Global Oil Services

abcGlobal Research

A slowing sector, but we see value in

restructuring plays, oversold 'problem' stocks and under-appreciated growth

Downgrading SLB to N from OW and MDR to UW(V) from N(V), upgrading KENZ to OW(V) from N(V)

Preferred names AKSO, SUBC, KENZ, seismic (PGS) and Anton Oil; we also see medium-term value in RIG

Looking into 2014 – the Year of the Horse

We’ve written this report as we see a disconnect developing

between share prices and the prospects for growth in parts of

oilfield services. We think this slowing but growing sector is

moving into 2014 at a canter at best but a number of stocks,

particularly larger caps, are pricing in more of a gallop. This

mispriced risk/reward could cause a sour end to the year

(a theme we’re already seeing play out in marine seismic).

We set out expecting to find selective growth in offshore

markets, where 25% growth in the deepwater rig fleet should

catalyse activity. But we ended up seeing more value in

restructuring plays (AKSO) and in ‘oversold risk’ in general

(SUBC, PGS, CGG, RIG); we also see under-appreciated

growth in KENZ and Chinese OFS (Anton Oil). Elsewhere,

the opportunities are less clear; we downgrade SLB to N from

OW (a sign of our overall stance on the sector), McDermott to

UW(V) from N(V), reflecting its risk profile through 2014,

and upgrade Kentz to OW(V) from N(V) after its suitors

withdrew from talks. We’re neutral on subsea equipment (FTI,

CAM) but prefer subsea installation (SUBC). We also lower

our view on seismic pricing in 2014 hitting our target prices

for CGG and PGS (although both remain on positive ratings).

Natural Resources & Energy Global Energy Equipment & Services

Mid-cycle blues

How selectivity can still let you play a slowing but growing oil services world

Our preferred stocks in global oilfield services

Companies Share price

Rating Tgt price

Potential upside

Aker Solutions (NOK, AKSO.OL) 79.6 OW(V) 120 51%Subsea 7 (NOK, SUBC.OL) 125.8 OW(V) 155 23%PGS (NOK, PGS.OL) 68.0 OW(V) 101 49%Kentz (GBPp, KENZ.L) 480.3 OW(V) 615 28%Anton Oilfield Services (HKD, 3337.HK) 5.45 OW(V) 7.22 32%

Pricing date 8 October 2013. Potential return equals the percentage difference between the current share price and the target price, including the forecast dividend yield when indicated. Source: HSBC estimates

15 October 2013 David Phillips* Global Co-head of Oil & Gas and Oil Services Research HSBC Bank plc +44 20 7991 2344 [email protected]

Phillip Lindsay* Analyst HSBC Bank plc +44 20 7991 2577 [email protected]

Thomas Hilboldt* Head of Oil, Gas & Petrochemicals Research, Asia Pacific The Hongkong and Shanghai Banking Corporation Limited +852 2822 2922 [email protected]

Tingting Si* Analyst The Hongkong and Shanghai Banking Corporation Limited +852 2996 6590 [email protected]

Neel Sinha* Head of Research, South East Asia The Hongkong and Shanghai Banking Corp Ltd, Singapore Branch +65 66580606 [email protected]

View HSBC Global Research at: http://www.research.hsbc.com

*Employed by a non-US affiliate of HSBC Securities (USA) Inc, and is not registered/qualified pursuant to FINRA regulations

Issuer of report: HSBC Bank plc

Disclaimer & Disclosures This report must be read with the disclosures and the analyst certifications in the Disclosure appendix, and with the Disclaimer, which forms part of it

Ratings and target price (TP) changes in this report

Company Share price

New rating

Old rating

New TP

Old TP

Pntl rtn, %

Aker Solutions (NOK, AKSO.OL) 79.6 OW (V) OW (V) 120 125 50.8BW Offshore (NOK, BWO.OL) 8 OW (V) OW (V) 10 9 24.5CGG (EUR, GEPH.PA) 15.4 OW (V) OW (V) 23 27 49.1Core Labs (USD, CLB) 175.3 N N 180 157 2.7Kentz (GBP, KENZ.L) 480.3 OW(V) N(V) 615 - 28Lamprell (GBP, LAM.L) 144.3 N(V) N(V) 150 160 4.0McDermott (USD, MDR) 7.13 UW(V) N(V) 6.75 - -5.3PGS (NOK, PGS.OL) 68 OW (V) OW (V) 101 111 48.6SBM Offshore (EUR, SBMO.AS) 15 N(V) N(V) 17 14.7 13.6Schlumberger (USD, SLB) 88.0 N OW 98 96 11.4TGS (NOK, TGS.OL) 147.5 OW (V) OW (V) 220 242 49.2

Source: HSBC estimates; Pricing date 8 October 2013. Potential return equals the percentage difference between the current share price and the target price, including the forecast dividend yield when indicated.

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Natural Resources & Energy Global Energy Equipment & Services 15 October 2013

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Investment summary 3

Slowing but growing… 9

Sub-sectors:

Seismic 25

Offshore drilling 35

Engineers, onshore and offshore

construction/installation 45

Subsea and Oilfield Equipment 70

Offshore support vessels (OSVs) 87

Floating production (FPSO) 93

Well services 104

Appendix: Event feedback 117

Valuations & risks 131

Disclosure appendix 200

Disclaimer 203

We acknowledge the assistance of Abhishek Kumar

(Associate, Bangalore) and Manikantha Garre (Associate,

Bangalore) in the production of this report.

Contents

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Mid-cycle blues in 2014

This report is a deliberate and early look-ahead

into 2014 and 2015. We’ve done this now as we

feel there are a number of growing pains affecting

both the oilfield service (OFS) sector and its oil

company client base, and given we are now in

‘budget season’, there are likely to be some

important pointers over the next few months as to

how 2014 may play out for E&P spending, and

for growth/project awards for the OFS industry.

The current state of play – we think OFS is

somewhere in the middle of a longer-term cycle.

This cycle has been playing out since 2009 – in

fact, there is reason to see the current cycle as

more of an extension of the last one, with just a

pause in new project activity in late 2008/early

2009, especially for offshore work. There are

several favourable structural trends to like –

offshore and subsea look set for long-term

growth, in particular – and industry backlogs are

strong (overall onshore & offshore backlogs for

EPC and equipment were USD202bn as at mid-

2013, up 19% y-o-y). But there look to be a

number of growing pains:

Endemic shortage of skilled labour, especially

offshore/subsea engineers;

Development costs have already caught up

with those in 2008, risking project economics

and cutting growth in E&P spending;

Supply is catching up (or has more than

caught up) with demand in some areas; and

From an OFS perspective, clients are more

global, projects are larger (and therefore

workflow is more lumpy) and there’s a

growing need to invest (vessels for deeper

water, new infrastructure for new regions).

Listing the ‘knowns & unknowns’ – as ex US

Secretary of Defense Donald Rumsfeld might say,

there are certain ‘known knowns’ on which we can

base our view. The most obvious is the 25%+

growth in the ultra-deepwater rig fleet we see

between last year and 2016e (and 22% growth in

the jackup/shallow water fleet as well). This

bodes well for future offshore activity and is a key

catalyst for a “stronger for longer” offshore and

subsea cycle. A key ‘known unknown’ is the oil

Investment summary

Chasing value in a slowing but growing sector – we prefer

restructuring plays, oversold risk and under-appreciated growth

A less positive tone – we downgrade SLB to N and MDR to

UW(V), and also cut estimates for seismic reflecting less pricing

upside in 2014; but we upgrade KENZ to OW(V)

Preferred stocks AKSO (TP NOK120), SUBC (TP NOK155), PGS

(TP NOK101), KENZ (TP 615p), Anton Oil (TP HKD7.22); also we

see medium-term value in RIG (TP USD67/CHF62)

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price, but our belief here is that we are firmly in a

sustained high oil price world (for one, we don’t

think shale oil will swamp the market).

Growing rig fleets, growing offshore capex

Source: IHS Petrodata, Infield Systems Ltd

Value in a slowing but growing sector – looking

at all these issues indicates to us that OFS is likely

– for a while – to be a ‘slowing but growing’

sector. But looking across our global coverage in

this space – covering stocks in the US, UK, Europe

and Asia – we feel the risk/reward looks mispriced

in several areas. We started out with this report

expecting to focus on selective areas of growth, but

we’ve actually ended up seeing more value in

‘problematic’ restructuring plays (eg, AKSO) and

oversold risk in general (eg, seismic, SUBC), in

addition to a few examples of underappreciated

pockets of growth (KENZ, Anton Oil).

Taking a less positive view – looking at the

ratings across our global coverage we are, on

balance, still more positive than negative

(although neutral if market cap weighted), but our

tone is less positive than before; this is typified by

our downgrade of SLB to Neutral in this report.

Key changes in this report – our main

fundamental change is to cut our outlook for

marine seismic pricing in 2014 (we see low

single-digit increases at best, versus +7.5%

before). We downgrade SLB to N from OW (after

a strong move up to the USD90 level) and

downgrade MDR to UW(V) from N(V) to reflect

what we see as a misaligned risk/reward, given

MDR’s commencement of offshore work on the

giant Ichthys project in 2014. We also upgrade

Kentz to OW(V) from N(V) following the end of

the potential offer from Amec.

Global oilfield services – YTD comparisons of share price moves and changes to 2014 consensus EPS

Source: Thomson Reuters Datastream

Our preferred names reflect restructuring

potential, oversold risk and under-appreciated

(and accelerating) growth potential.

Aker Solutions (OW(V), TP NOK120) –

AKSO continues to digest recent problem

contracts and quarterly volatility remains an

issue, but the underlying business quality is

robust (especially Subsea and MMO), and we

see material potential from further portfolio

and business restructuring. Recent

underperformance leaves AKSO on a record

(over 50%) discount to its peers.

Subsea 7 (OW(V), TP NOK155) – SUBC

continues to recover from its problematic

EPC work in Brazil, but this is nearing the

final straight. Its franchise offers the largest

and the purest play exposure to our favoured

sub-sector, subsea/SURF installation.

PGS (OW(V), TP NOK101) – we see seismic

in general as the stand-out ‘oversold risk’, and

notwithstanding we cut estimates (again) for

this space in this report, we see PGS’s current

0

20,000

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2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

overall rig fleet (LHS) floater rigs (LHS)offshore capex (RHS, USDm)

FPSO

Well Services

OSV

OFS Average

Drilling

Subsea & Oilfield

Equipment

E&C

Seismic

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2014

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YTD share Performance (USD based)

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valuations as discounting an overly negative

outcome for 2014/15e. On our numbers, PGS

is on 2014e multiples of 6.5x EPS, 3.3x

EV/EBITDA and around 1x book.

Kentz (OW(V), TP 615p) – with a backlog

soon to be over USD3bn and a potential

revenue booking of USD2bn or more in

2014e, KENZ is one of the few franchises in

OFS that is still accelerating. We continue to

think the market does not fully appreciate the

growth dynamic with this name.

Anton Oil (OW(V), TP HKD7.22) – Anton is

well positioned in a fast-growing OFS market

in China, with peer-group-leading leverage

via its partnership with Schlumberger (which

has been renewed for another three years and

expanded from Northwestern China to the

entire China onshore market and now covers

a full product offering and mutual supply).

Our least preferred names reflect our more

cautious view on several of the mainstream US

players, particularly the subsea equipment suppliers

where we see strong franchises but a few headwinds

(execution risks as companies handle record product

deliveries, competitive pricing for major greenfield

work, and an uptake of ‘high-tech’ equipment that is

likely to be slower than the market expects), in

addition to unforgivingly high valuations. This is

behind our Neutral (V) ratings on FTI and on

CAM, and a similar valuation angle (plus some

minor concerns about growth in 2014) is behind our

new Neutral rating on SLB.

We also downgrade MDR to UW(V), reflecting

our concerns over its ability to work through the

offshore stage of the giant Ichthys project, which

starts in H2 next year; we think current valuations

fail to price in any reasonable contingency for

new problems.

We also have concerns over AMEC and PFC

(both rated Neutral/Neutral (V)); we see AMEC’s

growth dynamic as under pressure and have

doubts whether it will reach its 2014 EPS targets

without help from a buyback or M&A deal, and

we see PFC facing a year where clear questions

remain over margin sustainability in its onshore

E&C business.

Oilfield services – our preferred stocks (grouped by theme)

Preferred group Stocks (all rated OW(V) or OW)

Overall Aker Solutions (AKSO.OL, TP NOK120), Subsea 7 (SUBC.OL, TP NOK155), PGS (PGS.OL, TP NOK101), Kentz (KENZ.L, TP 615p), Anton Oil (3337.HK, TP HKD7.22)

GEMS Kentz (KENZ.L, TP 615p), Anton Oil (3337.HK, TP HKD7.22), Technip (TECF.PA, TP EUR105), Saipem (SPMI.MI, TP EUR20), Honghua Group (0196.HK, TP HKD4.83)

Small & midcap (UK/EU)

Aker Solutions (AKSO.OL, TP NOK120), CGG (GEPH.PA, TP EUR23), PGS (PGS.OL, TP NOK101), Kentz (KENZ.L, TP 615p), Hunting (HTG.L, TP 1,050p)

Source: HSBC estimates

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cGlobal Oil Services: Valuation and rating summary, 2013e-15e

Share Rating Target Potential Mkt value 2013e ___________ P/E ____________ ________ EV/EBITDA _________ ________ EV/sales _________ Company price price return LC (m) USD (m) yield (%) 2013e 2014e 2015e 2013e 2014e 2015e 2013e 2014e 2015e

Aker Solutions (NOK, AKSO.OL) 79.6 OW(V) 120 50.8% 21,496 3,586 5.0% 11.0 7.1 5.6 6.1 4.4 3.5 0.6 0.5 0.4 Amec (GBP, AMEC.L) 1,061 N 1,130 6.5% 3,406 5,441 3.5% 12.9 12.6 11.7 9.1 8.4 7.4 0.8 0.7 0.7 Cameron (USD, CAM) 60.4 N(V) 64 6.0% 15,159 15,159 - 18.1 13.9 12.1 9.8 7.3 6.0 1.5 1.3 1.1 FMC (USD, FTI) 56.1 N(V) 56 -0.2% 13,618 13,618 - 25.9 17.0 12.8 14.9 10.2 7.5 2.0 1.7 1.4 Ezra (SGD, EZRA SP) 1.13 OW 1.25 10.6% 1096 885 1.1% 15.4 11.4 7.7 59.5 11.6 9.3 1.9 1.7 1.4 National Oilwell Varco (USD, NOV) 78.2 OW(V) 86 10.0% 33,545 33,545 0.5% 15.2 12.6 10.9 8.6 7.0 5.8 1.6 1.4 1.2 Lamprell (GBPp, LAM.L) 144.3 N(V) 150 4.0% 377 602 0.0% 52.7 14.0 7.3 9.6 6.3 4.1 0.5 0.5 0.4 Kentz (GBP, KENZ.L) 480.3 OW(V) 615 28.0% 577 922 0.0% 11.3 10.1 8.1 6.0 5.1 3.9 0.5 0.4 0.3 Schoeller-Bleckmann (EUR, SBOE.VI) 85.25 N(V) 82 -3.8% 1,181 1,597 1.6% 19.8 15.3 12.7 8.9 7.0 5.7 2.6 2.1 1.8 Hunting (GBP, HTG.L) 784.5 OW 1,050 33.8% 1,173 1,874 2.5% 13.1 10.7 10.2 8.1 6.6 6.0 1.5 1.3 1.2 Sinopec Engineering (HKD, 2386.HK) 9.5 OW(V) 13.6 43.2% 32,892 5,373 3.8% 8.1 8.3 7.5 3.0 2.4 1.7 0.3 0.3 0.2 Subsea 7 (NOK, SUBC.OL) 125.8 OW(V) 155 23.2% 47,826 7,979 3.0% 35.3 11.1 9.3 9.4 5.5 4.5 1.3 1.2 1.0 McDermott (USD, MDR) 7.13 UW(V) 6.75 -5.3% 1,730 1,730 0.0% NA 28.3 9.8 85.9 8.7 5.4 0.5 0.6 0.6 Wood Group (GBP, WG.L) 762 N 860 12.9% 2,839 4,536 1.6% 12.0 11.3 9.7 7.7 6.9 5.5 0.6 0.6 0.5 Petrofac (GBP, PFC.L) 1,341 N(V) 1,300 -3.1% 4,503 7,194 3.1% 11.2 10.3 8.7 7.5 6.7 5.5 1.2 1.0 1.0 Saipem (EUR, SPMI.MI) 16.6 OW(V) 20 20.7% 7,240 9,791 0.0% NA 13.0 8.8 19.9 6.2 4.8 0.9 0.9 0.9 Technip (EUR, TECF.PA) 87.1 OW(V) 105 20.5% 10,841 14,661 2.1% 16.4 13.1 11.0 8.8 6.7 5.4 1.1 0.9 0.8

Diversified engineers / manufacturers 16.0% 128,493 14.6 12.9 9.6 9.2 6.9 5.4 1.1 1.0 0.9

CGG (EUR, GEPH.PA) 15.4 OW(V) 23 49.1% 2,521 3,410 - 14.4 10.5 6.3 4.0 3.5 2.5 1.3 1.1 0.9 Fugro (EUR, FUGRc.AS) 43.8 N 50 14.1% 3,550 4,801 3.4% 8.3 14.9 11.6 6.7 6.3 5.3 1.5 1.3 1.2 PGS (NOK, PGS.OL) 68.0 OW(V) 101 48.6% 14,777 2,465 5.3% 8.0 6.5 6.2 3.6 3.2 3.1 1.9 1.7 1.7 TGS (NOK, TGS.OL) 147.5 OW(V) 220 49.2% 15,421 2,573 5.5% 10.2 8.7 8.4 2.9 2.6 2.4 2.5 2.2 2.0 Schlumberger (USD, SLB) 88.0 N 98 11.4% 119,559 119,559 1.4% 19.2 15.4 12.0 9.8 8.0 6.2 2.6 2.2 1.9 Honghua Gp (HKD, 196.HK) 2.5 OW(V) 4.83 93.2% 6,391 1,044 2.6% 7.7 7.0 6.1 6.8 5.6 4.9 1.0 0.9 0.7 Anton Oilfield (HKD, 3337.HK) 5.45 OW(V) 7.22 32.5% 9,286 1,517 1.7% 20.9 16.8 13.7 14.4 11.6 9.5 3.4 2.7 2.1 SPT Energy (HKD, 1251.HK) 3.8 UW(V) 3.2 -16.0% 4,600 751 1.3% 15.2 12.5 10.2 8.2 6.8 5.6 1.9 1.5 1.2 Core Labs (USD, CLB) 175.3 N 180 2.7% 8,350 8,350 0.8% 32.5 28.5 25.8 23.1 20.0 17.9 7.8 6.9 6.3 Core Labs (EUR, CLB NA) 104.6 N 136 4.3%

Seismic / well services 31.5% 144,471 15.2 13.4 11.1 8.8 7.5 6.4 2.7 2.3 2.0

SBM Offshore (EUR, SBMO.AS) 15.0 N(V) 17.00 13.6% 2,822 3,816 0.0% 14.0 7.5 7.5 5.7 5.2 5.0 1.3 1.2 1.1 BW Offshore (NOK, BWO.OL) 8.0 OW(V) 10 24.5% 5,525 922 9.0% 8.5 9.5 8.7 5.6 5.9 5.1 2.8 3.1 2.7 Bumi Armada (MYR, BUAB.KL) 4.0 N 4.2 6.3% 11,579 3,622 0.9% 23.4 18.8 18.6 14.4 10.7 8.2 7.3 5.9 5.7 Bourbon (EUR, GPBN.PA) 20.0 OW(V) 28 40.2% 1,353 1,829 2.0% 20.5 5.9 4.2 6.6 3.6 3.1 2.2 1.1 0.9 Seadrill (NOK, SDRL.OL) 270.7 N 280 3.4% 132,643 22,129 7.9% 18.3 12.6 9.0 13.1 10.6 8.9 6.8 5.9 5.1 Seadrill (USD, SDRL) 45.5 N 47.5 4.2% Transocean (CHF, RIGN.VX) 40.4 OW(V) 62.0 53.4% 14,551 16,204 5.0% 11.0 7.9 6.8 7.4 6.0 5.2 2.8 2.5 2.2 Transocean (USD, RIG) 45.0 OW(V) 67.0 53.4% COSL (HKD, 2883.HK) 20.4 N 19.6 -3.9% 73,450 11,998 1.7% 12.0 10.9 9.8 8.7 7.8 6.9 3.4 3.1 2.8

Offshore operators 22.7% 60,519 15.4 10.4 9.2 8.8 7.1 6.1 3.8 3.2 3.0

Sector average multiples/upside 21.2% 333,483 15.0 12.0 10.0 9.0 7.1 5.8 2.1 1.8 1.6

Market-cap-weighted potential return 14.2%

Source: HSBC estimates, Potential return equals the percentage difference between the current share price and the target price, including the forecast dividend yield when indicated. Prices as at market close of 8 October 2013.

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Distribution of our ratings across the key sub-sectors in oilfield services ( ↑= upgrade, ↑ = downgrade)


Seismic Drilling Engineering & Construction Subsea & Equipment supply vessels FPSOs Well Services

OW

/ O

W(V

)

PGS Transocean Subsea 7 Aker Solutions Bourbon BW Offshore Anton Oilfield

CGG Kentz (↑) NOV

TGS Technip Hunting

Saipem HongHua

Ezra

Sinopec Engineering

N /

N(V

)

Seadrill Amec Cameron SBM Offshore Schlumberger (↓)

COSL Petrofac FMC Technologies Bumi Armada Fugro

Wood Group Schoeller Bleckmann Core Labs

Lamprell

UW

/ UW

(V) McDermott (↓) SPT

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Global Oil Services- main changes to ratings, target Prices and 2013e-2014e net profit estimates across our coverage

Company Old rating New rating Change in rating

Old target New target Change (%) 2013e net (old)

2013e net (new)

Change (%) 2014e net (old)

2014e net (new)

Change (%)

Aker Solutions (NOK, AKSO.OL) OW (V) OW (V) No change 125 120 -4.0% 2,086.4 1,965.0 -5.8% 3,321.5 3,058.0 -7.9% Amec (GBP, AMEC.L) N N No change 1,130 1,130 n/a 246.0 246.0 n/a 251.0 251.0 n/a Anton Oilfield Services (HKD, 3337.HK) OW (V) OW (V) No change 7.22 7.22 n/a 448.0 448.0 n/a 562.0 562.0 n/a Bourbon (EUR, GPBN.PA) OW (V) OW (V) No change 28 28 n/a 70.0 70.0 n/a 242.0 242.0 n/a Bumi Armada (MYR, BUAB.KL) N N No change 4.2 4.2 n/a 494.0 494.0 n/a 616.0 616.0 n/a BW Offshore (NOK, BWO.OL) OW (V) OW (V) No change 9 10 11.1% 107.0 108.3 1.2% 93.0 97.4 4.7% Cameron (USD, CAM) N (V) N (V) No change 64 64 n/a 844.0 844.0 n/a 1096.0 1096.0 n/a CGG (EUR, GEPH.PA) OW (V) OW (V) No change 27 23 -14.8% 275.5 257.0 -6.7% 462.8 354.0 -23.5% COSL (HKD, 2883.HK) N N No change 19.6 19.6 n/a 6041.0 6041.0 n/a 6646.0 6646.0 n/a Core Labs (USD, CLB) N N No change 157 180 14.6% 244.8 248.5 1.5% 276.5 280.7 1.5% Ezra (SGD, EZRA.SI) OW OW No change 1.25 1.25 n/a 63.0 63.0 n/a 86.0 86.0 n/a FMC (USD, FTI) N (V) N (V) No change 56 56 n/a 522.0 522.0 n/a 798.0 798.0 n/a Fugro (EUR, FUGRc.AS) N N No change 50 50 n/a 434.0 434.0 n/a 243.0 243.0 n/a Honghua Group (HKD, 0196.HK) OW (V) OW (V) No change 4.83 4.83 n/a 825.0 825.0 n/a 905.0 905.0 n/a Hunting (GBP, HTG.L) OW OW No change 1,050 1,050 n/a 89.0 89.0 n/a 110.0 110.0 n/a Kentz (GBP, KENZ.L) N (V) OW (V) Rating

upgrade615 615 n/a 82.0 82.0 n/a 92.0 92.0 n/a

Lamprell (GBP, LAM.L) N (V) N (V) No change 160 150 -6.3% 6.1 11.4 86.9% 71 43.1 -39.3% McDermott (USD, MDR) N (V) UW (V) Rating

downgrade6.75 6.75 n/a -136.0 -136.0 n/a 61.0 61.0 n/a

National Oilwell Varco (USD, NOV) OW (V) OW (V) No change 86 86 n/a 2211.0 2211.0 n/a 2665.0 2665.0 n/a Petrofac (GBP, PFC.L) N (V) N (V) No change 1,300 1,300 n/a 645.0 645.0 n/a 696.0 696.0 n/a PGS (NOK, PGS.OL) OW (V) OW (V) No change 111 101 -9.0% 319.2 306.3 -4.0% 430.1 380.0 -11.6% Saipem (EUR, SPMI.MI) OW (V) OW (V) No change 20 20 n/a -411.0 -411.0 n/a 561.0 561.0 n/a SBM Offshore (EUR, SBMO.AS) N (V) N (V) No change 14.72 17 15.5% 186.8 292.0 56.3% 544.0 560.7 3.1% Schlumberger (USD, SLB) OW N Rating

downgrade96 98 +2.1% 6217.0 6217.0 n/a 7752.0 7752.0 n/a

Schoeller-Bleckmann (EUR, SBOE.VI) N (V) N (V) No change 82 82 n/a 60.0 60.0 n/a 77.0 77.0 n/a Seadrill (NOK, SDRL.OL) N N No change 280 280 n/a 1155.0 1155.0 n/a 1679.0 1679.0 n/a Sinopec Engineering (HKD, 2386.HK) OW (V) OW (V) No change 13.6 13.6 n/a 3575.0 3575.0 n/a 3975.0 3975.0 n/a SPT Energy (HKD, 1251.HK) UW (V) UW (V) No change 3.2 3.2 n/a 301.0 301.0 n/a 368.0 368.0 n/a Subsea 7 (NOK, SUBC.OL) OW (V) OW (V) No change 155 155 n/a 234.0 234.0 n/a 748.0 748.0 n/a Technip (EUR, TECF.PA) OW (V) OW (V) No change 105 105 n/a 665.0 665.0 n/a 839.0 839.0 n/a TGS (NOK, TGS.OL) OW (V) OW (V) No change 242 220 -9.1% 299.9 256.7 -14.4% 336.5 294.1 -12.6% Transocean (CHF, RIGN.VX) OW (V) OW (V) No change 62 62 n/a 1464.0 1464.0 n/a 2034.0 2034.0 n/a Wood Group (GBP, WG.L) N N No change 860 860 n/a 379.0 379.0 n/a 402.0 402.0 n/a


9


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Oilfield services – summary

In a world of sustained high oil prices but

declining production, the outlook for E&P

spending and the health of the oilfield services

industry should be robust. We continue to see a

good long-term outlook for this diverse sector, but

we’re now four to five years into this next leg of

the cycle and feel that for a number of reasons the

industry will likely be in a “slowing but growing”

mode while its customer base adapts to rising

costs, unconventionals and ever-shifting politics.

There is also the issue of oil services supply – eg;

more seismic vessels, more supply vessels, more

rigs and more pressure pumping kit – which has

had ample time to catch up and now is a moderate

overhang to further cyclical improvement in some

areas. And there has already been commentary

from some operators that E&P capex is likely to

peak in 2013 – we think this might be true in

selected cases, but we do still expect to see

moderate growth in E&P spending in 2014. But

this all indicates to us that the risks of a slightly

sour end to the year are rising – the economic

temptation for oil companies to shift some activity

(or new contract awards) into 2014 is likely to be

significant. And with this in mind, the 16% cut to

average oil services EPS we’ve seen year to date

may have more to go before we can – with typical

Q1 optimism – take a longer-term view.

But in this longer-term view, we do see the current

“industry mix” as a phase, not the end, and expect

the industry to resume a reasonable rate of growth.

Offshore markets remain a key structural growth

area – a 25% increase in the ultra-deepwater rig

fleet (and 22% growth in jackups) by 2016

indicates to us that the main tools for offshore work

are more numerous than before, with all that means

for facilitating more offshore activity – offshore

consultants Infield Systems see 11-12% compound

growth in offshore capex out to 2016. Subsea (and

associated) markets look well placed for

medium-term growth. Following this, our sub-

sector preferences are quite selective – we see

value in seismic and good growth in subsea

installation (especially SURF); our views

elsewhere are more stock-specific.

Slowing but growing…

In a slowing but growing oilfield services market, we see selective

value in restructuring, oversold risk and under-appreciated growth

We see a sustained high oil price environment and a 25% larger

deepwater rig fleet by 2016e; offshore & subsea should still grow

With OFS share prices up 12% and average EPS down 16% YTD,

our preferences are selective – AKSO, SUBC, KENZ, Anton Oil,

seismic in general (PGS), and we see medium-term value in RIG

10


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Overall sector outlook

The big picture – our framework

We do not intend to run through a detailed

analysis of oil and gas supply/demand in this

report, but rather to set out a snapshot of our key

macro assumptions and issues that we use to back

up our view of oilfield services activity across the

sector. These are:

We continue to assume that oil (Brent and

WTI) will not trade below the USD90-100/bbl

range for any meaningful amount of time. We

still see Saudi’s fiscal needs as indicating

strongly that it needs at least USD90/bbl (and

potentially more) to balance its budget, and we

expect it to respond to defend this price range

if oil prices were to weaken.

We do not think that shale oil will swamp the

world – this will remain an important issue,

especially for North America, but we see

shale oil as being one of the many new

sources of production that are needed to offset

the natural decline of existing production. We

also note that shale oil is not “cheap” per se,

with shale oil reservoirs in North America

needing USD50-80/bbl to make project

economics work and allow investment.

We see shale gas as being potentially more

important – the resource of unconventional

gas globally is much greater than that of oil,

and in the US it is clearly “cheaper” than gas

supplied into Europe and Asia, and there are a

number of ‘downstream’ opportunities that

can potentially monetise this to good effect –

gas-fuelled chemical manufacture, gas

liquefaction into LNG for export, gas-fuelled

power generation, gas-to-liquids technology

to produce chemicals and fuels, and also gas

as a transport fuel. Most of these themes –

especially the ‘gas as a transport fuel’ idea –

are likely to play out over the longer term.

We highlight also our recent joint economics and

oil publication on 22 September 2013 ‘Shale oil

and gas: US revolution, global evolution’, which

goes into the potential economic impacts of shale

oil and shale gas in greater detail.

Growing rig fleets – one of the key ‘known

knowns’ we see is ongoing growth in the

global rig fleet. We think this is a positive

driver for more offshore activity. Rigs –

especially ultra-deepwater – were a major

bottleneck for offshore work in the last cycle,

and the significant growth (and ongoing

growth) in the global rig fleet we see coming

into the market now and over the next few

years should be a positive catalyst for offshore

activity overall in the medium term. Based on

current plans for newbuild rigs, we see around

25% growth in the floater rig fleet and 22%

growth in jackups over 2012-16 (and we

expect this newbuild order book to grow more

in 2014). Infield sees a CAGR in offshore

capex of 11-12% over the same period.

Through previous cycles the correlation between a

larger rig fleet and higher offshore capex has

actually not been all that close but that may reflect

more the timing of investment cycles; we think

the connection is logical, particularly for this

cycle, and should also be a positive catalyst for an

array of offshore-linked industries such as survey,

offshore support and subsea.

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Share prices, earnings & multiples – looking

for value in the OFS sector

After a relatively strong performance through late

Q3/early Q4, the overall OFS sector is up 12% (in

local currencies) year to date. Surprisingly (for some,

given performance over recent years), the best-

performing sub-sector is the FPSO group, with only

Bumi Armada lower YTD (the other names are up

40-50%). Well services (and the Chinese well

services names) have also performed quite strongly,

up around 25% YTD. The asset-heavy drillers are up

11% YTD, with weaker performances from subsea

and oilfield equipment (up 10% YTD) and

engineering and construction (up slightly YTD); the

main underperformer has been seismic, currently

down 25% YTD.

