net income / (losses) 134 60 137 134 142 161 179


Working cap movement -39 -111 -11 -89 -91 -76 -113

Cashflow from operations 138 -18 141 58 64 98 79


Free cash flow 116 -56 114 32 37 70 49



Change in borrowings -3 0 0 0 0 0 0

Dividend -75 -75 -75 -75 -75 -75 -75

Other financing cash flow 0 211 0 0 0 0 0

Cashflow from financing activities -78 136 -75 -75 -75 -75 -75

Net cash flow 38 80 39 -42 -38 -5 -25


Net cash / (debt) 601 469 509 467 429 424 398

Balance Sheet (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E








Current assets 2210 3268 3638 3500 3567 3694 3912

Total Assets 2439 3613 3991 3861 3935 4069 4295


Borrowings 4 82 82 82 82 82 82


Current liabilities 1851 2997 3313 3122 3129 3177 3299

Borrowings 24 158 158 158 158 158 158

Provisions for liabilities and charges 37 31 31 31 31 31 31


Non-current liabilities 132 219 219 219 219 219 219





19 September 2016


PEERs







Figure 231: Tecnicas Reunidas in PEERs


19 September 2016



Wood Group (WG.L) Rating OUTPERFORM Price (13 Sep 16, p) 688.50 Target price (p) 850.00 Market Cap (£ m) 2,623.4 Enterprise value (£ m) 2,863.9 *Stock ratings are relative to the coverage universe in each



Research Analysts

Phillip Lindsay

44 20 7883 1644

[email protected]

Gregory Brown

44 20 7888 1440

[email protected]

Reorganisation brings benefits

■ Initiate coverage with Outperform, TP 850p: Wood Group is changing

under the leadership of Robin Watson – the reorganisation announced with

H1 results should enable a more efficient, collegiate and integrated service

provider to emerge from this downturn. The multi-business / multi-brand

structure of the past is being replaced by a streamlined organisational

structure that positions WG more as a life-of-field solutions provider with

specialist technical expertise. This should deepen customer relationships

and, in time, drive growth in the scopes of work WG can deliver to customers.

■ Two-stage recovery: Management structure delayering and a 30%

overhead cost reduction (with more in H2) position WG to perform well in a

recovery cycle, in our view. We see several phases to a recovery – Upstream

Engineering and US Onshore PSN should recover first, and there’s pent-up

demand for maintenance / modifications work for North Sea PSN. Subsea

Engineering appears subdued through 2017, whereas Downstream

Engineering should recover from its current lull.

■ Catalysts: Key contract awards that confirm recovery are gaining

momentum; key customer/competitor commentary. Bolt-on M&A remains a

key part of the strategy – deals tend to be EPS accretive. The pre-close

statement is scheduled 15 December.

■ Valuation: We value WG using an equally weighted combination of SOTP

and DCF. We view the company as a best-in-class engineering and

maintenance franchise with strong management and a robust balance sheet.

Furthermore, the valuation looks compelling – the 2017E PE of 13x falling to

11x in 2018E don't look stretched for a business about to enter a potential

recovery cycle and relative to past valuations. Wood Group is one of our top

picks within European OFS. Share price performance



13/09/16


Eu.89/US$1

Performance 1M 3M 12M Absolute (%) -5.6 9.1 15.7 Relative (%) -2.8 -3.2 7.3


Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ m) 5,852 5,215 5,448 5,787 EBITDAX (US$ m) 531.7 435.6 462.4 503.8 Pre-tax profit adjusted (US$ m) 138.6 211.4 281.0 322.1 CS EPS (adj.) (US$) 0.84 0.66 0.73 0.81 Prev. EPS (US$) ROIC avg (%) 7.1 6.5 8.1 9.4 P/E (adj.) (x) 10.8 13.7 12.5 11.3 P/E rel. (%) 64.1 76.9 81.2 82.6 EV/EBITDAX (x) 7.1 8.7 8.0 7.1


19 September 2016


Wood Group (WG.L)

Price (13 Sep 2016): 688.50p; Rating: OUTPERFORM; Target Price: 850.00p; Analyst: Phillip Lindsay


Revenue 5,852 5,215 5,448 5,787 EBITDA 532 436 462 504 Depr. & amort. (156) (154) (161) (161) EBIT 361 239 302 342 Net interest exp. (18) (21) (21) (20) Associates 27 31 32 34 PBT 139 211 281 322 Income taxes (62) (54) (72) (82) Profit after tax 77 158 209 240 Minorities (11) (10) (11) (11) Preferred dividends - - - - Associates & other 253 109 82 82 Net profit 318 256 281 311 Other NPAT adjustments (239) (109) (82) (82) Reported net income 79 147 199 229


EBIT 361 239 302 342 Net interest (18) (21) (21) (20) Cash taxes paid - - - - Change in working capital 47 42 (17) (31) Other cash and non-cash items 76 147 110 100 Cash flow from operations 466 407 374 390 CAPEX (36) (44) (52) (69) Free cashflow to the firm 430 363 322 321 Acquisitions (238) (7) 0 0 Divestments 2 14 0 0 Other investment/(outflows) (23) (31) (41) (44) Cash flow from investments (296) (68) (94) (113) Net share issue/(repurchase) 0 0 0 0 Dividends paid (106) (126) (130) (137) Issuance (retirement) of debt 85 (239) 0 0 Cashflow from financing (39) (389) (154) (161) Changes in net cash/debt 33 (50) 126 116 Net debt at start 327 294 344 218 Change in net debt (33) 50 (126) (116) Net debt at end 294 344 218 102



Per share 12/15A 12/16E 12/17E 12/18E

No. of shares (wtd avg.) (mn) 379 385 385 385 CS EPS (adj.) (US$) 0.84 0.66 0.73 0.81 Prev. EPS (US$) Dividend (US$) 0.30 0.33 0.35 0.37 Free cash flow per share (US$) 1.13 0.94 0.84 0.83

Valuation 12/15A 12/16E 12/17E 12/18E



ROE (%) 12.9 10.6 11.4 12.2 ROIC (avg.) (%) 7.1 6.5 8.1 9.4



Company Background

Wood Group is a international energy services company and leading independent engineering house. It primarily operates within the energy industry but also supports the renewables, power and water industries.



For Engineering / PSN / Turbine activities we assume blue sky revenues +10 / 7.5 / 5% from our base case scenario for 2017 and beyond (2016 impact is diluted). For margins we assume +2 / 1 / 0.5% for Engineering, PSN and Turbine activities respectively for

2017 and beyond (2016 impact is diluted). In our SOTP we assume multiples 1.5 / 1.0 / 0.5 pts higher from our base case, respectively. We flex DCF for long-term growth by +0.25%.


For Engineering / PSN / Turbine activities we assume grey sky revenues -10 / 7.5 / 5% from our base case scenario for 2017 and beyond (2016 impact is diluted). For margins we assume -2 / 1 / 0.5% for Engineering, PSN and Turbine activities respectively for 2017 and beyond (2016 impact is diluted). In our SOTP we assume multiples 1.5 / 1.0 / 0.5 pts lower from our base case, respectively. We flex DCF for long-term growth by -0.25%.






19 September 2016


Wood Group in charts

Figure 232: Organic and acquisition-based EBITA

growth Figure 233: EPS, DPS and dividend cover

Source: Company data, Credit Suisse research Source: Company data, Credit Suisse estimates

Figure 234: EPCM reimbursable and fixed price

exposure (as of FY 2015)

Figure 235: EPCM capex vs. opex exposure as % of

FY revenue (as of 2015)

Source: Company data Credit Suisse research Source: Company data, Credit Suisse research

Figure 236: Engineering customer profile[as of July

2016) Figure 237: PSN customer profile (as of July 2016)

Source: Company data Credit Suisse research Source: Company data, Credit Suisse research

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Wood Group

AMFW

WorleyParsons

Capex Opex

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Other

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45%

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19 September 2016


Wood Group (WG)

Divisional review – Engineering. The significant Tengiz contract plus awards of

Peregrino and Leviathan have stabilised the Upstream business, and there’s growing

confidence of recovery, particularly in the US Gulf, where WG’s market position is strong.

