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
Gregory Brown
44 20 7888 1440
James Wicklund
214 979 4111
Gregory Lewis, CFA
212 325 6418
Specialist Sales: Jason Turner
44 20 7888 1395
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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Reduction as of Q3 2015 Further Reduction Delivered to May 2016
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Covered stocks include: Technip, Saipem, Subsea 7, Hunting, Schoeller Bleckmann and PGS
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19 September 2016
Oilfield Services & Equipment 3
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
Oilfield Services & Equipment 4
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
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
■ 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
Oilfield Services & Equipment 5
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
Oilfield Services & Equipment 6
■ 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
Oilfield Services & Equipment 7
■ 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
63%
36% 33%27% 23% 20% 20%
6%
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-21%
-53%
-75%
-55%
-35%
-15%
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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
Oilfield Services & Equipment 13
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
Oilfield Services & Equipment 14
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
Oilfield Services & Equipment 15
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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Covered stocks include: Technip, Saipem, Subsea 7, Hunting, Schoeller Bleckmann and PGS
Key beneficiaries: PFC, TEC, CLB, CGG
19 September 2016
Oilfield Services & Equipment 16
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.
-10%
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RO
IC
Equipment Onshore E&C Other E&CEPCM Seismic
0%
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T T+1 T+2 T+3 T+4 T+5
2009-14 2015-20e
19 September 2016
Oilfield Services & Equipment 17
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
Oilfield Services & Equipment 18
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.
0% 10% 20% 30% 40% 50% 60%
Well Services
Rigs
RDT
Operations & Maintenance
Logistics
Installation
Fabrication & Construction
Equipment & Technology
EPMS
Engineering Services & Subsea
Reduction as of Q3 2015 Further Reduction Delivered to May 2016
19 September 2016
Oilfield Services & Equipment 19
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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19 September 2016
Oilfield Services & Equipment 20
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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19 September 2016
Oilfield Services & Equipment 21
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
Oilfield Services & Equipment 22
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
Oilfield Services & Equipment 23
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
Oilfield Services & Equipment 24
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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19 September 2016
Oilfield Services & Equipment 25
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
Oilfield Services & Equipment 26
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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19 September 2016
Oilfield Services & Equipment 27
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
Oilfield Services & Equipment 28
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
Oilfield Services & Equipment 29
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
Oilfield Services & Equipment 30
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
Oilfield Services & Equipment 31
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
0
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19 September 2016
Oilfield Services & Equipment 32
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
0
500
1,000
1,500
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1Q16A 2Q16A 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E 1Q18E 2Q18E 3Q18E 4Q18E
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US Rig Count Horizontal
19 September 2016
Oilfield Services & Equipment 33
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%
-8%
9%12%
-39%
-19%-23% -24%
-46%
-18%
-10%-14%
17%
-10%
3%
-11%
-55%
-45%
-35%
-25%
-15%
-5%
5%
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25%
North American E&P Integrateds NOCs Other E&P
2009 vs 2008 2015 vs 2014 2016E vs 2015 2017E vs 2016E
0
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North American E&P Integrateds NOCs Other E&P
19 September 2016
Oilfield Services & Equipment 34
■ 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
Oilfield Services & Equipment 35
‘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
Source: Company data, Credit Suisse Research, Thomson Reuters, UpstreamOnline, MEED, AOG, data correct as of September 7
th 2016
0
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JA
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2014 2015 2016
US
Dm
0 20,000 40,000 60,000 80,000 100,000
2014
2015
2016 ytd
Offshore Onshore
19 September 2016
Oilfield Services & Equipment 36
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
Source: Company data, Credit Suisse Research, Thomson Reuters, UpstreamOnline, MEED, AOG, data correct as of September 7
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
27%
Americas
12%
Asia Pacific
26%
Europe
2%
Middle East
33%
0
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19 September 2016
Oilfield Services & Equipment 37
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
Oilfield Services & Equipment 38
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
Offshore
Onshore
EPCFloating
SURF / SPS
Midstream
SURFT&I
BrownfieldSPS
Decommissioning
0 5000 10000 15000 20000
Mozambique
Algeria
Angola
Nigeria
Congo-Brazzaville
Ghana
Kenya
Namibia
Equatorial Guinea
Mauritania
ENISonatrach
Tullow
Hess
OphirChevron
Total Petronas
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Mamba Coral South Nene-Loango Hassi Tiaret PekanUltradeep
SouthLockichar
Biska Etan &Zabazaba
Dalia
19 September 2016
Oilfield Services & Equipment 39
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
Oilfield Services & Equipment 40
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
in USD millions, unless otherwise stated
Source: Company data, Credit Suisse Research, data correct as of September 7th 2016
Offshore
Onshore
EPCFloating
SURF
Brownfield
Integrated SURF/SPS SPS
SPS & SURF Seismic
FEEDEPIC
0 2000 4000 6000 8000 10000 12000
Indonesia
Malaysia
India
Australia
China
Thailand
Taiwan
Vietnam
ONGC
Chevron
InpexPetronas
ExxonMobil
CNOOC
CPC Corporation
Repsol TalismanHess Others
0
1000
2000
3000
4000
5000
6000
19 September 2016
Oilfield Services & Equipment 41
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
Oilfield Services & Equipment 42
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
Oilfield Services & Equipment 43
Figure 46: Middle East prospects Figure 47: Middle East 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 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
in USD millions, unless otherwise stated
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
Oilfield Services & Equipment 44
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
Oilfield Services & Equipment 45
Figure 51: European prospects by field Figure 52: European 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 53: European prospects by country (USDm) Figure 54: European 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 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
Oilfield Services & Equipment 46
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
Oilfield Services & Equipment 47
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
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 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
Oilfield Services & Equipment 48
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
Oilfield Services & Equipment 49
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
Oilfield Services & Equipment 50
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
1Q16A 2Q16A 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E 1Q18E 2Q18E 3Q18E 4Q18E
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
Oilfield Services & Equipment 51
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
1Q16A 2Q16A 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E 1Q18E 2Q18E 3Q18E 4Q18E
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
Oilfield Services & Equipment 52
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
200
300
400
500
600
700
800
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
Oilfield Services & Equipment 53
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
Oilfield Services & Equipment 54
Figure 70: Offshore project awards by region Figure 71: Key unawarded Offshore EPC projects
in USD millions, unless otherwise stated in USD millions, unless otherwise stated
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
Oilfield Services & Equipment 55
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
in USD millions, unless otherwise stated in USD millions, unless otherwise stated
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
6000
7000
8000
9000
19 September 2016
Oilfield Services & Equipment 56
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
Oilfield Services & Equipment 57
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
Oilfield Services & Equipment 58
Figure 76: Subsea tree order forecast Figure 77: Subsea tiebacks onstream forecast
Source: Infield Systems Source: Infield Systems
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
200
300
400
500
600
2010 2011 2012 2013 2014 2015 2016e 2017e 2018e 2019e 2020e
Firm Plan / Awarded Firm Plan Probable Possible
0
10
20
30
40
50
60
2016e 2017e 2018e 2019e 2020e
Africa Asia Australasia Europe Latin America Middle East North America
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
2010 2011 2012 2013 2014 2015 2016e 2017e 2018e 2019e 2020e
Operational Firm Plan Probable Possible Other*
2
24
84
12 12
7 812
23
64
18
6
48
86
0
10
20
30
40
50
60
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
2010 2011 2012 2013 2014 2015 2016e 2017e 2018e 2019e 2020e
Africa Asia Australasia Europe Latin America Middle East North America
19 September 2016
Oilfield Services & Equipment 59
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
Oilfield Services & Equipment 60
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
Oilfield Services & Equipment 61
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
2
3
4
5
6
7
CGG PGS AMFW PFC SPM WG AKSO SUBC TEC TRE
-3
-2
-1
0
1
2
3
4
5
CGG AMFW PGS SPM AKSO PFC WG SUBC TEC TRE
19 September 2016
Oilfield Services & Equipment 62
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
-2
-1
0
1
2
3
4
5
6
7
CGG PGS AMFW PFC SPM WG AKSO SUBC TEC TRE
-3
-2
-1
0
1
2
3
4
5
CGG PGS AMFW SPM PFC AKSO WG SUBC TEC TRE
19 September 2016
Oilfield Services & Equipment 63
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
Source: Company data, Credit Suisse estimates Source: Credit Suisse estimates
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
Source: Company data, Credit Suisse estimates Source: Credit Suisse estimates
-4
-2
0
2
4
6
8
CGG PGS AMFW PFC SPM WG AKSO SUBC TEC TRE
-4
-3
-2
-1
0
1
2
3
4
5
6
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
Oilfield Services & Equipment 64
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
Oilfield Services & Equipment 65
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
Source: Company data, Credit Suisse 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
Oilfield Services & Equipment 66
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
Source: Company data, Credit Suisse HOLT
19 September 2016
Oilfield Services & Equipment 67
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
Source: Company data, Credit Suisse HOLT
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Oilfield Services & Equipment 68
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
Source: Company data, Credit Suisse HOLT
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Oilfield Services & Equipment 69
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
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Oilfield Services & Equipment 70
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.
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Oilfield Services & Equipment 71
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
Oilfield Services & Equipment 73
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
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 USD1.00
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
Oilfield Services & Equipment 76
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
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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
Gregory Brown
44 20 7888 1440
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
Oilfield Services & Equipment 78
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
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
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 79
Key charts
Figure 108: Deepwater EPIC capex by region Figure 109: Subsea order forecast
in USD millions, unless otherwise stated
Source: Infield Systems Source: Infield Systems
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
8397
76 48 41
28
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19 September 2016
Oilfield Services & Equipment 80
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
Oilfield Services & Equipment 81
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
Associates / minorities 234 234
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
Oilfield Services & Equipment 82
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
Oilfield Services & Equipment 83
Figure 115: Aker Solutions in HOLT
Source: Credit Suisse 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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it S
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Scen
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AKER SOLUTIONS ASA (AKSO)
EB
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A M
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para
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% p
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to f
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-2.0% -94% -90% -83% -74%
23%
-62%
-1.0% -67% -58% -47% -34% -18%
0.0% -39% -26% -12% 5%
104%
1.0% -10% 5% 22% 42% 64%
2.0% 18% 36% 56% 79%
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.