Looking at consensus EPS and EBITDA

revisions for 2014 over this year so far – the

average oil services EPS forecast is down 16%

and average EBITDA forecast is down 8% (this

includes the US, UK, EU and certain Asian/Asean

names). On a sub-sector basis, the worst hit (in

terms of downgrades) have been the smaller

regional well services names exposed to the North

American market, followed by subsea installation

and seismic. It is important to note that the subsea

installation performance is driven by two specific

major issues – Saipem’s downgrades from its

profit warnings in Q1 and Q2 this year, and

McDermott’s series of contract problems (without

these two names, the subsea installation group

downgrades are only half as much).

The most resilient sub-sectors have been the

FPSO names (2014 forecasts largely unchanged

overall – a much better year versus 2011/12) and

the global well services names (2014 forecasts

down a single-digit amount).

Our suspicion is that there is still some more to

come in terms of downgrades to 2013 consensus

expectations; the year could still have a slightly

sour end. Although oil prices look to be firm

(Brent currently around USD110/bbl) through the

all-important Q4 budget-setting season for the

major oil companies, clearly there are growing

pressures on costs, cash flows and on potential

project economics, in addition to the usual

political and bureaucratic issues in certain parts of

the world, and we think that in some cases it is

likely this will lead to some work shifting into

early 2014. This could cover large project awards

as well as more immediate short-cycle work like

seismic. We do not see this as a new structural

risk in general, but we expect there will be several

companies for which 2013 could end up slowing

into the year-end before a better 2014.

Rig fleet growth versus offshore capex growth – y-o-y trends since the 1980s

Source: IHS Petrodata, Infield Systems Ltd

-15%

-10%

-5%

0%

5%

10%

15%

20%

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

overall rig fleet y-o-y % floater fleet y-o-y % offshore capex y-o-y %

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Sector valuations – we do not intend to go through

a detailed comparison of sector and sub-sector

valuations versus history here, but some key

indicators of where we are versus the past are:

In terms of P/E, the overall sector is slightly

below its long-term average (2000-present) at

around 15x EPS, versus 17.5x average (this

average does include a time when many

stocks were somewhat more cyclical so saw

inflated P/Es in trough conditions). In terms

of sub-sectors, seismic, well services, subsea

construction and the heavy-asset sectors

(drilling, OSVs and FPSOs) are below their

long-term P/E averages, subsea & offshore

equipment and E&C are in line.

In terms of EV/EBITDA, the overall sector is

slightly ahead of its long-term average at around

8.0-8.5x versus a long-term average of 8x (and

is in line with the average for FY2 estimates). In

terms of sectors, seismic, well services, FPSOs

and onshore drillers are below their long-term

averages; subsea & offshore equipment, subsea

construction and OSVs are above.

Sub-sector valuations vs long-term history – EV/EBITDA

Sub-sector Mean High Low Current Current % of mean

Seismic 5.8 10.1 2.1 4.3 74% Well services 8.0 13.6 3.1 6.9 85% Subsea & offshore equipment

8.5 15.1 2.9 10.2 120%

Equipment manufacturers

9.2 14.5 3.8 11.0 120%

E&C 8.7 16.7 3.8 8.1 93% Subsea installation 8.4 41.5 3.4 12.1 145% Shipyards 9.3 68.2 1.2 9.5 102% FPSO 10.3 20.8 4.9 8.8 85% Offshore drillers 8.7 16.2 3.7 8.7 100% Onshore drillers 6.4 11.0 2.6 5.5 85% OSV 8.0 11.5 4.5 9.0 113% OFS average 8.0 15.4 3.6 8.4 105%


In terms of price/book, the sector is below its

long-term average (1.8x versus an average of

around 2.4x). On a sub-sector level, seismic,

well services, subsea construction, FPSOs and

onshore drillers are below their own long-term

averages, while subsea and related equipment

manufacturers are above and other sectors

(offshore drillers and others) are more in line

with their long-term averages.

Consensus 2014 EBITDA forecast revisions (vs start 2013) Consensus 2014 EPS forecast revisions (vs start 2013)

Source: Thomson Reuters Datastream Source: Thomson Reuters Datastream

Sub-sector valuations vs long-term history – P/E

Sub-sector Mean High Low Current Current % of mean


19.2 30.9 5.9 19.5 102%


20.4 49.9 7.2 19.8 97%



-18%

-16%

-14%

-12%

-10%

-8%

-6%

-4%

-2%

0%

wel

l ser

vice

s - g

loba

l

subs

ea &

offs

hore

equi

pmen

t OSV

s

FPSO

offs

hore

dril

ling

E&C

wel

l ser

vice

s - o

vera

ll

seis

mic

subs

ea in

stal

latio

n

wel

l ser

vice

s -

regi

onal

2014 EBITDA revisions YTD

-45%

-40%

-35%

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

FPSO

wel

l ser

vice

s - g

loba

l

subs

ea &

offs

hore

equi

pmen

t OSV

s

offs

hore

dril

ling

E&C

wel

l ser

vice

s - o

vera

ll

seis

mic

subs

ea in

stal

latio

n

wel

l ser

vice

s - r

egio

nal

2014 EPS revisions YTD

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Sub-sector valuations vs long-term history – P/B

sub-sector Mean High Low Current Current % of mean


2.7 5.6 1.1 2.3 83%


3.4 7.0 1.7 5.2 154%



So is there any value in the sector? There are not

many sub-sectors that stand out on a simple

historical comparison (assuming of course that the

past 10-12 years of history are a reasonable and

relevant guide for the current cycle); the main

‘value’ seems to be with the seismic sector

(reflecting current market concerns about Q4

activity and 2014 pricing).

The other ‘below trend’ sectors are the drilling

sectors and FPSOs (some other sectors like subsea

installation look ‘cheap’ on some metrics but not

on others), but these areas are, we think, facing a

decidedly different cycle now versus that in

2004-08. Most of the larger offshore drillers face

the challenge of managing fleet mix (ie, handling

the higher opex and decreasing market

opportunities for the older rigs in the fleet), and

floating production markets – while growing – are

nowhere as fast growing (or perceived to be as

fast growing) as they were in the last cycle.

So our view on “value” in this sector really

comes down to a much more stock-specific

level – even though most of the issues and

concerns that financial markets have are more at a

macro level, with issues like E&P spending, oil

prices, US rig count, project delays and so on.

We think the market has overly de-risked areas

where there is still significant uncertainty,

particularly seismic (CGG, PGS and TGS),

‘problem portfolios’ like AKSO and stocks that

are recovering from recent contracting issues

(particularly SUBC), but has priced in quite high

expectations with subsea (FTI, CAM) and the top

end of well services (SLB) and the top end of

offshore drilling (SDRL). We have few issues

with the business models and strategies of these

companies – in fact most screen as ‘best in class’

– but we feel the risk/reward difference between

these stocks and those where restructuring and/or

strategic change (and a moderate following wind

from their markets) could drive significant

improvement is overly wide.

What’s on our mind for 2014

Five key themes/variables to watch in 2014

The pace of offshore awards from Africa –

with growth still possible for subsea markets

in 2014, what is clear is that Africa is key to

growth. Without a decent stream of African

project awards, industry growth is likely to

stall (and in particular those with less fully

global franchises could suffer more – we’d

note Saipem’s greater relative offshore

exposure to Africa than Technip/Subsea 7).

Subsea installation margins – although backlog

growth in 2014 is unlikely to be as strong as in

recent years, we still see growth; vital to the

investment case for this sector is the progression

of margins through 2014 as improved prices

offset higher staffing and other costs. This

margin dynamic is key for Technip, Subsea 7

and Ezra – Saipem and McDermott will be more

driven by their own recovery momentum.

Progression in the US rig / well count – a

large part of the oil & gas-exposed industrials

value chain (eg, Hunting, Schoeller

Bleckmann, Wier, Rotork) as well as the

mainstream service & equipment suppliers

themselves will be geared to whether the US

onshore market delivers some growth, or

14


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whether 2014 sees more destocking (from the

likes of SLB/HAL/BHI downwards). There

have been quite a few M&A moves and

investment appetite shifts (eg, Shell’s moves

into shale but subsequent write-downs); these

could result in disruptions to drilling plans.

Indications of marine seismic pricing –

expectations continue to come down and

several players are now even talking about

average pricing being flat through 2014

versus 2013. There will be key triggers for

this discussion from CGG’s capital markets

day (planned for 20 November) and PGS’s

capital markets day (planned for 18

December), in addition to discussions through

the upcoming Q3 results season (SLB results

due on 18 October, PGS due on 25 October

and CGG due on 7 November).

And the wildcards – key to watch progress on

seabed seismic (will commoditisation of OBC

– ocean bottom cable – result in this being a

real competitor to towed streamer seismic,

and could we see the first multi-client ocean

bottom work in 2014?) and in advanced

subsea (we’re watching Petrobras’ Marlim

project to see how FMC’s water/oil separation

pilot is progressing; this will be a key signal

as to the speed and extent of adoption).

Other stock-specific topics to watch out for

through 2014

The sense of this list is really to see where 2014

will be a particularly important year – not just in

terms of overall market growth but specific cases

where certain issues may well be made visible or

may be decided during 2014. The main examples

in this category we see are:

Underlying growth at Amec – we remain

concerned that Amec’s growth dynamic is (or

has) slowed, and with certain important

greenfield contracts rolling over there is a

need for more higher-margin work as well.

Signs that Amec’s growth is recovering will

be important if the market is not to question

its ability to hit its 2014e EPS targets without

significant M&A or buybacks.

E&C margins at Petrofac – this is not a new

theme now, but we are closer to the year

where Petrofac’s lump-sum E&C business

could face risks of significant margin

downside as it executes on lower-margin

work won in recent years. The quality and

mix of order intake will be key.

Restructuring at Aker Solutions – we expect

to hear more about portfolio changes at

AKSO in 2014; the spin-off of the marine

assets is planned for later in the year, but we

also see further potential changes in the

portfolio, with the group likely to focus on the

core Subsea and MMO businesses.

Order intake at Lamprell – the initial

restructuring story at Lamprell is done; new

management, refinancing and a clean-up of

the legacy contracts. The key for 2014 will be

to see how group backlog progresses in a

market that is likely to have decent appetite

for newbuild jackup orders – but do clients

prefer larger & more complex units than the

“Volkswagens of the jackup world” models

marketed by Lamprell?

Project execution in general at McDermott

but specifically with Ichthys, the “mega”

offshore project that McDermott moves

offshore in H2 2014. With this being seen by

the market as a project won at a low price, the

room for execution problems is limited.

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Project execution in general – given events

this year (and in some cases in previous years

as well), we think it is very important for

investor appetite for E&C companies that we

see “no new problems” at the likes of Saipem,

Subsea 7 and others; Saipem’s problems this

year, in particular, have caused some

investors to re-think their interest in owning

E&C-type companies in general.

Availability of finance – particularly in terms

of finance available for E&P companies to

invest (we’d note Norway is setting up funds to

help support smaller players and entrepreneurs

who might otherwise find it challenging to raise

funding; this is a continuation of the relatively

supportive culture to funding new ventures and

new technology in Norway, although good

funding availability can also fuel unwanted

supply-side growth as new players chase short-

term excess returns).

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Marine finance raising – 2009-present (in USDm)

Source: Bloomberg

Oil & gas financing – 2009-present (in USDm)

Source: Bloomberg

Marine and oil & gas financing – cumulative values per year (in USDm)

Source: Bloomberg

0

20

40

60

80

100

120

140

0

5000

10000

15000

20000

25000

30000

35000

Jan

09Fe

b 09

Mar

09

Apr 0

9M

ay 0

9Ju

n 09

Jul 0

9Au

g 09

Sept

09

Oct

09

Nov

09

Dec

09

Jan

10Fe

b 10

Mar

10

Apr 1

0M

ay 1

0Ju

n 10

Jul 1

0Au

g 10

Sep

10O

ct 1

0N

ov 1

0D

ec 1

0Ja

n 11

Feb

11M

ar 1

1Ap

r 11

May

11

Jun

11Ju

l 11

Aug

11Se

p 11

Oct

11

Nov

11

Dec

11

Jan

12Fe

b 12

Mar

12

Apr 1

2M

ay 1

2Ju

n 12

Jul 1

2Au

g 12

Sep

12O

ct 1

2N

ov 1

2D

ec 1

2Ja

n 13

Feb

13M

ar 1

3Ap

r 13

May

13

Jun

13Ju

l 13

Aug

13Se

p 13

marine finance raised (USDm, LHS) no of deals (RHS)

0

10

20

30

40

50

60

70

80

0

10,000

20,000

30,000

40,000

50,000

60,000

Jan-

09Fe

b-09

Mar

-09

Apr-0

9M

ay-0

9Ju

n-09

Jul-0

9Au

g-09

Sep-

09O

ct-0

9N

ov-0

9D

ec-0

9Ja

n-10

Feb-

10M

ar-1

0Ap

r-10

May

-10

Jun-

10Ju

l-10

Aug-

10Se

p-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11Fe

b-11

Mar

-11

Apr-1

1M

ay-1

1Ju

n-11

Jul-1

1Au

g-11

Sep-

11O

ct-1

1N

ov-1

1D

ec-1

1Ja

n-12

Feb-

12M

ar-1

2Ap

r-12

May

-12

Jun-

12Ju

l-12

Aug-

12Se

p-12

Oct

-12

Nov

-12

Dec

-12

Jan-

13Fe

b-13

Mar

-13

Apr-1

3M

ay 1

3Ju

n 13

Jul 1

3Au

g 13

Sep

13

oils amount raised (USD m) No of deals/month (RHS)

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

0

50000

100000

150000

200000

250000

Jan

09Fe

b 09

Mar

09

Apr 0

9M

ay 0

9Ju

n 09

Jul 0

9Au

g 09

Sept

09

Oct

09

Nov

09

Dec

09

Jan

10Fe

b 10

Mar

10

Apr 1

0M

ay 1

0Ju

n 10

Jul 1

0Au

g 10

Sep

10O

ct 1

0N

ov 1

0D

ec 1

0Ja

n 11

Feb

11M

ar 1

1Ap

r 11

May

11

Jun

11Ju

l 11

Aug

11Se

p 11

Oct

11

Nov

11

Dec

11

Jan

12Fe

b 12

Mar

12

Apr 1

2M

ay 1

2Ju

n 12

Jul 1

2Au

g 12

Sep

12O

ct 1

2N

ov 1

2D

ec 1

2Ja

n 13

Feb

13M

ar 1

3Ap

r 13

May

13

Jun

13Ju

l 13

Aug

13Se

p 13

marine cumulative value (USDm)(LHS) oils cumulative value (USDm)(RHS)

17


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Oilfield services – sector average P/E (based on FY1 consensus data) versus oil prices


Oilfield services – sector average EV/EBITDA (based on FY1 consensus data) versus oil prices


Oilfield services – sector average P/B (based on FY1 consensus data) versus oil prices


0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

160.0

0.0

5.0

10.0

15.0

20.0

25.0

30.0

Mar

-03

Sep-

03

Mar

-04

Sep-

04

Mar

-05

Sep-

05

Mar

-06

Sep-

06

Mar

-07

Sep-

07

Mar

-08

Sep-

08

Mar

-09

Sep-

09

Mar

-10

Sep-

10

Mar

-11

Sep-

11

Mar

-12

Sep-

12

Mar

-13

PE1 WTI Brent

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

160.0

0.0

2.0

4.0

6.0

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Mar

-03

Sep-

03

Mar

-04

Sep-

04

Mar

-05

Sep-

05

Mar

-06

Sep-

06

Mar

-07

Sep-

07

Mar

-08

Sep-

08

Mar

-09

Sep-

09

Mar

-10

Sep-

10

Mar

-11

Sep-

11

Mar

-12

Sep-

12

Mar

-13

EV/EBD1 WTI Brent

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

160.0

0.00.51.01.52.02.53.03.54.04.55.0

Mar

-03

Sep-

03

Mar

-04

Sep-

04

Mar

-05

Sep-

05

Mar

-06

Sep-

06

Mar

-07

Sep-

07

Mar

-08

Sep-

08

Mar

-09

Sep-

09

Mar

-10

Sep-

10

Mar

-11

Sep-

11

Mar

-12

Sep-

12

Mar

-13

PB1 WTI Brent

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The main changes in this report

We have made quite a number of changes in this

report – some reflecting a change in view across a

sub-sector (seismic pricing), some reflecting

stock-specific issues and updates after recent

contracts (Aker Solutions, Core Labs, BW

Offshore, SBM Offshore and Lamprell) and some

reflecting more a reaction to significant increases

(or falls) in share prices and, hence, where we see

a meaningful change in risk/reward (our ratings

changes with Kentz, Schlumberger and

McDermott). In more detail, our key changes are:

A weaker outlook for seismic marine

contract pricing and, therefore, for contract

margins in 2014e (plus a likely weaker end to

Q4 2013), in addition to a weaker multi-client

outlook in the near term (low prefunding

risks); our ratings on the main seismic names

remain positive, but our target prices fall to

EUR23 for CGG (from EUR27), NOK101

for PGS (from NOK111) and NOK220 for

TGS Nopec (from NOK242).

Downgrade Schlumberger to Neutral from

Overweight – we increase our target price

slightly to USD98 (from USD96) but no

longer see an attractive enough risk/reward

following a strong share price recovery

through late Q3.

Downgrade McDermott to Underweight (V)

from Neutral (V) – our target price remains

USD6.75, but we feel current share prices

offer little protection to the potential

risk/reward position of MDR through 2014,

particularly its commencement of offshore

work on the large Ichthys project.

Upgrade our Kentz rating, following the end

of the proposed M&A approach from

Amec/M+W and subsequent share price fall

in September; we raise our rating to

Overweight (V) from Neutral (V); target price

remains 615p.

Lower margins for Aker Solutions (some H1

problems persisting through H2) – we remain

positive on this name but cut our target price

slightly to NOK120 (from NOK125).

Higher assumed medium-term growth for

Core Labs, which drives our target price up

to USD180 from USD157.

Oilfield services – sub-sector share price performances year to date in 2013


-30.0%

-20.0%

-10.0%

0.0%

10.0%

20.0%

30.0%

40.0%

FPSO Chinese WellServices

Well Services OSV OFS Average Drilling Subsea andOilfield

Equipment

E&C Seismic

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Adjustment for recent major contracts and

contract extensions for the FPSO players BW

Offshore and SBM Offshore – our target

price for SBM moves up to EUR17 (from

EUR14.72) and for BWO it moves up to

NOK10 (from NOK9).

Update our assumptions for Lamprell to

reflect the pace of recent contract awards and

the likely competitive pressures in rig refurb

markets; we reduce our forecasts quite

materially but our target price falls less

aggressively to 150p (from 160p).

Key themes, stock screens and our preferred

names in oilfield services

Across our coverage, we do see a somewhat less

positive risk/reward balance than earlier in the

year – this is very much the message we intend to

send in this report with our downgrade of

Schlumberger to Neutral, the largest and most

global name under our coverage. From here we

think selectivity is absolutely key in finding

outperformance in this sector – in fact, the

opposite to our rule of thumb when the sector is

poised for a cyclical rebound, where we see the

most important choice being which stocks NOT to

own on the way up.

Our thought process at this stage has been to go

through a number of investment screens looking

at franchise quality, market share, returns (ROE),

restructuring potential, as well as overall valuation

versus historical trends and/or asset value (if

relevant). The “quality” screens are set up to

enable us to react if we see good quality appearing

at attractive valuations (although such

opportunities are currently lacking).

The net result of all these thoughts – which we

detail below – has been to end up with a selection

of names that are more biased to seeing value in

restructuring and under-appreciated growth than

to the largest franchises or market shares in the

sector (although most of these names have

franchises that are individually strong).

Our key names in oilfield services are:

Aker Solutions (TP NOK120) – potential for

significant strategic restructuring of its

portfolio around its core “jewels” of subsea

and MMO.

Subsea 7 (TP NOK155) – recovering from

problematic work in Brazil, but the market

leader in a strong sub-sector

(SURF installation).

Marine seismic in general – CGG (TP

EUR23), PGS (TP NOK101) and TGS (TP

NOK220) look oversold on Q4 and 2014

pricing concerns – seismic is still growing.

Transocean (TP USD67/CHF62) – the

cheapest (and largest) offshore rig fleet on the

market, although it is facing some older rig

utilisation concerns and the Macondo trial

remains in the background.

Also, we highlight our “under-appreciated

growth” category – this includes mid-cap

contractor Kentz (TP 615p, one of the few to

have an accelerating backlog) and from our

Asian OFS coverage Anton Oil (TP

HKD7.22, geared to strong potential growth

from Chinese E&P spending, plus a key

alliance/JV with Schlumberger).

Several of these names are, we think, likely to see

negative newsflow in the near term, but we

believe this is largely priced in and also –

importantly – we see significant potential upside

on a 12-month view. The restructuring candidates,

in particular, have strong potential to expand their

ROE over the medium term.

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The quality screen – ROE winners

In terms of sub-sectors, looking at consensus data

for the broader UK + EU + US + Asian names

across the industry, the strongest ROEs are with

the specialised equipment suppliers and with well

services (these ROEs are around 15-16%). Overall

average ROE for the entire sector for 2014 is

13%, and this is valued on around 2x book

(around average levels versus the sector’s

historical trend). The lowest ROE performers on a

sub-sector basis are seamless pipes, OSVs

(offshore support vessels) and subsea construction

(ROEs in the 7-11% range).

On a stock-by-stock basis, the strongest ROEs are

with Core Labs (a stand-out leader), then some

E&C names like CB&I, Petrofac, Kentz, and also

selected high-end manufacturers like FMC and

Rotork. The weakest ROEs are with some of the

under-pressure Asian shipyards and E&C names

(Rongsheng, GS E&C), the land drillers (eg,

Patterson UTI), some of the smaller North

American well services names (Key Energy and

Superior Energy) and some of the heavy asset

marine players that are either under pressure or

mid long-cycle investment (Farstad, Pacific

Drilling, Rowan). Seismic major CGG is also a

bottom-quartile ROE name, as is a recovering

Saipem and a restructuring McDermott.

From the stocks we have under coverage, there

are few red flags from this – the strongest

franchises tend to be reflected in the best ROEs –

although the comparisons can be more interesting

when we think about what the companies are

trying to achieve over the next few years. This

angle is really our favoured investment theme –

what interests us more and where we see more

potential for investors is with some strong (in

some cases leading) franchises that are currently

underperforming (or are part of a larger

underperforming portfolio) where there is the

potential for material improvement in returns (and

therefore in ROE) over the next one to two years.

Average ROE versus P/B for the main oilfield services sub-sectors (based on consensus 2014 data)

Source: Thomson Reuters Datastream, E&C = engineering & construction, OSV = offshore support vessels, FPSO = floating production storage and offloading

shipyards

FPSO

OSV

E&C

subsea construction

OFS equipment

subsea/offshore equipment

Offshore DrillersOnshore Drillers

seismic

seamless pipes

well services

OVERALL

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

0% 2% 4% 6% 8% 10% 12% 14% 16% 18%

P/B

(x)

ROE (%)

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This theme reflects well our liking for Aker

Solutions, CGG (and seismic in general – an

oversold sector), Transocean and Subsea 7, with

Kentz and Anton Oil more under-appreciated

growth plays.

The quality screen – market share winners

Out of our coverage stocks, the players with the

strongest market shares in specific businesses are:

FMC (40-50% market share in subsea

equipment manufacture & services).

FMC and Aker Solutions – dominant positions

in advanced subsea – processing, boosting,

separation – one of the key medium-term new

technology themes in subsea.

Core Labs – a unique franchise of reservoir

analysis and related services that is present in

one in four major wells worldwide, also

global #1 in well perforating guns (part of the

production enhancement division).

Fugro – the leading player with 80%+ market

share in offshore geotechnical and 40-50%

share in offshore survey services.

CGG – leading position in seismic equipment

with the Sercel business (60%+ market share).

NOV’s rig technology business (drilling

equipment & aftermarket services, 70%+

market share in drilling equipment for

deepwater floater rigs).

Technip’s Subsea business (60-70% market

share in flexible pipe manufacture, also

effectively a duopoly position in subsea

installation/flexlay).

Subsea 7 – the other major player in what is

effectively a duopoly in subsea/SURF

installation (flexlay work).

Saipem’s offshore division – part of a duopoly

in deepwater trunkline/gas pipeline pipelay

work (along with Allseas) and in top-end

heavy-lift work (along with Heerema).

Wood Group’s JP Kenny business – largest

market share in offshore engineering

(specifically subsea and riser systems).

Aker Solutions MMO division – 50% market

share in the Norwegian North Sea for

maintenance & modification work.

Schoeller Bleckmann – largest market share

in high-precision components (MWD/LWD)

for downhole tools and high-performance

drilling motors.

Schlumberger – “the” global blue-chip

provider of well services and associated

technology and services.

Out of all these businesses, the ones that stand out

to us in terms of risk/reward, given both the

medium-term market dynamic and the company

valuation, are Subsea 7’s SURF installation

franchise, Saipem’s Offshore business (one of the

reasons why we see potential in Saipem’s

recovering investment case), NOV’s rig tech

division (especially the structural growth prospects

this has in aftermarket services), Aker Solutions’

position in advanced subsea technology (an

important medium-term theme), and CGG’s Sercel

seismic equipment business (looking at improved

medium-term growth following the launch of major

new marine and land product offerings in 2013).

There are many other great businesses in this list,

but from an investment viewpoint we think they

look relatively fully priced, given the current

market environment.

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The restructuring screen

Given the current balance of risk/reward across

the sector, we do see somewhat more potential

with a restructuring or potential portfolio change

angle than with growth. The specific cases that

stand out to us are:

Aker Solutions – we see both internal process

improvement and portfolio restructuring as

possible in the medium term; both could drive

a major uplift to market perceptions of fair

value for this portfolio (particularly

highlighting the value of its high-end subsea

equipment and MMO franchise).

CGG – in the near term, we see some benefits

from the Fugro acquisition filtering through,

plus a continued restructuring of the

Acquisition business; in the longer term, we

think CGG will move to change (and

potentially move away from) the asset-heavy

and capital-intensive nature of its marine

acquisition business (potentially through

vessel sales or sale/lease structures).

Fugro – after announcing its new medium-term

strategy, Fugro’s growth aspirations are visible

down to a divisional level. The restructuring

angle is as much about changing the group’s

operational structure as it is about saving costs

– if it can deliver on the “OneFugro” strategy

then there is significant medium-term potential

from this franchise. But we see this playing out

over a distinctly medium-term timeframe; we

rate Fugro Neutral.

McDermott – a problematic portfolio with

several low-margin legacy projects plus

execution issues with current work, closure of

some yard operations in North America and the

challenge of trying to grow subsea expertise

with the giant Ichthys project looming in 2014.

We expect there are more restructuring moves

to come here – at present our view on

McDermott’s risk/reward balance is cautious

(we downgrade MDR to UW(V) in this report).

Saipem – still not out of the Algerian alleged

bribery situation and still reeling from a

number of major contracting issues onshore

and offshore, but “no new news” is good

news in terms of recent project execution. We

expect further restructuring in the medium

term once the Algerian situation is clear – we

think much of the long-term potential of

SPM’s franchise (especially the Offshore

business) is likely to re-emerge.

Measuring emerging market exposure across oilfield services (EM = Middle East, Asia, LatAm, Africa)

Source: Company data (NB based on 2012 data)

0%10%20%30%40%50%60%70%80%90%

100%

Lam

prel

l

BW O

ffsho

re

SBM

Offs

hore

Bour

bon

Offs

hore

Petro

fac

Kent

z

Saip

em

Tech

nip

PGS

Sead

rill

CG

G V

erita

s

Tran

soce

an

Schl

umbe

rger

FMC

Subs

ea 7

Cam

eron

Fugr

o

Nat

iona

l Oilw

ell V

arco

Woo

d G

roup

Cor

e La

bs

Aker

Sol

utio

ns

Hun

ting

Amec

Scho

elle

r-Ble

ckm

ann

% e

mer

ging

mkt

exp

osur

e (r

even

ues)

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Transocean – still not out of the Macondo legal

shadow, and facing some challenges with

utilisation for some of its older deepwater (not

ultra-deepwater) rigs as clients continue to show

preference for new, more efficient, more

capable and more HSE-compliant rigs. Last

year’s move to sell the old jackup fleet was one

step; we think more are possible with the

world’s largest rig fleet.

The emerging markets (EM) screen

One other simple screen we’ve looked at is to see

which companies have higher exposure to

emerging markets. This may sound overly

simplistic, but with more growth likely for

onshore and offshore E&P activity from Africa,

the Middle East, LatAm, Asia and Russia, we

think it is a reasonable reality check (although we

expect few surprises in terms of which companies

are positioned to grow more quickly or not).

There is also the angle that an increasing number

of EM investors can “invest in the company not

the listing”, so long as the stock in question has

60% or more exposure to emerging markets. By

definition, many of our stocks fit this criteria – in

fact, over all our covered stocks (even excluding

the ‘pure play’ EM names like the Chinese OFS

players), we see around 55-60% of revenues

coming from LatAm/Middle East/Africa and

Asia. The heavy asset players – eg, offshore

drillers – are harder to define as, of course, rigs

can move, but the mainstream names we’d

highlight with 60%+ EM exposure are:

Saipem, Technip, Petrofac, Kentz,

Schlumberger and Lamprell;

Also, potentially SBM Offshore, BW

Offshore and Bourbon (given the fleet

locations or weightings for these players tend

to move around less); and

The other global players – particularly

onshore + offshore equipment along with well

services – tend to have higher exposure to

North America (unconventional markets, in

particular) and the North Sea.

Oil services – overall revenue exposure to emerging markets

Source: Company data (NB based on 2012 data)

developed43%

Lat Am12%

Mid East and Africa32%

Asia ex AUS13%

Natu

ral Reso

urces &

En

ergy

Glo

bal E

nerg

y Eq

uip

men

t & S

ervices 15 O

ctob

er 2013

24

ab

c

Distribution of ratings across the key sub-sectors in oilfield services ( ↑= upgrade, ↑ = downgrade)


Seismic Drilling Engineering & Construction Subsea & Equipment supply vessels FPSOs Well Services

OW

/ O

W(V

)PGS Transocean Subsea 7 Aker Solutions Bourbon BW Offshore Anton Oilfield

CGG Kentz (↑) NOV

TGS Technip Hunting

Saipem HongHua

Ezra

Sinopec Engineering

N /

N(V

)

Seadrill Amec Cameron SBM Offshore Schlumberger (↓)

COSL Petrofac FMC Technologies Bumi Armada Fugro

Wood Group Schoeller Bleckmann Core Labs

Lamprell

UW

/ UW

(V) McDermott (↓) SPT

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Sub-sector: Seismic Stocks covered: CGG, PGS, TGS

Main sub-sector themes & momentum – “the

waiting game continues” is probably the most apt

phrase to describe seismic from an investor’s

viewpoint. The main companies are making

higher margins and more money than before, but

improvements remain moderate and financial

markets seem reluctant to believe that

improvements over the coming years will be

anything other than moderate as well. The years

that have passed since the trough in 2009/10 have

allowed ample time for sell-side estimates to ramp

up, and we think we are still in a subsequent phase

of “correction” to match the market.

This phase is not over – in this report we cut our

forecasts for CGG and PGS to reflect lower pricing

growth for 2014e (we had expected +7.5% but now

see a low single-digit increase on average over the

year). But this is not a new theme, and we think

2014 has more of a chance than previous years to

prove to be better than expected, particularly for

marine contract margins (although the higher

seasonality prevalent in seismic implies to us that –

in terms of business momentum – investing in

seismic is increasingly becoming a “first-half

trade” with all eyes on the summer season).

We covered our fundamental view on seismic in

our ‘Echo and the moneymen’ report, published

26 June 2013 on the back of the EAGE

conference in London – and our view has not

changed materially since then (although, as noted,

we now see less pricing improvement in 2014).