The pipeline business is robust, but Subsea markets look weak through 2017, and

perceived industry buy-in for the integrated SPS/SURF model clouds the medium-term

demand picture for its independent model. Downstream has performed well through the

downturn (even becoming more profitable than Upstream/Subsea for the first time), but

competition has intensified recently and the near-term pipeline is thin. We expect 2016 to

represent the bottom for Engineering, but the pace of growth (both volumes and margin

expansion) may be slow in the initial recovery phase. Our overall expectation for E&P

capex in 2017 is for a flat year with pockets of growth (ie the US).

Divisional Review – PSN. The opex-led PSN has been resilient, buoyed by Americas

markets excluding US Onshore (East Canada, Trinidad, US Gulf), market share

preservation in the UKCS (albeit at the cost of some margin), continued strength in

international operations, and a boost from Q4 2015 M&A. For US onshore, PSN’s broad

positioning across key basins should see it benefit from a step-up in drilling activity

(including completions, ie, DUCs). There should be some pent-up demand in the North

Sea given maintenance deferrals in the downturn, although timing is uncertain with many

customers capital constrained. Financial entities acquiring infrastructure assets may also

create more duty holder opportunities. Turbines Activities has not delivered against the

initial plans set out at the time of forming the JV with Siemens, with 2016 showing no real

improvement yoy.

Balance sheet / DPS. Cash conversion was disappointing in H1 2016 as customers took

longer to pay. Management tightened its credit-risk process earlier in the downturn, and no

material bad debts have arisen. WG’s balance sheet has been a source of investor

comfort through the downturn and positions it better than many peers to capitalise on a

recovery. Bolt-on M&A would likely remain a driver of growth as WG broadens its

capabilities in consultancy and integrity management, and we could see further moves into

industrial and perhaps environmental services. A large deal should not be ruled out, and

we think lending partners would be supportive, but we think it’s unlikely. On DPS, we think

double-digit growth may be unsustainable in 2017/18 (the board is committed in 2016); we

think the board should prioritise rebuilding DPS cover through a period of consolidation.

Forecasts – Our forecasts are broadly in line with consensus estimates for 2016/17 but

5%/10% ahead in 2018 on EBITA / EPS. There are headwinds and tailwinds as Wood

Group emerges from this downturn – as such, we see a gradual recovery in Engineering

and PSN in 2017 with momentum building in 2018/19. Delayering and a 30% overhead

cost reduction (thus far, there is more to come in H216) position WG to at least hold

margins in 2017 before delivering growth in 2018E and beyond.

Valuation and view – WG has delivered remarkably consistent financial performances

through the downturn, underpinned by exceptional management of costs. Focus should

now turn to recovery prospects where we see a mix of shorter-cycle growth from Upstream

Engineering (Downstream Engineering could also bounce back in 2017) and US

Unconventionals for PSN. We believe the reorganisation announced with H1 results

should enable a more efficient, collegiate and integrated service provider to emerge from

this downturn. The multi-business/multi-brand structure of the past is being replaced by a

streamlined organisational structure that positions WG more as a life-of-field solutions

provider with specialist technical expertise. This should deepen customer relationships

and, in time, drive growth in the scopes of work WG can deliver to customers. We view

Wood Group as a best-in-class engineering and maintenance franchise with strong

management and a robust balance sheet. Furthermore, the valuation looks compelling –

the 2017E PE of 13x falling to 11x in 2018E does not look stretched for a business about

to enter a recovery cycle and relative to past valuations. Wood Group is one of our top

picks within European OFS.

19 September 2016



■ For Engineering, we assume blue / grey sky revenues +/- 10% from our base-case

scenario with margins +/- 2% for 2017 and beyond (2016 impact is diluted);

■ For PSN, we assume blue / grey sky revenues +/- 7.5% and margins +/- 1.0% from our

base-case scenario for 2017 and beyond (diluted impact for 2016);

■ For Turbine Activities, we assume blue / grey sky revenues +/- 5.0% and margins +/-


■ In our SOTP, we assume multiples 1.5 / 1.0 / 0.5 pts higher / lower than our base case

for Engineering, PSN and Turbine Activities respectively. We flex our DCF for long-

term growth by +/- 0.25%.

Figure 238: Valuation summary – Wood Group

SOTP (USDm) 2017E 2017E EV/EBITDA EV/sales Implied EV Implied EV

EBITDA Sales multiple implied 2017E 2018E

Engineering 189 1550 10.5 1.28 1987.7 1898

Wood Group PSN 247 3243 7.5 0.57 1856.2 1736

Turbine Services 55 655 5.5 0.46 301.2 285

Central costs -29 0 7.8 0.00 -228.3 -213

Total 462 5448 7.8 0.72 3916.8 3706

net cash / (debt) -218.1 199

Associates / minorities 323.1 323

Implied market value 4021.9 4228

No. of shares (diluted) 384.9 385

Implied value per share (USD) 10.45 11


DCF (USDm)


premium

1.33 5.50% 8.20% 2.0%

EV 4128 4198

net cash / (debt) 218 102


MV 4669 4622


Valuation summary (GBp per share) Average 2017E 2018E

SOTP 824 804 845

DCF (USDm) 877 852 901


Blue Sky / Grey Sky


SOTP 55% 1274 1201 1347

DCF 68% 1472 1417 1527



SOTP -38% 511 512 510

DCF -38% 543 536 551



19 September 2016


HOLT







forecast returns to dip to 9.2% in 2022 and recover to 12.1% by 2025 – highest level

achieved across 2016 to 2025.




group Wood Group and AMEC Foster Wheeler into an “Engineering, Project Management

& Consultancy” cohort and apply a long term average discount rate of 4.16% to this group

for comparability.

The above assumptions suggest a HOLT warranted value of GBp 685.0 which compares

with our GBp 850 price target. The difference can be explained by a) HOLT using a real

discount rate 4.16%, which is below our nominal 8.20% WACC after an adjustment for


19 September 2016


Figure 239: Wood Group in HOLT

Source: HOLT®



USD -2.0% -1.0% 0.0% 1.0% 2.0% Sales Growth, % 3.0 -23.9 -8.6 4.8 6.7

EBITDA Mgn, % 8.8 9.5 8.4 8.5 8.7

Asset Turns, x 3.20 2.2 1.5 1.5 1.5

CFROI®, % 26.3 20.1 10.4 9.8 10.3

Disc Rate, % 5.3 5.0 4.2 4.2 4.2

Asset Grth, % 2.3 -1.7 24.6 2.3 3.1

Value/Cost, x 2.2 2.4 2.0 2.0 1.9

Economic PE, x 8.4 11.9 19.6 20.0 18.4

Leverage, % 23.8 27.1 36.2 36.4 36.8

More than

10%

downside

Within 10%More than

10% upside

Source: Credit Suisse HOLT®. CFROI and HOLTare trademarks or registered trademarks of Credit Suisse Group AG or its affiliates in the United States and other countries .