-20
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19 September 2016
Oilfield Services & Equipment 84
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 85
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
Cash and cash equivalents 3339 3862 2099 2057 2601 3097 3637
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 86
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
Oilfield Services & Equipment 87
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
analyst's or each team's respective sector.
¹Target price is for 12 months.
Research Analysts
Phillip Lindsay
44 20 7883 1644
Gregory Brown
44 20 7888 1440
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.
Share price performance
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
Performance 1M 3M 12M Absolute (%) 2.6 30.4 -31.1 Relative (%) 5.5 18.0 -39.6
Financial and valuation metrics
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
Oilfield Services & Equipment 88
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
Assets Total current assets 1,872 1,893 1,921 2,082 Total assets 5,572 5,191 5,092 5,128 Liabilities Total current liabilities 2,261 2,247 2,146 2,154 Total liabilities 3,964 3,950 3,849 3,857 Total equity and liabilities 5,572 5,191 5,092 5,128
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 analysis (%) 12/15A 12/16E 12/17E 12/18E
ROE (%) 14.6 14.3 14.7 16.4 ROIC (avg.) (%) 13.1 18.0 11.8 12.7
Credit ratios 12/15A 12/16E 12/17E 12/18E
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.
Blue/Grey Sky Scenario
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%.
Share price performance
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
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 89
AMFW in charts
Figure 119: Revenue vs. trading profit Figure 120: Trading profit overview
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
Figure 121: Trading cash flow and cash generation Figure 122: AMFW Net Debt to EBITDA evolution
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
Figure 123: AMFW net debt bridge
Source: Company data, Credit Suisse estimates
9%8%
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19 September 2016
Oilfield Services & Equipment 90
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
Oilfield Services & Equipment 91
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.
Blue sky / Grey sky scenario
■ 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
Oilfield Services & Equipment 92
Figure 124: Valuation summary – Amec Foster Wheeler
SOTP (GBPm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV
EBITDA Sales Multiple Implied 2017E 2018E
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
Associates / minorities 113 113
Implied market value 1638 1623
Implied value per share (pence) 425 421
DCF (GBPm)
Assumptions: Beta Risk WACC LT Growth 2017E 2018E
premium
1.41 5.50% 8.69% 2%
EV 3044 3074
Net (debt) / cash -1046 -1026
Asbestos liability -296 -296
Associates / minorities 113 113
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
Overall average (equally weighted) 450
Blue Sky / Grey Sky
Blue sky valuation % vs base case Average 2017E 2018E
SOTP 63% 688 686 690
DCF 44% 686 673 700
Overall average (equally weighted) 53% 687
Grey sky valuation % vs base case Average 2017E 2018E
SOTP -53% 200 205 195
DCF -39% 289 288 290
Overall average (equally weighted) -46% 244
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 93
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
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.
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 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
Oilfield Services & Equipment 94
Figure 125: AMEC Foster Wheeler in HOLT
Source: Credit Suisse HOLT
Current Price: GBp 531.0 Warranted Price: GBp 367.7 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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
HO
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AMEC FOSTER WHEELER PLC
(AMFW)
EB
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% p
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-2.0% -119% -109% -98% -86%
4%
-71%
-1.0% -93% -81% -67% -51% -34%
0.0% -66% -51% -35% -17%
78%
1.0% -39% -22% -3% 18% 41%
2.0% -12% 7% 28% 52%
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.
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Asset Turns (x)
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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate
CFROI & Discount Rate (in %)
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Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 95
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
Net finance expense -4 -40 -71 -71 -71 -71 -70
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
Effective tax rate 22% 22% 22% 23% 23% 23% 23%
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 96
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
Operating cash flows 112 502 446 77 77 78 66
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
Capex (net, inc intangible) -31 -38 -33 -31 -31 -36 -41
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
Cash and cash equivalents 495 340 223 254 274 306 352
Net cash / (debt) -803 -946 -1077 -1046 -1026 -994 -948
Balance sheet (GBPm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Property, plant and equipment 150 127 77 64 50 38 27
Goodwill & intangibles 3443 3025 2673 2560 2449 2336 2221
Other non-current assets 449 548 548 548 548 548 548
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
Cash and cash equivalents 495 340 223 254 274 306 352
Other current assets 45 64 244 353 460 570 693
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
Other non-current liabilities 224 231 231 231 231 231 231
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
Shareholders Equity and Liabilities 6065 5572 5191 5092 5128 5226 5371
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 97
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 128: AMEC Foster Wheeler in PEERs
Source: Credit Suisse PEERs
19 September 2016
Oilfield Services & Equipment 98
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
analyst's or each team's respective sector.
¹Target price is for 12 months.
[V] = Stock Considered Volatile (see Disclosure Appendix)
Research Analysts
Gregory Brown
44 20 7888 1440
Phillip Lindsay
44 20 7883 1644
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.
Share price performance
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$1
Performance 1M 3M 12M Absolute (%) 5.8 -8.6 -64.1 Relative (%) 3.0 -11.7 -62.8
Financial and valuation metrics
Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ 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
Oilfield Services & Equipment 99
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
Assets Total current assets 1,772 1,521 1,494 1,573 Total assets 5,513 5,199 5,092 5,102 Liabilities Total current liabilities 1,055 1,044 1,038 1,054 Total liabilities 4,155 3,876 3,869 3,886 Total equity and liabilities 5,513 5,199 5,092 5,102
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 analysis (%) 12/15A 12/16E 12/17E 12/18E
ROE (%) (43.4) (18.9) (6.7) (0.5) ROIC (avg.) (%) (27.1) (5.8) 0.0 2.7
Credit ratios 12/15A 12/16E 12/17E 12/18E
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.
Blue/Grey Sky Scenario
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%.
Share price performance
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
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 100
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
Source: Company data, Credit Suisse Research Source: Company data, Credit Suisse Research
Figure 133: CGG fleet distribution
Figure 134: CGG group margin vs. fleet on
multiclient
Source: Company data, Credit Suisse Research Source: Company data, Credit Suisse Research
5930
30 30 30130
342
455
605
420
40
370
25 25
440
0
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900
2014 2015 2016 2017 2018 2019 2020 2021 2022
Nordic Loan Term Loan High Yield Bond Convertible Bond RCF
-40
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Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2
2011 2012 2013 2014 2015 2016
Sales Operating Income (RHA)
6%
15%
34%
45%
2013 & before
Library 2014
Library 2015
WIP
Marine
88%
Land
12%
0
2
4
6
8
10
12
14
16
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2013 2014 2015 2016 Q1 2016 Q2 2016 Q3e 2016 Q4e
Contract Multiclient
0%
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20%
30%
40%
50%
60%
70%
80%
-30%
-25%
-20%
-15%
-10%
-5%
0%
5%
10%
2014 2015 2016 Q1 2016 Q2 2016 Q3e 2016 Q4e
Group margin (LHA) Fleet on Multiclient (RHA)
19 September 2016
Oilfield Services & Equipment 101
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
Oilfield Services & Equipment 102
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.
Blue sky / Grey sky scenario
■ 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
Oilfield Services & Equipment 103
Figure 135: Valuation summary – CGG
SOTP (USDm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV
EBITDA Sales Multiple Implied 2017E 2018E
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
Associates / minorities 219 219
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)
Assumptions: Beta Risk WACC LT Growth 2017E 2018E
Premium
2.50 13.75% 8.83% 2.0%
EV 2275 2430
Net (debt) cash -2138 -2142
Associates / minorities 219 219
MV 137 288
USD/EUR 1.12 1.12
Implied value per share 14.3 20.4
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
Source: Credit Suisse estimates
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
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
next cycle within this business. Based on our assumptions, HOLT calculates returns to
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
Oilfield Services & Equipment 104
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.
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
Source: Credit Suisse HOLT
Current Price: EUR22.06 Warranted Price: EUR 16.6 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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
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.
-40
-20
0
20
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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
Sales Growth (%)
-10
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EBITDA Margin
0.0
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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
Asset Turns (x)
-15
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-5
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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate
CFROI & Discount Rate (in %)
-20
0
20
40
60
80
100
1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 105
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%
Net finance expense -179 -166 -160 -151 -151 -151 -151
Other gains / losses / impairments -1004 -1244 -36 -22 -19 -17 -16
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 106
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
Other non-current assets 341 308 308 308 308 308 308
Non-current assets 3741 3678 3598 3530 3506 3556 3610
Cash and cash equivalents 385 521 464 460 497 563 826
Trade receivables 813 567 621 699 809 960 913
Inventories 329 202 168 158 164 169 152
Other current assets 245 231 241 256 276 304 296
Current Assets 1772 1521 1494 1573 1747 1996 2187
Total assets 5513 5199 5092 5102 5253 5552 5797
Trade and other payables 268 119 101 100 104 112 101
Borrowings 97 64 64 64 64 64 64
Provisions - current 220 165 165 165 165 165 165
Other current liabilities 471 697 709 726 751 784 774
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
Other non-current liabilities 156 137 137 137 137 137 137
Non-current Liabilities 3099 2831 2831 2831 2831 2831 2831
Shareholders equity 1312 1285 1184 1178 1300 1557 1824
Minority interest 46 39 39 39 39 39 39
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
Operating cash flows 2041 1899 484 489 506 507 541
Working cap movement -30 -44 165 -37 -66 -109 -141
Cashflow from operations 864 408 221 352 433 520 657
Capex (net, inc intangible) -274 -99 -146 -103 -133 -151 -193
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
Change in borrowings 94 234 0 0 0 0 0
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 107
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 139: CGG in PEERs
Source: Credit Suisse PEERs
19 September 2016
Oilfield Services & Equipment 108
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
analyst's or each team's respective sector.
¹Target price is for 12 months.