We still think the market has overly de-risked the

seismic space (asset heavy and asset light alike),

but we also recognise that the higher seasonality

in the marine cycle this time around (a result of,

amongst other things, a strong North Sea season

attracting 20-25 vessels) means that the “shoulder

quarters” of Q1 and Q4 are now more volatile.

Therefore, we do see risks that Q4/Q1 may

under-deliver versus expectations for contract

profitability and activity – we expect to hear more

about this short-term scenario in the Q3 results

season (starts on 18 October with Schlumberger/

WesternGeco). We’ve also seen some short-term

pressure on multi-client markets from this lower

vessel utilisation, with some (smaller) players

chasing work with very low prefunding.

But in the longer term, we still think this seismic

cycle will grow activity and expand margins. A

growing offshore rig fleet (floater fleet 25% larger

by 2016 versus 2012) is a key “known known”

that we think helps underpin the move into an

offshore era: Oil prices remain key for

Seismic: Relative share price chart since the start of 2013


-50.0%

-40.0%

-30.0%

-20.0%

-10.0%

0.0%

10.0%

20.0%

30.0%

Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13Average CGG ION PGS TGS Nopec Polarcus

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discretionary spend, but E&P activity continues to

grow, and we see ‘demand for data’ following,

catalysed by new multi-component technology

and a renaissance for the advisory multi-client

model. The market is also being helped by the

attractions of broadband/top-end seismic – uptake

has been very good, but we think oil companies

perhaps see less differentiation between which

broadband/high-end solution than you might

expect (it depends on the work in question, as the

very best needs particularly tough geological

targets to make it effective). We’d also note

several large multi-vessel contracts on the horizon

(one of which was awarded recently to CGG for

wide azimuth work in Angola, and more are out

for bid in Canada, Trinidad and Brazil); when

work commences, these are effectively likely to

remove vessels from the 2014 North Sea season,

tightening this market.

But despite marine supply looking under control

until 2016, we don’t think contract margins will

hit the dizzy heights of the last cycle, and we see a

more competitive market for seismic equipment.

And with the exception of the top-tier 3D vessels,

we think there are signs that the perception of

competitive advantage is shifting away from a

fully owned, asset-heavy model. We also see

signs that the uptake of seabed seismic is

growing; this has always been a highly priced but

high-quality option versus towed streamer

seismic, but its economic acceptance is becoming

closer. OBC (ocean bottom cable) seismic is

seeing some commoditisation; this is likely to

help improve its economic positioning.

A year of expectation management – much as in

previous years, 2013 began with a degree of

expectation that this, at last, could be a better year

for seismic versus market expectations. The first

line in the sand was PGS’s guidance for 2013

(given in mid-December 2012), which was broadly

in line with market expectations at that time. This

lack of surprise triggered a few weeks of relative

underperformance for PGS (and its peers), and

since then – for a range of reasons – the same

momentum has continued across this sub-sector.

CGG in particular suffered due to a weaker outlook

for Sercel margins, lower profitability in land

seismic and higher Fugro-related costs. Since then,

performance across the sector has been mixed –

some good margins (eg, PGS) but also some

lacklustre signs from key licence round events,

such as Brazil’s licence round with the presalt

Libra field (saw disappointing uptake from the

major international oil companies, in particular),

lacklustre feedback from major industry events

(eg, the EAGE conference in London in June) and

a lack of new activity in the Arctic (more a 2014

theme). More recently, post the SEG conference in

Houston, industry expectations for contract price

increases in 2014 seem to be moderating further,

and multi-client is seeing short-term competitive

pressures on prefunding in certain regions.

Free cash flow promising – our expectations for

peak-cycle contract margins in 2015 are below

those from the previous cycle – in terms of marine

contract pricing we assume +2.5% in 2014e, +5%

in 2015e and a moderate decline in 2016e – but

the period of improvement in profitability,

earnings and cash flow we see over the next few

years continues to support positive investment

ratings for most of the key seismic players we

cover. We see free cash flow/sales (free cash

margins) between 10-20% across our seismic

coverage, equivalent to high single-digit or low

double-digit free cash yields.

Stocks and changes in this report – versus our

broader sector coverage, all the seismic names

screen well in terms of potential upside (on our

12-month horizon). The main changes to the

fundamental assumptions we’ve made in this

report are lower prices for 2014e contract seismic

(hitting revenues and margins for PGS/CGG), and

27


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we lower forecasts for TGS following its recent

Q3 warning. Our preferred name is PGS (an

overly ‘cheap’ marine seismic pure play), but we

also see attractive risk/reward with CGG (cyclical

upside plus ‘self-help’ post the Geoscience deal),

and decent potential upside with multi-client

specialist TGS Nopec.

CGG (OW(V), TP EUR23 from EUR 27) – it is

something of an understatement to say that 2013

has not been the easiest year for CGG so far, but

for any increased risk there may be in the near term

(Q4 multi-client late sales, Q4 contract marine

pricing and the timing of order intake for Sercel),

we do still see decent opportunities for 2014 and

2015 that should help deliver stronger performances.

Sercel’s new product launches this year – multi-

component marine streamer plus the new range of

land acquisition equipment – bode well for future

growth (although this impact is likely to be weighted

towards H2 next year), and we see a moderate

cyclical tailwind pushing acquisition EBIT margins

towards the mid-teens % range by 2015e. We also

think CGG’s free cash flow profile should see

improvement in 2014/15e; we see 7% free cash

flow/sales in 2014e and 12% in 2015e (equivalent

to a free cash yield of over 15% for 2015e).

But the main issue with CGG – typifying the issue

for the sector in general – is the pace of likely

improvement (or lack of it) through next year. We

feel that the seasonal pricing downturn (through

Q4 2013 and Q1 2014) is likely to be worse than

usual; this, plus the delays in seeing major

contract work come to market (we’ve seen the

major contract award for CGG in Angola

announced, but are awaiting news from large

contract work in India, Canada, Brazil and so on)

means that we now think the contract marine

pricing environment CGG will experience over

next year as a whole will be more moderate than

we previously thought (low single-digit increase

at best, versus our earlier expectation of +7.5%).

We still expect a significantly stronger summer

season (North Sea driven) but the “shoulder

quarters” are likely to drag the annual average

lower (particularly Q1 2014). This means for our

assumptions we use only a small increase in

pricing for 2014e versus 2013e, and we also

assume overall acquisition EBIT margins are

around 10% (higher margins in the marine side,

but breakeven from the land business). We also

assume relatively limited profitability from the

SeaBed JV (echoing our assumptions for

Fugro – which owns 60% of this JV). The net

effects of these changes are slightly negative for

this year, but are more materially negative for

2014e. Our valuation for CGG is also impacted –

our target price is cut to EUR23 from EUR27

(down 15%). On our new numbers, CGG trades

on around 10x 2014e EPS and around 4x 2014e

EBITDA (our target price would see it on 2014e

multiples of around 15x EPS and 5x EBITDA).

Overall for CGG, the long-awaited seismic

recovery remains mostly long awaited, but its own

internal improvements are becoming more evident

(aiming to improve acquisition margins as well as

move the group to being more capital light –

potentially looking at the ownership structure of

CGG: Changes to key P&L forecasts (USDm, EPS in USD)

CURRENT FY2012a FY2013e FY2014e FY2015e

Sales 3,412.0 4,259.0 4,612.6 5,239.0 EBITDA 1,010.0 1,345.1 1,470.1 1,811.1 EBIT 365.6 525.6 692.3 980.6 Net 74.2 252.6 354.2 590.6 EPS 0.80 1.45 2.00 3.33

PREVIOUS FY2012a FY2013e FY2014e FY2015e Sales 4,259.0 4,852.5 5,339.0 EBITDA 1,369.7 1,671.4 1,927.2 EBIT 550.2 841.8 1,074.6 Net 271.5 462.8 656.1 EPS 1.55 2.61 3.70

change (%) FY2012a FY2013e FY2014e FY2015e Sales 0.0% -4.9% -1.9% EBITDA -1.8% -12.0% -6.0% EBIT -4.5% -17.8% -8.7% Net -7.0% -23.5% -10.0% EPS -6.9% -23.5% -10.0%

Source: Company data, HSBC forecasts for 2013e onwards

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its vessel fleet, we think). Plus in the medium

term, we see the multi-client/geoscience franchise

and Sercel continuing to supply growth, even if

the seismic industry itself does not supply as

much pricing leverage over 2014/15e as many

expected. CGG has underperformed in recent

weeks, and although there will probably still be

some downwards pressure on consensus estimates

in the near term, we see a share price of around

EUR15 as discounting a much worse scenario

than that most might fear. We look forward to the

group’s planned capital markets day in November

(likely around the 20th) to hear more about

guidance and the longer-term plans to reduce

capital intensity and increase growth.

CGG: Share price chart YTD in EUR per share


PGS (OW(V), TP NOK101 from NOK111) – as

the owner of the largest and most cost-effective

vessels in the marine seismic industry, PGS

continues to be well placed to grow with the

gradual (but structural) expansion in top-end

marine seismic work. Its best-in-class fleet is

taking several further steps forward with the

arrival to market of the new W-Class Ramforms

(this year and 2015). PGS has already seen a

higher-margin performance than any other player

(reported 30% contract margins in H1), and we

expect this spread versus its peers to continue. As

at mid-September, PGS also had decent vessel

bookings for the next few quarters (75-80% for

Q4, 50% for Q1 2014 and 30% for Q2 2014).

PGS’s main challenge has – for a while – been the

relative exuberance of market expectations; we

think this risk has gradually lessened through

2013, but with expectations for pricing and

profitability taking yet another step down across

the industry, we believe this downwards trend is

not quite over. Cash flow pre capex looks strong,

although PGS’s real free cash flow story starts in

2014e and ramps up in 2015e once newbuild

payments lessen (we see free cash flow/sales of

over 10% for both years; at current share prices

this is around a 8% free cash yield).

PGS: Sales leads and active tenders (up to end August)

Source: PGS

We make several changes to our assumptions for

PGS to reflect our changing view on the pace of

improvement in the industry. We assume lower

top-line growth for 2013/14e/15e reflecting

weaker pricing (we now assume low single-digit

pricing growth on average over the whole year)

and slightly lower margins for 2014/15e contract

work. We also assume lower multi-client

prefunding to reflect the competitive environment

(more a temporary effect in Q4/Q1) – we assume

the same level of multi-client capex and the same

degree of growth for late sales (apart from for

2013, where we’ve reduced our forecast late sales

to reflect industry trends). We also factor in

USD/NOK5.95 versus 5.90 before.

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These changes hit our forecasts for 2014/15e by

9-12%, and we also cut our target price to

NOK101 from NOK111 (down 9%). On our new

forecasts, PGS trades on 2014e multiples of only

6-7x EPS, 3x EBITDA and around 1x book –

distinctly low end versus its historical range. In

terms of free cash flow, we see PGS generating

around USD350m of free cash in 2014e and

2015e, equivalent to a free cash yield of around

7% at current share prices.

PGS: Share price chart YTD in NOK per share


PGS: Key P&L changes (USDm, EPS in USD)

CURRENT FY2012a FY2013e FY2014e FY2015e

Sales 1,518.5 1,648.7 1,869.6 1,859.5 EBITDA 778.1 867.9 1,006.6 1,030.9 EBIT 293.8 432.0 541.9 588.4 EPS 0.96 1.41 1.75 1.84

PREVIOUS FY2013e FY2014e FY2015e Sales 1,699.6 2,007.2 1,965.2 EBITDA 913.0 1,100.2 1,110.9 EBIT 449.5 609.6 639.5 EPS 1.47 1.98 2.03

change (%) FY2013e FY2014e FY2015e Sales -3.0% -6.9% -5.4% EBITDA -4.9% -8.5% -7.2% EBIT -3.9% -11.1% -8.0% EPS -4.0% -11.6% -9.3%


TGS (OW(V), TP NOK220 from NOK242) –

this pure-play multi-client story looks well placed

to grow further, although its progress in 2013 has

suffered during H2 due to delays in permitting for

major projects offshore Australia (environmental

protests delaying the issuing of permits – TGS did

three large 3D surveys in this area in 2012 but none

to date in 2013) and higher competition in the North

Sea (especially Barents Sea) from certain industry

players. This latter theme has become more

apparent as the industry moves out of the typical

North Sea season – some players are running

additional multi-client work well into Q4 with low

levels of prefunding (reflecting that some seismic

vessel owners – especially the smaller names –

have relatively low levels of vessel utilisation

booked for contract work in the near term).

But Q4 problems aside, we think the multi-client

model has further to run in this cycle, with signs

of a structural uptick in acceptance of its

"advisory heavy" multi-client model. Market

growth expectations have come back for TGS as

well through this year (particularly after the minor

Q2 warning and the more recent update), and we

now see a more realistic outlook.

We don't expect multi-client to grow at the 15% clip

it managed over the past 12-15 years, but we do see

a market capable of high single/low double-digit

growth over the medium term, although growth in

2014e is likely to be a closer match to overall E&P

spending (so mid-single-digit increases). We think

there should be some upside to this underlying

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TGS: Key P&L changes (in USD,, EPS in USD)

CURRENT FY2012a FY2013e FY2014e FY2015e FY2016e

Sales 932.2 844.0 955.0 1,038.1 923.9 EBITDA 802.1 707.8 809.7 864.0 779.4 EBIT 402.3 362.9 415.4 430.8 369.6 net 284.9 252.9 294.1 306.4 268.5 EPS 2.72 2.42 2.81 2.93 2.57

PREVIOUS FY2013e FY2014e FY2015e FY2016e Sales 989.7 1,096.9 1,182.4 1,053.8 EBITDA 843.2 933.9 988.0 892.4 EBIT 425.6 477.2 490.7 421.5 net 296.2 336.5 348.0 305.5 EPS 2.83 3.22 3.33 2.92

change (%) FY2013e FY2014e FY2015e FY2016e Sales -14.7% -12.9% -12.2% -12.3% EBITDA -16.1% -13.3% -12.6% -12.7% EBIT -14.7% -12.9% -12.2% -12.3% net -14.6% -12.6% -11.9% -12.1% EPS -14.6% -12.6% -11.9% -12.1%


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growth rate if TGS’s plans for large projects in

Australia come through in H1 2014 (which is TGS’s

expectation). This should support strong cash flow

generation for TGS. We see free cash flow/sales in

the 14-19% range for both 2014e and 2015e; at

current share prices, this is equivalent to a free cash

yield of around 5% for 2014e and 7% for 2015e.

Post TGS’s recent warning about delayed work in

Australia and ongoing (low prefunded) competition,

we’ve taken our forecasts down to be more in line

with its guidance (which is now for 2013 revenues

of USD810-870m, versus USD920m-1bn

previously, and for multi-client capex of USD400-

440m, down from USD520-590m before). We now

see multi-client investment moving back up to

around the USD510m level for 2014e (as the

Australian work comes through). The net effect of

these changes is to lower our forecasts by around

12% (for 2014e onwards). This could prove a

cautious assumption for 2014e if the Australian

work is all active, and the rest of the market grows

in the mid-high-single digit range, but we prefer to

be on the cautious side (and our multi-client capex

assumption matches this). The overall effect on our

fair value is similar to that on our EPS – our target

price falls to NOK220 from NOK242 (we also now

assume USD/NOK at 5.95 versus 5.90 previously).

Seismic sub-sector- EV/EBITDA one-year forward Seismic sub-sector- PE one-year forward


TGS: Share price chart YTD in NOK per share


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Mainstream seismic – progression of profitability (EBIT/sales), 2004-Q2 2013

Source: Company data

Mainstream seismic – quarterly y-o-y progression for revenues – multi-client, contract and overall


Mainstream seismic – multi-client libraries – book value progression, Q1 2007-Q2 2013


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CGG PGS TGS Nopec WesternGeco Veritas Fugro Geoscience average EBIT/sales (%) Wavefield Dolphin Geo

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Financials & valuation: CGG Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e

Profit & loss summary (USDm)

Revenue 3,412 4,259 4,613 5,239EBITDA 1,010 1,345 1,470 1,811Depreciation & amortisation -659 -819 -778 -830Operating profit/EBIT 366 526 692 981Net interest -159 -207 -212 -212PBT 190 377 523 852HSBC PBT 246 381 523 852Taxation -99 -105 -149 -243Net profit 74 253 354 591HSBC net profit 130 257 354 591

Cash flow summary (USDm)

Cash flow from operations 1,085 861 976 1,244Capex -733 -768 -707 -625Cash flow from investment -733 -2,035 -707 -625Dividends 0 0 0 0Change in net debt -626 1,178 -269 -619FCF equity 95 88 251 577

Balance sheet summary (USDm)

Intangible fixed assets 3,350 3,891 3,910 3,830Tangible fixed assets 1,160 1,835 1,745 1,619Current assets 3,473 3,336 3,693 4,543Cash & others 1,520 1,072 1,341 1,960Total assets 8,333 9,636 9,923 10,567Operating liabilities 985 1,306 1,238 1,292Gross debt 2,305 3,035 3,035 3,035Net debt 785 1,963 1,694 1,076Shareholders’ funds 4,493 4,746 5,100 5,691Invested capital 5,478 6,683 6,769 6,741

Ratio, growth and per share analysis

Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 7.2 24.9 8.3 13.6EBITDA -14.3 31.4 9.3 23.2Operating profit -35.1 43.9 31.7 41.6PBT -53.1 98.1 39.0 62.8HSBC EPS -63.0 81.2 38.0 66.7

Ratios (%)

Revenue/IC (x) 0.6 0.7 0.7 0.8ROIC 3.2 6.2 7.4 10.4ROE 3.1 5.6 7.2 10.9ROA 2.2 4.7 5.4 7.4EBITDA margin 30.0 31.6 31.9 34.6Operating profit margin 10.7 12.3 15.0 18.7EBITDA/net interest (x) 6.4 6.5 6.9 8.5Net debt/equity 17.1 40.5 32.6 18.6Net debt/EBITDA (x) 0.8 1.5 1.2 0.6CF from operations/net debt 138.3 43.9 57.6 115.6

Per share data (USD)

EPS Rep (fully diluted) 0.45 1.42 2.00 3.33HSBC EPS (fully diluted) 0.80 1.45 2.00 3.33DPS 0.00 0.00 0.00 0.00Book value 27.50 26.75 28.74 32.07

Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 1.3 1.3 1.2 0.9EV/EBITDA 4.4 4.2 3.7 2.6EV/IC 0.8 0.8 0.7 0.7PE* 26.1 14.4 10.4 6.3P/Book value 0.7 0.8 0.7 0.6FCF yield (%) 2.5 2.3 6.1 14.1Dividend yield (%) 0.0 0.0 0.0 0.0

Note: * = Based on HSBC EPS (fully diluted)

Issuer information

Share price (EUR)15.43 Target price (EUR)23.00 4

9.1

Reuters (Equity) GEPH.PA Bloomberg (Equity) CGG FPMarket cap (USDm) 3,711 Market cap (EURm) 2,729Free float (%) 100 Enterprise value (USDm) 5271Country France Sector Energy EquipmentAnalyst David Phillips Contact 44 207 991 2344

Price relative

Source: HSBC Note: price at close of 08 Oct 2013

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2011 2012 2013 2014CGG Rel to SBF-120

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Financials & valuation: Petro-Geo Services (USD) Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 1,519 1,649 1,870 1,860EBITDA 778 868 1,007 1,031Depreciation & amortisation -484 -436 -465 -443Operating profit/EBIT 294 432 542 588Net interest -38 -38 -45 -50PBT 228 394 495 537HSBC PBT 259 394 495 537Taxation -43 -88 -116 -138Net profit 186 306 380 400HSBC net profit 208 306 380 400


Cash flow from operations 737 672 803 841Capex -656 -868 -657 -677Cash flow from investment -656 -868 -657 -677Dividends -87 -130 -152 -163Change in net debt 15 262 93 -22FCF equity 89 -179 163 167


Intangible fixed assets 283 283 283 283Tangible fixed assets 1,820 2,252 2,444 2,419Current assets 837 707 817 1,119Cash & others 390 194 124 146Total assets 3,274 3,576 3,879 4,155Operating liabilities 397 457 508 548Gross debt 917 982 1,006 1,006Net debt 527 789 881 859Shareholders’ funds 1,922 2,098 2,326 2,564Invested capital 2,152 2,591 2,912 3,127


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 21.2 8.6 13.4 -0.5EBITDA 44.3 11.5 16.0 2.4Operating profit 107.9 47.1 25.4 8.6PBT 248.1 72.6 25.6 8.5HSBC EPS 325.9 47.1 24.0 5.2

Ratios (%)




Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 1.9 1.9 1.7 1.7EV/EBITDA 3.7 3.7 3.3 3.2EV/IC 1.3 1.2 1.1 1.0PE* 11.9 8.1 6.5 6.2P/Book value 1.3 1.2 1.1 1.0FCF yield (%) 3.3 -6.8 6.2 6.3Dividend yield (%) 3.5 5.3 6.1 6.6


Issuer information

Share price (NOK)67.95 Target price (NOK)101.00 4

8.6

Reuters (Equity) PGS.OL Bloomberg (Equity) PGS NOMarket cap (USDm) 2,486 Market cap (NOKm) 14,800Free float (%) 100 Enterprise value (USDm) 3108Country Norway Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

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Financials & valuation: TGS NOPEC Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 932 844 955 1,038EBITDA 802 708 810 864Depreciation & amortisation -400 -345 -394 -433Operating profit/EBIT 402 363 415 431Net interest 5 6 8 10PBT 408 364 423 441HSBC PBT 407 369 423 441Taxation -123 -111 -129 -134Net profit 285 253 294 306HSBC net profit 284 257 294 306


Cash flow from operations 663 593 671 725Capex -509 -447 -537 -524Cash flow from investment -492 -447 -537 -524Dividends -103 -103 -138 -155Change in net debt 12 -43 4 -46FCF equity 110 163 115 195


Intangible fixed assets 167 167 167 167Tangible fixed assets 683 786 929 1,020Current assets 801 812 858 941Cash & others 342 385 381 427Total assets 1,686 1,800 1,989 2,163Operating liabilities 404 403 453 493Gross debt 0 0 0 0Net debt -342 -385 -381 -427Shareholders’ funds 1,168 1,283 1,423 1,557Invested capital 905 977 1,120 1,208


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 53.2 -9.5 13.1 8.7EBITDA 64.1 -11.8 14.4 6.7Operating profit 67.3 -9.8 14.5 3.7PBT 68.3 -10.8 16.3 4.2HSBC EPS 66.3 -9.7 14.6 4.2

Ratios (%)

Revenue/IC (x) 1.2 0.9 0.9 0.9ROIC 34.0 28.2 28.4 26.2ROE 26.6 20.9 21.7 20.6ROA 18.9 14.5 15.5 14.8EBITDA margin 86.0 83.9 84.8 83.2Operating profit margin 43.2 43.0 43.5 41.5EBITDA/net interest (x) Net debt/equity -29.3 -30.0 -26.8 -27.4Net debt/EBITDA (x) -0.4 -0.5 -0.5 -0.5CF from operations/net debt



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


9.2

Reuters (Equity) TGS.OL Bloomberg (Equity) TGS NOMarket cap (USDm) 2,564 Market cap (NOKm) 15,268Free float (%) 100 Enterprise value (USDm) 2179Country Norway Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

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Sub-sector: Offshore drilling Stocks covered: 2883 HK (COSL), RIG, SDRL

Main sub-sector themes – offshore drilling

continues to be one of – if not the – strongest sub-

sectors in oilfield services. Newbuild activity has

continued through 2013, although not at the pace

seen in H1 2011 and the orderbook has seen

somewhat more interest in ordering new (and

harsh environment) jackups than floaters.

Offshore drilling – recent/planned deliveries of new-build rigs

Delivery year Drillship Semis Jackup

2013-delivered 8 25 0 2013-under construction 13 1 26 2014 21 4 30 2015 17 9 49 2016 11 6 13 Beyond 2017 15 4 1

Total 77 24 119

Source: ODS-Petrodata (as at End Sep 2013), Drillships for delivery after 2016 are mostly planned and are from Petrobras]

In simplistic terms, offshore drilling has two

categories where the entire fleet is relatively new

and growing, thanks to continued newbuild

investments (ultra-deepwater floaters and large

harsh environment jackups), one category where

the fleet is relatively old, is seeing some

retirements but little newbuild investment (older

midwater/non-ultra-deepwater floaters) and one

category where the fleet is relatively old but is

seeing significant retirements and newbuild

investments (standard jackups).

Ultra-deepwater rig markets look to be very

much in a “stronger-for-longer” cycle; despite the

delivery of a significant number of newbuilds to

market through 2012/13. Underlying market

demand continues to be strong enough to absorb

these new rigs coming to market, and we think

this dynamic is likely to continue, although we

also expect ultra-deep rates to remain range-

bound between USD550-625,000/day and in some

cases to move towards to lower end of this range.

We’d note recent data (from IHS/ODS Petrodata)

that shows out of the over 90 newbuild floaters

due to market over the next few years, the number

of available units continues to decrease and is

now around 25-30 rigs (11 available in 2014 and

the remainder for 2015/16).

This reflects genuine demand growth in ultra-

deepwater work as well as a structural preference

for new and up-to-date rigs. This latter theme we

term ‘offshore asset divergence’(others tend to

prefer the phrase ‘market bifurcation’) and is

something we have written about since mid-2011

when it started to become evident that newer, more

capable, more efficient and more HSE-compliant

Offshore drillers: Relative share price chart since the start of 2013


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vessels of many categories – not just drilling –

were starting to see a preference for their use from

oil companies. We expect this to continue – the

contracting opportunities we see over the near and

medium term for new and up-to-date rigs will

continue to be superior to that of older units, both

in terms of dayrates and contract duration. This

also means the overall supply dynamics for certain

categories of rigs are probably tighter than they

appear on paper – eg, currently the majority of

ultra-deepwater rigs are actually working on non-

ultra-deepwater work.

Current drilling activity for the ultra-deepwater fleet

Source: IHS/ODS Petrodata

Yard prices – particularly from the Korean yards

– remain relatively low for ultra-deepwater

floaters. ‘Nameplate’ newbuild prices were

around USD600m back in 2011 and showed signs

of improvement through 2012, but 2013 has seen

offered prices move down once again to around

(or slightly below in some cases) the USD600m

level. So the “opportunity” for a drilling

contractor is still there to order rigs at 2006 prices

that are significantly better equipped than those in

2006. We would note, however, that the

“delivered cost” of a new unit is somewhat greater

than those quoted from the yards (that refer to

what we term ‘empty rigs’) – including all spares

& equipment, the cost is, we think, more like

USD650-700m.

Also, floater rig specifications continue to move

up – partly in response to safety and regulatory

requirements (where post-Macondo standards are

being rolled out across the world, especially

where the major Western oil companies operate),

and partly in response to growing needs for

handling high-pressure/high-temperature

reservoirs and harsh environments (eg, we’d note

Statoil’s work with Inocean to design an

arctic-class drillship – its ‘Cat I’ model).

There are still opportunities in the market for

older floaters and older jackups, but we expect

these will likely – gradually – prove more and

more limited over the medium term. In this case,

the old theme of ‘a rising tide lifts all boats’ has

proved only partially true, and those drilling

companies that have significant fleets of older rigs

do face ongoing strategic challenges as to their

long-term upkeep (higher opex, classing surveys,

decreasing attractiveness to oil clients, decreasing

second-hand market value). Transocean disposed

of its fleet of standard jackups to privately owned

Shelf Drilling mid-2012, Noble Corp has

announced its intention to spin off its older floater

& jackup rigs into a new company and,

seemingly, the only major drilling company

drilling >6500 ft

21%

drilling <6500 ft

46%

(unknown)33%

Newbuild investment economics – ultra-deep floaters, jackups and tender rigs

Rates/returns Ultra-deep Jackups Tender rigs

Dayrate (USD/d) 550,000 160,000 170,000 Opex incl G&A (USD/d) 170,000 60,000 60,000 Tax (% of revenues) 4.00% 4.00% 4.00% Five-year cash flow (USDm) 605 140 223 Investment/cost (USDm) 600 210 200 Repayment period (yrs) 5.0 6.7 5.5 ROE 49% 32% 39%

Source: Seadrill (as stated at Q1 2013)

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without these challenges is Seadrill (with what is

the industry's most modern large fleet of jackup &

floater rigs).

Jackups – the jackup rig segment has seen a

mixture of all of these themes. An improving

cycle has – over the past 12-18 months – brought

work to many older units that were stacked a

couple of years ago. Modern standard jackups are

capable of securing dayrates in the USD160-

180,000/day range now, and better in some

markets, giving good newbuild returns. These

returns/payback periods are not as strong yet as

those in the ultra-deepwater floater category, due

in part to the stronger pricing power of the rig

builders – in this case mostly the Singapore yards,

although Chinese yards like COSCO Dalian are

building some reputation for constructing modern

jackup units (have built several for Seadrill).

There also have been a significant number of

older rig retirements and parallel investments in

more up-to-date newbuilds (of a variety of designs

– some LeTourneau, some F&G, some larger

Keppel-designed units), and there has also been a

clear theme of ordering rigs capable of handling

harsh environment/North Sea work.

The harsh environment market – both for

floaters and jackups – remains under-supplied in

the medium term (and rig rates are strong – both

UK and Norwegian regions), even to the point

that Statoil is pursuing its own bespoke designed

units that it plans to own. There was a boom in rig

building for this environment in the 1980s but

these rigs – which the market relies on – make up

2/3 of the fleet and are around 30 years old (and

are set up more for exploration drilling than

production work).

Statoil’s plans for the NCS see a major step-up

in drilling work – especially completion and

intervention – and around 125 wells per year in

2015/16 versus around 70 in 2012 (and 107 in

2008). The growth in this drilling activity has to

come from mobile units (see the 125 wells split

roughly into 25 from fixed platforms, 70

production wells from mobile drilling units and 30

for exploration work).

These needs – and the perception that the market

will likely be short of the right sorts of units – led

Statoil to work towards these ‘category’ designs

(a deliberate effort to standardise ‘fit for purpose’

designs for intervention and full scale drilling).

The designs are derivatives of accepted modern

designs – eg, the Category J jackup is a modified

CJ-70 Gusto model, and the Category D midwater

semi-sub is a modified GVA 4000. We think that

Seadrill’s and Maersk Drilling’s harsh environment

jackups are quite similar but just not quite as robust

in physical design (Statoil’s designs need to handle

both drilling and subsea completion).

Also, Statoil’s view was (and is) that it is hard to

structure very long-term lease contracts with the

drilling contractors (which would be its

preference, but driven more by the field licence

structure than Statoil itself), and rig-owners are

Jackups – market segmentation and descriptions

Jackup era Mat/slot rigs Legacy rigs ‘New’ jackups High-spec jackups

Build vintage 1970s 1980s 2005 onwards Mostly 2005 onwards Capability Smaller rigs, basic vertical

wells, most rigs centred on the US Gulf

Wide range of quality and upgraded/non-upgraded rigs; can handle most standard work

Overall similar in scope to 1980s rigs but newer tech, better HSE, more efficient

Harsh environment, leading drilling tech, larger units/ higher horsepower, often more bespoke designs

Current market situation Roughly 1/2 the fleet is cold stacked; structural decline of US shallow-water gas work

Typical utilisation rates around 70-80%

Good utilisation rates (90%+), fleet mostly at work/under contract

Fleet fully utilised; premium rates versus other new classes of rigs

Typical dayrates USD30-45,000 USD70-100,000 USD120-150,000 USD150-250,000

Source: HSBC

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likely to want the flexibility to move a rig around

the world over its lifetime. Therefore, ownership

of the units could be better suited (in some cases)

to be from the operator than from the contractor

side, although this over-simplifies the situation.

Statoil’s view is that ownership is best matched

where a specific (and bespoke) rig can be tied to a

long-life field licence – so far it has done this for

two jackup units (Cat J rigs).