82%

1.0% -7% 6% 21% 37% 56%

2.0% 11% 26% 43% 62%

-11% 3%

0.0% -26% -14% -1% 13%

HO

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it S

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ata

Wood Group

EB

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A M

arg

in (

para

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oin

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an

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casts

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-2.0% -63% -55% -46% -35%

30%

-23%

-1.0% -44% -35% -23%

-40

-30

-20

-10

0

10

20

30

40

2001 2004 2007 2010 2013 2016 2019 2022 2025

Sales Growth (%)

0

1

2

3

4

5

6

7

8

9

10

2001 2004 2007 2010 2013 2016 2019 2022 2025

EBITDA Margin

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

2001 2004 2007 2010 2013 2016 2019 2022 2025

Asset Turns (x)

-5

0

5

10

15

20

25

30

2001 2004 2007 2010 2013 2016 2019 2022 2025Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate


-30

-20

-10

0

10

20

30

2001 2004 2007 2010 2013 2016 2019 2022 2025


Asset Growth (in %)

19 September 2016


Figure 240: Summary financials – Wood Group


Engineering Revenue 2131 1729 1469 1550 1659 1808 1989

growth 7% -19% -15% 6% 7% 9% 10%

EBITA 232 215 162 174 195 226 249

growth -6% -7% -25% 7% 12% 16% 10%

margin % 10.9% 12.4% 11.0% 11.2% 11.8% 12.5% 12.5%

WGPSN Revenue 4636 3448 3103 3243 3453 3730 4028

growth 16% -26% -10% 5% 7% 8% 8%

EBITA 342 258 202 214 233 261 292

growth 30% -24% -22% 6% 9% 12% 12%

margin % 7.4% 7.5% 6.5% 6.6% 6.8% 7.0% 7.3%

Turbine Services Revenue 850 676 642 655 675 702 737

growth -22% -20% -5% 2% 3% 4% 5%

EBITA 33 44 42 43 46 49 53

growth -59% 33% -6% 4% 5% 8% 9%

margin % 3.9% 6.5% 6.5% 6.6% 6.8% 7.0% 7.3%

Central costs -57 -47 -32 -33 -35 -38 -41

Exceptional items / impairments 22.1 -159.1 -29.8 0 0 0 0

P&L 2014A 2015A 2016E 2017E 2018E 2019E 2020E

Revenue 7616 5852 5215 5448 5787 6239 6754

growth 8% -23% -11% 4% 6% 8% 8%

EBITDA 611 532 436 462 504 565 622

EBITA 550 470 373 398 438 498 553

growth 3% -15% -20% 7% 10% 14% 11%

margin 7.2% 8.0% 7.2% 7.3% 7.6% 8.0% 8.2%

EBIT 486 179 239 302 342 400 453


Pre-tax adjustments 1 4 -6 0 0 0 0

PTP 473 165 211 281 322 381 433

Tax -113 -62 -54 -72 -82 -97 -111

Tax rate 24% 38% 26% 28% 28% 28% 27%

Discontinued operations -26 14 0 0 0 0 0

Minority Interests -14 -11 -10 -11 -11 -12 -13

Net profit 320 106 147 199 229 272 310

Adj net profit 374 319 256 281 311 355 395

No. shares (FD) 375.2 379.3 384.9 384.9 384.9 384.9 384.9

EPS (CS, Adj) 99.6 84.0 66.5 72.9 80.7 92.2 102.7

EPS (IFRS) 85.2 27.9 38.2 51.6 59.4 70.5 80.5

DPS 27.5 30.3 33.3 35.0 36.7 38.6 40.5


19 September 2016


Figure 241: Cash flow and balance sheet – Wood Group


Operating profit 460 167 239 302 342 400 453


Working capital -106 59 42 -20 -37 -50 -41

Net cash from operating activities 460 466 407 374 390 427 482

Capex (inc intangible) -110 -83 -86 -97 -117 -131 -152

Free Cash Flow 350 384 321 277 274 296 330

M&A Spend (net) -200 -228 14 0 0 0 0


Net cash used in investing activities -388 -296 -68 -94 -113 -127 -148

Change in borrowings 621 85 -239 0 0 0 0

DPS cash cost -87 -105 -119 -130 -137 -144 -151

Other financing cash flows -17 -34 -30 -24 -24 -24 -24

Net cash used in financing activities 517 -53 -389 -154 -161 -168 -175

Net Cash Flow 589 117 -50 126 116 132 160


Net cash / (debt) -327 -294 -344 -218 -102 31 191


Property plant and equipment 195 204 200 201 219 246 288

Goodwill and other intangible assets 1944 2005 1995 1983 1975 1968 1964







Total assets 4387 4714 4740 4808 4956 5239 5575


Borrowings 15 677 677 677 677 677 677



Borrowings 495 495 495 495 495 495 495



Total shareholders’ equity 2546 2398 2426 2494 2586 2713 2873

Non-controlling interests 13 23 23 23 23 23 23

Total equity 2559 2421 2449 2517 2608 2736 2895

Total liabilities and equity 4387 4714 4740 4808 4956 5239 5575


19 September 2016


PEERs







Figure 242: Wood Group in PEERs


19 September 2016


Appendix

Glossary

Appraisal: The phase of petroleum operations that immediately follows successful

exploratory drilling

Blowout: An uncontrolled expulsion of oil, natural gas or water (usually brine) from a well

into the atmosphere

Cased Hole: A wellbore in which casing has been installed and cemented

Cementing: Filling the space between the casing and the wellbore walls with cement to

support the casing, and seal between zones

Christmas Tree: An assembly of valves for flow control of production fluids or gasses

installed at the top of the casing

Completion: To finish a well and prepare it for production

Coring: Taking a sample of the formation or rock to determine its geologic properties

Dayrate: The daily rate paid by an operator to a drilling contractor

Deep water: Between 500 and 1,500 metres of seawater

Directional drilling: The intentional deviation of a wellbore from the path it would naturally

take

Drill Bit: A tool located at the end of the drill string used for cutting or boring

Drillship: A maritime vessel modified to include a drilling rig and special station-keeping

equipment

Dry Hole: An exploratory well that, although reaching target depths, does not result in the

production of hydrocarbons

Electromagnetic Surveys (EM): A group of techniques in which natural or artificially

generated electric or magnetic fields are measured at the Earth's surface or in boreholes

in order to map variations in the Earth's electrical properties (resistivity, permeability or

permittivity)

E&C: Engineering & Construction

EPC: Engineering, Procurement & Construction

EPCI: Engineering, Procurement, Construction & Installation

EOR/IOR: Enhanced oil recovery / improved oil recovery

Exploration: The initial phase in petroleum operations that includes generation of a

prospect and drilling of an exploration well

Field: An area representing a group of producing oil and/or natural gas wells

FLNG: Floating liquefied natural gas

FPSO: Floating production, storage and offloading vessel

Fracturing: A stimulation treatment performed routinely on oil and gas wells in low-

permeability reservoirs

FEED: Front-end engineering design

GTL: Gas to liquids

Horizontal Drilling: Deviation of the wellbore at least 80° from vertical

19 September 2016


IMR: The inspection, repair and maintenance of oil and gas facilities

Jackup Rig: Bottom supported offshore drilling rig consisting of a floating platform that is

towed to location and ‘jacked’ up above the water on three or four legs.

LNG: Liquid natural gas

Ocean Bottom Cable (OBC): Typically an assembly of vertically oriented geophones and

hydrophones connected by electrical wires and deployed on the seafloor to record and

relay data to a seismic recording vessel

Operator: The operator of an oil or gas well or field

PLSV: Pipelay support vessel

Riser: Used in drilling, risers are large-diameter pipes that connect the subsea BOP (blow

out preventer) stack on top of the wellhead to a floating surface rig to take mud returns to

the surface

ROV: Remotely operated vehicle

Seismic: Refers to waves of elastic energy, such as that transmitted by pressure-waves

and shear-waves, in the frequency range of approximately 1 to 100 Hz. Seismic energy

(and the reflections of seismic energy) is studied by scientists to interpret the composition,

fluid content, extent and geometry of rocks in the subsurface

Semi-submersible: A particular type of floating vessel that is supported primarily on large

pontoon-like structures submerged below the sea surface

Shallow water: Less than 500 metres of seawater

SPS: Subsea production and processing system

Streamer: A surface marine cable, usually a buoyant assembly of electrical wires that

connects hydrophones and relays seismic data to the recording seismic vessel

Subsea tree: This is an assembly of valves, spools, and fittings used for an oil well, gas

well, water injection well, water disposal well, gas injection well, condensate well and other

types of wells

SURF: Subsea, umbilicals, risers and flowlines

Turnkey Contract: A contract under which the drilling contractor agrees to drill a well to

the operator’s specifications for a fixed lump-sum fee. The contractor carries the majority

of the operating risk

Ultra-deep water (UDW): Greater than 1,500 metres of seawater

Well Intervention (WI): A well intervention, or 'well work', is any operation carried out on

an oil or gas well during, or at the end of, its productive life that alters the state of the well

and/ or well geometry, provides well diagnostics and manages the production of the well

19 September 2016


Management profiles

Aker Solutions

Luis Araujo was named CEO in July 2014 after joining Aker Solutions in 2011 as president

for the company’s Brazilian operations. The Brazilian has more than 30 years of oil and

gas industry experience, including senior posts in GE, Wellstream, ABB and FMC

Technologies. He has a BEng in mechanical engineering from Gama Filho University in

Brazil and an MBA from the University of Edinburgh in Scotland. Mr Araujo owned 51,773

company shares and held no stock options at the end of 2015.