Research Analysts
Gregory Lewis, CFA
212 325 6418
Neesha Khanna
212 325 6974
Joseph Nelson
212 538 4894
Phillip Lindsay
44 20 7883 1644
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$109.02
Quarterly EPS Q1 Q2 Q3 Q4 2015A 0.86 0.91 0.95 0.62 2016E 0.37 0.35 0.38 0.40 2017E 0.43 0.51 0.59 0.70
Financial and valuation metrics
Year 12/15A 12/16E 12/17E 12/18E EPS (CS adj.) (US$) 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
Oilfield Services & Equipment 109
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
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
Source: Company data, Thomson Reuters, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 110
Europe/United Kingdom Oil & Gas Equipment & Services
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
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
Gregory Brown
44 20 7888 1440
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.
Share price performance
The price relative chart measures performance against the
FTSE 100 IDX which closed at 6665.6 on 13/09/16
On 13/09/16 the spot exchange rate was £.85/Eu 1.-
Eu.89/US$1
Performance 1M 3M 12M Absolute (%) -9.3 18.7 -5.2 Relative (%) -6.0 5.9 -14.5
Financial and valuation metrics
Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ 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
Oilfield Services & Equipment 111
Hunting Plc (HTG.L)
Price (13 Sep 2016): 415.50p; Rating: NEUTRAL; Target Price: 500.00p; Analyst: Phillip Lindsay
Income statement (US$ m) 12/15A 12/16E 12/17E 12/18E
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
Cash flow (US$ m) 12/15A 12/16E 12/17E 12/18E
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
Balance sheet (US$ m) 12/15A 12/16E 12/17E 12/18E
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 analysis (%) 12/15A 12/16E 12/17E 12/18E
ROE (%) 0.4 (8.0) 0.7 4.8 ROIC (avg.) (%) 0.5 (5.9) 0.8 4.0
Credit ratios 12/15A 12/16E 12/17E 12/18E
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.
Blue/Grey Sky Scenario
Our Blue Sky Scenario (p) 705.00
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%
Our Grey Sky Scenario (p) 364.00
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%
Share price performance
The price relative chart measures performance against the FTSE 100 IDX
which closed at 6665.6 on 13/09/16
On 13/09/16 the spot exchange rate was £.85/Eu 1.- Eu.89/US$1
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 112
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
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
Figure 144: Well intervention revenue and EBITA
comparison
Figure 145: Department incremental / decremental
performance and forecast
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
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Well Construction Well Completion Well Intervention
19 September 2016
Oilfield Services & Equipment 113
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
Oilfield Services & Equipment 114
Blue sky / Grey sky scenario
■ 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
EBITDA Sales Multiple Implied 2017E 2018E
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
Associates / minorities 30 30
Implied market value 882 1088
Implied value per share (GBp) 449 553
DCF (GBPm)
Assumptions: Beta Risk WACC LT Growth 2017E 2018E
premium
1.20 5.00% 7.65% 0.02
EV 952 1001
Net cash / (debt) -47 -2
Associates / minorities 30 30
MV 935 1029
GBP/USD 1.30 1.30
Implied value per share 476 523
Valuation summary (GBp/share) Average 2017E 2018E
SOTP 501 449 553
DCF 499 476 523
Overall average (equally weighted) 500
Blue Sky / Grey Sky
Blue sky valuation % vs base case Average 2017E 2018E
SOTP 53% 768 665 871
DCF 28% 642 611 672
Overall average (equally weighted) 41% 705
Grey sky valuation % vs base case Average 2017E 2018E
SOTP -36% 321 295 347
DCF -19% 407 387 427
Overall average (equally weighted) -27% 364
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 115
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
The charts in Figure 147 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
improve from -7.2% in 2016 to 7.2% by 2021. Thereafter we capture the next cycle and
forecast returns to dip to 0.9% in 2022 and recover to 5.8% 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 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
inflation, and b) our methodology also incorporates a multiple-based SOTP.
19 September 2016
Oilfield Services & Equipment 116
Figure 147: Hunting in HOLT
Source: Credit Suisse HOLT
Current Price: GBp 415.5 Warranted Price: GBp 434.6 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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
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.
66%
1.0% -20% -6% 11% 29% 50%
2.0% -9% 6% 24% 44%
0% 18%
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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate
CFROI & Discount Rate (in %)
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Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 117
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%
Other gains / losses / impairments -104 -299 -47 -39 -38 -37 -27
Net finance expense -5 -7 -3 -4 -3 -3 -2
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
Effective tax rate 27% 57% 16% 30% 30% 30% 30%
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 118
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
Operating cash flows 112 329 116 90 75 63 46
Working capital 4 96 104 -11 -21 -16 -14
Net cash flow from operating activities 229 142 88 52 78 122 143
Capex (net, inc intangible) -99 -79 -19 -19 -28 -48 -55
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
Net cash flow from investing activities -93 -82 -19 -19 -28 -48 -55
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
Cash and cash equivalents 38 22 85 118 163 219 279
Net cash / (debt) -131 -111 -80 -47 -2 54 114
Balance Sheet (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Property, plant and equipment 473 461 437 411 390 382 376
Goodwill and intangibles 665 411 375 339 305 273 251
Other non-current assets 49 60 60 60 60 60 60
Non-Current Assets 1187 932 872 810 755 715 687
Inventories 382 331 243 245 277 313 332
Trade and other receivables 286 140 95 110 123 133 139
Other current assets 26 38 65 63 62 62 63
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
Trade and other payables 198 104 75 82 105 136 146
Borrowings 65 52 52 52 52 52 52
Other Current Liabilities 47 20 20 20 20 20 20
Current Liabilities 310 177 147 154 178 208 218
Borrowings 158 117 117 117 117 117 117
Other non-current liabilities 62 34 34 34 34 34 34
Non-Current Liabilities 220 151 151 151 151 151 151
Shareholders equity 1408 1142 1035 1015 1024 1056 1103
Non-controlling interests 30 26 26 26 26 26 26
Total equity 1438 1168 1061 1041 1050 1082 1130
Shareholders Equity and Liabilities 1969 1496 1360 1347 1380 1441 1499
Source: Company data, Credit Suisse estimates. *(loss) / profit from operations is derived from EBITA less other gains, losses and impairments
19 September 2016
Oilfield Services & Equipment 119
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 150: Hunting in PEERs
Source: Credit Suisse PEERs
19 September 2016
Oilfield Services & Equipment 120
Europe/United Kingdom Oil & Gas Equipment & Services
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
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
Gregory Brown
44 20 7888 1440
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
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$1
Performance 1M 3M 12M Absolute (%) -3.9 14.3 -1.4 Relative (%) -1.0 1.9 -9.9
Financial and valuation metrics
Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ 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
Dividend (12/16E, US$) 0.66 Net debt/equity (12/16E,%) 68.1 Dividend yield (12/16E,%) 6.2 Net debt (12/16E, US$ m) 816.3 BV/share (12/16E, US$) 3.8 IC (12/16E, US$ m) 2,014.5 Free float (%) 75.0 EV/IC (12/16E, (x) 2.2 Source: Company data, Thomson Reuters, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 121
Petrofac (PFC.L)
Price (13 Sep 2016): 808.00p; Rating: OUTPERFORM [V]; Target Price: 1100.00p; Analyst: Phillip Lindsay
Income statement (US$ m) 12/15A 12/16E 12/17E 12/18E
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
Cash flow (US$ m) 12/15A 12/16E 12/17E 12/18E
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
Balance sheet (US$ m) 12/15A 12/16E 12/17E 12/18E
Assets Total current assets 5,502 5,699 5,585 5,867 Total assets 8,547 8,840 8,721 8,960 Liabilities Total current liabilities 4,914 5,183 4,846 4,856 Total liabilities 7,315 7,642 7,284 7,271 Total equity and liabilities 8,547 8,840 8,721 8,960
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
EV/Sales (x) 0.6 0.6 0.6 0.6 EV/EBITDA (x) 14.0 6.9 5.3 5.4 EV/EBIT (x) 42.9 9.8 6.9 6.8 Dividend yield (%) 6.17 6.17 6.17 6.64 P/E (x) 402.7 11.4 7.8 7.5
ROE analysis (%) 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
Credit ratios 12/15A 12/16E 12/17E 12/18E
Net debt/equity (%) 55.7 68.1 54.5 42.1 Dividend payout ratio (%) 2485.8 70.2 48.4 50.0
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.
Blue/Grey Sky Scenario
Our Blue Sky Scenario (p) 1756.00
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%
Our Grey Sky Scenario (p) 631.00
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%
Share price performance
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
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 122
Petrofac in charts
Figure 151: PFC backlog ageing Figure 152: Active E&C bids by region
Source: Company data Source: Company data
Figure 153: Key projects being bid Figure 154: Bid book by country
Source: Company data, Credit Suisse Research Source: Company data, Credit Suisse Research
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
Oilfield Services & Equipment 123
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
Oilfield Services & Equipment 124
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.
Blue sky / Grey sky scenario
■ 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
Oilfield Services & Equipment 125
Figure 156: Valuation summary - Petrofac
SOTP (USDm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV
EBITDA Sales Multiple Implied 2017E 2018E
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
Net (debt) / cash -784 -711
Associates / minorities 76 76
Implied market value 4794 4772
Implied value per share (GBp) 1085 1080
DCF (USDm)
Assumptions: Beta Risk WACC LT Growth 2017E 2018E
premium
1.25 5.00% 9.58% 2.0%
EV 5572 5807
Net (debt) / cash -784 -711
Associates / minorities
MV 4788 5096
GBP / USD 1.30 1.30
Implied value per share (GBp) 1083 1153
Valuation summary (GBp/share) Average 2017E 2018E
SOTP 1082 1085 1080
DCF 1118 1083 1153
Overall average (equally weighted) 1100
Blue Sky / Grey Sky
Blue sky valuation % vs base case Average 2017E 2018E
SOTP 60% 1736 1668 1804
DCF 59% 1777 1697 1856
Overall average (equally weighted) 60% 1756
Grey sky valuation % vs base case Average 2017E 2018E
SOTP -47% 577 617 537
DCF -39% 684 681 687
Overall average (equally weighted) -43% 631
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 126
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
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.