The various categories break down into:

Cat A – light well intervention based on a

semi-sub or ship-shape vessel concept

(Ulstein design) – will see some news on this

in Q4 2013;

Cat B’s – the (infamous) unit that was

cancelled (contract with Aker Solutions) –

aim is to do light well intervention, coiled

tubing work and heavier intervention jobs (we

expect this concept to return);

Cat C – more 'conventional designs' to have a

unit to do well intervention (light + heavy) as

well as some exploration/workover drilling;

Cat D – the ‘workhorse’ design for midwater

drilling, focusing on production work and

designed to be "Barents Sea ready" (four units

are under construction at DSME in Korea, with

the contractor being Songa) – Statoil’s view is

that this is probably the ‘best’ and most useable

design in the series so far;

Cat F – 'flotel', ie, floating accommodation

(two are under construction in Singapore);

Cat I – ice-class drillship – this is the new

model, currently in feasibility studies and the

early design competition was won by Inocean

in September this year (has to be able to

handle 2m of ice thickness; the aim is to have

the unit delivered in 2018); and

Cat J – production-drilling-focused jackup

rigs (based on the CJ-70 modified design),

three are under construction, two to be owned

by Statoil (being built at Samsung in Korea)

and one by Noble (being built in Singapore –

will be on a four-year contract (plus options)

with an implied dayrate of USD447k/day,

including mobilisation costs).

Main stocks and changes in this report – we do

not make any changes to our assumptions for the

drilling-exposed companies we cover in this report.

Our overall investment stance on the drilling space

has a more neutral balance, mainly as we see less

upside potential for rig rates in the next few years

(while the market absorbs a significant wave of

newbuild deliveries). The main opportunity we see

at a stock level is with Transocean, where the stock

continues to trade at a material discount to its fleet

market/replacement value.

COSL (N, TP HKD19.6) – three things have led

us to a more positive outlook for COSL since we

upgraded to Neutral after the 1H13 results (see

‘Strong drilling segment trumps all’,

20 August 2013) including better margin trends in

the drilling segment, additional jack-up purchases

and a favourable settlement of Norwegian tax

dispute. COSL purchased two jackups in August

2013, lifting the jackup rig total to 30. Financial

contributions from COSL Hunter and COSL Gift

are expected in 2014. The company’s deleveraging

process has started, with net gearing at 59.8% in

1H13 compared with 60.9% at the end of 2012 and

68.6% in 1H12. The company should have more

financial capacity to spend on capital expenditure.

Over 2012-15e, we forecast an 11% revenue

CAGR driving a 15% EBIT CAGR and 18% net

income CAGR, with our only restraint that the

shares look relatively fully valued despite the

positive directional trends in the P&L.

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COSL: Share price chart YTD in HKD per share -


Seadrill – (N, TP NOK280/USD47.5) – we

downgraded Seadrill to Neutral in July to reflect our

view that, despite the group’s strong industry

position, the level of further surprise potential

versus market expectations was for now rather more

limited (see ‘Reaching maximum drill depth’,

26 July 2013). We think dividends will continue to

grow – potentially more strongly in the medium

term than in the next few quarters (we’d note

SDRL’s aim for a run-rate EBITDA of USD4bn by

H1 2015) – and we see further corporate actions on

the horizon in the shape of the planned listing of

North Atlantic Drilling (NADL) in the US, and the

potential injection of further assets into Seadrill’s

US-listed MLP. We also think the group will

continue to secure decent financing for its newbuild

plans and good contracts for its yet-to-be-delivered

rigs, but we believe valuations are largely up with

events for now.

Transocean – (OW(V), TP USD67/CHF62) –

continues to be the name in this sub-sector where

we see the most value, albeit in the longer term.

RIG’s strategic challenges remain – sorting out

the longer-term strategic future of its older floater

units, ensuring good operational uptime with its

large fleet of ultra-deepwater capable units (which

drive over 60% of its replacement/market value

and EBITDA on our numbers) and handling the

ongoing legal investigation into the 2010

Macondo spill (the trial has now entered its

second phase). And in the near term, the group

does face some 'in-between contract' downtime

with some of its older deepwater floaters (this was

a theme mentioned in the Q2 conference call). But

overall we continue to see a marked disconnect

between RIG's equity value and the likely market

value of its fleet; part of this is, we think, due to a

lack of investor interest in the larger US-listed

drillers, and part due to legacy fears over what the

Macondo trial could bring (RIG settled with the

US DoJ earlier this year for USD1.4bn covering a

guilty plea for violating the US Clean Water Act).

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Seadrill: Share price chart YTD in NOK per share


Transocean: Share price chart YTD in USD per share


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Offshore drillers sub-sector: EV/EBITDA one-year forward Offshore drillers sub-sector: PE one-year forward


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Offshore drilling – average dayrate trends (USD/d) for jackup rigs, 2001-present

Source: IHS / ODS Petrodata

Offshore drilling – average dayrate trends (USD/d) for ultra-deepwater rigs, 2001-present


Offshore drilling – average utilisation rates across the main rig classes, 2001-present


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Financials & valuation: China Oilfield Services Neutral Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e

Profit & loss summary (CNYm)

Revenue 22,279 26,869 29,283 30,860EBITDA 9,035 10,508 11,555 12,513Depreciation & amortisation -3,173 -3,251 -3,359 -3,503Operating profit/EBIT 5,862 7,257 8,196 9,010Net interest -385 -514 -398 -312PBT 5,437 7,036 8,117 9,035HSBC PBT 5,437 7,036 8,117 9,035Taxation -867 -985 -1,461 -1,626Net profit 4,559 6,041 6,646 7,398HSBC net profit 4,559 6,041 6,646 7,398

Cash flow summary (CNYm)

Cash flow from operations 8,739 11,225 9,886 10,966Capex -8,415 -5,000 -6,000 -6,000Cash flow from investment -8,415 -5,000 -6,000 -6,000Dividends -809 -1,394 -1,815 -1,997Change in net debt 1,091 -4,832 -2,070 -2,970FCF equity 3,187 2,086 3,825 4,519

Balance sheet summary (CNYm)

Intangible fixed assets 4,235 4,235 4,235 4,235Tangible fixed assets 47,447 49,196 51,837 54,334Current assets 16,968 21,461 24,255 27,557Cash & others 9,815 14,646 16,717 19,686Total assets 69,159 75,401 80,835 86,635Operating liabilities 7,385 8,970 9,564 9,952Gross debt 33,370 33,370 33,370 33,370Net debt 23,555 18,724 16,653 13,684Shareholders’ funds 32,205 36,863 41,703 47,104Invested capital 51,449 51,276 54,046 56,488


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 20.2 20.6 9.0 5.4EBITDA 9.8 16.3 10.0 8.3Operating profit 13.7 23.8 12.9 9.9PBT 13.0 29.4 15.4 11.3HSBC EPS 12.9 32.5 10.0 11.3

Ratios (%)


Per share data (CNY)


Key forecast drivers

Year to 12/2012a 12/2013e 12/2014e 12/2015e

Jack-up avg realised day rate 108,000 118,800 124,740 130,977Semi-sub avg realised day rate 298,000 328,000 330,000 330,000Jack-up utilisation rate (%) 95 95 95 95Semi-subs utilisation rate (%) 95 93 93 93

Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information

Share price (HKD)20.40 Target price (HKD)19.60 -

3.9

Reuters (Equity) 2883.HK Bloomberg (Equity) 2883 HKMarket cap (USDm) 11,998 Market cap (HKDm) 93,045Free float (%) 32 Enterprise value (CNYm) 91664Country China Sector ENERGY EQUIPMENTAnalyst Thomas Hilboldt Contact +852 2822 2922

Price relative


6

11

16

21

26

31

6

11

16

21

26

31

2011 2012 2013 2014China Oilfield Services Rel to HSCEI

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Financials & valuation: Transocean Inc Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 9,196 9,658 10,734 11,464EBITDA 2,808 3,616 4,444 4,902Depreciation & amortisation -1,123 -1,111 -1,181 -1,261Operating profit/EBIT 1,685 2,506 3,263 3,641Net interest -667 -634 -635 -560PBT -161 1,796 2,629 3,081HSBC PBT 1,018 1,872 2,629 3,081Taxation -50 -394 -591 -693Net profit -219 1,398 2,034 2,385HSBC net profit 927 1,464 2,034 2,385


Cash flow from operations 2,488 -183 2,566 3,258Capex -1,409 -2,482 -1,540 -1,366Cash flow from investment -429 -2,297 -1,540 -1,366Dividends 0 -804 -814 -894Change in net debt -2,108 3,371 -213 -998FCF equity 975 -2,675 1,026 1,892




Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 0.6 5.0 11.1 6.8EBITDA 47.9 28.8 22.9 10.3Operating profit 274.6 48.7 30.2 11.6PBT 46.4 17.2HSBC EPS 56.0 38.9 17.2

Ratios (%)

Revenue/IC (x) 0.4 0.4 0.5 0.5ROIC 10.0 9.0 11.1 11.9ROE 5.9 9.9 14.1 15.1ROA 2.1 5.7 7.6 8.3EBITDA margin 30.5 37.4 41.4 42.8Operating profit margin 18.3 25.9 30.4 31.8EBITDA/net interest (x) 4.2 5.7 7.0 8.8Net debt/equity 42.1 72.6 65.3 53.3Net debt/EBITDA (x) 2.4 2.8 2.2 1.8CF from operations/net debt 37.6 26.2 37.1


EPS Rep (fully diluted) -0.62 3.89 5.67 6.64HSBC EPS (fully diluted) 2.62 4.08 5.67 6.64DPS 0.00 2.24 2.27 2.49Book value 43.89 38.38 41.78 45.93

Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information

Share price (CHF)40.42 Target price (CHF)62.00 5

3.4

Reuters (Equity) RIGN.VX Bloomberg (Equity) RIGN VXMarket cap (USDm) 16,131 Market cap (CHFm) 14,568Free float (%) 100 Enterprise value (USDm) 26124Country United States Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


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2011 2012 2013 2014Transocean Inc Rel to S&P 500

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Financials & valuation: Seadrill Ltd Neutral Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 4,479 4,946 5,986 7,335EBITDA 2,405 2,595 3,332 4,224Depreciation & amortisation -613 -714 -814 -967Operating profit/EBIT 1,792 1,881 2,518 3,257Net interest -315 -410 -478 -575PBT 1,437 1,448 2,060 2,755HSBC PBT 1,258 1,448 2,060 2,755Taxation -180 -152 -227 -317Net profit 1,146 1,155 1,679 2,343HSBC net profit 989 1,155 1,679 2,343


Cash flow from operations 1,853 2,020 2,703 3,430Capex -1,557 -3,476 -2,334 -3,779Cash flow from investment -1,445 -2,069 -2,334 -3,779Dividends -1,646 -1,688 -1,782 -1,991Change in net debt 1,311 976 1,426 2,354FCF equity 296 -1,455 370 -349


Intangible fixed assets 1,295 1,295 1,295 1,295Tangible fixed assets 14,801 15,806 17,325 20,138Current assets 2,573 2,728 2,597 1,713Cash & others 1,053 1,053 696 -480Total assets 19,633 20,843 22,282 24,260Operating liabilities 1,652 2,342 2,733 3,171Gross debt 11,827 12,803 13,872 15,049Net debt 10,774 11,750 13,176 15,530Shareholders’ funds 5,384 4,851 4,748 5,099Invested capital 15,964 16,433 17,789 20,456


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 6.8 10.4 21.0 22.5EBITDA 3.9 7.9 28.4 26.8Operating profit 2.3 5.0 33.9 29.3PBT -13.9 0.7 42.3 33.7HSBC EPS -46.4 16.8 45.4 39.5

Ratios (%)




Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 7.4 6.9 6.0 5.2EV/EBITDA 13.8 13.2 10.7 9.0EV/IC 2.0 2.0 1.9 1.8PE* 21.7 18.6 12.8 9.2P/Book value 3.5 3.8 3.8 3.6FCF yield (%) 1.3 -6.3 1.6 -1.5Dividend yield (%) 7.7 7.8 8.3 9.3


Issuer information


.4

Reuters (Equity) SDRL.OL Bloomberg (Equity) SDRL NOMarket cap (USDm) 21,335 Market cap (NOKm) 127,026Free float (%) 100 Enterprise value (USDm) 32575Country Norway Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


129149169189209229249269289309

129149169189209229249269289309

2011 2012 2013 2014Seadrill Ltd Rel to OBX INDEX

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Sub-sector: Engineers, onshore and offshore construction/installation Stocks covered: AMEC, EZRA, LAM, KENZ, MDR, PFC, TEC, SPM, 2386 HK (Sinopec Engineering), SUBC, WG

Main sub-sector themes – unless your name is

Technip, E&C has been a tough place to be thus

far in 2013 – major E&C blow-ups (Saipem, GS

E&C), project delays/cancellations (Browse, Mad

Dog, Hibernia), bribery and accounting

investigations (Saipem), and slowing growth and

subsequent negative earnings revisions have all

understandably dented investor confidence. The

financial industry is still adjusting to a lower-

growth oil & gas industry, and we think – in

general terms – the market may not have yet

reached the end of its downgrade cycle.

However, there are reasons for some optimism –

industry backlogs, particularly Offshore, are very

healthy and, we think, support volume growth and

some margin expansion in 2014/15, and a strong

drilling market (and growing rig fleet) should

support growth in development activity in the

medium term. In this section, we discuss the

outlook for offshore and onshore E&C, as well as

the asset-light ‘pure’ engineering side.

Overall offshore capex spending (USDm)

Source: Infield Systems

As at Q2 2013, backlogs for offshore EPC were

up 10% y-o-y at USD51bn, onshore was up 13%

at USD100bn, and overall EPC and equipment

backlogs combined were up 19% at USD202bn.

Offshore E&C – we think offshore markets

contain some of the areas to watch out for in

2014, particularly high-end subsea installation.

However, the market backdrop for the offshore

E&C/subsea installation market is still far from

perfect: sector backlogs are at record levels and

although we’ve seen close to record number of

subsea equipment orders in 2013 to date, the rate

of expansion is slowing, and we think 2014 is

unlikely to see much growth (less from Brazil in

particular); the market has tightened, but there is

more vessel supply on the horizon (particularly at

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E&C relative share price chart – since the start of 2013


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the top end) and more competition; the phasing of

projects in regions like Africa has been a positive

development, but several projects globally have

been postponed as oil companies struggle with

project economics (influenced by a number of

issues, not just costs – also reservoir problems

such as that discovered at BP’s Mad Dog II in the

US GoM, which now looks to need much more

water injection than originally planned).

The rate of order backlog expansion for the

installation players may well be slower in 2014

versus 2012/13, but there appears to be structural

growth potential in this industry longer term –

overall offshore capex should expand to USD130-

140bn pa in 2017/18 from USD80-90bn pa in

2012/13 (based on Infield data). The main growth

looks to be in the procurement/construction and

installation segments, offshore pipeline capex

flattish over 2012-14, pickup in 2015-18.

The key regional trends are – West Africa buoyed

by a recovering/re-emerging Nigeria and Angolan

pre-salt remain the key drivers, whereas Brazilian

activity appears stable at a high level for the next

few years. East Africa is working towards

greenfield developments but infrastructure awards

must lead installation awards (major contract

awards are unlikely much before 2015). The

North Sea remains an active market with medium-

term prospects bolstered by discoveries,

particularly in Norway, whereas the picture is

mixed in Asia Pacific with a slowing Australian

market contrasting with higher activity in

Indonesia and South East Asia.

Subsea installation – there are some key points

on this sub-sector we feel are important for the

medium term:

General trends – we see tieback distances

increasing materially but less export line

activity – this is potentially a good mix for

TEC/SUBC (especially reel-lay capacity), but

less so for parts of SPM (and Allseas).

The overall sense for installation markets is that

supply has indeed run ahead of demand, and the

market will need the 2016/17/18 market growth

expectations to deliver or some vessel owners

might be pitching new vessels into a market

that looks similar (or slightly weaker) to that

now (much depends on growth from Africa).

But this picture is selective – eg, genuine heavy

lift (5,000t+) looks undersupplied and getting

tighter, deepwater pipelay looks oversupplied

now but good by 2017/18 if the market sees

that expected pickup in work post 2016 (largely

W Africa, some Brazil).

We are also seeing more examples of subsea

and pipeline work coming together (bundling

– clients looking for fewer 'touchpoints' with

contractors) – we mentioned this theme in our

'Deep Blue III' subsea thematic (published 8

February 2013) so this is clearly persisting.

Vessel orders from newer entrants are (mostly

– with the exception of PFC) trying to build

cheaper designs to be able to chase 80% of

top-end work for less than 80% of the price.

The industry remains split on the economics

of “Swiss army knife” top-end vessels that

can do everything – pipelay, heavy lift and

flexlay. It really needs a specific combination

of work for these to pay off well, which most

projects don't see – it is likely to see these

being used quite widely but perhaps not to see

these getting the premium rates the owners

may expect (good utilisation, average IRR).

Brazil pipelay – a few interesting moving

parts here – the fleet is partly 1980s built,

partly 2000-10 built and partly newbuilds due

2015 (the new Brazil PLSVs). It is clear that

the old vessels have less work in prospect in

the medium term (these are mostly owned by

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SUBC and TEC) so these vessels might

re-contract or leave the region, leading to a

potential middle-tier supply risk for elsewhere

in the flexlay market (these are 150-300t

top-tension vessels).

For the overall offshore market, cost-inflation

issues and supply-chain bottlenecks remain an

impediment, but deepwater/ultra-deepwater

project development economics continue to be

competitive (hurdle rate on average around

USD80-90/bbl, slightly lower in Brazil, slightly

higher in West Africa due to less mature

infrastructure/fewer tieback opportunities).

Decent exploration success and a 25%-plus

increase in the deepwater rig fleet (2012-16) is a

key catalyst for higher development activity.

More signs of frame agreements for offshore

services (OSVs, survey, subsea) imply to us that

the industry is anticipating higher activity and is

keen to lock down supply/prices.

Offshore spending – we think it is interesting to

note the view from Infield Systems on oil price

sensitivity for this area of investment:

in a world where oil is materially (and

sustainably) above USD100/bbl, offshore

investment could increase by some 10-20%; and

conversely, if oil prices decline to USD60/bbl

in the medium term, the view is that delays are

likely and overall spending is flat-to-declining

from 2012 onwards (although note 50% of

2016 work is already sanctioned versus

20-25% of work in 2018).

Onshore E&C – onshore markets operate on a

different cycle to onshore with very different

competitive backdrops. In MENA, paradoxically

2009/10 were peak years for project awards as

Saudi Arabia and Abu Dhabi capitalised on

advantageous project costs and terms/conditions –

the effects of this have been evident this year with

several large write-downs from European and

Korean contractors. 2011/12 were comparatively

quieter years, and, as the 2009/10 wave of

projects draws to a close, we’re now entering a

new phase of advancing project development –

2013 has seen a marked pick-up in project award

momentum. We expect this to continue through

2014 and in the medium term could be boosted

further by unconventionals – we note Saudi

Aramco plans to release a design tender to

develop shale gas in three locations in Q4 2013.

GCC prospects pipeline (USD215bn)

Source: MEED

The competitive landscape has not changed

materially – the Korean contractors remain the

dominant force across MENA (about 60% of all

major contracts across the GCC awarded to

Koreans in 2011-13) and their low-cost position

and political ties across the region suggest this

stronghold is unlikely to be broken anytime soon.

European contractors like Saipem and Petrofac

retain a decent position in the region (Petrofac, in

particular, has been successful securing work in

Abu Dhabi in 2013) and is very active bidding for

work (often in consortium with Korean players)

whereas Technip appears to be far more selective.

Following various E&C blow-ups, the market has

theorised bidding could become more rational but

this remains to be seen.

This award cycle is more ‘gas’ (for industry,

petrochemical activity and internal demand, rather

than export) and ‘downstream’ focused than its

Chemicals, $72bn

Refinery, $44bn

Gas processing,

$31bn

Upstream Oil, $28bn

Upstream Gas, $20bn

Midstream, $19bn

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predecessor (which was more ‘upstream’ and ‘oil’

led). ‘Stand-out’ projects include the Clean Fuels

and New Refinery projects in Kuwait, the Jizan

refinery in Saudi Arabia, the Sitra refinery in

Bahrain, the Al-Karaana Petrochemical Complex

in Qatar, Sohar Refinery in Oman and several

upstream/midstream/infrastructure projects

attempting to move forward in Iraq (Rumaila,

Zubair, West Qurna, etc). MEED suggests over

80% of the GCC pipeline could be awarded over

the next 9-12 months.

North Africa on the whole is less active, and

while Algeria is again beginning to award projects

the overall volume of work available is much

lower than previously. Outside the MENA region,

Russia and the FSU appear more active, and the

North America market is more active on

downstream opportunities emanating from shale

activity (petrochemical, LNG etc), whereas

Australian onshore markets are cooling (Browse

resurrected using offshore liquefaction). In fact,

North American markets could be the surprise in

the medium term, particularly if numerous LNG

export schemes obtain approval; interestingly

we’d note that several of the key international

E&C players in the Middle East have been

moving some of their “A-teams” back to the US.

Engineering – the pure engineers and project

management companies have seen a slowdown in

order intake and double-digit growth now looks a

real challenge in 2014. However, greater project

complexity requires greater engineering man

hours and, overall, the fundamentals remain

supportive. Indeed, the volume of discoveries and

‘the hopper’ of conceptual/FEED activity supports

a recovery in ‘the volume market’ in 2015/16 as

projects in the North Sea, Gulf of Mexico and

Africa progress. We think these types of business

models (asset light, cash generative, reimbursable)

offer investors exposure to E&P capex and wider

oil services themes without construction risk and

largely without lump-sum risk. While such

characteristics may be more ‘in vogue’ against a

market averse to E&C/lump-sum risk, our

enthusiasm for these stocks is tempered by a more

uncertain near-term growth outlook.

Overall investment view on E&C and

Engineering – we expect the market’s enthusiasm

for E&C and engineering stocks to remain

lukewarm in the near term – our overall stance on

this company grouping is more balanced than it has

been for some time. However, we see pockets of

value: our preferred names are Technip and Subsea

7 and least preferred is McDermott. We view

Technip as the ‘quality stock' but current valuations

suggest greater potential upside with Subsea 7.

Saipem has recovered well from its share price

lows, but we still see sufficient upside to justify a

positive stance. We also see good medium-term

potential with Sinopec Engineering. In the smaller-

cap arena, we like Kentz’s onshore growth profile,

and also Ezra in the subsea installation space. We

are neutral on Onshore E&C and the

engineering/project management businesses –

Lamprell, Petrofac, Wood Group and AMEC.

Finally, we are Underweight (V) McDermott.

Main stocks and changes in this report – the

only stock in this section where we’ve made

changes is Lamprell, where we’ve updated our

assumptions to reflect its pace of newbuild orders

and the likely more competitive environment in its

rig refurb business.

AMEC (N, TP 1,130p) – the sheer breadth of

AMEC’s business should offer resilience but several

end markets (oil sands, mining and power) have

proved challenging in 2013, and conventional oil &

gas is growing less strongly than previously. Some

notable greenfield contracts are winding down (eg,

Kearl, Clair Ridge, Cygnus) and may prove difficult

to replace, but lower-margin brownfield momentum

remains strong. We sit 12% below consensus EPS in

2014. We think AMEC’s focus on ‘high-end’

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services is limiting its growth opportunity – the

failed acquisition of Kentz tried to rectify this but

also would have seen AMEC take on more lower-

end ‘blue-collar construction/EPC work. We

estimate a GBP475m buyback could propel EPS to

100p in 2014, but without this AMEC is unlikely to

reach its target. We continue to see AMEC as a

fundamentally good business with attractive

characteristics – asset light, cash generative, low-risk

reimbursable contracting structures, high ROE.

However, the growth opportunity appears to be

limited, the new organisational structure is not yet

bearing fruit and the potentially exciting JVs signed

in recent years are not yet delivering.

Amec: Share price chart YTD in GBPp per share


Ezra (OW, TP SGD1.25) – 2013 has been a

roller-coaster ride for Ezra shareholders thus far.

Despite strong subsea revenue growth in recent

quarters, the paltry subsea profits suggested a

longer ‘learning curve’ might be required before

margins improve. This combined with temporary

delays and issues in the OSV business drove

losses in the core business – and a plunging share

price. Then September saw a gravity-defying

50%+ share price recovery amidst press chatter

over a potential takeover by larger industry

players (Reuters, 11 September 2013). Subsea

growth prospects good but Ezra must tackle

execution issues. We stay bullish about subsea

installation and expect strong demand for three to

five years from rising deepwater production. For

Ezra, the key issue has been realising margins in a

relatively new business – the top line is not a

concern and order wins are coming through too

with y-t-d subsea book growing strongly by c70%

y-o-y. We anticipate early 2014 as inflection point

in subsea profitability with some thorny (ie, thin

margin) contracts out of the way and the new

additions to the subsea fleet Lewek Express and

Lewek Centurion fully deployed; focus will then

move onto the deployment to market of the new

flagship the Lewek Constellation (in August this

year this was awarded USD120m of work in West

Africa from VAALCO).

Ezra: Share price chart YTD in SGD per share


Lamprell (N(V), TP 150p, down from 160p) –

after a turbulent year plagued by major execution-

related issues, LAM is now almost out of its ‘fire-

fighting’ stage and can look ahead to some

normality. The new management team is now

officially in place (although there has been a

recent change of CFO), most (if not all) legacy

problems have been addressed, including the

remaining refinancing issues. But after a

disruptive 2012, we still see LAM’s recovery

process as a medium-term event, and its return to

profitability will likely be gradual. In the medium

term, we continue to see decent recovery potential

from its ‘traditional’ areas of strength – we see a

clear focus now on jackup rigs (newbuilds and

refurbishment) and offshore platform

construction. These two areas dominate LAM’s

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pipeline of bidding activity (which was USD4.6bn

at the end of H1 2013). We see newbuild activity

growing for LAM’s LeTourneau 116E rigs (these

designs are the “Volkswagens” of the jackup

fleet), refurbishment activity looks to have good

momentum in the Middle East (local demand and

international-owned rigs coming into the region),

although competitive pressures are growing, and

North Sea platform work continues to grow

(although they face continued competition from

Asian fabrication players). With an order book of

USD1.1bn (down on end-2012) and a bid pipeline

of USD4.6bn (up on end-2012), we think LAM is

reasonably placed with good medium-term

potential, but we see fewer near-term triggers and

for now don’t see sufficient potential upside to

warrant a more positive rating.

The changes to our forecasts reflect two main

themes – a slower order intake of newbuild EPC

work (jackup rigs) and a more competitive

environment in the Middle East for rig

refurbishment work (LAM commented on this at

the time of its H1 results; we think the group will

still prove well placed for larger and more

complex refurbishment/repair work). LAM’s

currently low-margin recovering P&L does make

these changes look more material on a relative

basis than they are to the group’s overall

valuation, but nevertheless our forecasts are

significantly lower for the next few years; this is

driven more by our lower forecasts (especially

margins) for rig refurb than it is by our

assumptions of less newbuild order intake.

Lamprell: Key P&L changes (all in USDm apart from EPS)

CURRENT FY2012 FY2013e FY2014e FY2015e FY2016e

Sales 1,045.5 1,111.9 1,051.9 1,247.5 1,227.4 EBITDA -50.5 56.3 84.9 127.7 150.0 EBIT -84.5 23.0 51.0 88.0 110.5 net -110.5 11.4 43.1 82.5 105.9 EPS -0.40 0.04 0.17 0.32 0.41

PREVIOUS FY2013e FY2014e FY2015e FY2015e Sales 1,147.7 1,224.0 1,512.6 1,488.1 EBITDA 50.5 112.6 191.9 173.4 EBIT 16.8 79.8 152.3 133.9 net 6.1 71.0 146.0 129.7 EPS 0.02 0.27 0.56 0.50

change (%) FY2013e FY2014e FY2015e FY2015e Sales -3.1% -14.1% -17.5% -17.5% EBITDA 11.4% -24.6% -33.5% -13.5% EBIT 37.2% -36.1% -42.2% -17.5% net 86.0% -39.3% -43.5% -18.3% EPS 86.0% -39.3% -43.5% -18.3%

Source: Company data, HSBC estimates from 2013e onwards

Our valuation for LAM is rather less affected –

this is due to higher comparable peer group

multiples (affecting our sum-of-the-parts model),

our assumptions of lower capex and a better year-

end net cash position than before (affects our

DCF), and also our book value metrics (based

more on 2013e tangible book value). We also shift

our FX assumptions for USD/GBP to 1.60 from

1.50 previously; our target price is cut to 150p

from 160p. We’d note that at current levels LAM

is trading on around 3x tangible book for 2013e

(and on around 1.4x reported book value); this is

already in the upper end of the range seen for its

larger (and more established) peers in the SE

Asian shipyard space (Keppel Corp and Sembcorp

trade in the 2x-3x book range).

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Lamprell: Share price chart YTD in GBPp per share


Kentz (upgrade to OW(V) from N(V), TP

615p) – the last few months have unsurprisingly

been dominated by the recent approaches from

Amec and the M+W Group, but it has been clear

for a while that Kentz’s underlying story is

accelerating, and now the M&A story is ‘off the

table’, we think the market’s focus should return

to what we see as one of the strongest growth

stories in the sector.

A key question is whether the group is set to revisit

its historical growth rates (it saw 23-24% top-line

CAGR over 2007-12). The group’s backlog is close

to double that in 2010 (should hit USD3bn soon this

year), and it bid USD4.5bn of work in Q2 alone

(which at its historical one-in-three win rates

implies USD1.5bn of order intake on top of the

USD979m booked in H1); this could set the group

towards USD2bn of revenue in 2014e. And Kentz’s

prospect pipeline (6-12-month view) is up 48% to

almost USD7bn. With good prospects in TSS

(47% H1 top-line growth and 80% backlog growth),

a recovery, at last, in prospect for EPC (see growth

resuming in 2014e) and more opportunities in

construction (backlog flat but bidding pipeline

almost double that 12 months ago) the group's

outlook is clearly for growth. The mix of growth is

changing – more EPC, more TSS – which should

help margins remain above those in recent years

(6-7% EBIT range rather than around 5%).

All this and low capex implies a typical OFS

problem – what to do with the cash (USD179m of

the cash balance at H1 is 'Kentz's own cash').

We'd note Kentz continues to look at M&A, and

we think it is likely it will look, in particular, at

growing its footprint in EPC.

The main change we’re making here is to upgrade

our rating to OW(V) (from N(V)) – back to where

we were before the M&A discussions over

summer. We continue to see Kentz as offering one

of the strongest growth stories in the sector at

present, and we still think that its growth dynamic

(more a derivative of overall E&C backlog

growth) is not well understood by the market; we

see ample opportunity for Kentz to exceed market

expectations over the medium term.

Kentz: Share price chart YTD in GBPp per share


McDermott (downgrade to UW(V) from N(V),

TP USD6.75) – MDR's fortunes lurched from bad

to worse through H1, thanks to delays/execution

issues with work in Malaysia and Saudi

(Safaniyah), plus costs related to the closure of the

loss-making Morgan City yard (and overall

restructuring of the Atlantic business). There are

certain key issues in the near term (Papa Terra

work in Brazil, management of problem contracts,

plus potential new project wins) that could arrest

MDR's sequential decline, but with offshore work

on Ichthys looming next year, we think any relief

would likely be short lived. On MDR's existing

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guidance, 2013 will be a loss-making year, and

the key question is whether next year can be any

better. As at mid-2013, MDR was half full (or half

empty) for 2014; this work is only likely to

deliver low single-digit margins, so much depends

on what other work MDR can book to fill up the

rest of the year in this busy (but not booming)

offshore cycle. MDR's guidance is for 2014

margins to be in the 5-8% range (we assume

below this and see 2014e EBIT margins at 4%).

And market sentiment next year will, we think,

increasingly be dominated by progress on Ichthys.

Given its size, this was always going to be a

company-defining project (as at the H1 point,

work was 3% complete, with the engineering

scope 2/3 complete and USD1.2bn of the

USD1.4bn procurement scope contracted,

including the USD750m installation via

Heerema). Amidst all these concerns, one positive

is the cash position (worth USD1.8/share), which

does give some support. Since end Q2, MDR has

traded around its tangible book value of

USD7.4/share (our target price of USD6.75 is

equivalent to 2013e book value after an additional

USD150m of charges).