Svein Stoknes was named CFO in September 2014. The Norwegian joined Aker Solutions

in 2007 and has held numerous key posts, including head of finance of Aker Solutions’

subsea business. Stoknes graduated from the Norwegian School of Management and has

an MBA from Columbia Business School. Stoknes held 21,702 company shares and had

no stock options at the end of 2015.

Amec Foster Wheeler

Jonathan Lewis was appointed Chief Executive Officer on 1 June 2016. Before this he had

been employed in a number of senior roles at Halliburton Company Inc since 1996 – most

recently as a Senior Vice President and member of the Halliburton Executive Committee,

with responsibility, since 2014, for leading its largest division, Completion & Production.

Prior roles included leadership of the Europe/Sub-Saharan Africa Region (the largest

operating region outside North America) and the Drilling and Evaluation Division.

Ian McHoul was appointed Chief Financial Officer on 8 September 2008 (and was

additionally Interim CEO between 17 January 2016 and 31 May 2016). Ian qualified as a

Chartered Accountant with KPMG in 1984. His early career was spent in the brewing

industry. Between 1985 and 1995 he held various positions with the Foster’s Brewing

Group, including General Manager, Strategy. He was Finance & Strategy Director of the

Inntrepreneur Pub Company Limited from 1995 to 1998 and then served at Scottish &

Newcastle plc from 1998 to 2008, first as Finance Director of Scottish Courage and later

as Group Finance Director of Scottish & Newcastle plc.

CGG

Jean-Georges Malcor has been Chief Executive Officer of CGG since June 30, 2010. He

joined the company in January 2010 as President. Jean-Georges Malcor began his career

at the Thomson CSF group as an acoustic engineer in the Underwater Activities division

where he was responsible for hydrophone and geophone design and towed streamer

programmes.

Stéphane-Paul Frydman is CGG’s Chief Financial Officer and Senior Executive Vice

President, Finance & Strategy, a position he has held since 2007. Before taking on his

current role, Stephane-Paul served as Vice President Group Controller and Treasurer and

previously held the position of Vice President in charge of corporate financial affairs,

reporting to the Chief Financial Officer, from 2002 to 2005.

Hunting

Dennis Procter was appointed to Hunting’s board as a director in 2000 and Chief

Executive in 2001. Prior to this Dennis was chief executive of Hunting Energy Services

from March 2000 after joining the group in 1993. Dennis has held senior positions in the oil

services industry in Europe, the Middle East and North America.

Peter Rose was appointed as Hunting’s Finance Director in 2008. Peter is a chartered

accountant and prior to joining Hunting held senior financial positions with Babcock

International.

Petrofac

19 September 2016


Ayman Asfari joined Petrofac in 1991 to establish Petrofac International, of which he was

CEO. In 2002 he became Group Chief Executive. He has more than 30 years’ experience

in the oil and gas industry, having worked as managing director of a major civil and

mechanical construction business in Oman. Ayman is a member of the board of trustees

of the American University of Beirut, founder and Chairman of the Asfari Foundation and

member of the Senior Panel of Advisors of Chatham House.

Tim Weller was appointed as Petrofac’s CFO in September 2011 from Cable & Wireless

Worldwide, where he had been chief financial officer between May 2010 and July 2011.

Until May 2010, Tim was chief financial officer at United Utilities Group PLC and had

previously held chief financial officer roles with RWE Thames Water Limited and Innogy

Holdings PLC (now RWE npower Holdings PLC) from 2002 to 2006. Tim served as a non-

executive director of BBC Worldwide until March 2013. Tim will leave Petrofac in October

2016 and will be replaced by Alastair Cochran, who was most recently Transition Head of

BG Global Strategy and Business Development.

Alastair has 25 years' experience, began his career with KPMG and spent his earlier

career in investment banking, including with Morgan Stanley and Credit Suisse, advising

on a wide range of capital market and M&A transactions.

Marwan Chedid joined Petrofac in 1992 when the business was first established in

Sharjah, having previously worked for CCC, a major consolidated contractor company

based in the Gulf and the Middle East, for eight years. In 2007, he was appointed Chief

Operating Officer of the Engineering & Construction International business, with day-to-

day responsibility for the successful delivery of overall operations. In January 2009, he

became Managing Director of Engineering & Construction Ventures before being

appointed as Chief Executive, ECOM, in January 2012. Effective 1 January 2016, he was

appointed Group Chief Operating Officer.

PGS

Jon Erik Reinhardsen joined PGS in April 2008 as President and Chief Executive Officer.

Before his appointment at PGS, he was President, Global Primary Products Growth in

Alcoa, developing and implementing major primary metal and refining growth opportunities

worldwide. Jon Erik is a member of the board of directors of Borregaard ASA (2016-),

Telenor ASA (2014-), Awilhelmsen Management AS (2010-). He has served on the board

of directors of Cameron Int Corp (2009-2016), Hoegh Autoliners AS and Hoegh LNG

Holdings Ltd (2006-2014).

Gottfred Langseth joined PGS in November 2003 and was named Senior Vice President

and Chief Financial Officer on 1 January 2004. He was Chief Financial Officer at the

information technology company Ementor ASA from 2000 to 2003. Mr. Langseth was

Senior Vice President Finance and Control at the offshore construction company Aker

Maritime ASA from 1997 to 2000. He served with Arthur Andersen Norway from 1991 to

1997, qualifying as a Norwegian state authorised public accountant in 1993.

Saipem

Stefano Cao was appointed as CEO of Saipem in May 2015. Stefano has spent much of

his career at Eni and Saipem, starting in 1976 when he joined Saipem as a project

manager. He was COO between 1993 and 1996, and managing director from 1996 to

1999. He was Chairman and CEO of Saipem between 1999 and 2000 when he was

appointed as COO of Eni’s E&P division.

Paolo Andrea Colombo was appointed as Saipem’s Chairman in May 2015. He is also the

founding partner and Chairman of Colombo and Associati and was previously chairman on

ENEL. He is a member of Alitalia and Mediaset’s Board of Directors and is the Chairman

of GE Capital’s Interbanca’s Board of Statutory Auditors.

19 September 2016


Giulio Bozzini was appointed as Chief Financial and Stategy Officer in June 2016. Giulio

was previously head of planning and control at Eni.

Schoeller-Bleckmann

Gerald Grohamnn serves as CEO of Schoeller Bleckmann. He was appointed in October

2001, and his current term expires in December 2018. Gerald was also a member of

Supervisory Board of ABAG Aktiengesellschaft until February 2011.

Klaus Mader was appointed as CFO of Schoeller Bleckmann in October 2015 after the

retirement of Franz Gritsch. Klaus was previously Executive Vice President Finance &

Administration of the globally operating Tyrolit group. He spent 15 years with Tyrolit,

before that he had gained professional experience at Wienerberger Baustoffindustrie AG,

Immorent AG and TPA Treuhand Partner Austria. Klaus’ current term expires in

September 2018.

Subsea 7

Kristian Siem became chairman of the Board of Directors of Subsea 7 in January 2011,

before which he was Chairman of the Board of Directors of Subsea 7 Inc. from January

2002. Mr Siem has a degree in Business Economics and has been active in the oil and

gas industry since 1972. Mr Siem is the Chairman of Siem Industries Inc. and Vice

Chairman of NKT Holding A/S. Mr Siem is a Director of Siem Offshore Inc., Siem Shipping

Inc. (formerly Star Reefers Inc.), North Atlantic Smaller Companies Investment Trust plc

and Frupor S.A. Past directorships include Kvaerner ASA and Transocean Inc.