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 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
Oilfield Services & Equipment 127
Figure 157: Petrofac in HOLT
Source: HOLT®
Current Price: GBp 808.0 Warranted Price: GBp 879.5 Valuation date: 13-Sept-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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
HO
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PETROFAC LIMITED (PFC)
EB
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% p
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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
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.
-20
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2002 2005 2008 2011 2014 2017 2020 2023
Sales Growth (%)
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2002 2005 2008 2011 2014 2017 2020 2023
EBITDA Margin
0.0
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2002 2005 2008 2011 2014 2017 2020 2023
Asset Turns (x)
-5
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2002 2005 2008 2011 2014 2017 2020 2023Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate
CFROI & Discount Rate (in %)
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2002 2005 2008 2011 2014 2017 2020 2023
Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 128
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
Net finance expense -57 -92 -87 -78 -78 -77 -77
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
Effective tax rate 5% 20% 16% 20% 16% 16% 16%
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 129
Figure 159: Cash flow and balance sheet – Petrofac
Cash flow (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Profit before tax and exceptional items 634 20 385 584 580 626 681
Operating cash flows 74 47 122 70 78 56 38
Working capital -60 602 -58 -180 -190 -52 -2
Net cash flow from operating activities 648 669 448 474 468 629 717
Capex (net, inc intangible) -589 -186 -317 -218 -166 -162 -163
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
Net cash flow from investing activities -528 -318 -352 -218 -166 -162 -163
Change in borrowings 524 42 0 0 0 0 0
DPS cash cost -225 -223 -223 -224 -229 -247 -267
Other financing cash flows -25 -39 0 0 0 0 0
Net cash flow from financing activities 274 -220 -223 -224 -229 -247 -267
Net cash flow 394 131 -128 33 72 220 287
Cash and cash equivalents 977 1101 974 1006 1079 1299 1586
Net cash / (debt) -733 -686 -816 -784 -711 -491 -204
Balance sheet (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Property, plant and equipment 1698 1775 1871 1866 1823 1790 1763
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
Trade and other payables 2670 2510 2794 2539 2530 2566 2711
Accrued contract expenses 800 1233 1127 1061 1076 1112 1174
Bank loans and overdrafts 9 520 520 520 520 520 520
Other Current Liabilities 690 651 743 726 730 739 755
Current Liabilities 4169 4914 5183 4846 4856 4936 5160
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
Shareholders equity 1861 1230 1196 1435 1687 1959 2258
Minority interests 10 2 2 2 2 2 2
Total equity 1871 1232 1198 1437 1689 1961 2260
Shareholders Equity and Liabilities 8930 8547 8840 8721 8960 9320 9869
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 130
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 160: Petrofac in PEERs
Source: Credit Suisse PEER
19 September 2016
Oilfield Services & Equipment 131
Europe/Norway Oil & Gas Equipment & Services
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
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
Gregory Brown
44 20 7888 1440
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.
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$1
Performance 1M 3M 12M Absolute (%) -10.0 -15.9 -48.4 Relative (%) -7.4 -20.2 -52.1
Financial and valuation metrics
Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ 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
Oilfield Services & Equipment 132
Petroleum Geo Services (PGS.OL)
Price (13 Sep 2016): Nkr16.6; Rating: OUTPERFORM [V]; Target Price: Nkr27.00; Analyst: Phillip Lindsay
Income statement (US$ m) 12/15A 12/16E 12/17E 12/18E
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)
Cash flow (US$ m) 12/15A 12/16E 12/17E 12/18E
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
Balance sheet (US$ m) 12/15A 12/16E 12/17E 12/18E
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 analysis (%) 12/15A 12/16E 12/17E 12/18E
ROE (%) (11.6) (14.6) (9.8) (1.1) ROIC (avg.) (%) (16.7) (6.6) (2.6) 0.7
Credit ratios 12/15A 12/16E 12/17E 12/18E
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.
Blue/Grey Sky Scenario
Our Blue Sky Scenario (Nkr) 51.00
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
Our Grey Sky Scenario (Nkr) 10.00
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
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
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 133
PGS in charts
Figure 161: Cash investment vs. prefunding rate for
multiclient Figure 162: Multiclient book value and vintage
In US $ millions
Source: Company data, Credit Suisse Research Source: Company data, Credit Suisse Research
Figure 163: Annual fleet distribution
Figure 164: Onshore/Offshore multiclient NBV as at
Q2 2016
Source: Company data, Credit Suisse Research Source: Company data, Credit Suisse Research
Figure 165: PGS cost profile (USDm) Figure 166: PGS capex profile (USDm)
Source: Company data, Credit Suisse Research Source: Company data, Credit Suisse Research
1% 2%4%
7%
24%
62%
2011 2012 2013 2014 2015 WIP & 2016
0%
50%
100%
150%
200%
250%
300%
350%
0
20
40
60
80
100
120
140
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%
60%
70%
80%
90%
100%
2010 2011 2012 2013 2014 2015 2016e 2017e 2018e
Multiclient Marine and Other
Marine
88%
Land
12%
274 269288 281
190208 209
186175
158
0
50
100
150
200
250
300
350
Q1 Q2 Q2 Q4 Q1 Q2 Q2 Q4 Q1 Q2
2014 2015 2016
Operations Regional / project / management
Other marine Imaging & Engineering
0
50
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250
300
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500
2012 2013 2014 2015 2016e 2017e 2018e 2019e 2020e
Newbuild Capex Maintenance and other
19 September 2016
Oilfield Services & Equipment 134
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
Oilfield Services & Equipment 135
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.
Blue sky / Grey sky scenario
■ 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)
■ In our SOTP, we assume multiples 1.0 / 0.25 pts higher / lower than our base case for
Marine Contract / Multi-Client Pre-funding, Late-Sales, and Imaging. We flex DCF for
long-term growth by +/- 0.25%.
19 September 2016
Oilfield Services & Equipment 136
Figure 167: Valuation summary - PGS
SOTP (USD) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV
EBITDA Sales Multiple Implied 2017E 2018E
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
Associates / minorities 51 51
Implied market value (USD) 734 903
NOK/USD 8.21 8.21
Implied market value (NOK) 6032 7419
Implied value per share 25.2 31.0
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
Associates / minorities 51 51
MV 587 856
NOK/USD 8.21 8.21
Implied value per share 20.7 29.8
Valuation Summary (NOK/share) Average 2017E 2018E
SOTP 28 25 31
DCF 25 21 30
Overall average (equally weighted) 27
Blue Sky / Grey Sky
Blue sky valuation % diff to base Average 2017e 2018e
SOTP 53% 43 37 49
DCF 126% 58 52 64
Overall average (equally weighted) 89% 51
Grey sky valuation
SOTP -45% 16 15 16
DCF -83% 4 0 8
Overall average (equally weighted) -63% 10
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 137
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
The charts in Figure 169 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
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.
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.
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%
Source: Credit Suisse HOLT
19 September 2016
Oilfield Services & Equipment 138
Figure 169: PGS in HOLT
Source: Credit Suisse HOLT
Current Price: NOK 16.6 Warranted Price: NOK 25.1 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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
HO
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-
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PETROLEUM GEO-SERVICES ASA
(PGS)
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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
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.
-40
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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
Sales Growth (%)
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EBITDA Margin
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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
Asset Turns (x)
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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate
CFROI & Discount Rate (in %)
-40
-20
0
20
40
60
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100
1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 139
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%
Net finance expense -57 -59 -36 -41 -40 -38 -36
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 140
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
Cash and cash equivalents 55 82 77 37 166 325 504
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
Cash and cash equivalents 55 82 77 37 166 325 504
Restricted Cash 20 19 19 19 19 19 19
Other Current Assets 136 99 224 224 224 224 224
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
Other current liabilities 38 24 51 70 91 109 127
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
Total non-current liabilities 1252 1152 1343 1343 1343 1343 1343
Shareholders equity 1902 1464 1350 1217 1203 1271 1382
Minority interest 0 0 0 0 0 0 0
Total liabilities and shareholders equity 3563 2914 3042 2929 2939 3030 3162
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 141
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 172: PGS in PEERs
Source: Credit Suisse PEERs
19 September 2016
Oilfield Services & Equipment 142
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
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
Gregory Brown
44 20 7888 1440
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.
Share price performance
The price relative chart measures performance against the
FTSEUROFIRST 300 INDEX which closed at 1332.9 on
13/09/16
On 13/09/16 the spot exchange rate was €1/Eu 1.-
Eu.89/US$1
Performance 1M 3M 12M Absolute (%) -8.5 7.7 -62.5 Relative (%) -6.8 1.8 -57.8
Financial and valuation metrics
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
Oilfield Services & Equipment 143
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
Assets Total current assets 7,564 7,310 7,258 7,385 Total assets 16,319 15,908 15,620 15,642 Liabilities Total current liabilities 9,458 5,658 5,102 4,862 Total liabilities 12,800 8,700 8,144 7,904 Total equity and liabilities 16,319 15,908 15,620 15,642
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 analysis (%) 12/15A 12/16E 12/17E 12/18E
ROE (%) (13.9) 4.5 3.8 3.6 ROIC (avg.) (%) (3.7) 3.9 4.0 3.9
Credit ratios 12/15A 12/16E 12/17E 12/18E
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
Blue/Grey Sky Scenario
Our Blue Sky Scenario (€) 0.82
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%
Our Grey Sky Scenario (€) 0.20
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%
Share price performance
The price relative chart measures performance against the FTSEUROFIRST
300 INDEX which closed at 1332.9 on 13/09/16
On 13/09/16 the spot exchange rate was €1/Eu 1.- Eu.89/US$1
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 144
Saipem in charts
Figure 173: New orders and book-to-bill Figure 174: Backlog evolution
Source: Company data Source: Company data
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
Source: Company data
0.99 1.02
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UR
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Offshore Onshore Drilling: Offshore
Drilling: Onshore Book to bill
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Client Location
Eni Portugal
Eni Worldwide
Eni Angola
Eni North Sea
Eni Indonesia
-
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
Oilfield Services & Equipment 145
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
Oilfield Services & Equipment 146
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.