We continue to see MDR’s investment case as

very much ‘in transition’ at present; progress on

legacy projects and the Ichthys ramp-up will be

key over the next 6-12 months, but our concerns

are that – at least on our numbers – the market

does not seem to factor in a sufficient “cushion”

in valuations to reflect the inherent risk with the

Ichthys project. The overall picture here is well

known – the project was won at a low price versus

competition (won versus Saipem and at an earlier

stage, Technip and Subsea 7/Nippon Steel) and,

therefore, the contingency in this project if there

are any operational issues is likely to be slim. The

offshore installation part of the project is planned

to start in Q3 2014 using MDR’s North Ocean

102 and Emerald Sea vessels (Heerema is doing a

significant part of the heavy lift, J-lay and reel-lay

work with its ‘Aegir’ flagship). Given this picture,

we think MDR’s modest share price recovery

since its Q2 problems now puts the stock in a

relatively high-risk position. We think there could

be a short-term recovery for MDR if 2013

guidance can be reasserted (ie, no new problems)

at the Q3 results, but the bigger picture dominates

our view – we maintain our USD6.75 target price

(behind which, we’d note, we assume that Ichthys

is not a disaster for MDR, so there is downside to

this fair value if there are major problems), and

we downgrade our rating to UW(V) from N(V).

McDermott: Share price chart YTD in USD per share


Petrofac (N(V), TP 1,300p) – there are several

moving parts in 2014 – the level of contingency

release from high-margin contracts closing out this

year (notably South Yoloten); the margin assumed

on work in highly competitive markets like

Saudi/Abu Dhabi; the timing of new orders (does

IPCI in Kazakhstan reach profit recognition in 2014

or 2015?) and the geography where new work is

secured. We see a 200bp decline in OEC margins in

2014, and, given the competitive environment, we

see limited potential to reverse this trend. New

awards in higher-margin markets are essential to

counter-balance the current workload. We continue

to see OEC net profit growth in 2014/15 as a real

challenge for PFC. Better-than-expected production

from production-enhancement contracts in Mexico

(and longer-than-expected plateaux production in

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Block PM304) auger well for IES performance,

although OPO has near-term growth challenges.

The road to 2015 and beyond and further insights

into the company’s offshore/subsea strategy will be

covered at the capital markets event on 5 December,

but at this juncture we continue to see a balanced

risk/reward in PFC.

Petrofac: Share price chart YTD in GBPp per share


Technip (OW(V), EUR105) – management has

positioned TEC to outperform the market through

organic investments, technology development,

JVs and acquisitions. In a market risk averse to

E&C and lump-sum risk, TEC stands out from the

crowd as ‘the’ consistent performer. Only rarely

do E&C companies experience perfect execution

on EPC projects, but TEC’s approach to

mitigating risk has been consistent for many years

– target projects early (conceptual/FEED stage)

where it has competitive edge (technology or

otherwise) and maintain a diverse portfolio in

terms of project size, market segment and

geography. The strong engineering culture within

TEC appears fully aligned with its financial

controls and approach to risk management. Group

backlog is at record levels and while the rate of

backlog expansion may not continue at 1.35

(average for past six quarters), we remain

comfortable with the growth outlook in 2013-15e

– and believe TEC’s business model is well

placed to benefit from underlying market trends

(deeper, further, harsher, etc).

Technip: Share price chart YTD in EUR per share


Saipem (OW(V), TP EUR20) – the operational

performance on problematic contracts has

improved, notably in Mexico and Canada, and this

should support a positive commercial resolution.

Significant organisational focus on risk

management and project execution bodes well for

the existing book of work and future contract

award opportunities. The market backdrop is

generally supportive with Saipem engaged in a

very active bidding programme. While the FID

process is convoluted and project award timing

tricky to predict, Saipem is confident in its ability

to build a quality backlog (including ‘mega

awards’ like South Stream) capable of driving

P&L recovery in 2014-16. The market is sceptical

on Brazil, but management remains confident in

both execution capability and ability to secure

further work. Question marks persist around

ENI’s intentions for its 43% stake, but we think

ENI will want to see Saipem nursed back to full

health before making any decisions. Overall, the

Saipem recovery plan appears to be taking shape

but ongoing investigations (Algeria/Consob)

remain an unwelcome distraction.

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Saipem: Share price chart YTD in EUR per share


Sinopec Engineering (OW(V), TP HKD13.60) –

our outlook for the shares remains positive due to

SEG’s solid and sustainable backlog growth, big

new contracts in the pipeline for 2H13-2015e and a

relatively stable margin compared with peers.

Recent newsflow suggests China’s coal chemical

industry is benefiting from a more positive policy

environment, and we believe this is constructive for

equities with exposure to China’s coal chemical

E&C market. As the industry leader, Sinopec

Engineering (SEG) is the best-positioned player.

Our 2013 new contract forecast of RMB70bn,

which if realised would sustain SEG’s

backlog/2013e revenue at 2.3x. This target looks

easily achievable as the company already signed

RMB45bn new contracts in 1H13 and in 2H13e,

we expect a few contracts for some Sinopec-led

coal chemical projects and LNG terminal projects

to materialise (1.3mtpa MTO project in Ordos, two

600ktpa CTO projects in Guizhou and Henan, two

LNG terminals projects in Tianjin and Guangxi).

Our 2013-15e earnings forecasts are the lowest on

the Street as we are factoring in a slow decline in

margins (EBIT margin from 9.9% in 2012 to 9.6%

in 2015e) due to an increasing proportion of

overseas business in the backlog, from 37% at

end-2012 to 47% in 1H13 (the company indicates

overseas EPC projects typically have lower

margins than domestic ones). Over 2012-15e, we

forecast a 13% revenue CAGR driving a 12%

EBIT and net income CAGR.

Sinopec Eng: Share price chart YTD in HKD per share


Subsea 7 (OW(V), TP NOK155) – excluding

Guara Lula, group EBITDA margins were 26%

(close to record levels) in Q2 2013, and while Q2 is

unlikely to be replicated in subsequent quarters, we

have increased confidence in the underlying level of

profitability and medium-term margin outlook.

SUBC’s backlog is at record levels, has more than

doubled over three years and has potential to grow

further. More positive dialogue with Petrobras

around risk sharing on pre-salt contracts may pave

the way for a somewhat larger business in Brazil

than we currently envisage (we see potential for a

USD1bn business by 2017/18 based on PLSV

activity alone but EPIC work could boost this

materially). We think drawing a line under Guara

Lula is crucial to de-risking the SUBC equity story

(installation of the first of four buoys is imminent)

but with the remainder of the portfolio seemingly in

good shape, the market should regain confidence in

Street expectations for 2014/15.

Subsea7: Share price chart YTD in NOK per share


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Wood Group (N, TP 860p) – we think the

contribution from the unusually large Mafumeira

and Ichthys contracts could aggregate to 10-15%

of Engineering EBITA in 2013 but as these

projects close out, there are limited prospects to

replace this high volume of work. There appears

to be a sufficient undercurrent of activity (notably

in JP Kenny, the subsea business) to deliver a

stable y-o-y performance in 2014, but material

growth looks challenging. However, based on the

pipeline of opportunities, particularly in the Gulf

of Mexico, we believe 2015 could recover

strongly. In WGPSN, we see underlying growth in

mid-single digits with a favourable North

American mix change driving a stronger profit

outturn, and we see potential for incremental

contract wins in the North Sea and internationally,

and scope for further M&A in North America.

We’ve thought for a while that the main focus of

the ongoing strategic review is around GTS but

that JVs within this division (eg, those with Rolls

Royce) may complicate a structural solution – to

this end the recently announced planned JV with

Siemens’ (OEM) aftermarket maintenance

business looks to be a decent solution (Wood will

have 51% of the JV and the opex activities will be

reported as part of PSN – Wood sees decent

synergy potential from this deal, around GBP15m

per year from year 3). But, overall, the much

weaker near-term engineering outlook limits our

enthusiasm for the stock on a 12-month view.

Wood Group: Share price chart YTD in GBPp per share


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E&C sub-sector EV/EBITDA one-year forward E&C sub-sector PE one-year forward


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Evolution of onshore and offshore E&C backlogs, 2005-present


Y-o-Y growth in onshore and offshore E&C backlogs, 2005-present


Offshore installation – backlog growth and EBIT margin trends, 2005-present


020,000

40,00060,000

80,000100,000

120,000140,000

160,000180,000

Q1

05Q

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back

log

(USD

m)

Onshore EPC Offshore EPC

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Offshore y-o-y (%) Onshore y-o-y (%)

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Backlog (U

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IT M

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ave subsea installation EBIT % instal ln backlog (USDm)

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Current 'pipeline' of major offshore projects up for bid (values in USDm)

Country Region Project/Field Operator/Contractee Contract details Bidders Value (USDm)

Russia Europe South Stream project Gazprom To install c925kms of pipeline at max. depth of 2250m Saipem, Others (unknown yet) 13,000 Angola Africa Kaombo project Total EPIC based SURF package Technip/Heerema Marine, Saipem 3,500 Malaysia-Thailand Joint development area

Asia North Malay basin gas project phase one

Hess Corp Contract includes a central processing platform with 18000-20000-tonne topsides & an eight-legged jacket (designed to process 450mcf/d of gas) as well as a 2000-tonne bridge-linked wellhead platform

Saipem, McDermott, SMOE, COOEC, Hyundai Heavy, DSME, Samsung Heavy, SapuraKencana, Brooke Dockyards, Boustead Heavy Industries, Labuan Shipyards & Engineering, KKB Eng.

3,500

Mozambique Africa Prosperidade Gas Anadarko Petroleum EPC for offshore installation activities - pipelines, flowlines & umbilicals

Technip/Heerema, Subsea 7/Saipem, McDermott/Allseas

3,000

Mozambique Africa Area 4 Eni EPC contract for subsea development (subsea infrastructure and gas export pipelines)

Technip/Heerema, Subsea 7/Saipem, McDermott/Allseas

2,500

Indonesia Asia Gendalo-Gehem Chevron Procurement and installation of export pipelines (150kms + 88kms) and SURF

Technip/Heerema Marine/Swiber Offshore, Saipem/Rekayasa Industries, Subsea 7/Timas Suplindo, Allseas/Emas Offshore

1,900

Nigeria Africa Etan & Zabazaba fields Eni SURF/Subsea equipment for 29 subsea wells Saipem, Others (unknown yet) 1,800 Indonesia Asia Tangguh LNG BP Fixed facilities contract (for train 3) - two 3000tonne wellhead

platforms (a 3-slot & a 4-slot) Saipem/Timas Suplindo, Gunanusa/Swiber Offshore, McDermott, Meindo Elang Indah/COOEC, L&T/Bakrie Industries, Emas Offshore/Rekayasa Industries

1,800

Saudi Arabia/Kuwait Middle East Dorra gas field Al-Khafji Joint Operations EPIC contract for the field - six platforms, flowlines, gas gathering facilities, 200kms export pipeline & 100kms cables

Petrofac/COOEC, Technip, Saipem, McDermott 1,500

Brazil South America

Route3 project Petrobras Third pipeline (313kms, 24") to export new supplies of natural gas linking several FPSOs to be deployed at Lula and Sapinhoa fields to Comperj petrochemicals complex

Saipem, Technip, Allseas, Odebrecht 1,500

Nigeria Africa Bonga Southwest Shell SURF - pipelines/flowlines/risers & installation Technip, Saipem, Subsea 7, Petrofac, Heerema Marine Contractors, Emas, SapuraKencana, West Africa Ventures (Sea Trucks), Fenog Nigeria

1,250

Brazil South America

Santos basin pre-salts Petrobras to supply flexible risers for two FPSOs (c54 risers expected to be used) at Lula Alto and Lula Central blocks

Technip, Natioal Oilwell Varco, Wellstream (GE) 1,100

Angola Africa Lucapa Chevron fixed facilities contract Saipem, Others (unknown yet) 1,000 Brazil South

America Carioca Petrobras EPIC contract to supply and install rigid subsea riser system Technip, Saipem, Odebrecht Oil & Gas 1,000

Malaysia Asia Bokor Redevelopment Petronas EPCIC of 20000-tonne central processing platform plus seven satellite structures

Sapura-Kencana, Malaysia Marine Heavy/Technip JV

800

China Asia Liuhua 29-1 gas field Husky Energy EPIC contract for the field development (to tie-in with Liwan gas development) - detailed design, supply and installation of flowlines, spur lines, jumpers, tie in spools etc also 180kms pipelines, 40kms umbilical

Saipem, Subsea 7, Technip, Allseas, COOEC, McDermott, Emas, Swiber Offshore

800

Azerbaijan Europe Shah Deniz phase 2 project BP Subsea installation work related to 500kms of subsea pipelines Saipem, Others (unknown yet) 800 Vietnam Asia Nam Con Son 2 project PetroVietnam 300kms long pipeline Subsea 7, Technip, McDermott, Saipem, Hyundai,

Swiber, TL Offshore 700

Thailand Asia Various Chevron Multi-platform contract (from 2013-17) that covers EPC of wellhead platforms for Gulf of Thailand

- 600

Australia Australia Julimar-Brunello gas project Apache To supply and install subsea flowlines, umbilicals and other lines totalling 200kms between Brunello and Wheatstone platform

Allseas, McDermott, Technip, Subsea 7 600

Total 42,650


Natu

ral Reso

urces &

En

ergy

Glo

bal E

nerg

y Eq

uip

men

t & S

ervices 15 O

ctob

er 2013

58

ab

cCurrent 'pipeline' of major onshore projects up for bid (values in USDm)

Country Region Project/Field Operator/Contractee Contract details Bidders Value (USDm)

Russia Europe South Stream project Gazprom To install c1455kms of pipeline in Europe and eight compressor stations - 8,200Oman Middle East Khazzan tight gas project BP EPC contractor to build surface facilities - central processing facilities, the

gas processing plant, flowlines, pipelines & assoc. facilities Petrofac/Consolidated Contractors Company, Technip/Galfar E&C/Al-Hassan engineering/Special Technical Services, CB&I/L&T, Bechtel corporation/Bhawan engineering Company

3,500

Abu Dhabi Middle East Fujairah integrated refinery & petrochemicals complex

Ipic EPC of 200mbbl/d refinery (being built in the I phase). Two packages - 1) process units and utilities, 2) offsites & infrastructure

Daelim Industrial, GS E&C, Hyundai E&C, Hyundai Heavy, Samsung Engineering, SK E&C

3,500

Canada North America Kitimat LNG Chevron/Apache LNG export facilities development Saipem, Others (unknown yet) 3,000Qatar Middle East Idd el-Shargi North Dome

oilfield expansion project Occindental Petroleum Six packages for this phase V maintain potential (100mbbl/d) expansion -

processing platform, wellhead platforms+jacket, pipelines, infield flowlines, Halun island modification, accommodation platform

McDermott, NPCC, L&T, Hyundai Heavy, Samsung Heavy, DSME

3,000

Iraq Middle East Karbala refinery project Iraqi Oil Ministry EPC contract for the refinery development - 3,000Saudi Arabia

Middle East Khurais oil field expansion project

Saudi Aramco EPC to add new facilities in order to increase the field’s capacity by 300mbbl/d on top its existing capacity of 1.2mmbbl/d

- 3,000

Qatar Middle East Al-Sejeel petrochemicals complex

Qatar Petrochemical Company

EPC #1 - mixed-feed cracker Technip, CB&I Lummus, KBR, Linde 3,000

Kuwait Middle East Clean fuels project Kuwait National Petroleum Company

EPC 1 - revamp and upgrade work at the Mina al-Ahmadi refinery KBR/China Huanqiu Contracting & Engineering Corporation, Petrofac/Samsung Engineering/CB&I, JGC/SK E&C/GS E&C, Saipem/Hyundai E&C/Hyundai Heavy/Daelim Industrial, Chiyoda/L&T, Tecnicas Reunidas/Hanwha E&C, Fluor/Hyundai Heavy/Daewoo E&C

3,000

Kuwait Middle East Clean fuels project Kuwait National Petroleum Company

EPC 2 - revamp, upgrade & extension at Mina Abdullah along with dismantling Shuaiba refinery

KBR/China Huanqiu Contracting & Engineering Corporation, Petrofac/Samsung Engineering/CB&I, JGC/SK E&C/GS E&C, Saipem/Hyundai E&C/Hyundai Heavy/Daelim Industrial, Chiyoda/L&T, Tecnicas Reunidas/Hanwha E&C, Fluor/Hyundai Heavy/Daewoo E&C

3,000

Turkey Europe Star refinery project SOCAR EPC contract to build the refinery Saipem, Others (unknown yet) 2,800Kuwait Middle East Clean fuels project Kuwait National

Petroleum Company EPC 3 - expansion of facilities and utilities at Mina al-Ahmadi KBR/China Huanqiu Contracting & Engineering Corporation,

Petrofac/Samsung Engineering/CB&I, JGC/SK E&C/GS E&C, Saipem/Hyundai E&C/Hyundai Heavy/Daelim Industrial, Chiyoda/L&T, Tecnicas Reunidas/Hanwha E&C, Fluor/Hyundai Heavy/Daewoo E&C

2,500

Kuwait Middle East Various Kuwait Oil Company EPC of three oil & gas gathering centres Saipem, Technip, Aker Solutions, Foster Wheeler, JGC, Chiyoda, Daelim, GS E&C, Hyundai E&C, Hyundai Heavy, Samsung Engg., SK E&C

2,000

Iraq Middle East Various Iraqi Oil Ministry Scope includes 29 storage tanks with 66mcm capacity each (seven at Nassiriya oil depot and 22 at Bin Umar oil depot)

Saipem, China Petroleum Pipeline Bureau, Daewoo Engineering, Entrepose, Toyo Engineering, Punj Lloyd

2,000

Bahrain Middle East Sitra refinery rehabilitation & expansion project

Bahrain Petroleum Company

EPC #2 - crude unit & associated facilities - 2,000

Bahrain Middle East Sitra refinery rehabilitation & expansion project

Bahrain Petroleum Company

EPC #3 - hydrocracker & associated facilities - 2,000

Oman Middle East Sohar Refinery expansion project

Oman Refineries & Petrochemicals Company

EPC contracts for expanding the design capacity from 116mbbl/d to 187mbbl/d

Tecnicas Reunidas, Daelim/Petrofac, L&T/GS E&C, Samsung Engineering/Chiyoda, SK E&C/Hyundai E&C

1,890

Iraq Middle East Rumaila oil field expansion project

BP total of three packages are available on the first processing plant – 1) three trains of 150mbbl/d processing capacity each

Samsung Engineering, Hyundai E&C, Petrofac, CPECC, Saipem, Foster Wheeler, Fluor

1,800

Nigeria Africa Refineries upgrade project NNPC EPC contract to upgrade three refineries - Port Harcourt Refining Company, Kaduna Refining & Petrochemicals Company, Warri Refining & Petrochemicals company

Saipem, Others (unknown yet) 1,500

Indonesia Asia Tangguh LNG BP LNG facilities development (for train 3) Saipem, Others (unknown yet) 1,250 Total 55,940


59


abc

Financials & valuation: AMEC Neutral Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e

Profit & loss summary (GBPm)

Revenue 4,158 4,038 4,042 4,246EBITDA 341 353 358 380Depreciation & amortisation -79 -53 -53 -56Operating profit/EBIT 262 300 304 324Net interest -1 1 3 6PBT 261 293 299 322HSBC PBT 329 336 342 367Taxation -52 -77 -79 -84Net profit 208 215 220 237HSBC net profit 250 246 251 269

Cash flow summary (GBPm)

Cash flow from operations 260 291 337 342Capex -19 -21 -25 -20Cash flow from investment -183 -31 -35 -20Dividends -98 -107 -110 -119Change in net debt 422 -104 -187 -202FCF equity 196 196 241 251

Balance sheet summary (GBPm)

Intangible fixed assets 969 926 883 839Tangible fixed assets 70 83 99 108Current assets 1,304 1,447 1,651 1,928Cash & others 275 379 566 768Total assets 2,518 2,631 2,809 3,049Operating liabilities 1,155 1,160 1,229 1,352Gross debt 176 176 176 176Net debt -99 -203 -390 -592Shareholders’ funds 1,079 1,186 1,296 1,414Invested capital 913 916 838 754


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 27.5 -2.9 0.1 5.0EBITDA 10.4 3.6 1.3 6.2Operating profit 3.1 14.5 1.5 6.4PBT -12.4 12.1 2.2 7.5HSBC EPS 10.5 5.5 2.8 7.3

Ratios (%)

Revenue/IC (x) 4.9 4.4 4.6 5.3ROIC 26.1 26.7 29.4 34.4ROE 20.4 21.7 20.2 19.9ROA 8.7 8.5 8.2 8.2EBITDA margin 8.2 8.7 8.8 9.0Operating profit margin 6.3 7.4 7.5 7.6EBITDA/net interest (x) 341.0 Net debt/equity -9.1 -17.1 -30.0 -41.8Net debt/EBITDA (x) -0.3 -0.6 -1.1 -1.6CF from operations/net debt

Per share data (GBPp)


Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information

Share price (GBPp)1,061 Target price (GBPp)1,130 6

.5

Reuters (Equity) AMEC.L Bloomberg (Equity) AMEC LNMarket cap (USDm) 5,083 Market cap (GBPm) 3,156Free float (%) 100 Enterprise value (GBPm) 2824Country United Kingdom Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

Price relative


676

776

876

976

1076

1176

1276

676

776

876

976

1076

1176

1276

2011 2012 2013 2014AMEC Rel to FTSE ALL-SHARE

60


abc

Financials & valuation: Ezra Holdings Limited Overweight Financial statements

Year to 08/2012a 08/2013e 08/2014e 08/2015e


Revenue 984 1,041 1,263 1,605EBITDA 96 33 185 239Depreciation & amortisation -45 -45 -48 -50Operating profit/EBIT 51 -12 137 189Net interest -35 -44 -50 -55PBT 87 56 101 148HSBC PBT 87 56 101 148Taxation -22 10 -13 -20Net profit 65 63 86 126HSBC net profit 65 63 86 126


Cash flow from operations -194 21 7 51Capex -289 -256 -159 -130Cash flow from investment -296 -232 -159 -130Dividends -12 -10 -13 -19Change in net debt 297 121 200 80FCF equity -539 -269 -215 -155


Intangible fixed assets 234 234 234 234Tangible fixed assets 1,264 1,476 1,586 1,667Current assets 1,053 1,129 1,371 1,741Cash & others 133 141 171 217Total assets 2,732 3,030 3,395 3,860Operating liabilities 478 535 569 705Gross debt 1,244 1,373 1,603 1,729Net debt 1,111 1,232 1,432 1,512Shareholders’ funds 1,008 1,062 1,185 1,392Invested capital 1,940 2,163 2,451 2,719


Year to 08/2012a 08/2013e 08/2014e 08/2015e

Y-o-y % change

Revenue 76.0 5.7 21.4 27.0EBITDA 38.9 -65.8 461.8 29.5Operating profit 17.5 -123.1 38.3PBT 76.7 -35.9 81.3 47.3HSBC EPS 44.0 -7.3 35.1 47.2

Ratios (%)

Revenue/IC (x) 0.6 0.5 0.5 0.6ROIC 2.3 -0.7 5.1 6.3ROE 7.0 6.1 7.6 9.8ROA 3.8 4.2 4.2 5.0EBITDA margin 9.8 3.2 14.6 14.9Operating profit margin 5.2 -1.1 10.8 11.8EBITDA/net interest (x) 2.8 0.7 3.7 4.3Net debt/equity 110.2 113.2 118.0 106.3Net debt/EBITDA (x) 11.6 37.5 7.8 6.3CF from operations/net debt 1.7 0.5 3.4




Year to 08/2012a 08/2013e 08/2014e 08/2015e

Offshore supply fleet (No) 37 40 42 44Platform/Supply av.rate (USD/d 32,000 33,000 33,000 34,000AHTS average rate (USD/bhp/day 2 2 2 2Subsea revenue growth (%) 95 15 30 45Subsea operating margin (%) 7 -9 8 10Triyards operating margin (%) 16 7 7 7

Valuation data

Year to 08/2012a 08/2013e 08/2014e 08/2015e

EV/sales 1.8 1.9 1.7 1.4EV/EBITDA 18.9 59.5 11.6 9.2EV/IC 0.9 0.9 0.9 0.8PE* 14.2 15.4 11.4 7.7P/Book value 0.9 0.8 0.8 0.7FCF yield (%) -76.6 -37.4 -30.3 -22.2Dividend yield (%) 0.0 1.1 1.4 1.9


Issuer information

Share price (SGD)1.13 Target price (SGD)1.25 1

0.6

Reuters (Equity) EZRA.SI Bloomberg (Equity) EZRA SPMarket cap (USDm) 885 Market cap (SGDm) 1,105Free float (%) 62 Enterprise value (USDm) 1953Country Singapore Sector ENERGY EQUIPMENTAnalyst Neel Sinha Contact +65 66580606

Price relative


0

0.5

1

1.5

2

2.5

0

0.5

1

1.5

2

2.5

2011 2012 2013 2014Ezra Holdings Limited Rel to STRAITS TIMES INDEX

61


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Financials & valuation: Lamprell Plc Neutral (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 1,045 1,112 1,052 1,248EBITDA -50 56 85 128Depreciation & amortisation -34 -33 -34 -40Operating profit/EBIT -85 23 51 88Net interest -22 -12 -8 -5PBT -110 11 43 83HSBC PBT -105 11 43 83Taxation -1 0 0 0Net profit -110 11 43 83HSBC net profit -106 11 43 83


Cash flow from operations 222 -9 67 89Capex -17 -28 -42 -47Cash flow from investment -17 -28 -42 -47Dividends 0 -5 -16 -29Change in net debt -206 42 -8 -13FCF equity 206 -37 25 42


Intangible fixed assets 220 211 203 194Tangible fixed assets 166 169 186 201Current assets 676 709 691 790Cash & others 263 222 230 243Total assets 1,067 1,094 1,084 1,190Operating liabilities 463 484 447 499Gross debt 159 159 159 159Net debt -104 -62 -71 -84Shareholders’ funds 406 413 440 493Invested capital 335 384 403 443


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue -8.9 6.4 -5.4 18.6EBITDA -149.8 50.9 50.3Operating profit -208.0 121.7 72.5PBT -272.8 277.1 91.4HSBC EPS -231.2 277.1 91.4

Ratios (%)

Revenue/IC (x) 2.1 3.1 2.7 3.0ROIC -17.0 6.4 12.9 20.7ROE -22.5 2.8 10.1 17.7ROA -7.5 2.2 5.0 8.2EBITDA margin -4.8 5.1 8.1 10.2Operating profit margin -8.1 2.1 4.8 7.1EBITDA/net interest (x) 4.9 10.9 24.4Net debt/equity -25.6 -15.1 -16.1 -16.9Net debt/EBITDA (x) 2.1 -1.1 -0.8 -0.7CF from operations/net debt


EPS Rep (fully diluted) -0.42 0.04 0.17 0.32HSBC EPS (fully diluted) -0.40 0.04 0.17 0.32DPS 0.00 0.02 0.06 0.11Book value 1.55 1.58 1.68 1.89

Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 0.5 0.5 0.5 0.4EV/EBITDA 9.6 6.3 4.1EV/IC 1.5 1.4 1.3 1.2PE* 52.6 14.0 7.3P/Book value 1.5 1.5 1.4 1.2FCF yield (%) 33.9 -6.1 4.1 6.9Dividend yield (%) 0.0 0.8 2.7 4.8


Issuer information

Share price (GBPp)144 Target price (GBPp)150 4

.0

Reuters (Equity) LAM.L Bloomberg (Equity) LAM LNMarket cap (USDm) 605 Market cap (GBPm) 376Free float (%) 100 Enterprise value (USDm) 538Country United Kingdom Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


28

78

128

178

228

278

328

378

428

28

78

128

178

228

278

328

378

428

2011 2012 2013 2014Lamprell Plc Rel to FTSE ALL-SHARE

62


abc

Financials & valuation: Kentz Corp Ltd Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 1,563 1,724 2,005 2,280EBITDA 119 130 145 173Depreciation & amortisation -14 -14 -16 -18Operating profit/EBIT 105 116 129 155Net interest 0 2 2 5PBT 105 119 133 163HSBC PBT 105 119 133 163Taxation -26 -33 -35 -42Net profit 70 82 92 113HSBC net profit 70 82 92 113


Cash flow from operations 124 -21 89 124Capex -4 -30 -35 -35Cash flow from investment 13 -30 -35 -35Dividends -15 -17 -20 -23Change in net debt 9 72 -30 -62FCF equity 119 -51 54 89


Intangible fixed assets 4 4 4 4Tangible fixed assets 47 63 82 99Current assets 623 704 775 865Cash & others 223 151 181 242Total assets 706 804 894 1,001Operating liabilities 373 409 430 453Gross debt 2 2 2 2Net debt -221 -149 -178 -240Shareholders’ funds 278 339 408 493Invested capital 77 211 250 273


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)




Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


8.0

Reuters (Equity) KENZ.L Bloomberg (Equity) KENZ LNMarket cap (USDm) 912 Market cap (GBPm) 566Free float (%) 100 Enterprise value (USDm) 751Country United Kingdom Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


288

338

388

438

488

538

588

638

288

338

388

438

488

538

588

638

2011 2012 2013 2014Kentz Corp Ltd Rel to FTSE ALL-SHARE

63


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Financials & valuation: McDermott Underweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 3,642 2,952 3,049 3,475EBITDA 448 19 203 378Depreciation & amortisation -112 -81 -81 -93Operating profit/EBIT 336 -62 121 286Net interest 0 -10 -22 -28PBT 349 -96 108 263HSBC PBT 324 -67 108 263Taxation -131 -56 -32 -72Net profit 206 -165 61 175HSBC net profit 191 -136 61 175


Cash flow from operations 288 -143 151 234Capex -286 -310 -320 -495Cash flow from investment -286 -249 -320 -495Dividends 0 0 0 0Change in net debt 30 428 170 261FCF equity -130 -446 -163 -251


Intangible fixed assets 41 41 41 41Tangible fixed assets 1,412 1,641 1,880 2,282Current assets 1,790 1,480 1,402 1,370Cash & others 659 445 361 230Total assets 3,334 3,253 3,413 3,785Operating liabilities 884 700 715 781Gross debt 103 317 402 532Net debt -557 -129 41 302Shareholders’ funds 1,887 1,723 1,783 1,958Invested capital 1,699 2,016 2,247 2,683


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 5.7 -18.9 3.3 14.0EBITDA 33.6 -95.8 987.5 86.5Operating profit 32.9 -118.5 135.2PBT 52.4 -127.5 144.1HSBC EPS 27.9 -171.7 187.5

Ratios (%)

Revenue/IC (x) 2.4 1.6 1.4 1.4ROIC 13.7 -5.3 4.0 8.4ROE 10.8 -7.5 3.5 9.3ROA 6.9 -4.1 2.7 5.9EBITDA margin 12.3 0.6 6.6 10.9Operating profit margin 9.2 -2.1 4.0 8.2EBITDA/net interest (x) 1.8 9.4 13.5Net debt/equity -28.5 -7.2 2.2 14.9Net debt/EBITDA (x) -1.2 -6.9 0.2 0.8CF from operations/net debt 367.9 77.3


EPS Rep (fully diluted) 0.87 -0.70 0.26 0.74HSBC EPS (fully diluted) 0.80 -0.58 0.26 0.74DPS 0.00 0.00 0.00 0.00Book value 7.94 7.29 7.55 8.29

Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 0.3 0.5 0.6 0.6EV/EBITDA 2.6 83.4 8.5 5.3EV/IC 0.7 0.8 0.8 0.7PE* 8.9 27.7 9.6P/Book value 0.9 0.9 0.9 0.8FCF yield (%) -7.2 -24.6 -9.0 -13.8Dividend yield (%) 0.0 0.0 0.0 0.0


Issuer information

Share price (USD)7.13 Target price (USD)6.75 -

5.3

Reuters (Equity) MDR.N Bloomberg (Equity) MDR USMarket cap (USDm) 1,687 Market cap (USDm) 1,687Free float (%) 100 Enterprise value (USDm) 1559Country United States Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