Jean Cahuzac has been Chief Executive Officer of Subsea 7 since April 2008 and an

Executive member of the Board of Directors since May 2008. Mr Cahuzac has over 30

years’ experience in the offshore oil and gas industry, having held various technical and

senior management positions around the world. From 2000 until April 2008 he worked at

Transocean in Houston, US, where he held the positions of Chief Operating Officer and

then President. Prior to this he worked at Schlumberger from 1979 to 2000 where he

served in various positions including Field Engineer, Division Manager, VP Engineering

and Shipyard Manager, Executive VP and President of the drilling division. Jean is a

Board member of Shelf Drilling Inc. and has no other external appointments with public

companies.

Ricardo Rosa joined Subsea 7 as CFO in July 2012. Before his appointment he was

Transocean’s Executive Vice President and CFO. He joined Transocean as Vice President

and Controller in Houston, subsequently becoming Senior Vice President for Asia Pacific

and the Middle East in Singapore, and then for Europe and Africa in Paris. He previously

worked for Schlumberger between 1983 and 2000..

Technip

Thierry Pilenko is Chairman and CEO of Technip. Before joining Technip in 2007 he was

chairman and CEO of Veritas DGC, a seismic services company based in Houston. While

at Veritas DGC he successfully managed its merger with CGG. Prior to this appointment,

Pilenko held various management and executive positions with Schlumberger where he

started in 1984 as a geologist.

Julian Waldron joined Technip in October 2008, as Group Chief Financial Officer. He

started his career at UBS Warburg where he spent 14 years. He then worked at Thomson

where he was Chief Financial Officer from 2001 and interim Chief Executive Officer from

March 2008 to August 2008. Julian has been an Independent Non-Executive Director of

Management Consulting Group (MCG) since 2008, and has recently been appointed as

MCG’s Deputy Chairman. He is also Chairman of the Engineering Construction Risk

Institute (ECRI).

19 September 2016


Tecnicas Reunidas

Jose Llado Fernandez-Urrutia is the executive chairman of Tecnicas Reunidas, having

been appointed in May 2006. Jose Llado was previously the Minister of Trade and Minister

of Transport and Communications for the Spanish government between 1976 and 1978,

and was also the Spanish Ambassador to the US from 1978 to 1982. Jose Llado also

holds the role of CEO at Aragonesas Promocion de Obra y Construcciones, and is the

chairman of Araltec, S.L.

Juan Llado Arburua was appointed as First Vice Chairman of the Board of Directors at

Tecnicas, having been appointed in May 2006. Juan is a member of the Board of Directors

at Eurocontrol, Master Sociedad Anonima de Ingenieria y Arquitectura, Initec Plantas

Industriales, Initec Infrastructuras, Espanole de investigacio y desarrollo, serves as

Chairman of Empresarios Agrupados Internacional and is a vice chairman at Araltec and

Aragonesas Promocion de Obras y Construcciones.

Wood Group

Robin Watson succeeded Bob Keiller on his retirement. Robin became chief executive of

Wood Group in January 2016, having been COO and an executive member of the Wood

Group board since January 2013 and CEO PSN since 2012. Robin has more than 30

years of engineering and industry experience, with the past 11 years spent in a variety of

executive positions and being actively engaged with various industry and governmental

representative bodies, including as board member of Oil and Gas UK and the Oil and Gas

Contractors Council.

David Kemp has been Chief Financial Officer of Wood Group since May 2015. David

joined Wood Group in 2013 as CFO of Wood Group PSN and was responsible for aspects

of finance and administration, IT, real estate, and legal services. David has more than 20

years’ experience in the oil & gas sector. Prior to joining Wood Group, he served in

executive roles at Trap Oil Group, Technip, Simmons and Company International, and

Hess Corporation, working across Finance, M&A and Operations.

19 September 2016


Companies Mentioned (Price as of 13-Sep-2016) ABB (ABB.N, $22.24) Aker Solutions (AKSOL.OL, Nkr36.54, NEUTRAL[V], TP Nkr35.0) Amec Foster Wheeler (AMFW.L, 531.0p, UNDERPERFORM, TP 450.0p) Anadarko Petroleum Corp. (APC.N, $57.59) Anton Oil (3337.HK, HK$0.73) Atwood Oceanics, Inc. (ATW.N, $7.19) BP (BP.L, 420.55p) BW Offshr (BWO.OL, Nkr0.29) Babcock (BAB.L, 1073.0p) Baker Hughes Inc. (BHI.N, $48.34) Bechtel Corporation (Unlisted) Borregaard (BRGD.OL, Nkr66.75) Bumi Armada Bhd (BUAB.KL, RM0.73) CGG (GEPH.PA, €22.06, UNDERPERFORM[V], TP €17.5) CNOOC (0883.HK, HK$9.48) COSL (2883.HK, HK$6.04) CPC (CPC.HN, D21500.0) CTCI Corp (9933.TW, NT$42.35) Chevron Corp. (CVX.N, $99.43) Chicago Bridge & Iron (CBI.N, $28.43) Chiyoda Corp (6366.T, ¥819) ConocoPhillips (COP.N, $41.01) Core Laboratories (CLB.N, $108.25, NEUTRAL, TP $115.0) DNO ASA (DNO.OL, Nkr8.145) DOF (DOF.OL, Nkr0.93) Daewoo E&C (047040.KS, W5,940) Diamond Offshore Drilling, Inc (DO.N, $15.16) EMAS Offshore (EMAS.SI, S$0.07) ENI (ENI.MI, €13.11) Edison International (EIX.N, $71.63) EnQuest (ENQ.L, 28.0p) Ensco Plc. (ESV.N, $6.89) Ernst & Young (Unlisted) ExxonMobil Corporation (XOM.N, $85.21) Fluor (FLR.N, $49.58) Forum Energy Technologies, Inc. (FET.N, $17.55) Frank's International (FI.N, $11.7) GS E&C (006360.KS, W27,350) General Electric (GE.N, $29.85) Halliburton (HAL.N, $41.11) Hanwha (000880.KS, W35,950) Helmerich & Payne, Inc. (HP.N, $57.18) Hess Corporation (HES.N, $47.77) Hi-Crush Partners, LP (HCLP.N, $15.35) Hilong (1623.HK, HK$1.0) Hoegh LNG (HLNGH.OL, Nkr83.0) Hunting Plc (HTG.L, 415.5p, NEUTRAL[V], TP 500.0p) Hyundai Heavy Industries (009540.KS, W132,500) INPEX Corp (1605.T, ¥847) ION Geophysical (IO.N, $5.71) Ithaca Energy (IAE.L, 65.25p) JGC Corp (1963.T, ¥1,661) Jacobs Engineering (JEC.N, $50.15) KBR Inc. (KBR.N, $14.62) Keppel Corporation (KPLM.SI, S$5.22) Kiewit Corporation (Unlisted) Larsen & Toubro Limited (Unlisted) MODEC, INC. (6269.T, ¥1,744) Marathon Oil Corp (MRO.N, $14.34) McDermott International (MDR.N, $4.78) Moody's Corporation (MCO.N, $107.32) Morgan Stanley (MS.N, $31.46) Nabors Industries, Ltd. (NBR.N, $9.31) National Oilwell Varco (NOV.N, $33.09) Nexans (NEXS.PA, €47.55) Noble Corporation (NE.N, $5.54) Oceaneering Intl, Inc. (OII.N, $25.52) Offshore Oil Engineering (600583.SS, Rmb6.99) Oil States International (OIS.N, $28.73) Oil and Natural Gas Corporation Limited (ONGC.BO, Rs251.15) Oman Oil Company (Unlisted) Ophir Energy plc (OPHR.L, 70.0p) Pacific Drilling (PACD.N, $3.26) Patterson-UTI Energy, Inc. (PTEN.OQ, $18.44) Petrobras (PETR4.SA, R$13.01) Petrofac (PFC.L, 808.0p, OUTPERFORM[V], TP 1100.0p) Petroleum Geo Services (PGS.OL, Nkr16.6, OUTPERFORM[V], TP Nkr27.0) Polarcus (PLCS.OL, Nkr0.39) Precision Drilling Corporation (PDS.N, $3.77) Qatar Petroleum (Unlisted) RWE (RWEG.F, €14.59) Rosneft (ROSNq.L, $5.575) Rowan Companies (RDC.N, $12.75) Royal Dutch Shell plc (RDSa.L, 1831.5p) SBM Offshore (SBMO.AS, €11.98) Saipem (SPMI.MI, €0.38, NEUTRAL[V], TP €0.45) Samsung Heavy Industries (010140.KS, W10,100)