Blue sky / Grey sky scenario
■ 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
Oilfield Services & Equipment 147
Figure 178: Summary financials – Saipem
SOTP (EURm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV
EBITDA Sales Multiple Implied 2017E 2018E
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
Associates / minorities 180 180
Implied market value (EURm) 4807 4703
Implied value per share 0.48 0.47
DCF (EURm)
Assumptions: Beta Risk WACC LT Growth 2017E 2018E
premium
1.25 5.50% 8.1% 2.00%
EV 5270 5205
Net (debt) / cash -1299 -997
Associates / minorities 180 180
MV 4151 4387
Implied value per share 0.41 0.43
Valuation summary (EUR/share) Average 2017E 2018E
SOTP 0.47 0.48 0.47
DCF 0.42 0.41 0.44
Overall average (equally weighted) 0.45
Blue Sky / Grey Sky
Blue sky valuation % vs base case Average 2017E 2018E
SOTP 75% 0.82 0.89 0.75
DCF 90% 0.81 0.78 0.84
Overall average (equally weighted) 82% 0.82
Grey sky valuation % vs base case Average 2017E 2018E
SOTP -54% 0.21 0.18 0.25
DCF -56% 0.19 0.19 0.19
Overall average (equally weighted) -55% 0.20
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 148
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
The charts in Figure 179 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
improve from 2.9% in 2016 to 3.1% by 2022. Thereafter we capture the next cycle and
forecast returns to decline to 1.8% in 2023 and recover to 2.2% 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 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 EUR 0.55 versus our target
price of EUR0.45.
19 September 2016
Oilfield Services & Equipment 149
Figure 179: Saipem in HOLT
Source: HOLT®
Current Price: EUR 0.38 Warranted Price: EUR 0.55 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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%
HO
LT
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it S
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naly
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Scen
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o D
ata
SAIPEM SPA (SPMI)
EB
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para
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% p
oin
t ch
an
ge
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ore
casts
)
-2.0% -86% -65% -41% -14%
105%
17%
-1.0% -54% -31% -4%
-40
-20
0
20
40
60
80
1996 1999 2002 2005 2008 2011 2014 2017 2020 2023
Sales Growth (%)
0
5
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20
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30
1996 1999 2002 2005 2008 2011 2014 2017 2020 2023
EBITDA Margin
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0.1
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1996 1999 2002 2005 2008 2011 2014 2017 2020 2023
Asset Turns (x)
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0
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4
6
8
10
1996 1999 2002 2005 2008 2011 2014 2017 2020 2023Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate
CFROI & Discount Rate (in %)
-20
-10
0
10
20
30
40
1996 1999 2002 2005 2008 2011 2014 2017 2020 2023
Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 150
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%
Net finance expense -199 -244 -163 -126 -124 -123 -123
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 151
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
Operating cash flows 859 767 694 689 643 677 733
Working cap movement 569 -468 -108 -139 -72 -310 -342
Net cash flow from operations 1198 -507 740 806 820 679 781
Capex (net, inc intangible) -694 -561 -416 -419 -518 -678 -878
Free cash flow 504 -1068 324 387 302 1 -97
Other investing cash flows -4 166 0 0 0 0 0
Net cash flow from investing activities -698 -395 -416 -419 -518 -678 -878
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
Cash and cash equivalents 1602 1066 1826 2214 2516 2517 2420
Net cash / (debt) -4424 -5390 -1687 -1299 -997 -996 -1093
Balance Sheet (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Property, plant & equipment, net 7601 7287 7007 6736 6609 6609 6753
Intangible assets, net 760 758 760 761 761 763 764
Other non-current assets 533 710 710 710 710 710 710
Total Non-Current Assets 8894 8755 8477 8206 8081 8082 8227
Trade receivables 3391 3348 2881 2596 2490 2810 3304
Inventories 2485 2286 1738 1584 1515 1676 1947
Cash and cash equivalents 1602 1066 1826 2214 2516 2517 2420
Other current assets 1222 864 986 1020 1040 1041 1030
Total Current Assets 8700 7564 7431 7414 7561 8044 8701
Total assets 17594 16319 15908 15620 15642 16126 16928
Trade and other payables 5669 5186 4086 3530 3290 3448 3846
ST borrowings 2780 3672 972 972 972 972 972
Other current liabilities 1156 600 600 600 600 600 600
Current Liabilities 9605 9458 5658 5102 4862 5020 5418
Long-term debts 3314 2841 2541 2541 2541 2541 2541
Provisions for contingencies 218 238 238 238 238 238 238
Other non-current liabilities 279 263 263 263 263 263 263
Total Non-Current Liabilities 3811 3342 3042 3042 3042 3042 3042
Shareholders equity 4137 3474 7163 7432 7693 8020 8423
Minority interest 41 45 45 45 45 45 45
Total Shareholders equity 4178 3519 7208 7477 7738 8065 8468
Total liabilities and shareholders equity 17594 16319 15908 15620 15642 16126 16928
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 152
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 182: Saipem in PEERs
Source: Credit Suisse Research
19 September 2016
Oilfield Services & Equipment 153
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
analyst's or each team's respective sector.
¹Target price is for 12 months.
Research Analysts
Gregory Brown
44 20 7888 1440
Phillip Lindsay
44 20 7883 1644
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.
Share price performance
The price relative chart measures performance against the
VIENNA SE AUSTRIAN TRADED IDX Index which closed
at 2356.4 on 13/09/16
On 13/09/16 the spot exchange rate was €1/Eu 1.-
Eu.89/US$1
Performance 1M 3M 12M Absolute (%) -11.0 1.6 6.6 Relative (%) -13.9 -10.8 3.2
Financial and valuation metrics
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
Oilfield Services & Equipment 154
Schoeller Bleckmann Oilfield Equipment (SBOE.VI)
Price (13 Sep 2016): €52.65; Rating: OUTPERFORM; Target Price: €70.00; Analyst: Gregory Brown
Income statement (€ m) 12/15A 12/16E 12/17E 12/18E
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
Balance sheet (€ m) 12/15A 12/16E 12/17E 12/18E
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 analysis (%) 12/15A 12/16E 12/17E 12/18E
ROE (%) (4.2) (7.1) 3.9 9.7 ROIC (avg.) (%) 0.8 (6.4) 4.2 10.0
Credit ratios 12/15A 12/16E 12/17E 12/18E
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.
Blue/Grey Sky Scenario
Our Blue Sky Scenario (€) 99.00
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%
Our Grey Sky Scenario (€) 50.00
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%
Share price performance
The price relative chart measures performance against the VIENNA SE
AUSTRIAN TRADED IDX Index which closed at 2356.4 on 13/09/16
On 13/09/16 the spot exchange rate was €1/Eu 1.- Eu.89/US$1
Source: Company data, Thomson Reuters, Credit Suisse estimates.
19 September 2016
Oilfield Services & Equipment 155
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
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
Figure 187: HPC revenue / EBIT vs. rig count Figure 188: OE revenue / EBIT vs. rig count
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
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19 September 2016
Oilfield Services & Equipment 156
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
Oilfield Services & Equipment 157
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.
Blue sky / Grey sky scenario
■ 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)
■ In our SOTP, we assume multiples 1.5 / 1.0 pts higher / lower than our base case for
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
EBITDA Sales Multiple Implied 2017E 2018E
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
Net (debt) cash -22 -2
Associates / minorities 0 0
Implied market value (EUR) 1046 1159
Implied value per share 66 73
DCF (EURm)
Assumptions: Beta Risk Premium WACC LT Growth 2017E 2018E
0.90 5.50% 6.9% 2.0%
EV 1125 1160
Net (debt) cash -22 -2
MV 1103 1158
Implied value per share 69 72
Valuation summary (EUR/share) Average 2017E 2018E
SOTP 69 66 73
DCF 71 69 72
Overall average (equally weighted) 70
Blue Sky / Grey Sky
Blue sky valuation % diff to base Average 2017e 2018e
SOTP 35% 95 87 102
DCF 46% 102 99 106
Overall average (equally weighted) 41% 99
Grey sky valuation
SOTP -28% 51 50 52
DCF -30% 49 48 50
Overall average (equally weighted) -29% 50
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 158
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
The charts in Figure 190 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
improve from -5.7% in 2016 to 11.9% by 2021. Thereafter we capture the next cycle and
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.
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 EUR 78.88, close to our EUR
70 target price.
19 September 2016
Oilfield Services & Equipment 159
Figure 190: Schoeller Bleckmann in HOLT
Source: Credit Suisse HOLT
Current Price: EUR 52.65 Warranted Price: EUR 78.88 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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
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.
155%
1.0% 3% 30% 61% 97% 140%
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19 September 2016
Oilfield Services & Equipment 160
Figure 191: Summary financials - Schoeller Bleckmann
Divisionals (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
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
Effective Tax rate (underlying) 33% 5% 25% 30% 30% 30% 30%
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 161
Figure 192: Cash flow and balance sheet - Schoeller Bleckmann
Cash flow 2014A 2015A 2016E 2017E 2018E 2019E 2020E
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
Capex (net, inc intangible) -45 -23 -16 -29 -42 -50 -58
Free cash flow 23 80 54 32 28 47 68
M&A -23 0 -90 0 0 0 0
Other investing cash flows 4 5 0 0 0 0 0
Cashflow from investing activities -64 -18 -106 -29 -42 -50 -58
Change in borrowings -12 4 0 0 0 0 0
Dividend -24 -24 -8 -8 -8 -8 -8
Other financing cash flows -3 -5 0 0 0 0 0
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
Balance Sheet 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Property, plant & equipment, net 204 193 173 158 150 145 145
Goodwill and intangibles 160 132 215 212 211 212 216
Other non-current assets 29 24 26 26 26 26 26
Total non-current assets 393 350 413 396 387 384 388
Trade accounts receivable 107 49 31 45 59 74 86
Inventories 165 134 87 82 100 119 135
Cash and cash equivalents 130 196 152 176 196 235 295
Other current assets 5 12 9 10 11 12 13
Total current assets 408 391 280 313 366 441 530
Total assets 800 741 693 709 753 825 917
Trade accounts payable 24 11 16 16 20 24 27
Bank loans and overdrafts 67 45 39 39 39 39 39
Other current liabilities 54 31 31 31 31 31 31
Total current liabilities 146 87 86 87 90 94 97
Long-term loans 98 125 158 158 158 158 158
Other non-current liabilities 101 78 37 44 50 57 62
Total non-current liabilities 199 203 196 202 208 215 221
Shareholders equity 456 450 412 420 454 516 599
Minority interest 0 0 0 0 0 0 0
Total liabilities and shareholders equity 800 741 693 709 753 825 917
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 162
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 193: Schoeller Bleckmann in PEERs
Source: Credit Suisse Research
19 September 2016
Oilfield Services & Equipment 163
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
analyst's or each team's respective sector.