2

7

12

17

22

27

2

7

12

17

22

27

2011 2012 2013 2014McDermott Rel to S&P 500

64


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Financials & valuation: Petrofac Ltd Neutral (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 6,240 6,578 7,428 7,915EBITDA 896 1,004 1,166 1,392Depreciation & amortisation -130 -161 -211 -258Operating profit/EBIT 764 843 954 1,134Net interest 7 0 1 3PBT 765 841 960 1,145HSBC PBT 765 841 960 1,145Taxation -135 -197 -252 -312Net profit 632 645 696 822HSBC net profit 632 645 696 822


Cash flow from operations -457 604 803 1,038Capex -397 -1,000 -743 -712Cash flow from investment -607 -1,000 -743 -712Dividends -201 -220 -226 -244Change in net debt 1,262 617 173 -79FCF equity -885 -396 60 326


Intangible fixed assets 432 432 432 432Tangible fixed assets 897 1,736 2,268 2,722Current assets 3,218 2,908 3,109 3,382Cash & others 582 -35 -208 -129Total assets 5,244 5,774 6,505 7,234Operating liabilities 2,052 2,148 2,409 2,559Gross debt 349 349 349 349Net debt -233 384 557 478Shareholders’ funds 1,549 1,974 2,444 3,023Invested capital 1,913 2,964 3,607 4,107


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)

Revenue/IC (x) 4.2 2.7 2.3 2.1ROIC 42.3 26.5 21.4 21.4ROE 47.5 36.6 31.5 30.1ROA 12.5 11.8 11.6 12.2EBITDA margin 14.3 15.3 15.7 17.6Operating profit margin 12.2 12.8 12.8 14.3EBITDA/net interest (x) Net debt/equity -15.0 19.4 22.7 15.8Net debt/EBITDA (x) -0.3 0.4 0.5 0.3CF from operations/net debt 157.3 144.0 217.0



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 1.1 1.1 1.0 0.9EV/EBITDA 7.7 7.4 6.5 5.4EV/IC 3.4 2.4 2.0 1.8PE* 11.2 10.9 10.1 8.6P/Book value 4.6 3.6 2.9 2.3FCF yield (%) -11.5 -5.1 0.8 4.2Dividend yield (%) 3.0 3.0 3.3 3.9


Issuer information

Share price (GBPp)1,341 Target price (GBPp)1,300 -

3.1

Reuters (Equity) PFC.L Bloomberg (Equity) PFC LNMarket cap (USDm) 7,471 Market cap (GBPm) 4,639Free float (%) 72 Enterprise value (USDm) 7211Country United Kingdom Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

Price relative

Source: HSBC Note: price at close of 08 Oct 2013 Stated accounts as of 31 Dec 2004 are IFRS compliant

1003110312031303140315031603170318031903

1003110312031303140315031603170318031903

2011 2012 2013 2014Petrofac Ltd Rel to FTSE ALL-SHARE

65


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Financials & valuation: Technip Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e

Profit & loss summary (EURm)

Revenue 8,204 9,442 10,845 11,953EBITDA 1,017 1,196 1,510 1,764Depreciation & amortisation -195 -239 -303 -340Operating profit/EBIT 822 957 1,207 1,425Net interest -53 -44 -43 -25PBT 748 915 1,168 1,405HSBC PBT 775 943 1,189 1,419Taxation -205 -265 -339 -407Net profit 540 645 824 991HSBC net profit 560 665 839 1,001

Cash flow summary (EURm)

Cash flow from operations 453 847 1,141 1,340Capex -519 -519 -515 -508Cash flow from investment -723 -523 -518 -511Dividends -173 -209 -226 -288Change in net debt 538 -115 -397 -540FCF equity -199 279 578 783

Balance sheet summary (EURm)

Intangible fixed assets 2,932 2,932 2,932 2,932Tangible fixed assets 2,796 3,076 3,288 3,456Current assets 5,258 6,094 7,007 7,981Cash & others 2,289 2,376 2,674 3,214Total assets 11,581 12,697 13,822 14,964Operating liabilities 4,671 5,396 6,085 6,583Gross debt 2,106 2,077 1,978 1,978Net debt -183 -298 -696 -1,236Shareholders’ funds 4,001 4,421 4,956 5,600Invested capital 4,026 4,330 4,468 4,572


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)

Revenue/IC (x) 2.3 2.3 2.5 2.6ROIC 15.6 16.4 20.0 23.1ROE 14.6 15.8 17.9 19.0ROA 5.1 5.8 6.7 7.3EBITDA margin 12.4 12.7 13.9 14.8Operating profit margin 10.0 10.1 11.1 11.9EBITDA/net interest (x) 19.1 27.1 34.9 70.0Net debt/equity -4.6 -6.7 -14.0 -22.0Net debt/EBITDA (x) -0.2 -0.2 -0.5 -0.7CF from operations/net debt

Per share data (EUR)


Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 1.3 1.1 0.9 0.8EV/EBITDA 10.5 8.8 6.7 5.4EV/IC 2.4 2.2 2.0 1.9PE* 19.4 16.4 13.1 11.0P/Book value 2.7 2.5 2.2 2.0FCF yield (%) -1.8 2.5 5.3 7.2Dividend yield (%) 1.9 2.1 2.6 3.2


Issuer information


0.5

Reuters (Equity) TECF.PA Bloomberg (Equity) TEC FPMarket cap (USDm) 13,392 Market cap (EURm) 9,849Free float (%) 93 Enterprise value (EURm) 9471Country France Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

Price relative


47

57

67

77

87

97

107

47

57

67

77

87

97

107

2011 2012 2013 2014Technip Rel to SBF-120

66


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Financials & valuation: Subsea 7 SA Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 6,297 6,850 7,306 8,040EBITDA 1,139 921 1,541 1,790Depreciation & amortisation -331 -390 -409 -450Operating profit/EBIT 808 530 1,131 1,339Net interest -29 -51 -52 -49PBT 1,069 479 1,079 1,291HSBC PBT 736 479 1,079 1,291Taxation -222 -265 -351 -419Net profit 830 196 709 851HSBC net profit 605 234 748 889


Cash flow from operations 515 569 1,152 1,283Capex -713 -788 -658 -643Cash flow from investment -354 -788 -658 -643Dividends -211 -228 -236 -236Change in net debt 158 447 -258 -404FCF equity -151 -201 514 660


Intangible fixed assets 2,599 2,599 2,599 2,599Tangible fixed assets 3,748 4,146 4,394 4,587Current assets 3,821 3,442 3,788 4,385Cash & others 1,288 841 1,098 1,502Total assets 10,495 10,514 11,108 11,898Operating liabilities 2,368 2,427 2,548 2,741Gross debt 1,535 1,535 1,535 1,535Net debt 248 695 437 33Shareholders’ funds 6,325 6,284 6,757 7,355Invested capital 6,512 6,919 7,134 7,328


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 15.0 8.8 6.7 10.0EBITDA 13.5 -19.2 67.4 16.2Operating profit 26.2 -34.4 113.4 18.4PBT 70.5 -55.2 125.3 19.6HSBC EPS 31.1 -62.6 219.4 18.9

Ratios (%)




Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


3.2

Reuters (Equity) SUBC.OL Bloomberg (Equity) SUBC NOMarket cap (USDm) 7,433 Market cap (NOKm) 44,256Free float (%) 74 Enterprise value (USDm) 7928Country Norway Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

Price relative


87

97

107

117

127

137

147

157

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97

107

117

127

137

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157

2011 2012 2013 2014Subsea 7 SA Rel to OBX INDEX

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Financials & valuation: Saipem Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 13,369 13,001 12,496 12,315EBITDA 2,207 620 1,822 2,171Depreciation & amortisation -726 -764 -793 -790Operating profit/EBIT 1,481 -143 1,029 1,381Net interest -148 -246 -241 -197PBT 1,349 -371 802 1,193HSBC PBT 1,349 -371 802 1,193Taxation -393 -40 -240 -358Net profit 902 -464 509 782HSBC net profit 956 -411 561 835


Cash flow from operations 231 382 1,840 1,786Capex -1,015 -910 -812 -800Cash flow from investment -1,007 -910 -812 -800Dividends -309 -301 0 -170Change in net debt 1,009 829 -1,028 -816FCF equity -787 -552 1,009 972


Intangible fixed assets 756 756 756 756Tangible fixed assets 8,254 8,400 8,420 8,430Current assets 7,853 7,323 7,230 7,436Cash & others 501 86 600 1,008Total assets 16,979 16,595 16,521 16,738Operating liabilities 6,088 6,001 5,880 5,840Gross debt 4,779 5,194 4,680 4,272Net debt 4,278 5,107 4,080 3,264Shareholders’ funds 5,405 4,693 5,255 5,920Invested capital 10,274 10,392 9,925 9,774


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 6.2 -2.8 -3.9 -1.4EBITDA 3.4 -71.9 193.7 19.1Operating profit -0.8 -109.7 34.1PBT -2.2 -127.5 48.8HSBC EPS -3.1 -143.0 48.8

Ratios (%)

Revenue/IC (x) 1.4 1.3 1.2 1.3ROIC 11.3 -1.5 7.1 9.8ROE 18.9 -8.1 11.3 14.9ROA 6.5 -0.7 4.5 6.0EBITDA margin 16.5 4.8 14.6 17.6Operating profit margin 11.1 -1.1 8.2 11.2EBITDA/net interest (x) 14.9 2.5 7.6 11.0Net debt/equity 77.0 105.5 75.5 53.8Net debt/EBITDA (x) 1.9 8.2 2.2 1.5CF from operations/net debt 5.4 7.5 45.1 54.7


EPS Rep (fully diluted) 2.05 -1.05 1.15 1.77HSBC EPS (fully diluted) 2.17 -0.93 1.27 1.89DPS 0.68 0.00 0.38 0.59Book value 12.24 10.63 11.90 13.41

Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 0.9 1.0 0.9 0.9EV/EBITDA 5.2 19.9 6.2 4.8EV/IC 1.1 1.2 1.2 1.1PE* 7.6 13.0 8.8P/Book value 1.3 1.5 1.4 1.2FCF yield (%) -10.5 -7.4 13.5 13.0Dividend yield (%) 4.1 0.0 2.3 3.6


Issuer information


0.7

Reuters (Equity) SPMI.MI Bloomberg (Equity) SPM IMMarket cap (USDm) 9,943 Market cap (EURm) 7,312Free float (%) 57 Enterprise value (EURm) 12452Country Italy Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

Price relative


7

17

27

37

47

57

7

17

27

37

47

57

2011 2012 2013 2014Saipem Rel to BCI ALL-SHARE INDEX

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Financials & valuation: Sinopec Engineering (Group) Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 38,526 44,170 49,988 55,824EBITDA 4,531 5,050 5,849 6,727Depreciation & amortisation -699 -687 -999 -1,370Operating profit/EBIT 3,832 4,364 4,850 5,357Net interest 405 210 241 273PBT 4,252 4,583 5,096 5,640HSBC PBT 4,252 4,583 5,096 5,640Taxation -935 -1,008 -1,121 -1,241Net profit 3,317 3,575 3,975 4,399HSBC net profit 3,317 3,575 3,975 4,399


Cash flow from operations 1,556 5,118 5,856 6,654Capex -369 -2,553 -3,218 -2,792Cash flow from investment -1,668 -2,553 -3,218 -2,792Dividends -374 -498 -1,251 -1,391Change in net debt 861 -12,977 -1,363 -2,447FCF equity 3,632 1,699 1,750 2,967


Intangible fixed assets 477 459 445 436Tangible fixed assets 7,495 9,379 11,612 13,043Current assets 29,051 45,596 50,638 56,776Cash & others 4,822 17,822 19,209 21,680Total assets 37,130 55,542 62,803 70,363Operating liabilities 26,605 30,502 34,520 38,551Gross debt 157 180 204 228Net debt -4,665 -17,642 -19,005 -21,452Shareholders’ funds 7,081 21,091 23,815 26,823Invested capital 5,595 7,110 8,967 10,025


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 25.9 14.6 13.2 11.7EBITDA 8.6 11.5 15.8 15.0Operating profit 2.9 13.9 11.1 10.5PBT 0.2 7.8 11.2 10.7HSBC EPS -1.7 -14.5 -1.9 10.7

Ratios (%)





Year to 12/2012a 12/2013e 12/2014e 12/2015e

Revenue Growth % 25.9 14.6 13.2 11.7Gross margin % 14.3 14.6 14.4 14.4EBIT margin % 9.9 9.9 9.7 9.6

Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information

Share price (HKD)9.41 Target price (HKD)13.60 4

4.5

Reuters (Equity) 2386.HK Bloomberg (Equity) 2386 HKMarket cap (USDm) 5,373 Market cap (HKDm) 41,667Free float (%) 33 Enterprise value (CNYm) 15143Country China Sector ENERGY EQUIPMENTAnalyst Tingting Si Contact +852 2996 6590

Price relative


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2011 2012 2013 2014Sinopec Engineering (Grou Rel to HSCEI

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Financials & valuation: Wood Group Neutral Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 6,821 7,386 7,711 8,195EBITDA 505 589 622 719Depreciation & amortisation -129 -144 -143 -148Operating profit/EBIT 376 445 480 571Net interest -13 -18 -16 -14PBT 367 427 464 557HSBC PBT 448 525 558 654Taxation -109 -117 -128 -153Net profit 257 307 333 400HSBC net profit 317 379 402 470




Intangible fixed assets 1,839 1,757 1,678 1,597Tangible fixed assets 199 282 333 381Current assets 2,029 2,488 2,920 3,371Cash & others 172 339 567 879Total assets 4,161 4,621 5,025 5,443Operating liabilities 1,454 1,686 1,833 1,943Gross debt 327 327 327 327Net debt 155 -13 -240 -552Shareholders’ funds 2,227 2,464 2,720 3,028Invested capital 2,441 2,502 2,531 2,526


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 20.4 8.3 4.4 6.3EBITDA 33.1 16.7 5.6 15.5Operating profit 42.9 18.4 7.9 19.0PBT -92.2 16.3 8.7 20.1HSBC EPS 41.5 19.3 6.1 17.0

Ratios (%)

Revenue/IC (x) 3.1 3.0 3.1 3.2ROIC 13.8 16.1 16.8 19.5ROE 15.1 16.1 15.5 16.3ROA 6.7 7.4 7.3 8.0EBITDA margin 7.4 8.0 8.1 8.8Operating profit margin 5.5 6.0 6.2 7.0EBITDA/net interest (x) 39.1 33.3 40.0 53.1Net debt/equity 6.9 -0.5 -8.8 -18.2Net debt/EBITDA (x) 0.3 0.0 -0.4 -0.8CF from operations/net debt 124.9



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


2.9

Reuters (Equity) WG.L Bloomberg (Equity) WG/ LNMarket cap (USDm) 4,603 Market cap (GBPm) 2,858Free float (%) 93 Enterprise value (USDm) 4591Country United Kingdom Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

Price relative


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514

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714

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914

1014

414

514

614

714

814

914

1014

2011 2012 2013 2014Wood Group Rel to FTSE ALL-SHARE

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Sub-sector: Subsea and Oilfield Equipment Stocks covered: AKSO, CAM, FTI, 196 HK (HongHua Group), HTG, NOV, SBOE

Main sub-sector themes – the ‘equipment’ space

in oilfield services (which we often term “capital

goods in disguise”) has seen a number of divergent

trends through 2013, the key ones, in our view,

being: (1) destocking across the onshore value

chain in North America; (2) strong but volatile

demand growth from unconventionals-driven

Chinese onshore markets; and (3) strong growth in

equipment linked to offshore markets, particularly

subsea equipment, but also continued activity in

newbuild rig ordering.

The overall themes – as is often the case in long-

cycle offshore work – have not changed massively

over the past few months, but there is more

evidence that the industry is in a ‘growing but

slowing’ phase; backlog growth has been good

(very good for subsea equipment awards) but the

higher base effect plus the likely phasing of awards

in the next couple of years (a general comment, but

specifically the case in Brazil) implies that the

industry is going through a phase of high activity

but perhaps less growth in the medium term, before

stronger longer-term growth (driven more by

West Africa – Angola plus a recovering Nigeria).

Clearly, much of the medium-term growth outlook

depends on Africa.

Global offshore capex

Source: Infield Systems Ltd

As at the end of Q2, subsea equipment backlogs

were up 48% y-o-y in Q2; these totalled

USD25.9bn up from a post-financial crisis low of

USD11-12bn in late 2009/early 2010. This year,

Q2 was one of the strongest quarters over the past

10 years in terms of subsea tree awards (173 trees

awarded, with roughly 2/3 market share going to

FMC). In fact, both FMC and Aker Solutions had

record quarters for tree awards this year – Aker in

Q1 and FMC in Q2. The overall split of recent

award activity has been driven by Africa and

South America (making up around 60% of

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Subsea and oilfield equipment relative share price chart since the start of 2013


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Fugro CameronDril-Quip OceaneeringNOV Schoeller BleckmannHunting AverageTechnip EzraAker Soln FMC

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awards) with good activity also in the North Sea

and US Gulf (around 35% from these other two

regions), with the remainder of activity coming

from Asia Pacific markets. In terms of the oil

companies behind these awards, just over ½ the

activity in Q2 came from Petrobras and Total,

with EnQuest, Exxon, Chevron and Shell making

up around another 30%.

Subsea global manufacturing capacity utilisation trends

Source: Infield Systems Ltd

For offshore spending overall, versus our views

from 12-18 months ago, we see more activity in

East Africa and more in Norway, but less in

Australia. The outlook still looks quite robust

even given recent delays and postponements, but

underlying subsea capex is likely to see only a

small increase in 2014 and could be slightly lower

in 2015. This reflects current delays in Nigerian

awards feeding through; conversely the stronger

growth that is likely in 2017/18 is Nigerian

activity speeding up – if this is not evident in

project awards in 2014/15, then it will likely drive

slower subsea activity in the latter half of this

decade. In the near term, Brazil is likely to be

quiet for contract awards in 2014 – this has been

very busy in 2013, but market forecasts from

Infield Systems see 2014 slightly weaker, 2015

flat, then award activity resuming in 2016 (subsea

tree facilities in Brazil are fairly fully utilised for

the next few years).

Looking at subsea in 2014 in more detail, the top

5 awards in prospect look to be from Angola x 2,

Ghana, Brazil (Shell project) and the UK. In total,

West Africa makes up 6 of the top 10 awards, but it

is also important to note it is likely that certain

mega-projects will come in stages, ie, Kaombo

(Angola, Block 32) will likely be partly 2014,

partly 2015, and the TEN project looks likely to be

coming in early 2014 (we think market

assumptions are more for 2013). For 2015, there

still looks to be less from Brazil but activity in the

US GoM should be picking up, plus there should

be more West African work. The top 5 awards in

prospect are US GoM x 2, Angola, Nigeria and

offshore Libya (although there are more risks with

this last region due to its political situation).

Subsea trees – market shares 2008-12

Source: FMC Technologies, Quest

The other area of subsea equipment markets that

continues to move ahead – albeit gradually – is

that of subsea processing; boosting, separation

(oil/gas and oil/water) and associated technologies

like handling longer step-outs (currently up to 40-

45km, but would like to handle 80km or more)

and subsea power (an area of significant interest

to some of the major capital goods players like

Siemens and ABB). One high-profile test case is

the Marlim field subsea separation in Brazil – this

is just one well at present, but the next step is to

scale up to a field solution, then to a basin

solution for the Campos; the signs are that it is

working, but progression here is likely to be a

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FMC41%

Cameron19%

Aker19%

GE15%

DrilQuip6%

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relatively long-term process (at least on a

financial market timescale). One other important

angle on this “advanced subsea” area is that at

present, in our view, only FMC and Aker Subsea

are positioned to chase this market. In the future,

the new OneSubsea business (JV with Cameron

and Schlumberger) will doubtless target this

market as well (and is well placed for multiphase

flow handling with its Framo business).

Medium-term view of subsea services, worth USD2.5bn

Source: FMC Technologies

Onshore activity – we do not intend to go

through regional onshore markets in detail in this

report, but we’d note the dominance of

unconventionals as key themes for equipment

demand in certain markets.

In North America, the onshore supply chain has

been adapting to a lower growth market in terms

of rig count; we think expectations last year were

for a 2,000 rig market in 2013, but the market has

had to adjust to a 1,700-rig market. This lower

growth has seen a significant degree of inventory

‘burn through’ during H1; we expect the majority

of this destocking should have been through the

system by roughly mid-year/Q3, so we expect H2

to show more the underlying market growth

(which is still likely to be on the low side).

In China, we see two key pillars increasing

onshore service intensity, and therefore likely to

prove positive for equipment demand:

accelerating decline rates at mature oilfields and

increasing use of more sophisticated drilling and

service activities in new production due to depth,

pressure and low reservoir permeability –

particularly addressing the challenge of shale

reservoirs. China’s oilfield services market is

relatively under-supplied with the technology

needed to address unconventionals, so we expect

to see strong long-term growth for companies

exposed to this theme.

Main stocks and changes in this report – we

have not made any fundamental changes to our

assumptions for the companies in this section.

installation45%

asset management

23%

w ell access24%

equipment interv ention

8%

Multiphase meters (MPM) regional pattern of demand in 2012 is dominated by mature regions


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Aker Solutions (OW, TP NOK120 from

NOK125) – as we discuss in ‘Unlocking the value’,

14 June 2013, we believe there is hidden value in

AKSO, and a refocusing of the group could yield

significant upside to investors. We see two main

scenarios: 1) divesting of smaller/ periphery

businesses and become a more-focused player with

businesses that are the no.1, no.2 or no.3 in their

respective markets; and 2) spin-off a ‘jewel in the

crown’ like drilling equipment (management is

committed to building a world-class

subsea business).

For Aker Solutions, 2013 has been somewhat

disappointing, and we see further moderate

downwards adjustment to consensus numbers to

come (see our changes below). But the medium-

term growth outlook should support a faster rate of

growth in 2014 versus 2013 (although a lower rate

than the 12% experienced in 2012) at improved

margins. Subsea is crucial for the group to deliver

on its margin plan, and MMO and drilling

equipment should return to 2012 profitability in

2014. Risk mitigation across the group has

improved and the quality of backlog is higher than

it was a year ago. In essence, we believe AKSO is

in good shape to grow the core businesses, while

simplifying the business structure.

Main changes – we reduce FY13e EBITDA/EPS by

4%/6% on ongoing capacity costs in engineering,

uncertainty over the financial close-out of the

Ecofisk project (impacting MMO and engineering),

a slow ramp-up of the Skandi Aker contract in

Angola during Q3, plus ongoing restructuring in the

German operations within drilling equipment.

While the majority of these issues should be

confined to FY13, we take a more cautious

approach in FY14 with respect to Subsea margin

progression (ongoing Brazilian headwind), oilfield

marine assets (uptime on the Skandi Aker) and

engineering (assume further delays in project

awards and prolonged capacity costs). The net result

of this is a 6%/8% cut to our EBITDA/EPS. Our

forecast changes for FY15 and beyond are less

severe. The overall impact on our valuation is a cut

in target price to NOK120 (from NOK125).

Aker changes to key P&L forecasts (in NOKm, EPS in NOK)


Sales 44,922.0 48,224.1 53,219.1 56,510.7 55,407.3 EBITDA 4,739.0 4,435.7 5,922.0 6,979.9 6,325.6 EBIT 3,573.0 3,193.5 4,517.2 5,492.2 4,846.7 HSBC EPS 8.65 7.25 11.28 14.23 12.78

PREVIOUS FY2012a FY2013e FY2014e FY2015e FY2016e Sales 48,580.3 53,628.7 56,961.3 55,857.9 EBITDA 4,601.6 6,267.8 7,062.0 6,371.4 EBIT 3,353.0 4,855.7 5,566.2 4,884.4 HSBC EPS 7.70 12.26 14.50 12.95

change (%) FY2012a FY2013e FY2014e FY2015e FY2016e Sales -0.7% -0.8% -0.8% -0.8% EBITDA -3.6% -5.5% -1.2% -0.7% EBIT -4.8% -7.0% -1.3% -0.8% HSBC EPS -5.8% -7.9% -1.8% -1.3%

Source: Company Data, HSBC forecasts for 2013e onwards

Aker Solutions: Share price chart YTD in NOK per share


Cameron (N(V), TP USD64) – Cameron is

moving through a phase of integration and new

business setup after the OneSubsea transaction

with Schlumberger, in addition to facing a rather

soft market in onshore North American markets.

At the Q2 earnings point, Cameron lowered its

margin expectations for the new combined

OneSubsea business for 2013e on account of

project delays from the Framo business. We also

think it is prudent to expect start-up and other

associated costs to weigh on profitability for the

next 6-12 months. Also, Cameron’s exposure to

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the onshore market has experienced order related

issues with delays in project booking; this was a

feature in H1 that affected the valves &

measurement business, in particular. We don’t see

a meaningful revival in these businesses until

2014e, although we think the underlying growth

in North American onshore markets should

improve sequentially (as spare parts/consumables

inventories are used up). But Cameron’s other

businesses are doing well, particularly those

linked to offshore work – it reported record

bookings in surface, and the drilling business

continues to perform well with aftermarket

growth in excess of 20%. Overall, we maintain

our Neutral stance on the stock – CAM is a solid

combination of long- and short-cycle businesses

but at current levels, we don’t see sufficient

potential upside to warrant a more positive rating. FMC Technologies (N(V), TP USD56) – FMC

continues to consolidate its position as the market

leader in subsea equipment. The group accounted

for well over 60% of order intake for subsea

Xmas trees in Q2 2013 and is on track to achieve

a yearly record order intake of USD5.5-6.0bn in

the subsea business. This compares with

USD4.6bn subsea order intake in 2012 and

follows some significant awards over the past

three to six months (eg, Total’s Egina project in

Africa and the major call-off from Petrobras).

FMC expects this will leave it with USD5.4-5.9bn

of backlog by the start of 2014, out of which it

expects to convert 50-55% into revenues during

2014 itself (the backlog conversion to revenues

has been around 60% over recent years). With

medium-term bookings relatively strong across

the industry, pricing has been picking up for

around the past 18 months (and we believe

continues to improve), supporting mid-teen EBIT

margins for FMC’s subsea manufacturing

business in 2014e and potentially stronger in

2015e. FMC’s current EBIT margin guidance for

Subsea Technologies is for 12-13% in 2013,

improving to 14-15% in 2014.

The service side of the business (light-well

intervention and equipment refurbishment) is also

FMC Technologies subsea backlog (USDm) and book-to-bill (x), 2010-Q2 2013


Cameron: Share price chart YTD in USD per share


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improving, which we think should be accretive for

margins as we move into the middle of the

decade. But FMC’s recent performance has seen

subsea product margins prove slightly

disappointing so far this year (FMC downgraded

its margin forecast for 2013e at the time of the last

quarterly results), and the onshore North

American-exposed businesses remain a drag.

Our overall impression on FMC has not changed

materially in recent months – it has a market-leading

franchise in a robust end-market – but with the stock

trading at 17x earnings (and over 10x EV/EBITDA)

for 2014e, we think the market is already pricing in

much of the medium-term potential in FMC’s

subsea equipment franchise, and we don’t see

sufficient potential upside for a more positive rating.

FMC Tech: Share price chart YTD in USD per share


Honghua Group (OW(V), TP HKD4.83) – the

outlook for land drilling rig order growth remains

robust, and Honghua holds a sizable, high-quality

backlog. As at July 2013, the land rig backlog

reached 93 sets, valued at RMB7.5bn, with two-

thirds of deliveries in 2H13, and the remainder in

2014. GPM in 2H13e is likely to remain under

pressure as land rig deliveries to UAE’s National

Drilling Company have lower margins and comprise

a large proportion of 2H13e revenue. The company

remains uncertain about when it will book its first

offshore jack-up order and whether this will occur in

4Q13. Negotiations with three potential overseas

buyers are at a final but critical stage. One jackup

order could be worth USD2bn or 12% of Honghua’s

2013e target sales. Management believes the

RMB10bn 2013 revenue target, which is up 100%

yoy, is achievable, even without the signing of the

first jackup order. In addition, we believe the new

oilfield services business has good prospects, and the

demand for replacement parts and maintenance

services should provide a steady revenue stream, as

the company has already sold more than 800 land

rigs since incorporation. Over 2012-15e, we forecast

a 32% revenue CAGR driving a 31% EBIT CAGR

and 25% net income CAGR.

Honghua Group: Share price chart YTD in HKD per share


Hunting (OW, TP 1,050p) – problematic areas in

H1 (Canada market disruption caused by weather

and weak natural gas prices, destocking of certain

product lines: US pipe and electronics) are

recovering. Stable/strong activity levels in US

shale/Gulf of Mexico and continued growth in

Asia Pacific and the Middle East (plus the North

Sea) support a stronger H2 (we assume a

42%/58% H1/H2 split in 2013e). The underlying

market trends (towards multi-pad wells and

'zipper' fracking onshore, and deeper

waters/harsher environments offshore) continue to

be supportive. Demand-led new capex in the US

(new 40-acre site in Houston for premium

connections) illustrates management’s confidence

in the long-term outlook and investing in testing/

certification facilities should improve speed to

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market for proprietary products. In addition,

management continues to pursue bolt-on

acquisition opportunities. The Lean manufacturing

drive continues, with notable efficiency

improvements in Titan, enabling HTG to improve

its competiveness. All in, we think this brings the

company’s targeted 20% EBITDA margin into

range with H2 2013 and 2014 a real possibility.

Hunting: Share price chart YTD in GBPp per share


National Oilwell Varco (OW(V), TP USD86) –

NOV remains a powerful and broad franchise of

oilfield equipment and services; its most recent

move was to announce the planned spin-off of its

(relatively newly combined) distribution business.

This has proved a positive trigger for the share

price, but, at least versus our own expectations,

NOV is now at a level where we see somewhat

less potential upside than before. And we see

some offsetting themes in the near term for

NOV’s portfolio – likely decent order intake

(continuing the momentum from Q2) and

potentially better underlying growth from onshore

North American markets (as destocking runs its

course), but we do see some risks that the margin

issues seen in Q2 could continue into the

remainder of this year (at least into Q3).

The Q2 margin dip was particularly in rig

technology and was due to: (1) supply chain

issues arising from accelerated delivery schedules,

with NOV set to commission 55 rigs this year;

(2) product mix, in particular from weaker

demand for land rigs and well intervention across

North America; and (3) start-up costs on capacity

expansion projects. NOV is addressing these

issues; pricing and commercial contract terms are

already changing to take into consideration more

realistic delivery schedules (and NOV indicated

pricing is up a mid-single-digit percentage in Q2).

We expect margins to start to improve over the

next 6-12 months and reach a “normal” strong

cycle level in the mid-twenties percent range in

18-24 months. Elsewhere, the FPSO business is

picking up and overall backlog is strong at

USD13.95bn (1.5x book-to-bill for Rig Tech in

Q2). The other lines of petroleum services and

distribution are performing reasonably well in a

challenging environment (US is down but

international operations are holding reasonably

well). Overall, we continue to see NOV as well

placed in several key market segments – eg,

deepwater, unconventionals – but after a strong

share price performance through Q3, we now see

it as less of a stand-out value case versus its peers.

On our numbers, NOV trades on 2014e multiples

of 12-13x P/E and around 7x EV/EBITDA –

relatively undemanding versus its history and, in

our view, relatively undemanding versus its

medium-term potential.

National Oilwell: Share price chart YTD in USD per share


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National Oilwell Varco

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Schoeller Bleckmann (N(V), TP EUR82) – new

orders troughed in Q4 2012 with quarterly

momentum improving since (P&L should trough

in H2 2013 because of the lag between bookings

and sales). Historically, SBO’s product/service

lines shared a similar margin profile, but lower

utilisation (and some pricing discounts) for its

high-precision components range has put

downward pressure on margins, whereas drilling

motors and repair/service margins have held up

better as volumes have been more resilient. New

product introductions (and new iterations of

existing products) in drilling motors are helping

and there is increased client demand for repair

services (although displacing demand for original

equipment). There is a significant M&A war-chest

and management continues to pursue niche/

technology opportunities. US onshore activity

remains the key driver of SBO, and we expect a

modest pick-up in activity in H2 with this trend

continuing into 2014, but we think the current

share price reflects this.