19 September 2016


Saudi Aramco (Unlisted) Schlumberger (SLB.N, $77.08) Schoeller Bleckmann Oilfield Equipment (SBOE.VI, €52.65, OUTPERFORM, TP €70.0) Seadrill (SDRL.N, $2.15, UNDERPERFORM[V], TP $1.0) Sembcorp Marine Ltd. (SCMN.SI, S$1.285) Siem Offshore (SIOFF.OL, Nkr1.9) Siemens (SIEGn.DE, €102.15) Simmons Fst Natl (SFNC.OQ, $49.22) Sinopec (0386.HK, HK$5.36) Sinopec Engineering (2386.HK, HK$6.57) Sonatrach (Unlisted) Spectrum (SPU.OL, Nkr25.0) Statoil (STL.OL, Nkr126.1) Subsea 7 S.A. (SUBC.OL, Nkr84.7, UNDERPERFORM, TP Nkr75.0) Superior Energy Services, Inc. (SPN.N, $15.32) TGS-NOPEC Geophysical (TGS.OL, Nkr143.8) Technip (TECF.PA, €51.3, OUTPERFORM, TP €65.0) Tecnicas Reunidas (TRE.MC, €32.5, UNDERPERFORM, TP €28.0) Tenaris (TENR.MI, €11.58) Tetra Technologies, Inc. (TTI.N, $5.8) Total (TOTF.PA, €42.0) Transocean Inc. (RIG.N, $9.31) Tullow Oil (TLW.L, 217.5p) U.S. Silica (SLCA.N, $40.74) UBS Group AG (UBSG.S, SFr14.0) United Utilities (UU.L, 976.5p) Vallourec (VLLP.PA, €3.97) Weatherford International, Inc. (WFT.N, $6.26) Weir (WEIR.L, 1492.0p) Wood Group (WG.L, 688.5p, OUTPERFORM, TP 850.0p) Woodside Petroleum (WPL.AX, A$27.57) WorleyParsons (WOR.AX, A$7.66)

Disclosure Appendix

Important Global Disclosures Phillip Lindsay and Gregory Brown each certify, with respect to the companies or securities that the individual analyzes, that (1) the views expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his or her compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report. The analyst(s) responsible for preparing this research report received Compensation that is based upon various factors including Credit Suisse's total revenues, a portion of which are generated by Credit Suisse's investment banking activities

As of December 10, 2012 Analysts’ stock rating are defined as follows: Outperform (O) : The stock’s total return is expected to outperform the relevant benchmark* over the next 12 months. Neutral (N) : The stock’s total return is expected to be in line with the relevant benchmark* over the next 12 months. Underperform (U) : The stock’s total return is expected to underperform the relevant benchmark* over the next 12 months. *Relevant benchmark by region: As of 10th December 2012, Japanese ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractiv e, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. As of 2nd October 2012, U.S. and Canadian as well as European ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. For Latin Ame rican and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return of the relevant country or regional benchmark; prior to 2nd October 2012 U.S. and Canadian ratings were based on (1) a stock’s absolute total return potential to its current share price and (2) the relative attractiv eness of a stock’s total return potential with in an analyst’s coverage universe. For Australian and New Zealand stocks, the expected total return (ETR) calculation includes 1 2-month rolling dividend yield. An Outperform rating is assigned where an ETR is greater than or equal to 7.5%; Underperform whe re an ETR less than or equal to 5%. A Neutral may be assigned where the ETR is between -5% and 15%. The overlapping rating range allows analysts to assign a rating that puts ETR in the context of associated risks. Prior to 18 May 2015, ETR ranges for Outperform and Underperform ratings did not overlap with Neutral thresholds between 15% and 7.5%, which was in operation from 7 Ju ly 2011. Restricted (R) : In certain circumstances, Credit Suisse policy and/or applicable law and regulations preclude certain types of communications, including an investment recommendation, during the course of Credit Suisse's engagement in an investment banking transaction and in certain other circumstances. Not Rated (NR) : Credit Suisse Equity Research does not have an investment rating or view on the stock or any other securities related to the company at this time. Not Covered (NC) : Credit Suisse Equity Research does not provide ongoing coverage of the company or offer an investment rating or investment view on the equity security of the company or related products.

Volatility Indicator [V] : A stock is defined as volatile if the stock price has moved up or down by 20% or more in a month in at least 8 of the past 24 months or the analyst expects significant volatility going forward.

Analysts’ sector weightings are distinct from analysts’ stock ratings and are based on the analyst’s expectations for the fundamentals and/or valuation of the sector* relative to the group’s historic fundamentals and/or valuation: Overweight : The analyst’s expectation for the sector’s fundamentals and/or valuation is favorable over the next 12 months. Market Weight : The analyst’s expectation for the sector’s fundamentals and/or valuation is neutral over the next 12 months. Underweight : The analyst’s expectation for the sector’s fundamentals and/or valuation is cautious over the next 12 months. *An analyst’s coverage sector consists of all companies covered by the analyst within the relevant sector. An analyst may cover multiple sectors.

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Credit Suisse's distribution of stock ratings (and banking clients) is:

Global Ratings Distribution

Rating Versus universe (%) Of which banking clients (%) Outperform/Buy* 53% (50% banking clients) Neutral/Hold* 29% (24% banking clients) Underperform/Sell* 18% (44% banking clients) Restricted 0% *For purposes of the NYSE and NASD ratings distribution disclosure requirements, our stock ratings of Outperform, Neutral, an d Underperform most closely correspond to Buy, Hold, and Sell, respectively; however, the meanings are not the same, as our stock ratings are determined on a relative basis. (Please refer to definitions above.) An investor's decision to buy or sell a security should be based on investment objectives, current holdin gs, and other individual factors.

Credit Suisse’s policy is to update research reports as it deems appropriate, based on developments with the subject company, the sector or the market that may have a material impact on the research views or opinions stated herein. Credit Suisse's policy is only to publish investment research that is impartial, independent, clear, fair and not misleading. For more detail please refer to Credit Suisse's Policies for Managing Conflicts of Interest in connection with Investment Research: http://www.csfb.com/research-and-analytics/disclaimer/managing_conflicts_disclaimer.html Credit Suisse does not provide any tax advice. Any statement herein regarding any US federal tax is not intended or written to be used, and cannot be used, by any taxpayer for the purposes of avoiding any penalties.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Aker Solutions (AKSOL.OL)

Method: We value Aker Solutions using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 1.5, WACC of 8.75% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 7.3x / 7.5x for 2017/18e. The net result drives a target price of NOK35, which is consistent with our Neutral rating.

Risk: Upside risks to our NOK35 target price and Neutral rating include higher than expected oil prices leading to higher E&P capex and subsequent recovery in subsea markets as well as stronger than expected win rates for subsea and MMO markets, and higher margin / returns. Downside risks include lower E&P capex as a result of a further fall in oil price, project execution issues, corporate governance issues given the ownership structure and competitive pressures from vertically integrated peers such as Technip / FMC Technologies

Target Price and Rating Valuation Methodology and Risks: (12 months) for Amec Foster Wheeler (AMFW.L)

Method: We value Amec Foster Wheeler using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 1.41, WACC of 8.46% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 7.5x / 6.9x for 2017/18e. The net result drives a target price of GBP4.50, which is consistent with our Underperform rating.

Risk: Risks to our GBP4.50 target price and underperform rating include higher than expected oil prices leading to greater than expected E&P capex, particularly offshore, better than expected win rates and higher margin and returns. We also see a risk that planned disposals may achieve a higher than expected valuation.

Target Price and Rating Valuation Methodology and Risks: (12 months) for CGG (GEPH.PA)

Method: We value CGG using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 2.5, WACC of 8.9% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 5x / 4x for 2017/18e. The net result drives a target price of EUR17.5, which is consistent with our Underperform rating.