¹Target price is for 12 months.
[V] = Stock Considered Volatile (see Disclosure Appendix)
Research Analysts
Gregory Lewis, CFA
212 325 6418
Neesha Khanna
212 325 6974
James Wicklund
214 979 4111
Joseph Nelson
212 538 4894
Gregory Brown
44 20 7888 1440
Phillip Lindsay
44 20 7883 1644
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.
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$7.51
Quarterly EPS Q1 Q2 Q3 Q4 2015A 0.85 0.77 0.21 0.54 2016E 0.26 0.37 0.19 0.15 2017E 0.06 0.01 -0.09 -0.17
Financial and valuation metrics
Year 12/15A 12/16E 12/17E 12/18E EPS (CS adj.) (US$) 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
Oilfield Services & Equipment 164
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
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$7.51
Source: Company data, Thomson Reuters, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 165
Europe/Norway Oil & Gas Equipment & Services
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
analyst's or each team's respective sector.
¹Target price is for 12 months.
Research Analysts
Phillip Lindsay
44 20 7883 1644
Gregory Brown
44 20 7888 1440
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.
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$1
Performance 1M 3M 12M Absolute (%) -8.4 14.5 26.5 Relative (%) -5.8 10.2 22.7
Financial and valuation metrics
Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ 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
Oilfield Services & Equipment 166
Subsea 7 S.A. (SUBC.OL)
Price (13 Sep 2016): Nkr84.7; Rating: UNDERPERFORM; Target Price: Nkr75.00; Analyst: Phillip Lindsay
Income statement (US$ m) 12/15A 12/16E 12/17E 12/18E
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
Cash flow (US$ m) 12/15A 12/16E 12/17E 12/18E
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)
Balance sheet (US$ m) 12/15A 12/16E 12/17E 12/18E
Assets Total current assets 2,026 1,784 1,969 1,999 Total assets 7,854 7,813 7,951 7,997 Liabilities Total current liabilities 1,774 1,373 1,440 1,378 Total liabilities 2,508 2,107 2,175 2,112 Total equity and liabilities 7,854 7,813 7,951 7,997
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
EV/Sales (x) 0.6 0.9 0.9 0.9 EV/EBITDA (x) 2.4 3.4 6.4 5.8 EV/EBIT (x) 4.9 6.7 79.6 38.5 Dividend yield (%) 0.00 0.00 0.00 0.00 P/E (x) 7.0 9.9 50.8 32.9
ROE analysis (%) 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
Credit ratios 12/15A 12/16E 12/17E 12/18E
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.
Blue/Grey Sky Scenario
Our Blue Sky Scenario (Nkr) 118.00
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%
Our Grey Sky Scenario (Nkr) 36.00
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%
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
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 167
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
1500
2000
2500
557 544 499 162
108
550
100
200
300
400
500
600
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
Oilfield Services & Equipment 168
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
Oilfield Services & Equipment 169
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.
Blue sky / Grey sky scenario
■ 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 +/-
1.0% from our base-case scenario for 2017 and beyond (diluted impact for 2016);
■ 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
SOTP (USDm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV
EBITDA Sales Multiple Implied 2017E 2018E
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
Associates / minorities 338 338
Implied market value (USDm) 3460 3284
Implied market value (NOKm) 28685 27224
Implied value per share 83 78
DCF (USDm)
Assumptions: Beta Risk WACC LT Growth 2017E 2018E
premium
1.45 5.50% 9.70% 2%
EV 2155 2238
Net (debt) / cash 319 385
Associates / minorities 338 338
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
Overall average (equally weighted) 75
Blue Sky / Grey Sky
Blue sky valuation % vs base case Average 2017E 2018E
SOTP 26% 101 89 114
DCF 97% 135 131 140
Overall average (equally weighted) 58% 118
Grey sky valuation % vs base case Average 2017E 2018E
SOTP -37% 51 49 52
DCF -69% 21 22 21
Overall average (equally weighted) -52% 36
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 170
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
The charts in Figure 200 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 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.
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 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
Oilfield Services & Equipment 171
Figure 200: Subsea 7 in HOLT
Source: Credit Suisse HOLT
Current Price: NOK 84.7 Warranted Price: NOK 41.1 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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
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-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
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.
-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
CFROI & Discount Rate (in %)
-20
-10
0
10
20
30
40
1996 1999 2002 2005 2008 2011 2014 2017 2020 2023
Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 172
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
Other gains / losses / impairments -1160 -488 0 0 0 0 0
Pre-tax profit -252 167 501 90 144 207 362
Tax -152 -222 -155 -28 -45 -64 -112
Effective Tax rate (underlying) 16% 31% 31% 31% 31% 31% 31%
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 173
Figure 202: Cash flow and balance sheet – Subsea 7
Cash flow (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Net income / (losses) before taxes -230 185 360 70 108 153 262
Operating cash flows 1411 800 203 302 256 246 205
Working cap movement 269 64 -348 -32 -26 -20 -3
Cashflow from operations 1450 1049 215 339 338 379 463
Capex (net, inc intangible) -868 -645 -404 -254 -272 -311 -353
Free cash flow 582 404 -189 85 66 68 111
Other investing cash flows 40 91 0 0 0 0 0
Cashflow from investing activities -828 -554 -404 -254 -272 -311 -353
Change in borrowings -337 -65 0 0 0 0 0
DPS / Buyback cash cost -360 -8 0 0 0 0 -46
Other financing cash flows -23 -23 0 0 0 0 0
Cash flow from financing activities -720 -96 0 0 0 0 -46
Net cash flow -98 399 -189 85 66 68 65
Cash and cash equivalents 573 947 758 843 909 977 1042
Net cash / (debt) -6 423 234 319 385 453 518
Balance Sheet (USDm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
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
Total Non-Current Assets 6463 5828 6029 5982 5998 6063 6211
Trade and other receivables 840 584 547 641 608 611 713
Construction contracts - assets 378 278 278 278 278 278 278
Other accrued income and prepaid
expenses
283 152 152 152 152 152 152
Cash and cash equivalents 573 947 758 843 909 977 1042
Other Current Assets 87 65 48 54 51 50 55
Total Current Assets 2162 2026 1784 1969 1999 2069 2241
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
Other Current Liabilities 102 192 192 192 192 192 192
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
Shareholders equity 5587 5377 5737 5807 5915 6068 6284
Minority interest -25 -31 -31 -31 -31 -31 -31
Total Shareholders Equity 5562 5346 5707 5776 5884 6037 6253
Total liabilities and shareholders equity 8624 7854 7813 7951 7997 8132 8451
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 174
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 203: Subsea 7 in PEERs
Source: Credit Suisse PEERs
19 September 2016
Oilfield Services & Equipment 175
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
analyst's or each team's respective sector.
¹Target price is for 12 months.
Research Analysts
Phillip Lindsay
44 20 7883 1644
Gregory Brown
44 20 7888 1440
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.
Share price performance
The price relative chart measures performance against the
CAC 40 INDEX which closed at 4387.2 on 13/09/16
On 13/09/16 the spot exchange rate was €1/Eu 1.-
Eu.89/US$1
Performance 1M 3M 12M Absolute (%) 0.6 11.5 17.2 Relative (%) 2.9 5.7 21.0
Financial and valuation metrics
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
Oilfield Services & Equipment 176
Technip (TECF.PA)
Price (13 Sep 2016): €51.3; Rating: OUTPERFORM; Target Price: €65.00; Analyst: Phillip Lindsay
Income statement (€ m) 12/15A 12/16E 12/17E 12/18E
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)
Balance sheet (€ m) 12/15A 12/16E 12/17E 12/18E
Assets Total current assets 8,546 8,726 7,451 7,361 Total assets 15,536 15,670 14,359 14,246 Liabilities Total current liabilities 8,907 8,720 7,260 7,048 Total liabilities 10,991 10,804 9,344 9,132 Total equity and liabilities 15,536 15,670 14,359 14,246
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
EV/Sales (x) 0.4 0.4 0.6 0.6 EV/EBITDA (x) 3.9 3.7 5.7 6.2 EV/EBIT (x) 5.4 4.7 7.7 8.7 Dividend yield (%) 3.90 3.90 3.90 3.90 P/E (x) 10.0 10.9 15.7 18.0
ROE analysis (%) 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
Credit ratios 12/15A 12/16E 12/17E 12/18E
Net debt/equity (%) (42.6) (45.0) (27.2) (27.0) Dividend payout ratio (%) 39.2 42.6 61.1 70.3
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.
Blue/Grey Sky Scenario
Our Blue Sky Scenario (€) 108.00
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%
Our Grey Sky Scenario (€) 36.00
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%
Share price performance
The price relative chart measures performance against the CAC 40 INDEX
which closed at 4387.2 on 13/09/16
On 13/09/16 the spot exchange rate was €1/Eu 1.- Eu.89/US$1
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 177
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
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
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
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
Book t
o b
ill
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
3.5
4
4.5
5
2014
Baseline
2015 2016e 2017e
EU
Rbn
36
27
24 23
20
0
5
10
15
20
25
30
35
40
2013 2014 2015 1H 2016 2017e
Num
ber
of
Vess
els
Wholly owned Jointly owned Leased Under construction
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
US
Dm
0
2000
4000
6000
8000
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12000
14000
16000
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Dm
19 September 2016
Oilfield Services & Equipment 178
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
Oilfield Services & Equipment 179
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.