National Oilwell Varco – book-to-bill (x) for rig technology, 2006-Q2 2013

Source: NOV

Schoeller Bleckmann – share price chart YTD in EUR per share


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Subsea and oilfield equipment sub-sector- EV/EBITDA one-year forward

Subsea and oilfield equipment sub-sector- PE one-year forward


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Evolution of subsea equipment backlogs, 2005-present


Rig orders since 2000

Source: HIS/ODS-Petrodata

Subsea tree order since 2007 and forecasts until 2017e

Source: Infield Systems Ltd; numbers for 2013 onwards are Infield forecasts

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Financials & valuation: Aker Solutions Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e

Profit & loss summary (NOKm)

Revenue 44,922 48,224 53,219 56,511EBITDA 4,739 4,436 5,922 6,980Depreciation & amortisation -1,166 -1,242 -1,405 -1,488Operating profit/EBIT 3,573 3,193 4,517 5,492Net interest -613 -646 -554 -544PBT 2,957 2,298 4,119 5,184HSBC PBT 3,082 2,659 4,119 5,184Taxation -697 -586 -1,050 -1,322Net profit 2,249 1,696 3,058 3,856HSBC net profit 2,345 1,965 3,058 3,856

Cash flow summary (NOKm)

Cash flow from operations 708 4,594 4,143 5,140Capex -2,470 -2,489 -2,129 -1,978Cash flow from investment -1,243 -2,414 -2,054 -1,978Dividends -1,059 -1,080 -1,080 -1,070Change in net debt 1,785 -739 -1,009 -2,092FCF equity -778 1,889 1,659 2,662

Balance sheet summary (NOKm)



Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 12.2 7.4 10.4 6.2EBITDA 37.6 -6.4 33.5 17.9Operating profit 97.2 -10.6 41.5 21.6PBT -56.8 -22.3 79.3 25.9HSBC EPS 105.1 -16.2 55.6 26.1

Ratios (%)


Per share data (NOK)


Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


0.8

Reuters (Equity) AKSO.OL Bloomberg (Equity) AKSO NOMarket cap (USDm) 3,663 Market cap (NOKm) 21,810Free float (%) 58 Enterprise value (NOKm) 26182Country Norway Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

Price relative


415161718191101111121131

415161718191

101111121131

2011 2012 2013 2014Aker Solutions Rel to OBX INDEX

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Financials & valuation: Cameron Neutral (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 8,502 9,913 11,346 12,483EBITDA 1,317 1,528 1,973 2,251Depreciation & amortisation -255 -302 -330 -371Operating profit/EBIT 1,062 1,225 1,643 1,880Net interest -94 -104 -104 -104PBT 940 1,062 1,565 1,826HSBC PBT 973 1,132 1,565 1,826Taxation -188 -244 -368 -429Net profit 752 790 1,096 1,259HSBC net profit 779 844 1,096 1,259


Cash flow from operations 740 646 1,151 1,510Capex -427 -545 -596 -593Cash flow from investment -777 55 -596 -593Dividends 0 0 0 0Change in net debt 111 -631 -556 -917FCF equity 308 91 530 867


Intangible fixed assets 1,924 2,624 2,624 2,624Tangible fixed assets 1,765 1,908 2,174 2,396Current assets 6,911 8,779 10,073 11,518Cash & others 1,703 2,334 2,890 3,807Total assets 11,158 13,870 15,430 17,097Operating liabilities 3,384 4,105 4,570 4,978Gross debt 2,076 2,076 2,076 2,076Net debt 373 -258 -814 -1,731Shareholders’ funds 5,566 6,356 7,452 8,711Invested capital 5,513 6,871 7,411 7,754


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)

Revenue/IC (x) 1.7 1.6 1.6 1.6ROIC 16.7 15.2 17.6 19.0ROE 15.2 14.2 15.9 15.6ROA 8.0 7.2 8.7 9.1EBITDA margin 15.5 15.4 17.4 18.0Operating profit margin 12.5 12.4 14.5 15.1EBITDA/net interest (x) 14.0 14.7 19.0 21.7Net debt/equity 6.7 -3.4 -9.4 -17.5Net debt/EBITDA (x) 0.3 -0.2 -0.4 -0.8CF from operations/net debt 198.3



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information

Share price (USD)60.35 Target price (USD)64.00 6

.0

Reuters (Equity) CAM.N Bloomberg (Equity) CAM USMarket cap (USDm) 14,853 Market cap (USDm) 14,853Free float (%) 100 Enterprise value (USDm) 15,237Country United States Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


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59

64

69

34

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59

64

69

2011 2012 2013 2014Cameron Rel to S&P 500

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Financials & valuation: FMC Technologies Neutral (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 6,151 6,993 8,127 9,385EBITDA 758 961 1,340 1,726Depreciation & amortisation -146 -201 -204 -235Operating profit/EBIT 616 759 1,136 1,491Net interest -27 -41 -41 -41PBT 601 717 1,107 1,469HSBC PBT 590 717 1,107 1,469Taxation -166 -190 -305 -404Net profit 430 522 798 1,060HSBC net profit 422 522 798 1,060


Cash flow from operations 328 1,037 1,001 1,147Capex -406 -420 -406 -375Cash flow from investment -1,020 -420 -406 -375Dividends 0 0 0 0Change in net debt 1,019 -610 -595 -772FCF equity -271 616 587 757


Intangible fixed assets 945 945 945 945Tangible fixed assets 1,432 1,650 1,853 1,993Current assets 3,488 4,130 5,091 6,301Cash & others 342 952 1,547 2,319Total assets 5,903 6,763 7,926 9,276Operating liabilities 2,409 2,747 3,112 3,402Gross debt 1,641 1,641 1,641 1,641Net debt 1,299 689 94 -678Shareholders’ funds 1,837 2,359 3,157 4,217Invested capital 3,115 3,027 3,230 3,518


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)

Revenue/IC (x) 2.6 2.3 2.6 2.8ROIC 19.1 18.2 26.3 32.0ROE 25.9 24.9 28.9 28.8ROA 8.9 8.8 11.3 12.7EBITDA margin 12.4 13.7 16.5 18.4Operating profit margin 10.0 10.9 14.0 15.9EBITDA/net interest (x) 28.7 23.4 32.7 42.1Net debt/equity 70.1 29.0 3.0 -16.0Net debt/EBITDA (x) 1.7 0.7 0.1 -0.4CF from operations/net debt 25.2 150.6 1062.4



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information

Share price (USD)56.09 Target price (USD)56.00 -

0.2

Reuters (Equity) FTI.N Bloomberg (Equity) FTI USMarket cap (USDm) 13,288 Market cap (USDm) 13,288Free float (%) 100 Enterprise value (USDm) 13956Country United States Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


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57

62

32

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62

2011 2012 2013 2014Fmc Technologies Rel to S&P 500

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Financials & valuation: Honghua Group Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 5,068 8,977 9,866 11,724EBITDA 821 1,372 1,581 1,754Depreciation & amortisation -148 -183 -243 -246Operating profit/EBIT 673 1,189 1,338 1,507Net interest 29 -139 -186 -175PBT 709 1,058 1,160 1,340HSBC PBT 709 1,058 1,160 1,340Taxation -168 -212 -232 -268Net profit 529 825 905 1,045HSBC net profit 529 825 905 1,045


Cash flow from operations -508 -841 1,022 553Capex -1,100 -812 -306 -166Cash flow from investment -1,100 -812 -306 -166Dividends -105 -155 -165 -181Change in net debt 971 1,808 -550 -206FCF equity -91 -1,661 707 380


Intangible fixed assets 202 164 133 108Tangible fixed assets 2,969 3,636 3,731 3,675Current assets 6,618 8,937 10,077 11,959Cash & others 984 439 989 1,195Total assets 9,846 12,793 13,998 15,800Operating liabilities 3,272 4,266 4,708 5,618Gross debt 1,983 3,246 3,246 3,246Net debt 999 2,807 2,257 2,050Shareholders’ funds 4,456 5,126 5,866 6,730Invested capital 5,533 8,032 8,244 8,929


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)

Revenue/IC (x) 1.1 1.3 1.2 1.4ROIC 11.3 14.5 13.5 14.3ROE 12.4 17.2 16.5 16.6ROA 7.0 8.6 8.1 8.2EBITDA margin 16.2 15.3 16.0 15.0Operating profit margin 13.3 13.2 13.6 12.9EBITDA/net interest (x) 9.9 8.5 10.0Net debt/equity 21.8 53.2 37.3 29.6Net debt/EBITDA (x) 1.2 2.0 1.4 1.2CF from operations/net debt 45.3 27.0



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


3.2

Reuters (Equity) 0196.HK Bloomberg (Equity) 196 HKMarket cap (USDm) 1,044 Market cap (HKDm) 8,097Free float (%) 30 Enterprise value (CNYm) 9295Country China Sector OIL & GASAnalyst Thomas Hilboldt Contact +852 2822 2922

Price relative


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6

0

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3

4

5

6

2011 2012 2013 2014Honghua Group Rel to HSCEI

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Financials & valuation: Hunting Overweight Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e

Profit & loss summary (GBPm)

Revenue 826 886 968 1,011EBITDA 144 164 196 206Depreciation & amortisation -54 -67 -71 -70Operating profit/EBIT 90 97 125 136Net interest -6 -8 -7 -7PBT 169 84 118 130HSBC PBT 123 127 156 163Taxation -38 -23 -31 -34Net profit 129 59 85 92HSBC net profit 86 89 110 115

Cash flow summary (GBPm)

Cash flow from operations 141 157 168 179Capex -59 -70 -73 -51Cash flow from investment -43 -70 -73 -51Dividends -24 -28 -29 -31Change in net debt -56 -21 -27 -62FCF equity 29 50 57 95

Balance sheet summary (GBPm)

Intangible fixed assets 490 453 416 382Tangible fixed assets 249 288 327 341Current assets 523 588 676 766Cash & others 102 123 149 212Total assets 1,295 1,363 1,453 1,523Operating liabilities 151 188 223 231Gross debt 269 269 269 269Net debt 167 146 119 57Shareholders’ funds 802 833 888 950Invested capital 1,008 1,018 1,047 1,046


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 35.6 7.2 9.3 4.4EBITDA 92.4 14.0 19.6 5.2Operating profit 119.5 7.6 28.7 8.7PBT 67.1 -50.4 41.0 9.5HSBC EPS 57.4 4.4 22.6 4.7

Ratios (%)


Per share data (GBPp)


Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information

Share price (GBPp)785 Target price (GBPp)1,050 3

3.8

Reuters (Equity) HTG.L Bloomberg (Equity) HTG LNMarket cap (USDm) 1,864 Market cap (GBPm) 1,158Free float (%) 84 Enterprise value (GBPm) 1311Country United Kingdom Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

Price relative


474

574

674

774

874

974

1074

474

574

674

774

874

974

1074

2011 2012 2013 2014Hunting Rel to FTSE ALL-SHARE

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Financials & valuation: National Oilwell Varco In Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 20,041 22,235 23,998 25,819EBITDA 4,173 4,051 4,655 5,302Depreciation & amortisation -628 -705 -706 -730Operating profit/EBIT 3,545 3,273 3,949 4,572Net interest -48 -110 -142 -173PBT 3,505 3,179 3,847 4,474HSBC PBT 3,565 3,239 3,907 4,534Taxation -1,022 -1,017 -1,231 -1,432Net profit 2,491 2,170 2,624 3,051HSBC net profit 2,534 2,211 2,665 3,091


Cash flow from operations 85 1,718 2,808 2,907Capex -650 -611 -720 -839Cash flow from investment -2,360 -2,989 -720 -839Dividends -198 -173 -209 -243Change in net debt 2,855 1,380 -1,950 -1,888FCF equity -446 1,154 2,119 2,055


Intangible fixed assets 11,915 13,201 13,201 13,201Tangible fixed assets 2,945 3,943 3,957 4,067Current assets 15,678 15,647 18,251 21,158Cash & others 3,319 1,939 3,889 5,776Total assets 31,484 33,737 36,355 39,372Operating liabilities 3,411 3,675 3,886 4,103Gross debt 3,149 3,149 3,149 3,149Net debt -170 1,210 -740 -2,627Shareholders’ funds 20,239 22,236 24,651 27,459Invested capital 23,808 27,177 27,635 28,547


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 36.7 10.9 7.9 7.6EBITDA 19.5 -4.7 17.0 13.9Operating profit 20.7 -7.7 20.7 15.8PBT 20.0 -9.3 21.0 16.3HSBC EPS 24.5 -13.0 20.6 16.0

Ratios (%)

Revenue/IC (x) 1.0 0.9 0.9 0.9ROIC 12.0 8.7 9.8 11.1ROE 13.4 10.4 11.4 11.9ROA 8.8 6.9 7.7 8.3EBITDA margin 20.8 17.9 19.4 20.5Operating profit margin 17.7 14.7 16.5 17.7EBITDA/net interest (x) 86.9 36.1 32.9 30.6Net debt/equity -0.8 5.4 -3.0 -9.5Net debt/EBITDA (x) 0.0 0.3 -0.2 -0.5CF from operations/net debt 142.0



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


0.0

Reuters (Equity) NOV.N Bloomberg (Equity) NOV USMarket cap (USDm) 33,423 Market cap (USDm) 33,423Free float (%) 100 Enterprise value (USDm) 34210Country United States Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


45505560657075808590

45505560657075808590

2011 2012 2013 2014National Oilwell Varco In Rel to S&P 500

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Financials & valuation: Schoeller-Bleckmann Neutral (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 512 459 540 624EBITDA 160 133 163 191Depreciation & amortisation -40 -39 -44 -47Operating profit/EBIT 120 94 119 144Net interest -7 -4 -4 -5PBT 110 79 113 135HSBC PBT 112 87 113 135Taxation -34 -25 -35 -42Net profit 76 54 77 93HSBC net profit 77 60 77 93


Cash flow from operations 103 128 102 114Capex -53 -50 -40 -34Cash flow from investment -70 -50 -40 -34Dividends -19 -24 -19 -24Change in net debt -9 -40 -33 -45FCF equity 50 80 64 83


Intangible fixed assets 127 120 114 108Tangible fixed assets 165 184 186 178Current assets 376 402 480 556Cash & others 138 184 226 282Total assets 698 735 810 873Operating liabilities 126 128 135 119Gross debt 173 178 187 197Net debt 34 -6 -39 -84Shareholders’ funds 361 392 450 519Invested capital 404 394 418 442


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 25.3 -10.4 17.8 15.5EBITDA 27.9 -17.0 23.1 16.9Operating profit 33.3 -21.9 26.6 20.7PBT 40.8 -28.0 42.2 20.2HSBC EPS 45.5 -23.1 30.0 20.2

Ratios (%)




Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information

Share price (EUR)85.25 Target price (EUR)82.00 -

3.8

Reuters (Equity) SBOE.VI Bloomberg (Equity) SBO AVMarket cap (USDm) 1,855 Market cap (EURm) 1,364Free float (%) 69 Enterprise value (EURm) 1360Country Austria Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

Price relative


38

48

58

68

78

88

98

108

118

38

48

58

68

78

88

98

108

118

2011 2012 2013 2014Schoeller-Bleckmann Rel to ATX

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Sub-sector: Offshore support vessels (OSVs) Stocks covered: GBB

Main sub-sector themes – the offshore support

vessel sector still benefits from growing activity

but continues to weather the impacts of increasing

supply. General delays to offshore work over the

past 12-18 months (plus some major project

postponements – eg, Mad Dog II in the US GoM,

Browse offshore Australia and Hadrian offshore

NE Canada) have also paralleled continued

newbuild efforts across the sector. There are in

many markets clear signs of “asset divergence”

between new and old vessels – based on overall

performance, fuel economy (clients typically pay

for this so this is a material issue) and health &

safety (HSE) issues (particularly where major

Western oil companies are the clients), we expect

this trend will continue.

The overall demand drivers for the industry

remain positive – there have been delays in

offshore construction work, but the industry has

seen continued backlog growth (as at end Q2, we

see total offshore EPC backlogs at around

USD51bn, up 10% y-o-y). Hand in hand with this

is a growing rig fleet, where there is (looking at

all planned newbuilds) a 30% increase in both

floater and jackup rigs over 2012-16. There is a

lower requirement for OSVs in this floater mix,

given the dominance of drillships, but there is still

decent growth in the fleet, although this growth is

less than the 40% or so growth seen over the OSV

fleet in general for 2012-16 (we’d note growth in

the AHTS – anchor handling – fleet is less at 16%

over the same period).

A growing rig fleet – supply CAGR out to 2016

GROWTH Drillships Semi-subs Jackups Floaters overall

2007/08 to 2015/16 276% 43% 58% 88% CAGR 18% 5% 6% 8%

2013 to 2016 47% 9% 17% 21% CAGR 14% 3% 5% 7%

2012 to 2016 83% 9% 30% 30% CAGR 16% 2% 7% 7%

Source: IHS/ODS Petrodata

There has also been continued growth in subsea

support work, although we’d note these markets

face similar challenges from supply-side growth,

and certain players are making efforts to

restructure their position in this business (such as

Fugro). But subsea markets are looking more

promising in terms of growth than offshore

overall – subsea installation backlogs at end

Q2 2013 totalled around USD35bn, up 20% y-o-y.

Offshore support vessels: Relative share price chart since the start of 2013

Source: Thomson Financial Datastream

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Bourbon AverageDof Asa Farstad Shipping AsaSolstad Offshore Asa Havila Shipping AsaTidewater Inc. Gulfmark Offshore, Inc.Bumi Armada Bhd

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In terms of vessel classes, the AHTS segment is

still under some pressure, although the amount of

newbuilds due to market versus the current fleet is

now around 10% (this proportion has halved

versus that in mid-2011). North Sea spot market

rates look better on average for 2013 versus 2012

by 20-30%, although recent rates have weakened

to close to 2012 levels; rates for the larger/high-

end vessels have improved in Q2 versus Q1. This

stronger performance from higher-end vessels

continues to be a theme in most OSV categories –

echoing the ‘asset divergence’ theme.

Through the 2013 summer season in the North

Sea, demand for larger vessels improved and

absorbed more supply from the spot market, and

longer term the balance of increasing

development activity and a higher rig count looks

positive for demand. There is new supply set to

enter the North Sea market in the next 12-18

months, but as we’ve noted, the overall level of

new supply for the AHTS segment is less onerous

than that for PSVs.

Global fleet of AHTS and relative newbuild share

Source: Farstad, NB AHTS = anchor handling supply vessel

There is still overall oversupply in the PSV

segment; the relative number of newbuilds due to

market has been around 40% of the size of the

existing fleet since end-201 and remained at this

level as at mid-2013, implying a significant

supply overhang in the medium term.

The more specialised North Sea market has

proved better, though, and peak spot market rates

look higher this year versus 2012 and 2011

(around 20% higher). This has been helped by

growth in activity across the board, including

good growth in production support and drilling

support work.

The North Sea season also looks set to see better

term contract demand, but slightly less spot

demand in 2014, so given a slightly larger fleet,

we see overall utilisation rates similar or slightly

below those from this year (peaked in June around

95-96%) – still close to 95% (and also the

seasonal Q4/Q1 low point looks slightly stronger

than that in Q4 12/Q1 13 at around 88%). The

overall annual utilisation for this year in the North

Sea looks similar to that seen in recent years at

around 90%, but there is a potential supply

overhang from new larger PSVs that could enter

the North Sea market over the next 6-12 months.

Global fleet of PSVs and relative newbuild share

Source: Farstad, NB PSV = platform supply vessel

For both main market segments – PSVs and

AHTS – an overall improvement in the North Sea

therefore really needs other regions to see a more

sustained improvement in demand to pull vessels

out of the market on term work. The decent

growth in offshore and subsea backlogs – as well

as significant expansion in the offshore rig fleet –

bodes well for the potential to see this happen

through the medium term (although it is important

the market sees an increasing net number of rigs,

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not just in the number of new rigs coming to

market, given numerous retirements). This

‘offshore dynamic’ should make the OSV

segment one of the most obvious beneficiaries of

the growing rig fleet/offshore construction theme;

the challenge remains with the level of supply

growth that is set to come to market.

The overall demand growth looks well supported

with work from Africa (west and east); several

newer players have pitched vessels into Brazil as

well (we think most of the Western players see

Brazil as a “necessary evil” – too big to ignore but

a tough market in which to make decent returns –

but there are signs that this market is improving,

as international oil companies commit more

development spend into the region).

There are also decent volume growth

opportunities in Asia/Australia (and rates have

seen slight improvement in Asia); although no

effect is evident yet, there are concerns that the

demand picture could be affected by the

postponement and re-think over the Browse

project. The main challenge for this region is

continued oversupply of vessels – around 40% of

newbuild vessels are assembled in China and

often seek initial work in the Asian market.

Main stocks and changes in this report – we

have made no changes to our assumptions for

Bourbon (the only OSV name we cover). Post

Bourbon’s H1 results, we did lower our EPS

forecasts significantly, but this was mostly

delayed and lower one-off gains on vessel sales,

following changes in our expectations for the

timing of (and one-off P&L gains from) its major

vessel sale/leaseback plans.

Bourbon (OW(V), TP EUR28) – we think

Bourbon’s investment case remains attractive,

although clarity over the group’s bottom line is

likely to remain mixed, while the proposed

USD2.5bn sale-and-leaseback transactions

(announced earlier this year) work through the

group’s financials. These are progressing –

contracts are signed for the first tranche of 51

vessels for a total of around USD1.5bn (these

transactions should be completed over the next 10

months). Otherwise, the core business is in decent

shape – deepwater offshore markets are seeing

good demand in Africa (day rates increasing due

to strong utilisation levels), and shallow water

markets are set for decent growth in the medium

term with significant deliveries of new jackups to

market (on average, a jackup needs two to four

PSVs to support). With this backdrop of a

growing rig fleet, growing offshore construction

markets and expanding production support work,

we think Bourbon's fundamentals look quite

robust, and we maintain our positive stance.

Bourbon offshore share price chart YTD in EUR per share


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A growing offshore rig fleet, 1970-2020

Source: IHS Petrodata

Offshore support vessels sub-sector EV/EBITDA one- year forward

Offshore support vessels sub-sector PE one-year forward


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Current fleet positioning across the supply vessel fleet (as at end H1 2013)

Source: Farstad, NB AHTS = anchor handling supply vessel, PSV = platform supply vessel

Current and future size of the supply vessel fleet (1998-2016e)


Historical and future y-o-y growth in supply across the supply vessel fleet (1998-2016e)


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Financials & valuation: Bourbon Offshore Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e




Cash flow from operations 252 328 403 511Capex -376 -454 -448 -330Cash flow from investment -373 26 745 -399Dividends -53 -29 -89 -69Change in net debt 106 -313 -1,113 -77FCF equity -124 -125 -46 181


Intangible fixed assets 42 42 42 42Tangible fixed assets 3,327 3,610 3,580 3,740Current assets 676 748 1,150 1,273Cash & others 195 195 473 493Total assets 4,109 4,580 4,980 6,064Operating liabilities 424 1,094 1,973 2,839Gross debt 2,256 1,943 1,108 1,050Net debt 2,061 1,748 635 558Shareholders’ funds 1,339 1,454 1,809 2,085Invested capital 3,425 3,111 2,326 1,723


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 17.8 17.8 25.9 17.3EBITDA 27.7 23.3 17.2 12.4Operating profit 63.0 53.8 68.1 25.9PBT 443.3 177.6 149.8 -20.6HSBC EPS 265.4 150.5 246.6 42.3

Ratios (%)




Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 2.9 2.3 1.2 1.0EV/EBITDA 9.1 6.7 3.7 3.3EV/IC 1.0 1.0 0.9 1.2PE* 51.3 20.5 5.9 4.2P/Book value 0.9 0.9 0.8 0.7FCF yield (%) -8.7 -8.8 -3.2 12.6Dividend yield (%) 4.1 2.0 6.2 4.8


Issuer information


0.2

Reuters (Equity) GPBN.PA Bloomberg (Equity) GBB FPMarket cap (USDm) 2,025 Market cap (EURm) 1,489Free float (%) 100 Enterprise value (EURm) 3237Country France Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


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Sub-sector: Floating production (FPSO) Stocks covered: BWO, BAB (Bumi Armada), SBMO

Main sub-sector themes – there has been a

perception over recent years that FPSO markets

have lacked activity; growth may have been

lacking but there has been a reasonable number of

new contracts in the past three to four years.

FPSO project awards in recent years

Source: SBM Offshore, as at H1 2013

There have been fewer large newbuild awards

(more an issue for the EPC side of the industry –

shipyards as well as some FPSO specialists), but

several smaller and larger lease awards have been

coming to market. This reflects the ongoing

growth in offshore capex and the inevitable

progression of development spending towards

floating production solutions.

Constituents of the current floating production fleet

Source: BW Offshore, as at H1 2013

But FPSO markets have up to now generally

underperformed other offshore sub-sectors either

in terms of improving (visible) returns (such as

the trend seen in offshore drilling) or in terms of

growing backlog (versus that seen in offshore

installation – notwithstanding the exception of

SBM Offshore, where backlog has grown

substantially due to major new work in Brazil, and

also in the deepwater US Gulf).

In recent years, the many delays in project awards

have been for a variety of reasons, including

tighter redundancy requirements on topsides and

other equipment, and hence project re-designs

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(driven especially by the changing behaviour of

international oil companies post the Macondo

spill in the US Gulf in 2010).

The main growth in activity in the past 12-18

months – particularly in terms of value – has been

more at the large/complex vessel end of the

market. This has centred on Brazil, where the

ultra-deepwater market has opening up for

selected large presalt projects to

international/local partnerships (mainly to the

benefit of SBM Offshore and its partners; in

addition, these recent contracts look to be at better

economics than others in recent years). The

activity at the lower/smaller-vessel end of the

market is still highly competitive, particularly due

to aggressive local players – and we think that

competition is likely to grow in some regions at

the top end as well (eg, in Brazil).

In addition to Brazil, the offshore fabrication market

is seeing some signs that potential cost inflation (and

the risk of delays to first oil) is helping lower-priced

“non-local” content to be more acceptable to

national oil companies elsewhere – eg, recent

comments from AOG (African Oil & Gas,

September 2013) indicated that there are early

indications Sonangol may be easing back on

stringent local content requirements in order to cap

project inflation and improve project economics.

AOG suggested DSME will win the South N’Dola

platform job with minimal local content (deck built

in South Korea; the jacket elsewhere in Asia) despite

Sonangol initially insisting on in-country fabrication

for both jacket and deck. According to the article,

DSME’s proposal is over 30% cheaper than the local

content-compliant offer from Petromar/Sonamet.

In terms of the medium-term market outlook, BWO

sees around 10-15 project awards per year over the

medium term (this view has not really changed for

the past 12-18 months). SBM Offshore sees 54

projects on a three-year horizon, split roughly 60%

lease and 40% build/EPC (or as yet unclear whether

sale or lease). As at the mid-year point, Modec saw

around 25 FPSO projects on its ‘potential projects’

radar screen, as well as two to three potential FLNG

projects. We think securing growth in this market is

likely to prove quite region-dependent (eg, strong

regional and growing international players like

Bumi Armada look well placed for growth in their

local markets, but face quite aggressive local

competition from smaller players).

FLNG – we do not intend to run through a detailed

analysis of the FLNG market in this report, but

we’d note this area is where significant pre-

FEED/design interest is now from oil companies

(the Australian Government is setting up an FLNG

hub/centre of excellence in Perth). Currently, there

are seven to eight projects/prospects (equivalent to

10 vessels) on the horizon:

Snapshot of potential FPSO projects (as at mid-2013)

Africa SE Asia & Pacific Brazil Gulf of Mexico

Kosmos MAT FPSO, Ghana CSJOC Block 10/11 FPSO, Vietnam

Carioca FPSO Pemex Ta'Kuntah FSO extension

ENI FPSO, Ghana Chevron Thai Ubon FPSO/FSO, Thailand

Tartaruga Verde e Mestica FPSO Pemex Ayatsil FPSO

Total Block 32 FPSO, Angola Petronas FLNG 2, Malaysia Parque dos Doces FPSO Hess Stampede TLP BP Block 18 FPSO, Angola JX Layang FPSO, Malaysia Deep Waters Sergipe FPSO Noble Gunflint semi-sub BP Block 31 FPSO, Angola INPEX Masela FLNG, Indonesia Sul de Parque des Baleias FPSOMaersk Chissonga FPSO/TLWP, Angola

Noble Leviathan gas, Israel Maromba FPSO

Cobalt Block 21 FPSO, Angola Brunei FPSO Carcara FPSOTullow Kudu FPS, Namibia Woodside Lady Nora FPSO,

Australia Gunambi GTL FPSO

Woodside Laverda FPSO/semi-sub, Australia

Source: Modec

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GDF's Bonaparte – this is in the competitive

concept definition stage, down to TEC versus

KBR, expect FEED by year end then move to

EPC; and need to set up the yard partnerships

for construction work (JP Kenny doing the

subsea engineering).

The 'new' Browse FLNG – following the

Shell model so TEC/Samsung well placed for

this one, and FEED looks set for mid-2014,

and taking FID likely mid-2015; ultimately this

will be three vessels but will be phased.

XOM's Scarborough – this benefits from a dry

gas feed so the design can handle larger LNG

topsides (will be 6-7mtpa, so 2x Prelude’s

capacity) – currently looks like

Chiyoda/Saipem for the main job and TEC’s

Genesis for the subsea engineering.

PTTEP's Cash/Maple – this is in pre-FEED at

present, and it looks like competition is

Hoegh/KBR versus SBM/Linde. This will be

unusual versus other FLNG as it is likely to be

a leased vessel; in this context, it is worth

noting SBM’s FLNG designs for a mid-sized

vessel (effectively two LNG tankers joined

side by side and one front tank on each side

removed to make space for the LNG

equipment). Also, Hoegh LNG announced

recently that it had won a pre-FEED study on

a FLNG project for an "un-named" Asian

client (with full FEED likely in H1 2014).

Sunrise – this actually was on the board

pre-Prelude but was delayed due to (ongoing)

border/scope of work disputes with East

Timor (which wants onshore LNG to boost

employment, not FLNG).

Echuca Shoals (early stage) – in the Browse

basin, 100% owned/operated by Nexus

Energy; Nexus said in June this year that

Echuca plus other prospects under the same

permit gave enough potential gas volumes to

support FLNG (total of just over 5Tcf).

There’s also the Crux field that Nexus saw as

a potential FLNG project (FID for this is

more like a 2015-17 timeframe).

Arnhem/Pinhoe (early stage) – 50/50

ownership between Shell and Chevron, these

fields are seen by Shell (comments from

Q1 2013) as potentially large enough to

support a FLNG development.

FPSO vessel topside weight trends, 1990s-recent major awards

Source: SBM Offshore

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Main changes in this report – the main changes

we’re making are to update our views on SBM

Offshore for recent project awards and other

newsflow, and also update for some shifts in FX

pairs (using USD/EUR 1.35 from 1.30 before).

Bumi Armada (N, TP MYR4.20) – we like

BAB’s strengths in engineering control, its

de-risked bareboat charter structure and

aggressive depreciation policy, lowering asset

redeployment risk – the company continues to

deliver 'best-in-class' EBITDA margins of c45-

50%. But new projects have not quite materialised

at the pace of two per year that the company was

previously targeting. This order scarcity has been

an industry-wide issue with 2012 seeing just four

to five awards globally (of which BAB won nil)

and YTD 2013 just slightly better – and

competition has also increased with fewer

contracts to go around. We think award delays are

not a near-term ‘timing’ issue but almost the new

norm as discussions with companies and industry

consultants suggest. Key reasons are: 1) technical

delays related to evolving additional regulator-

driven safety requirements; 2) growing local

content requirement from Asian and African

governments (Brazil already there), increasing

project timelines; 3) re-pricing round from oil

companies (can add three to four months) due to

#1 and #2.

BW Offshore (OW(V), TP NOK10 from NOK9)

– BWO spent a significant amount of its time

during 2011/12 in the “distressed equity story”

category, thanks to a number of operational

challenges, necessary but unexpected vessel

upgrades and an unclear financial liability from the

problematic Papa Terra project in Brazil. But

gradually BWO’s fleet has returned to a position to

be able to earn “run-rate cash flow”, the Papa Terra

situation has been largely sorted out (BWO took a

USD15m charge owing to an extension of the yard

stay and some additional work scope) and uptime

across the fleet has been robust; group EBITDA for

H1 2013 reached USD225m (an annual run-rate of

USD450m, assuming no fleet changes).