Risk: The upside risks to our EUR17.5 target price and Underperform rating include higher than expected commodity prices leading to greater than anticipated E&P spend and license round activity. A faster recovery in marine pricing could also lead to an early replacement cycle for equipment.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Core Laboratories (CLB.N)

Method: Our $115 Target Price and Neutral rating for CLB is based on a DCF analysis using a 7.5% WACC and long-term growth rate of 1.5%.

Risk: Risks that could prevent CLB from reaching our $115 target price and Neutral rating are those specific to the company and those that relate to the oil and gas industry. Industry specific risks include (1) oil prices, (2) global oil demand, (3) global economy, (4) global E&P CAPEX spending, (5) interest rate risk, (6) environmental and government laws/regulations, (7) geopolitical risks, (8) foreign exchange risk, (9) increased competition. Company specific risks include (1) guidance revisions, (2) increased competition, (3) loss of customers or key contracts, (4) inability to protect or obtain patents or licenses, (5) customer concentration, (6) inability to maintain the dividend, (7) maintaining compliance with debt covenants, (8) loss of a key supplier, (9) availability of credit to fund future growth, (10) customer and

19 September 2016


counterparty risk, (11) obsolete technology or products, (12) loss of business due to declining oil prices, global oil demand or E&P CAPEX spending, (13) loss of key employees.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Hunting Plc (HTG.L)

Method: We value Hunting using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 1.2, WACC of 7.7% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 16x / 10x for 2017/18e. The net result drives a target price of GBp500, which is consistent with our Neutral rating.

Risk: Upside risks to our GBp500 target price and Netural rating include a faster recovery in commodity prices leading to increased drilling activity in North America and elsewhere, and a subsequent improvement in pricing. Downside risks include additional weakness in oil prices which would result in lower demand for sophisticated technologies. Other downside risks include rising DSOs, risks to hydraulic fracturing for environmental and political reasons and market share erosion.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Petrofac (PFC.L)

Method: We value Petrofac using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 1.25, WACC of 9.4% and long-term growth of 2%. For SOTP we apply PE multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 9.0x / 8.5x for 2017/18e. The net result drives a target price of GBp1100, which is consistent with our Outperform rating.

Risk: Downside risks to our Outperform rating with GBp1100 target price are primarily related to cost overruns or material project delays for which there is no contingency. Risks also include lower than expected E&P and downstream capital expenditure, a slower pace of contract awards from NOCs and further delays in disposing of the IES book.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Petroleum Geo Services (PGS.OL)

Method: We value PGS using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 2.0, WACC of 8.6% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 4.6x / 3.6x for 2017/18e. The net result drives a target price of NOK27, which is consistent with our Outperform rating.

Risk: Downside risks to our NOK27 target price and Outperform rating include lower oil prices than currently forecast, leading to lower exploration investment and weaker marine pricing. Downside risks also include an unlikely banking covenant breach and the reactivation of marine vessels causing a headwind to marine pricing.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Saipem (SPMI.MI)

Method: We value Saipem using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 1.25%, WACC of 8.08% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 5.0x / 4.5x for 2017/18e. The net result drives a target price of EUR0.45, which is consistent with our Neutral rating.

Risk: Upside risks to our target price of EUR0.45 and Neutral rating include strong execution of legacy backlog, better than expected order intake trends, a favourable outcome in the ongoing Algerian corruption probe, a more benign competitive market, a more resilient offshore drilling cycle and a positive resolution to contractual issues and improved working capital / cash positions. Downside risks include any issues with legacy backlog, the inability to re-contract idle drilling rigs and an unfavourable outcome to ongoing legal issues.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Schoeller Bleckmann Oilfield Equipment (SBOE.VI)

Method: We value Schoeller Bleckmann using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 0.9%, WACC of 6.9% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 12.2x / 8.5x for 2017/18e. The net result drives a target price of EUR70, consistent with our Outperform rating.

Risk: The downside risks to our EUR70 target price and Outperform rating include a further contraction in North American onshore drilling, market share erosion and a weaker pricing environment

Target Price and Rating Valuation Methodology and Risks: (12 months) for Seadrill (SDRL.N)

Method: Our $1 target price and Underperform rating for SDRL is based on 10x multiple of our 2017 EBITDA (earnings before interest, tax, depreciation and amortization). We believe SDRL trades at a discount to its peers supporting our Underperform rating.

19 September 2016


Risk: Risks of SDRL not achieving our $1 target price and Underperform rating are company specific risks: (1) declining UDW day rates; (2) Hemen Holdings (Fredriksen Family) is the majority owner (23.2% stock ownership); (3) nonaccretive or ill-timed acquisitions; (4) availability of credit to fund future growth; (5) customer and counterparty risk; (6) loss of customers; (7) accidents, (8) environmental and government regulations where rigs operate; (9) lack of available crew; (10) antitakeover provisions that make it difficult to replace the board of directors; (11) failure of shipyards to deliver newbuildings and industry specific risks: (1) oil prices, (2) global oil demand, (3) global GDP, (4) global E&P capex spending, (5) interest rate risk, (6) environmental and government regulations, (7) oversupply of offshore drilling rigs, (8) increased competition, (9) inclement weather, and (10) geopolitical risks.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Subsea 7 S.A. (SUBC.OL)

Method: We value Subsea 7 using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 1.45, WACC of 9.71% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 5.9x / 5.0x for 2017/18e. The net result drives a target price of NOK75, which is consistent with our Underperform rating.

Risk: Risks to our NOK75 target price and underperform rating include a sharp recovery in oil price, greater than expected resilience to brownfield/life of field competition, a stronger contract win rate and higher E&P capital expenditures by oil and gas companies vs. our current expectations.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Technip (TECF.PA)

Method: We value standalone Technip using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 1.2, WACC of 7.9% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 6.5x / 7.3x for 2017/18e. The net result drives a target price of EUR65, which is consistent with our Outperform rating.

Risk: Downside risks to our target price of EUR65 and our Outperform rating include project complications and execution issues impacting current backlog, issues with Yamal project financing, an unfavourable outcome from legal proceedings in Algeria, project award delays impacting book to bill and future backlog levels, competitive intensity increasing and the failure to ccomplete the proposed merger with FMC Technologies.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Tecnicas Reunidas (TRE.MC)

Method: We value Tecnicas Reunidas using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 1.25, WACC of 9.2% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 4.75x / 4.75x for 2017/18e.The net result drives a target price of EUR28, which is consistent with our Underperform rating.

Risk: The risks to our Underperform rating and EUR28 target price are related to order backlog and project execution. Should oil prices recover beyond our expectation we should expect a stronger orderbook momentum, and potential favourable changes to project T&Cs. Stronger project execution could also lead to unforeseen bonus payments, however, any issues are likely to incur significant costs.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Wood Group (WG.L)

Method: We value Wood Group using an equally weighted combination of DCF and SOTP, using 2017e and 2018e. For DCF we assume a beta of 1.33, WACC of 8.20% and long-term growth of 2%. For SOTP we apply EBITDA multiples to each division based on business quality, comparable companies, historical multiples, cycle phasing and growth expectations. For the group, this results multiples of 7.8x / 6.8x for 2017/18e. The net result drives a target price of GBP8.50, which is consistent with our Outperform rating.

Risk: Downside risks to our GBP8.50 target price and Outperform rating include market share erosion by late-cycle competitors in engineering, greater competitive threats for the North Sea PSN business, pricing pressures and protracted contract negotiations with customers, lower than expected capital expenditure by oil comnpanies and a subsequent slower pace of contract awards

Please refer to the firm's disclosure website at https://rave.credit-suisse.com/disclosures for the definitions of abbreviations typically used in the target price method and risk sections.