Blue sky / Grey sky scenario
■ 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 +/-
1.0% from our base-case scenario for 2017 and beyond (diluted impact for 2016);
■ In our SOTP, we assume multiples 1.0 / 0.5 pts higher / lower than our base case for
Subsea and Onshore / Offshore, respectively. For our DCF we flex long-term growth by
+/- 0.25%.
19 September 2016
Oilfield Services & Equipment 180
Figure 210: Valuation summary – Technip
SOTP (EURm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV
EBITDA Sales Multiple Implied 2017E 2018E
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 cash / (debt) 1361 1381
Net construction contracts -1117 -1069
Associates / minorities 107 107
Implied market value (EURm) 7476 7409
Implied value per share 63.69 63.12
DCF (EURm)
Assumptions: Beta Risk WACC LT Growth 2017E 2018E
premium
1.20 6.60% 7.91% 2%
EV 6843 7904
Net cash / (debt) -1361 -1381
Net construction contracts 1117 1069
Associates / minorities 107 107
MV 7194 8322
Implied value per share 61.28 70.90
Valuation summary (EUR/share) Average 2017E 2018E
SOTP 63.40 63.69 63.12
DCF 66.09 61.28 70.90
Overall average (equally weighted) 65
Blue Sky / Grey Sky
Blue sky valuation % vs base case Average 2017E 2018E
SOTP 45% 91.84 88.98 94.71
DCF 88% 124.45 117.57 131.34
Overall average (equally weighted) 67% 108
Grey sky valuation % vs base case Average 2017E 2018E
SOTP -34% 41.87 43.84 39.91
DCF -54% 30.28 26.66 33.91
Overall average (equally weighted) -44% 36
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 181
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
The charts in Figure 211 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 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.
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 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 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
Oilfield Services & Equipment 182
Figure 211: Technip in HOLT
Source: Credit Suisse HOLT
Current Price: EUR 51.30 Warranted Price: EUR 58.33 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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
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.
92%
1.0% -2% 12% 29% 49% 70%
2.0% 14% 30% 48% 69%
7% 24%
0.0% -18% -5% 10% 28%
HO
LT
-
C
red
it S
uis
se A
naly
st
Scen
ari
o D
ata
TECHNIP SA (TECF)
EB
ITD
A M
arg
in (
para
llel
% p
oin
t ch
an
ge
to f
ore
casts
)
-2.0% -51% -41% -28% -14%
47%
2%
-1.0% -34% -23% -9%
-40
-20
0
20
40
60
80
1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
Sales Growth (%)
0
2
4
6
8
10
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16
1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
EBITDA Margin
0.0
0.5
1.0
1.5
2.0
2.5
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1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
Asset Turns (x)
0
5
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15
20
25
30
1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate
CFROI & Discount Rate (in %)
-35
-25
-15
-5
5
15
25
35
45
1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 183
Figure 212: Summary financials – Technip
Divisionals 2014A 2015A 2016E 2017E 2018E 2019E 2020E
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%
Net finance expense -129 -157 -71 -73 -78 -76 -72
Other gains / losses / impairments -74 -470 0 0 0 0 0
Pre-tax profit 623 175 781 545 474 540 666
Tax -180 -119 -241 -168 -146 -167 -206
Effective Tax rate (underlying) 29% 68% 30% 30% 30% 30% 30%
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 184
Figure 213: Cash flow and balance sheet – Technip
Cash flow 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Net income / (losses) 442 56 551 384 334 381 470
Operating cash flows 320 425 246 226 223 232 248
Working cap movement 105 562 -62 -965 -57 170 308
Cashflow from operations 868 1043 734 -355 499 783 1026
Capex (net, inc intangible) -376 -295 -252 -239 -245 -282 -331
Free cash flow 492 748 482 -594 254 501 695
M&A -59 -31 0 0 0 0 0
Other investing cash flows 49 22 0 0 0 0 0
Cashflow from investing activities -385 -303 -252 -239 -245 -282 -331
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
Cash and cash equivalents 3738 4501 4753 3925 3944 4210 4670
Net cash / (debt) 1125 1938 2190 1362 1381 1647 2107
Balance Sheet 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Property, plant & equipment, net 2501 2577 2550 2538 2538 2563 2616
Intangible assets, net 3497 3583 3564 3540 3517 3497 3478
Other non-current assets 807 830 830 830 830 830 830
Total non-current assets 6805 6990 6944 6908 6885 6890 6925
Construction contracts - assets 756 652 564 440 421 467 551
Advances paid to suppliers 554 479 415 323 309 344 405
Trade receivables 1577 1551 1695 1546 1480 1643 1938
Other current assets 1169 1363 1298 1217 1206 1237 1293
Cash and cash equivalents 3738 4501 4753 3925 3944 4210 4670
Total current assets 7795 8546 8726 7451 7361 7902 8859
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
Other current liabilities 2099 2335 2592 2463 2405 2391 2399
Total current liabilities 7386 8907 8720 7260 7048 7447 8205
Non-current financial debts 2357 1626 1626 1626 1626 1626 1626
Other non-current liabilities 482 458 458 458 458 458 458
Total non-current liabilities 2839 2084 2084 2084 2084 2084 2084
Shareholders equity 4363 4536 4857 5006 5106 5252 5487
Minority interest 12 9 9 9 9 9 9
Total liabilities and shareholders equity 14600 15536 15670 14359 14246 14791 15784
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 185
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
Source: Company data
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
Oilfield Services & Equipment 186
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
Oilfield Services & Equipment 187
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
Oilfield Services & Equipment 188
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
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 189
Figure 218: Forsys Subsea FEED Study Overview
Source: Company data
Figure 219: Cumulative Integrated FEED Study Awards
Source: Technip
16
0
2
4
6
8
10
12
14
16
18
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No.
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ED
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19 September 2016
Oilfield Services & Equipment 190
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 220: Technip in PEERs
Source: Credit Suisse PEERs
19 September 2016
Oilfield Services & Equipment 191
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
analyst's or each team's respective sector.
¹Target price is for 12 months.
Research Analysts
Phillip Lindsay
44 20 7883 1644
Gregory Brown
44 20 7888 1440
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.
Share price performance
The price relative chart measures performance against the
MADRID SE INDEX which closed at 879.2 on 13/09/16
On 13/09/16 the spot exchange rate was €1/Eu 1.-
Eu.89/US$1
Performance 1M 3M 12M Absolute (%) 1.5 31.2 -21.3 Relative (%) 1.2 24.5 -10.2
Financial and valuation metrics
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
Oilfield Services & Equipment 192
Tecnicas Reunidas (TRE.MC)
Price (13 Sep 2016): €32.495; Rating: UNDERPERFORM; Target Price: €28.00; Analyst: Phillip Lindsay
Income statement (€ m) 12/15A 12/16E 12/17E 12/18E
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)
Balance sheet (€ m) 12/15A 12/16E 12/17E 12/18E
Assets Total current assets 3,268 3,638 3,500 3,567 Total assets 3,613 3,991 3,861 3,935 Liabilities Total current liabilities 2,997 3,313 3,122 3,129 Total liabilities 3,216 3,532 3,341 3,348 Total equity and liabilities 3,613 3,991 3,861 3,935
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
EV/Sales (x) 0.3 0.3 0.3 0.3 EV/EBITDA (x) 13.5 6.4 6.8 6.6 EV/EBIT (x) 15.7 7.2 7.6 7.4 Dividend yield (%) 4.28 4.28 4.28 4.28 P/E (x) 29.4 12.7 13.0 12.3
ROE analysis (%) 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
Credit ratios 12/15A 12/16E 12/17E 12/18E
Net debt/equity (%) (118.1) (110.7) (89.8) (73.1) Dividend payout ratio (%) 125.8 54.5 55.5 52.7
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.
Blue/Grey Sky Scenario
Our Blue Sky Scenario (€) 45.00
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%
Our Grey Sky Scenario (€) 17.00
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%
Share price performance
The price relative chart measures performance against the MADRID SE INDEX
which closed at 879.2 on 13/09/16
On 13/09/16 the spot exchange rate was €1/Eu 1.- Eu.89/US$1
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 193
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
Oilfield Services & Equipment 194
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
Oilfield Services & Equipment 195
Blue sky / Grey sky scenario
■ 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
SOTP (EURm) 2017E 2017E EV/EBITDA EV/Sales Implied EV Implied EV
EBITDA Sales Multiple Implied 2017E 2018E
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
Net cash / (debt) 467 429
Associates / minorities 4 4
Implied market value (EURm) 1460 1477
Implied value per share 27 27
DCF (EURm)
Assumptions: Beta Risk WACC LT Growth 2017E 2018E
premium
1.25 6.25% 9.17% 2%
EV 974 1028
Net (debt) / cash 467 429
Associates / minorities 4 180
MV 1444 1636
Implied value per share 27 30
Valuation summary (GBp/share) Average 2017E 2018E
SOTP 27.33 27.17 27.49
DCF 28.68 26.89 30.46
Overall average (equally weighted) 28
Blue Sky / Grey Sky
Blue sky valuation % diff to base Average 2017e 2018e
SOTP 53% 41.9 39.7 44.1
DCF 65% 47.2 44.5 49.9
Overall average (equally weighted) 59% 45
Grey sky valuation
SOTP -37% 17.1 18.1 16.2
DCF -41% 16.9 15.7 18.2
Overall average (equally weighted) -39% 17
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 196
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
The charts in Figure 228 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 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.
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 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
Oilfield Services & Equipment 197
Figure 228: Tecnicas Reunidas in HOLT
Source: Credit Suisse HOLT
Current Price: EUR 32.50 Warranted Price: EUR 28.88 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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
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.
87%
1.0% 0% 10% 21% 33% 47%
2.0% 29% 41% 55% 70%
-39% -32%
0.0% -29% -21% -13% -3%
HO
LT
-
C
red
it S
uis
se A
naly
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Scen
ari
o D
ata
TECNICAS REUNIDAS S.A. (TRE)
EB
ITD
A M
arg
in (
para
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% p
oin
t ch
an
ge
to f
ore
casts
)
-2.0% -84% -81% -77% -74%
8%
-69%
-1.0% -57% -52% -46%
-20
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100
2002 2005 2008 2011 2014 2017 2020 2023
Sales Growth (%)
0
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2
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2002 2005 2008 2011 2014 2017 2020 2023
EBITDA Margin
0.0
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2002 2005 2008 2011 2014 2017 2020 2023
Asset Turns (x)
-5
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2002 2005 2008 2011 2014 2017 2020 2023Historical CFROI Historical Transaction CFROIForecast CFROI Forecast CFROICFROI Discount Rate
CFROI & Discount Rate (in %)
-20
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0
10
20
30
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2002 2005 2008 2011 2014 2017 2020 2023
Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 198
Figure 229: Summary financials – Tecnicas Reunidas
Divisionals (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
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
Effective Tax rate (underlying) 19% 27% 25% 25% 25% 25% 25%
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 199
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
Operating cash flows 43 32 15 13 13 13 13
Working cap movement -39 -111 -11 -89 -91 -76 -113
Cashflow from operations 138 -18 141 58 64 98 79
Capex (net, inc intangible) -22 -38 -27 -26 -27 -28 -30
Free cash flow 116 -56 114 32 37 70 49
Other investing cash flows -1 0 0 0 0 0 0
Cashflow from investing activities -23 -38 -27 -26 -27 -28 -30
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
Cash and cash equivalents 628 709 748 706 668 663 638
Net cash / (debt) 601 469 509 467 429 424 398
Balance Sheet (EURm) 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Property, plant & equipment, net 52 64 72 80 89 97 107
Goodwill and intangibles 62 66 66 65 64 63 62
Other non-current assets 115 215 215 215 215 215 215
Non-current assets 229 345 353 360 368 375 383
Trade and other receivables 1437 2402 2714 2621 2724 2851 3090
Cash and cash equivalents 628 709 748 706 668 663 638
Other current assets 145 158 175 173 176 179 185
Current assets 2210 3268 3638 3500 3567 3694 3912
Total Assets 2439 3613 3991 3861 3935 4069 4295
Trade and other payables 1654 2611 2927 2744 2756 2809 2937
Borrowings 4 82 82 82 82 82 82
Other current liabilities 194 304 304 296 291 286 280
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
Other non-current liabilities 71 30 30 30 30 30 30
Non-current liabilities 132 219 219 219 219 219 219
Shareholders equity 453 394 456 516 583 669 774
Minority interest 3 4 4 4 4 4 4
Total liabilities and shareholders equity 2439 3613 3991 3861 3935 4069 4295
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 200
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 231: Tecnicas Reunidas in PEERs
Source: Credit Suisse PEERs
19 September 2016
Oilfield Services & Equipment 201
Europe/United Kingdom Oil & Gas Equipment & Services
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
analyst's or each team's respective sector.
¹Target price is for 12 months.
Research Analysts
Phillip Lindsay
44 20 7883 1644
Gregory Brown
44 20 7888 1440
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
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$1
Performance 1M 3M 12M Absolute (%) -5.6 9.1 15.7 Relative (%) -2.8 -3.2 7.3
Financial and valuation metrics
Year 12/15A 12/16E 12/17E 12/18E Revenue (US$ 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
Dividend (12/16E, US$) 0.33 Net debt/equity (12/16E,%) 14.1 Dividend yield (12/16E,%) 3.7 Net debt (12/16E, US$ m) 344.2 BV/share (12/16E, US$) 6.7 IC (12/16E, US$ m) 2,792.8 Free float (%) 94.6 EV/IC (12/16E, (x) 1.4 Source: Company data, Thomson Reuters, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 202
Wood Group (WG.L)
Price (13 Sep 2016): 688.50p; Rating: OUTPERFORM; Target Price: 850.00p; Analyst: Phillip Lindsay
Income statement (US$ m) 12/15A 12/16E 12/17E 12/18E
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
Cash flow (US$ m) 12/15A 12/16E 12/17E 12/18E
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
Balance sheet (US$ m) 12/15A 12/16E 12/17E 12/18E
Assets Total current assets 2,057 2,097 2,175 2,314 Total assets 4,714 4,740 4,808 4,956 Liabilities Total current liabilities 1,496 1,495 1,494 1,551 Total liabilities 2,293 2,291 2,291 2,347 Total equity and liabilities 4,714 4,740 4,808 4,956
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
EV/Sales (x) 0.6 0.7 0.7 0.6 EV/EBITDA (x) 7.1 8.7 8.0 7.1 EV/EBIT (x) 10.4 15.9 12.2 10.4 Dividend yield (%) 3.34 3.67 3.85 4.05 P/E (x) 10.8 13.7 12.5 11.3
ROE analysis (%) 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
Credit ratios 12/15A 12/16E 12/17E 12/18E
Net debt/equity (%) 12.1 14.1 8.7 3.9 Dividend payout ratio (%) 36.1 50.1 48.0 45.5
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.
Blue/Grey Sky Scenario
Our Blue Sky Scenario (p) 1373.00
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%.
Our Grey Sky Scenario (p) 527.00
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%.
Share price performance
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
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates
19 September 2016
Oilfield Services & Equipment 203
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
0
100
200
300
400
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600
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
US
Dm
Organic EBITA EBITA from acquisitions
0.0
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0.80
1.00
1.20
2013 2014 2015 2016e 2017e 2018e 2019e 2020e
Div
idend C
ove
r
US
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har
e
Adj EPS DPS dividend cover (RHA)
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
Independent
20%
IOC
25%
NOC
15%
Other
40% Independent
45%
IOC
40%
NOC
5%
Other
10%
19 September 2016
Oilfield Services & Equipment 204
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
Oilfield Services & Equipment 205
Blue sky / Grey sky scenario
■ 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 +/-
0.5% from our base-case scenario for 2017 and beyond (diluted impact for 2016);
■ 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
Implied value per share (GBp) 804 845
DCF (USDm)
Assumptions: Beta Risk WACC LT Growth 2017E 2018E
premium
1.33 5.50% 8.20% 2.0%
EV 4128 4198
net cash / (debt) 218 102
Associates / minorities 323 323
MV 4669 4622
Implied value per share (GBp) 852 901
Valuation summary (GBp per share) Average 2017E 2018E
SOTP 824 804 845
DCF (USDm) 877 852 901
Overall average (equally weighted) 850
Blue Sky / Grey Sky
Blue sky valuation % vs base case Average 2017E 2018E
SOTP 55% 1274 1201 1347
DCF 68% 1472 1417 1527
Overall average (equally weighted) 61% 1373
Grey sky valuation % vs base case Average 2017E 2018E
SOTP -38% 511 512 510
DCF -38% 543 536 551
Overall average (equally weighted) -38% 527
Source: Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 206
HOLT
We have linked our forecasts to Credit Suisse HOLT – an objective, proprietary corporate
performance and valuation framework.
The charts in Figure 239 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
improve from 10.4% in 2016 to 11.8% by 2021. Thereafter we capture the next cycle and
forecast returns to dip to 9.2% in 2022 and recover to 12.1% by 2025 – highest level
achieved across 2016 to 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 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
inflation, and b) our methodology also incorporates a multiple-based SOTP.
19 September 2016
Oilfield Services & Equipment 207
Figure 239: Wood Group in HOLT
Source: HOLT®
Current Price: GBp 688.5 Warranted Price: GBp 685.0 Valuation date: 13-Sep-16
Sales Growth (parallel % point change to forecasts) Dec 14A Dec 15A Dec 16E Dec 17E Dec 18E
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%
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-2.0% -63% -55% -46% -35%
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-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
CFROI & Discount Rate (in %)
-30
-20
-10
0
10
20
30
2001 2004 2007 2010 2013 2016 2019 2022 2025
Historical Asset Growth Rate Forecast GrowthForecast Growth RAGRNormalised Growth Rate
Asset Growth (in %)
19 September 2016
Oilfield Services & Equipment 208
Figure 240: Summary financials – Wood Group
Divisionals 2014A 2015A 2016E 2017E 2018E 2019E 2020E
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
Net finance expense -14 -18 -21 -21 -20 -20 -19
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 209
Figure 241: Cash flow and balance sheet – Wood Group
Cash flow 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Operating profit 460 167 239 302 342 400 453
Operating cash flows 106 240 126 92 85 77 70
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
Other investing cash flows -78 15 5 3 4 4 5
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
Cash and cash equivalents 734 851 801 927 1044 1176 1336
Net cash / (debt) -327 -294 -344 -218 -102 31 191
Balance Sheet 2014A 2015A 2016E 2017E 2018E 2019E 2020E
Property plant and equipment 195 204 200 201 219 246 288
Goodwill and other intangible assets 1944 2005 1995 1983 1975 1968 1964
Other non-current assets 602 448 448 448 448 448 448
Total non-current assets 2740 2657 2643 2633 2642 2662 2699
Trade and other receivables 1444 1176 1100 1119 1213 1342 1480
Cash and cash equivalents 183 851 801 927 1044 1176 1336
Other current assets 21 30 196 128 58 59 60
Total current assets 1647 2057 2097 2175 2314 2577 2876
Total assets 4387 4714 4740 4808 4956 5239 5575
Trade and other payables 969 754 719 719 775 855 953
Borrowings 15 677 677 677 677 677 677
Other current liabilities 110 66 99 99 99 174 253
Total current liabilities 1094 1496 1495 1494 1551 1706 1883
Borrowings 495 495 495 495 495 495 495
Other non-current liabilities 239 302 302 302 302 302 302
Total non-current liabilities 734 797 797 797 797 797 797
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
Source: Company data, Credit Suisse estimates
19 September 2016
Oilfield Services & Equipment 210
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 242: Wood Group in PEERs
Source: Credit Suisse PEERs
19 September 2016
Oilfield Services & Equipment 211
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
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Oilfield Services & Equipment 212
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
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Oilfield Services & Equipment 213
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
Oilfield Services & Equipment 214
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.
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Oilfield Services & Equipment 215
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).
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Oilfield Services & Equipment 216
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.
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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)
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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
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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.
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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
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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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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.
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