See the Companies Mentioned section for full company names The subject company (PGS.OL, SBOE.VI, TRE.MC, AKSOL.OL, PFC.L, SPMI.MI, HTG.L, SDRL.N, GEPH.PA, WG.L, TECF.PA, CLB.N, BHI.N, HAL.N, SLB.N, SPN.N, HCLP.N, SLCA.N, TTI.N, FET.N, FI.N, OIS.N, CBI.N, 600583.SS, FLR.N, OII.N, 2386.HK, SIEGn.DE, JEC.N, KBR.N, TENR.MI, NBR.N, PDS.N, ATW.N, 2883.HK, DO.N, NE.N, PACD.N, RDC.N, RIG.N, RWEG.F) currently is, or was during the 12-month period preceding the date of distribution of this report, a client of Credit Suisse. Credit Suisse provided investment banking services to the subject company (SPMI.MI, GEPH.PA, CLB.N, HAL.N, SLB.N, SPN.N, HCLP.N, 600583.SS, TENR.MI, PDS.N, ATW.N, 2883.HK, DO.N, NE.N, RIG.N, RWEG.F) within the past 12 months. Credit Suisse provided non-investment banking services to the subject company (SIEGn.DE) within the past 12 months

19 September 2016


Credit Suisse has managed or co-managed a public offering of securities for the subject company (GEPH.PA, CLB.N, HAL.N, HCLP.N, DO.N, RIG.N) within the past 12 months. Credit Suisse has received investment banking related compensation from the subject company (SPMI.MI, GEPH.PA, CLB.N, HAL.N, SLB.N, SPN.N, HCLP.N, 600583.SS, TENR.MI, PDS.N, ATW.N, 2883.HK, DO.N, NE.N, RIG.N, RWEG.F) within the past 12 months Credit Suisse expects to receive or intends to seek investment banking related compensation from the subject company (PGS.OL, SBOE.VI, TRE.MC, AKSOL.OL, PFC.L, SPMI.MI, HTG.L, SDRL.N, GEPH.PA, WG.L, TECF.PA, CLB.N, 3337.HK, BHI.N, HAL.N, SLB.N, SPN.N, WFT.N, HCLP.N, TTI.N, FET.N, FI.N, OIS.N, CBI.N, 600583.SS, MDR.N, FLR.N, OII.N, 2386.HK, SIEGn.DE, JEC.N, KBR.N, TENR.MI, VLLP.PA, HP.N, NBR.N, PTEN.OQ, PDS.N, ATW.N, 2883.HK, DO.N, ESV.N, NE.N, PACD.N, RDC.N, RIG.N, RWEG.F) within the next 3 months. Credit Suisse has received compensation for products and services other than investment banking services from the subject company (SIEGn.DE) within the past 12 months As of the date of this report, Credit Suisse makes a market in the following subject companies (BHI.N, HAL.N, SLB.N, SPN.N, SLCA.N, OIS.N, FLR.N, OII.N, JEC.N, KBR.N, HP.N, NBR.N, PTEN.OQ, ATW.N, DO.N, ESV.N, NE.N, RDC.N, RIG.N). Please visit https://credit-suisse.com/in/researchdisclosure for additional disclosures mandated vide Securities And Exchange Board of India (Research Analysts) Regulations, 2014 Credit Suisse may have interest in (ONGC.BO) As of the end of the preceding month, Credit Suisse beneficially own 1% or more of a class of common equity securities of (SUBC.OL, HCLP.N, 2883.HK). Credit Suisse beneficially holds >0.5% long position of the total issued share capital of the subject company (HCLP.N). Credit Suisse beneficially holds >0.5% short position of the total issued share capital of the subject company (MDR.N). Credit Suisse has a material conflict of interest with the subject company (SLB.N) . Credit Suisse is acting as financial advisor to Cameron International (CAM) on its announced acquisition by Schlumberger (SLB).

For other important disclosures concerning companies featured in this report, including price charts, please visit the website at https://rave.credit-suisse.com/disclosures or call +1 (877) 291-2683. For date and time of production, dissemination and history of recommendation for the subject company(ies) featured in this report, disseminated within the past 12 months, please refer to the link: https://rave.credit-suisse.com/disclosures/view/report?i=247248&v=5d1shiy6g23vhlwyvru30g2uj .

Important Regional Disclosures Singapore recipients should contact Credit Suisse AG, Singapore Branch for any matters arising from this research report. The analyst(s) involved in the preparation of this report may participate in events hosted by the subject company, including site visits. Credit Suisse does not accept or permit analysts to accept payment or reimbursement for travel expenses associated with these events. Restrictions on certain Canadian securities are indicated by the following abbreviations: NVS--Non-Voting shares; RVS--Restricted Voting Shares; SVS--Subordinate Voting Shares. Individuals receiving this report from a Canadian investment dealer that is not affiliated with Credit Suisse should be advised that this report may not contain regulatory disclosures the non-affiliated Canadian investment dealer would be required to make if this were its own report. For Credit Suisse Securities (Canada), Inc.'s policies and procedures regarding the dissemination of equity research, please visit https://www.credit-suisse.com/sites/disclaimers-ib/en/canada-research-policy.html. Credit Suisse Securities (Europe) Limited (Credit Suisse) acts as broker to (WG.L). The following disclosed European company/ies have estimates that comply with IFRS: (PFC.L, SPMI.MI, SDRL.N, WG.L, TECF.PA, SIEGn.DE, TENR.MI, VLLP.PA, RWEG.F). Credit Suisse has acted as lead manager or syndicate member in a public offering of securities for the subject company (SDRL.N, GEPH.PA, CLB.N, HAL.N, SLB.N, HCLP.N, 600583.SS, OII.N, PDS.N, 2883.HK, DO.N, RIG.N, RWEG.F) within the past 3 years. Principal is not guaranteed in the case of equities because equity prices are variable. Commission is the commission rate or the amount agreed with a customer when setting up an account or at any time after that. This research report is authored by: Credit Suisse Securities (USA) LLC .....................................................James Wicklund ; Gregory Lewis, CFA ; Neesha Khanna ; Joseph Nelson Credit Suisse International ....................................................................................................................................... Phillip Lindsay ; Gregory Brown To the extent this is a report authored in whole or in part by a non-U.S. analyst and is made available in the U.S., the following are important disclosures regarding any non-U.S. analyst contributors: The non-U.S. research analysts listed below (if any) are not registered/qualified as research analysts with FINRA. The non-U.S. research analysts listed below may not be associated persons of CSSU and therefore may not be subject to the NASD Rule 2711 and NYSE Rule 472 restrictions on communications with a subject company, public appearances and trading securities held by a research analyst account. Credit Suisse International ....................................................................................................................................... Phillip Lindsay ; Gregory Brown

Important Credit Suisse HOLT Disclosures With respect to the analysis in this report based on the Credit Suisse HOLT methodology, Credit Suisse certifies that (1) the views expressed in this report accurately reflect the Credit Suisse HOLT methodology and (2) no part of the Firm’s compensation was, is, or will be d irectly related to the specific views disclosed in this report. The Credit Suisse HOLT methodology does not assign ratings to a security. It is an analytical tool that involves use of a set of proprietary quantitative algorithms and warranted value calculations, collectively called the Credit Suisse HOLT valuation model, that are consistently applied to all the companies included in its database. Third-party data (including consensus earnings estimates) are systematically translated into a number of default algorithms available in the Credit Suisse HOLT valuation model. The source financial statement, pricing, and earnings data provided by outside data vendors are subject to quality control and may also be adjusted to more closely measure the underlying economics of firm performance. The adjustments provide consistency when analyzing a single company across time, or analyzing multiple companies across industries or national borders. The default scenario that is produced by the Credit Suisse HOLT valuation model establishes the baseline valuation for a security, and a user then may adjust the default variables to produce alternative scenarios, any of which could occur.

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19 September 2016


Additional information about the Credit Suisse HOLT methodology is available on request. The Credit Suisse HOLT methodology does not assign a price target to a security. The default scenario that is produced by the Credit Suisse HOLT valuation model establishes a warranted price for a security, and as the third-party data are updated, the warranted price may also change. The default variable may also be adjusted to produce alternative warranted prices, any of which could occur. CFROI®, HOLT, HOLTfolio, ValueSearch, AggreGator, Signal Flag and “Powered by HOLT” are trademarks or service marks or registered trademarks or registered service marks of Credit Suisse or its affiliates in the United States and other countries. HOLT is a corporate performance and valuation advisory service of Credit Suisse.

For Credit Suisse disclosure information on other companies mentioned in this report, please visit the website at https://rave.credit-suisse.com/disclosures or call +1 (877) 291-2683.

19 September 2016


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