BWO now sits with a USD7.8bn backlog, giving

visibility out to 2022 (USD3.7bn of this is from is

firm contracts, with the remainder from contract

options; the group’s current customer split is 26%

NOC, 41% IOC and E&P, and 33% Petrobras). The

group has decent liquidity (USD400m on tap) and

the shareholder return angle continues to improve in

line with BWO’s underlying EBITDA. The aim is to

distribute 20-25% of EBITDA, and BWO has

distributed 22% of EBITDA since Q1 2011

(although the quarterly dividend has been somewhat

volatile while group EBITDA was under pressure

from problem contracts and additional necessary

maintenance/upgrade work). The run rate EBITDA

from H1 supports an annual payout of some

USD90-113m, equivalent to a yield of 10-12%.

In our assumptions for BWO, we still expect one

additional medium-sized FPSO (as yet

unannounced) that starts up end 2014/early 2015, so

our assumptions for capex are significantly higher

for 2013e overall than the run-rate implied for H1. If

such a new contract is not awarded this year, BWO’s

cash flow is likely to prove significantly stronger

than our expectations (but its medium-term growth is

likely to be lower); this could give BWO the

confidence in the near term to pay out dividends near

the top end of its guided 20-25% range.

Bumi Armada: Share price chart YTD in MYR per share


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In terms of growth on the horizon, BWO is seeing

market opportunities more from the Gulf of

Mexico (particularly the Mexico side, where it has

significant experience in operations), Africa and

Europe/Mediterranean. BWO also sees further

profitable opportunities from vessel

redeployments, in some cases using vessels that

were originally constructed in the 1970s but

continue to find new leases of (contracted) life –

five key good cases of redeployments in the

recent past are with the vessels BW Athena,

Cidade de Sao Vicente, Petrolia Nautipa, Berge

Helene and Sendje Berge. This redeployment

angle is important for the influence it has on

vessel asset value – BWO sees asset value for its

BW Athena at USD500m and USD700m for the

BW Pioneer (currently in the US Gulf) – as a

comparison, its current market value is around

USD925m (EV around USD2.6bn).

Overall, BWO is no longer the distressed recovery

story it was in 2012 and no longer offers the

classic “high-risk/high-return” opportunity to

investors it did in the past, but this remains, in our

view, an attractively valued story with good cash

flow, promise of continued high-yielding dividend

payments and the potential for further growth

from a recovering FPSO market.

We’ve updated our assumptions for BWO for

recent contract extensions (some improved dayrates

for selected vessels) and also pushed out our

assumption of a new lease project start-up (had

assumed late 2014, now assuming mid/late 2015) –

this has had little effect on our earnings near term

but hits 2015e (delayed start-up of new project

EBITDA); the offset is, we assume, lower capex in

the near term (especially for 2013e). We also shift

our FX assumption for USD/NOK to 5.95 from

5.75. The net effect on our valuation is positive and

our target price moves up to NOK10 from NOK9.

BW Offshore changes to P&L forecasts (in USDm, EPS in USD)


Sales 909.4 882.7 828.7 899.7 918.0 EBITDA 246.7 445.2 427.6 474.0 471.0 EBITDA (incl assoc) 247.6 446.4 429.4 476.3 472.8 EBIT 93.7 191.0 188.7 215.2 207.5 EBIT (incl assoc) 94.6 192.2 190.5 217.5 209.2 EPS 0.00 0.16 0.14 0.15 0.15

PREVIOUS FY2013e FY2014e FY2015e FY2016e Sales 854.8 835.2 939.2 912.8 EBITDA 437.6 428.4 496.9 484.3 EBITDA (incl assoc) 438.8 430.2 499.2 486 EBIT 191.0 187.7 227.3 222.2 EBIT (incl assoc) 192.2 189.5 229.6 223.9 EPS 0.16 0.14 0.17 0.17

change (%) FY2013e FY2014e FY2015e FY2016e Sales 3.3% -0.8% -4.2% 0.6% EBITDA 1.7% -0.2% -4.6% -2.7% EBITDA (incl assoc) 1.7% -0.2% -4.6% -2.7% EBIT 0.0% 0.5% -5.3% -6.6% EBIT (incl assoc) 0.0% 0.5% -5.3% -6.6% EPS -1.7% 1.1% -9.5% -11.0%

Source: Company Data, HSBC forecasts for 2013e onwards

BW Offshore: Share price chart YTD in NOK per share


SBM Offshore (N(V), TP EUR17 from

EUR14.72) – the past 18-24 months have been a

period of immense change for SBM. The group

has faced major legacy project problems and

negotiations (especially with Talisman’s Yme

project), capital raising (in total USD463m from

private placements in December and March, plus

a rights issue in April) and various non-core

disposals (sale & lease of Monaco real estate, sale

of Gusto MSC and the cryogenic hose technology

and a possible sale of the SBM Installer vessel).

More recently, SBM has seen the largest project

wins in its history, taking backlog to over

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USD22bn (on a directional accounting basis). The

group’s positioning as a top-tier lease FPSO

player has positioned it almost perfectly as the

key international beneficiary of Petrobras’ move

to allocate (selectively) more of its presalt floating

production needs to the lease market. There is also

the USD2.1bn (10-year lease) contract SBM won

recently from Shell for the ultra-deepwater Stones

project in the US Gulf. We think there are also

signs that the terms of these more recent contracts

are improving – we think these are more likely to

be back firmly in the target 12-14% IRR band.

SBM’s capacity for large projects is clearly filling

up, but there is likely more for SBM to chase – for

instance, smaller-scale FLNG (we'd note SBM has

been marketing a specific concept model here –

linking two converted LNG tankers). But we think

material backlog growth from here could be more

difficult, so in effect most of SBM’s new project

growth is now visible (if not so easily forecastable).

We still see opportunities from redeployments of

existing FPSO vessels, so there could be additional

upside from this theme over the medium term.

One challenge – which SBM has worked on quite

intently – is the transparency of its financials,

namely the operating/finance lease issues (IAS 17

rules on leases) that in recent years have

somewhat clouded the 'forecastability' of its

financials (especially cash flow).

The group now gives both IFRS and 'directional'

reporting (more in line with the real structure of

the business and its cash flows – an operating

lease presentation) and as of next year will guide

on a 'directional' basis. So apart from the

challenge for most observers of having to run two

parallel/linked models (one IFRS, one

'directional'), SBM’s finances should be clearer

(or at least clearer to forecast).

That said, although the finance lease issues have

caused some confusion in recent years, we don't

think SBM's valuation has particularly suffered.

For one, the legacy issues (Yme, Deep Panuke)

were a much greater impact, but also we think most

financial market models were (or still are)

relatively simple to the point that the cash flow

'missing' (due in later years) from reported finance

lease figures was at least partly recognised in

forecasting a higher LSTK revenue line and higher

LSTK margins (and letting this flow through the

P&L and cash flow – incorrectly in terms of how it

should be recognised under the finance lease

structure, but recognised nevertheless).

And in terms of valuations, when we first factored

in the finance lease effects (several years ago), we

also reduced the multiple we used to value the

LSTK business in our sum-of-the-parts model (so

our valuation reflected the greater volume of work

but not the materially higher margin (11-12%

versus SBM’s old LSTK guidance for 5-10%).

Our changes to our assumptions reflect SBM’s

recent major contracts as well as our own

assumptions over likely margins in the medium

term (and SBM’s own guidance for 2013 –

revenues of USD4.3bn on an IFRS basis), as well

as various one-off gains that boost 2013e. Our

changes are in general positive for our EPS

forecasts, and our target price moves up to

EUR17 from EUR15 before.

SBM key IFRS P&L changes (in USDm, EPS in USD)


Sales 3,695.3 4,338.0 4,301.5 4,501.0 4,755.8 EBITDA 770.6 974.0 999.2 1,003.8 949.7 EBIT 550.0 436.4 717.5 716.1 648.7 Net (post mins) -79.5 292.0 560.7 566.2 521.1 EPS -0.46 1.44 2.70 2.68 2.39

PREVIOUS FY2012a FY2013e FY2014e FY2015e FY2016e Sales 3,891.3 4,285.7 4,778.3 4,666.0 EBITDA 832.0 981.7 970.7 907.6 EBIT 323.3 706.3 682.4 607.1 Net (post mins) 186.8 544.0 525.7 471.7 EPS 0.92 2.62 2.49 2.17

change (%) FY2012a FY2013e FY2014e FY2015e FY2016e Sales 11.5% 0.4% -5.8% 1.9% EBITDA 17.1% 1.8% 3.4% 4.6% EBIT 35.0% 1.6% 4.9% 6.9% Net (post mins) 56.3% 3.1% 7.7% 10.5% EPS 56.3% 3.1% 7.6% 10.2%


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SBM Offshore: Share price chart YTD in EUR per share


FPSO sub-sector EV/EBITDA one-year forward FPSO sub-sector PE one-year forward


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Water depth progression for key FPSO projects (by date of 1st oil)

Source: SBM Offshore, as at H1 2013

SBM's view on the outlook for new FPSO project activity (as at end Q1 2013)

Source: SBM Offshore

FPSO markets - split between converted and newbuild vessels (as at end 2012)

Source: SBM Offshore, HSBC estimate for 2012

Kuito

Espadarte

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Financials & valuation: BW Offshore Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 909 883 829 900EBITDA 247 445 428 474Depreciation & amortisation -227 -254 -239 -259Operating profit/EBIT 94 191 190 217Net interest -66 -53 -64 -81PBT 29 139 126 137HSBC PBT -45 139 126 137Taxation -29 -31 -29 -31Net profit 0 108 97 106HSBC net profit 0 108 97 106


Cash flow from operations 153 342 333 369Capex -228 -207 -290 -202Cash flow from investment -38 -207 -290 -202Dividends -41 -72 -93 -99Change in net debt -48 -86 30 -89FCF equity -63 135 43 167


Intangible fixed assets 190 187 184 182Tangible fixed assets 2,700 2,656 2,710 2,656Current assets 339 616 540 639Cash & others 102 188 159 248Total assets 3,241 3,482 3,466 3,519Operating liabilities 510 693 673 727Gross debt 1,779 1,779 1,779 1,779Net debt 1,677 1,591 1,620 1,531Shareholders’ funds 1,127 1,194 1,209 1,218Invested capital 2,617 2,578 2,602 2,502


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 7.5 -2.9 -6.1 8.6EBITDA -20.8 80.3 -3.8 10.9Operating profit -83.9 823.9 -0.9 14.2PBT -42.1 385.8 -9.4 8.2HSBC EPS -100.0 -10.0 8.7

Ratios (%)




Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 2.9 2.8 3.1 2.7EV/EBITDA 10.5 5.6 5.9 5.2EV/IC 1.0 1.0 1.0 1.0PE* 8.6 9.5 8.8P/Book value 0.8 0.8 0.8 0.8FCF yield (%) -6.7 14.5 4.6 17.9Dividend yield (%) 4.4 8.9 10.4 10.8


Issuer information


4.5

Reuters (Equity) BWO.OL Bloomberg (Equity) BWO NOMarket cap (USDm) 908 Market cap (NOKm) 5,403Free float (%) 100 Enterprise value (USDm) 2494Country Norway Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

Price relative


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Financials & valuation: Bumi Armada Neutral Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e

Profit & loss summary (MYRm)

Revenue 1,659 1,815 2,222 2,256EBITDA 860 925 1,218 1,571Depreciation & amortisation -356 -344 -502 -885Operating profit/EBIT 504 581 716 686Net interest -114 -78 -71 -68PBT 469 583 728 729HSBC PBT 469 583 728 729Taxation -81 -86 -108 -104Net profit 386 494 616 621HSBC net profit 386 494 616 621

Cash flow summary (MYRm)

Cash flow from operations 1,027 1,374 1,124 1,357Capex -893 -886 -586 -1,078Cash flow from investment -1,003 -886 -586 -1,078Dividends -88 -99 -123 -124Change in net debt 407 -265 -258 -34FCF equity -61 324 358 108

Balance sheet summary (MYRm)

Intangible fixed assets 1 1 1 1Tangible fixed assets 5,313 5,855 5,939 6,132Current assets 1,444 1,091 1,367 1,423Cash & others 501 548 670 680Total assets 6,930 7,158 7,562 7,881Operating liabilities 439 487 547 378Gross debt 2,668 2,450 2,314 2,291Net debt 2,167 1,902 1,644 1,610Shareholders’ funds 3,750 4,145 4,638 5,135Invested capital 5,820 5,913 6,091 6,497


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 7.5 9.4 22.4 1.5EBITDA 10.5 7.6 31.7 29.0Operating profit 11.7 15.2 23.3 -4.2PBT 7.5 24.4 24.9 0.1HSBC EPS -10.0 28.1 24.6 0.8

Ratios (%)


Per share data (MYR)


Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information

Share price (MYR)3.95 Target price (MYR)4.20 6

.3

Reuters (Equity) BUAB.KL Bloomberg (Equity) BAB MKMarket cap (USDm) 3,622 Market cap (MYRm) 11,579Free float (%) 30 Enterprise value (MYRm) 13294Country Malaysia Sector ENERGY EQUIPMENTAnalyst Neel Sinha Contact +65 66580606

Price relative


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2011 2012 2013 2014Bumi Armada Rel to KLSE COMPOSITE INDEX

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Financials & valuation: SBM Offshore Neutral (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 3,695 4,338 4,302 4,501EBITDA 771 974 999 1,004Depreciation & amortisation -848 -268 -282 -288Operating profit/EBIT -77 436 717 716Net interest -87 -87 -91 -88PBT -36 350 627 628HSBC PBT -36 350 627 628Taxation -38 -43 -47 -47Net profit -79 292 561 566HSBC net profit -79 292 561 566


Cash flow from operations 703 335 864 857Capex -643 -525 -580 -475Cash flow from investment -301 -525 -580 -475Dividends -99 0 -280 -140Change in net debt -176 -73 -283 -241FCF equity 60 10 284 382


Intangible fixed assets 29 29 29 29Tangible fixed assets 2,482 2,740 3,038 3,225Current assets 2,939 3,231 3,357 3,563Cash & others 748 785 926 1,047Total assets 6,335 6,886 7,310 7,703Operating liabilities 2,172 2,188 2,174 2,143Gross debt 2,531 2,495 2,353 2,232Net debt 1,783 1,710 1,427 1,185Shareholders’ funds 1,469 2,039 2,620 3,164Invested capital 2,529 3,027 3,324 3,627


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue 17.1 17.4 -0.8 4.6EBITDA -2.8 -8.6 41.9 0.5Operating profit 64.4 -0.2PBT 79.2 0.1HSBC EPS 87.7 -0.7

Ratios (%)

Revenue/IC (x) 1.5 1.6 1.4 1.3ROIC -6.3 13.8 20.9 19.1ROE -5.8 16.6 24.1 19.6ROA 2.3 6.3 9.9 9.4EBITDA margin 20.9 16.2 23.2 22.3Operating profit margin -2.1 10.1 16.7 15.9EBITDA/net interest (x) 8.9 8.1 11.0 11.4Net debt/equity 115.8 81.0 53.0 36.6Net debt/EBITDA (x) 2.3 2.4 1.4 1.2CF from operations/net debt 39.4 19.6 60.6 72.3


EPS Rep (fully diluted) -0.46 1.44 2.70 2.68HSBC EPS (fully diluted) -0.46 1.44 2.70 2.68DPS 0.00 0.00 1.35 1.34Book value 7.79 9.83 12.62 14.76

Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 1.6 1.4 1.3 1.2EV/EBITDA 7.8 6.1 7.6 7.6EV/IC 2.0 1.7 1.5 1.3PE* 14.2 7.6 7.6P/Book value 2.3 2.0 1.6 1.3FCF yield (%) 1.2 0.2 5.6 7.5Dividend yield (%) 0.0 0.0 6.6 6.6


Issuer information


3.6

Reuters (Equity) SBMO.AS Bloomberg (Equity) SBMO NAMarket cap (USDm) 4,234 Market cap (EURm) 3,114Free float (%) 100 Enterprise value (USDm) 5110Country Netherlands Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

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Sub-sector: Well services Stocks covered: 3337 HK (Anton Oil), CLB, FUR, SLB, 1251 HK (SPT)

Main sub-sector themes – the well services

market has seen three major themes in particular

through this year – stabilisation of the market in

North America, growth of the market in

international markets outside North America and

stronger growth of the market in certain evolving

areas like China (where the industry is taking its

first steps in shale gas work). Overall, profitability

is stabilising for the mainstream players, with Q2

this year seeing sales up y-o-y, but margins

slightly lower (160bp down). The sequential

improvement Q2 versus Q1 was the most positive

step-up seen for two years, due largely to an

improving US market and signs of pricing

strength in international markets.

For onshore markets in North America there has

been continued destocking through various parts of

the value chain during H1 this year (using up

consumables as the industry adjusts to a rig count

of around 1,700, versus industry expectations from

last year that this would likely be a 2,000-rig

industry for 2013). We continue to expect the

medium-term outlook to be one of a return to

moderate growth (mid-single-digit percent at best).

Major well services – year-on-year top-line growth versus margin spread, 2005-Q2 2013

Source: Company data, NB data is average of SLB, BHI, HAL, WFT

One other important angle working through the

industry in North America this year is a lessening of

the raw material cost increases that caused margin

pressure for some players last year (eg, guar gum

and certain proppants/specific grades of sand). We’d

also note more evidence of the structurally higher

importance and value of advanced chemicals in the

unconventionals extraction process – European

chemical player Solvay recently announced the

USD1.4bn acquisition of US oil & gas specialty

chemicals player Chemlogics. Solvay sees the US oil

& gas-related chemicals market as worth around

USD8bn this year, versus a global market worth

around USD14bn, and sees a market CAGR of 6%

R² = 0.9239

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Well Services: Relative share price chart since the start of 2013


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over the medium term. The value split for chemicals

usage is dominated by stimulation (worth around

USD5bn out of the USD8bn US market this year).

Split by value of the US oilfield chemicals market (2013 data)

Source: Solvay

Average oilfield chemicals cost per rig per day

(in USD/rig/day) Vertical well Horizontal well

Stimulation 700 500 Drilling 1,100 11,000 Total 1,800 11,500

Source: Solvay (based on 2012 data)

The overall growth pattern from the North

American market will, we think, continue to

reflect the balance between increasing service

intensity, drilling efficiency gains (10% per year

on average, so fewer rigs but more footage drilled

and more consumables used) and a moderate level

of growth in the overall rig fleet. Along with a

growing offshore rig fleet in the US GoM

(especially ultra-deepwater), we think this should

underpin moderate growth overall. Margin

improvements should follow, but we think there is

still some pressure pumping capacity that was

deliberately idled by the main players (in H1) that

has to come back to market; this is likely to be at

least some drag on the speed of margin

improvement in the next few quarters.

Markets outside North America should continue

to grow and also – importantly – should continue

to see some margin upside, continuing the

positive momentum we’ve seen through Q1 and

Q2 this year. This has been due to growth from

certain regions – eg, Russia, some parts of LatAm,

the Middle East and China – and also to the

inevitable pick-up in offshore activity and related

services with the ongoing growth in the global

offshore rig fleet and expansion of backlog for

offshore construction work.

Oilfield services in China – the oilfield services

market in China has been one of the few

perceived ‘boom’ areas in the sector this year.

Market expectations for growth are perhaps not as

aggressive as they were earlier this year (and we’d

note the dramatic share price acceleration this

space saw in H2 2012).

But in the medium term, the OFS market in China

looks positioned for growth; the market is

expanding and expectations for aggregate market

growth in drilling, completion, reservoir and

stimulation are in the 8-15% pa range or

USD11-14bn in total new value to 2020e

according to estimates from both SPT and

PetroKing. The unlisted OFS businesses at the

parent company levels of CNPC and Sinopec

Group continue to dominate more than 80% of the

onshore market value for drilling, completion and

reservoir services (2013e USD18.1bn). While

offshore, COSL captures c50% of the OFS

spending by its sister company CNOOC. COSL is

increasing both offshore China deep-water

capabilities and experience, and expanding

incrementally overseas in drilling, supply and

seismic in the key Middle East, North Sea and

potentially the North American market.

We see two key pillars increasing onshore service

intensity: accelerating decline rates at mature

oilfields and increasing use of more sophisticated

drilling and service activities in new production due

to depth, pressure and low reservoir permeability.

production31%

stimulation61%

drilling & cementing

8%

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Production enhancement – as a longer-term

theme, we believe the mainstream well services

players will continue to target production

management/enhancement work (although this is

likely to be quite selective in terms of the

regions). So far, in recent years certain players –

mostly from well services – have invested in

production enhancement/drilling management

work. This has been a successful route to reinvest

cash for longer-term returns, but has not been

without its operational challenges, and has seen

aggressive pricing behaviour in some markets (eg,

drilling management contracts in Northern

Mexico a few years ago).

Contractors and service companies in this market

have been the likes of Petrofac (the IES business,

eg, work in Romania, Malaysia, North Sea and

Mexico), Halliburton (eg, in Saudi) and

Schlumberger (the IPM business, eg, in Mexico,

Malaysia, the Middle East and Russia). The tie-up

between Petrofac and Schlumberger to chase

work in this area (particularly looking at what is

coming in Mexico) is, in our view, a possible sign

of more to come – one of the strategic challenges

in this industry has been to tie up downhole

services expertise with topside/large-scale project

management (which is probably the ideal skillset

mix for this type of work).

Production enhancement work also has attracted

interest from the E&P industry itself – although

IOCs cannot book reserves, this type of work is

seen as a relatively high return route to recycling

capital (given rapid cost recovery that is part of

the contract) and is also a “foot in the door” for oil

companies into resource-rich regions that are seen

to be opening up to international involvement. As

an indication, for some of Pemex’s production

enhancement work, it indicated companies that

showed interest were Petrofac, Schlumberger,

Halliburton, Baker Hughes and various local

Mexican oil services companies, BP, Chevron,

Repsol and Enap Sipetrol (Chile).

Main changes in this report – the main change

we’re making is the downgrade of our rating on

Schlumberger to Neutral from Overweight (TP up

slightly to USD98 from USD96). This is driven

more by SLB’s own strong share price performance

through late Q3/early Q4 than any fundamental

change, in our view, of SLB, but it is symbolic of

our overall theme in this report, namely that the

OFS universe is growing but slowing.

Anton Oilfield Services (OW(V), TP HKD7.22)

– Anton is a well-positioned oilfield service

company operating in China's growing market for

oil and gas fracking wells and related services.

Chinese oil services relative share price chart since the start of 2013


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This subsector demands high-end technology,

high-quality services and quick turnaround. Anton

is positioned to execute for clients, leverage its

partnership with Schlumberger, and to ride

industry tailwinds to grow its bottom line.

In September 2013, Anton renewed its cooperation

agreement with Schlumberger for another three

years. In addition, cooperation is deepened and

expanded geographically from the Northwestern

China market to the entire onshore China market;

product-wise, from selected products to full product

offerings; and in procurement from one-way

procurement to mutual supply.

Anton restated its 2013e revenue target of

RMB2.6bn, up 30% yoy, of which RMB1bn was

achieved in 1H13, while another RMB1.1bn will

be recognised from the existing backlog. The

remainder will be booked from new contracts

expected in 2H13e. Multistage fracking jobs are a

key component of operations. ASPs have been

declining but margins have remained relatively

stable, as Anton has contained costs by using new

technology and more domestically produced tools

and equipment. The 2013e capex budget remains

RMB400mn, or 15% of revenue, with the

majority budgeted for pressure pumps and drilling

rigs. Over 2012-15e, we forecast a 32% revenue

CAGR driving a 29% EBIT CAGR and 32% net

income CAGR.

Core Labs (N, TP USD180 from USD157) –

CLB continues to outperform growth in industry

activity while maintaining strong capital

discipline and delivering excellent FCF

generation. The US-centric production

enhancement division is delivering strong results

on a more favourable oil/gas mix (more oil versus

gas) and offshore/onshore mix (greater weighting

to the Gulf of Mexico/West Africa), improved

penetration of its proprietary product lines, plus

greater service intensity (more closely spaced frac

stages, more proppant pumping, etc). Reservoir

description has experienced some headwinds ytd

(unusually bad seasonal break-up in Canada,

Bakken weather and drilling delays in Australia),

but H2 and longer-term prospects appear

somewhat better. Reservoir management

performance has been solid with management

hopeful of securing the large study in Western

Siberia on the Bazhenov shale. We continue to

view CLB as the sector’s ‘class act’ and believe

its premium valuation is justified.

Core Labs – changes to key P&L forecasts (USDm, EPS in USD)

CURRENT FY2012 FY2013e FY2014e FY2015e FY2016e

Sales 981.1 1,083.0 1,195.8 1,284.6 1,198.3 EBITDA 320.2 367.4 414.7 451.6 412.9 EBIT 297.3 341.5 386.9 421.9 381.7 Pre-tax 288.5 332.7 375.7 413.7 376.7 EPS 4.54 5.40 6.17 6.80 6.19

PREVIOUS FY2013e FY2014e FY2015e FY2016e Sales 1,067.5 1,178.5 1,249.2 1,103.1 EBITDA 362.4 409.2 440.5 383.8 EBIT 336.5 381.2 410.1 351.2 Pre-tax 327.7 369.9 401.9 346.0 EPS 5.32 6.08 6.60 5.68

change (%) FY2013e FY2014e FY2015e FY2016e Sales 1.5% 1.5% 2.8% 8.6% EBITDA 1.4% 1.3% 2.5% 7.6% EBIT 1.5% 1.5% 2.9% 8.7% Pre-tax 1.5% 1.5% 2.9% 8.9% EPS 1.5% 1.6% 3.0% 8.9%

Source: Company data, HSBC estimates for 2013e onwards

Main changes – following improved guidance

around revenues in September and our view that

margins will continue to improve in H2, we

increase FY13 sales/EPS by 1%/2%. From a

higher FY13 base, we also raise our FY14 sales/

Anton Oilfield: Share price chart YTD in HKD per share


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EPS by 1%/2%. Beyond this, we now see faster

growth in the deepwater segment (based on

known rig deliveries) and a structural increase in

US activity (driven by higher industrial demand)

and this translates into materially higher growth in

FY15/16 where our EPS forecasts are 3%/9%

higher. The positive impact of higher forecasts

combined with a reduction in five-year adjusted

beta rate drive an increase in our equally weighted

SOTP/DCF-based target price to USD180

(EUR136) from USD157 (EUR120).

Core Labs: Share price chart YTD in USD per share


Fugro (N, TP EUR50) – we downgraded our

rating on Fugro recently to Neutral (see

‘Surveying the costs of growth’, 1 October 2013),

following our assessment of its new medium-term

strategy (which it set out in late September). We

felt this event set out a step change in its level of

financial detail & guidance, and made its growth

ambitions clearly visible at a divisional level. But

we also felt it was clear from these plans that

there will be significant costs of modernising and

achieving that growth – higher capex and lower

EBIT margins (especially in Survey). Our overall

view on Fugro’s industry position is largely

unchanged – it has some of the strongest and most

technical individual franchises in our coverage

universe in oilfield services. But after a period full

of portfolio change (seismic disposal), turbulence

(working capital issues, accounting fears,

management change) and strategic reassessment,

the new shape we see emerging is a slightly lower

margin and a notably more capital-intensive mix

than our previous view earlier this year.

Also, with its various end-markets (mostly)

growing more slowing than before, we think the

payback on its restructuring and growth capex is

really going to be more visible in the medium term

(subsea re-focusing, new Geotech/survey vessels,

and the ‘One Fugro’ strategy). We feel Fugro’s true

potential will become more obvious over this

medium-term timescale (also echoing the likely

growth in some of its key markets, eg, offshore oil

& gas growth, fuelled by an expanding rig fleet).

Factoring in this mix means our target price is

EUR50 – at this level, we do not see enough

potential upside for a positive rating.

Fugro: Share price chart YTD in EUR per share


Schlumberger (downgrade to N from OW, TP

USD98 from USD96) – this year has seen two

important trends working through SLB’s business,

namely signs of stabilisation in SLB’s North

American business (as the onshore market adjusts

to a 1,700-1,800-rig market, and the offshore

GoM market continues to grow in line with a

growing deepwater rig fleet), and gradual

improvements in pricing & activity in

international markets (this year, notably the

Middle East, Russia and China).

We expect SLB’s North American operations to

continue to reflect the favourable trends of higher

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service intensity and new technology-driven

drilling efficiency gains (making simple rig count

a less exact metric by which to gauge service

activity), but we do expect the underlying mix to

remain lower-growth onshore with stronger

growth from the GoM. We also expect

WesternGeco to reflect the seismic industry – a

lower-growth cycle than 2004-08, but improving

into 2014, albeit with Q4 seeing a moderate

potential utilisation risk like peers. We see SLB’s

medium-term international momentum

continuing, driven by overall expansion in

offshore work globally, and in onshore work in

certain areas. We also see growth in

unconventionals work in areas other than North

America (although this is early stage work – areas

like China and onshore Australia for gas, and

Argentina/Russia for oil). Also, SLB’s newly set

up JV with Cameron in subsea equipment &

services – OneSubsea – should realise its

considerable potential in what we see as a

structurally growing subsea market, although we'd

note at the Q2 point, Cameron guided for margins

slightly below the level we'd expected (start-up

costs and some issues at Framo).

Overall, SLB’s position in this 'slowing but

growing' oilfield services world remains strong,

and valuations are not quite at the average 20x or

higher PEs we've seen in the previous cycle (on

our numbers, currently on PEs of 19x 2013e and

16x 2014e, and on EV/EBITDA of 10x 2013e and

8x 2014e). But our overall thesis for this sector is

that oilfield services is in a ‘slowing but growing’

phase, and given SLB’s size and coverage we feel

it is too large to escape this theme. We raise our

target price slightly (to USD98 from USD96) to

reflect our assumption of a higher valuation of

reservoir production and drilling (in the sum-of-

the-parts model), but following recent share price

appreciation to the USD90 per share, we now no

longer see sufficient potential upside to justify a

positive rating, and we downgrade our rating to

Neutral from Overweight.

Schlumberger: Share price chart YTD in USD per share


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Well services sub-sector EV/EBITDA one-year forward Well services sub-sector PE one-year forward


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SPT Energy (UW(V), TP HKD3.2) – runs an

asset-light model with major exposure to oil

services in Kazakhstan and gas services in China.

SPT’s strategy is to structure its business so that it

can follow PetroChina (857 HK, HKD8.68, OW,

TP HKD11.4) and Sinopec (386 HK, HKD6.23,

UW, TP HKD5.5) in their domestic and

international E&P activities. Revenue exposure to

the CNPC group including PetroChina is and will

continue to remain at a high level of 80%. Core

drilling and well completion businesses show strong

momentum and benefit from the more recent

marketing of turnkey contracts and significant

increase in domestic business, mainly in the Tarim

basin, in western China. In the reservoir segment,

domestic competition is increasing, resulting in

lower margins. Over 2012-15e, we forecast a 26%

revenue CAGR driving a 23% EBIT CAGR and

22% net income CAGR.

SPT Energy: Share price chart YTD in HKD per share


Well services revenue progression (SLB, HAL, BHI, WFT) over 2004-Q2 2013


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Well services EBIT margins progression


US rig count – horizontal versus vertical

Source: Baker Hughes Rig Count

US rig count – oil versus gas

Source: Baker Hughes Rig Count

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Financials & valuation: Anton Oilfield Services Overweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 2,005 2,858 3,659 4,653EBITDA 452 668 842 1,054Depreciation & amortisation -54 -115 -152 -200Operating profit/EBIT 398 553 690 854Net interest -31 -8 -10 -12PBT 367 545 680 842HSBC PBT 367 545 680 842Taxation -50 -82 -102 -126Net profit 303 448 562 701HSBC net profit 303 448 562 701


Cash flow from operations 350 292 572 729Capex -232 -429 -549 -698Cash flow from investment -273 -429 -549 -698Dividends -47 -98 -157 -197Change in net debt 130 235 134 166FCF equity 102 -137 23 31


Intangible fixed assets 371 371 371 371Tangible fixed assets 1,003 1,318 1,714 2,212Current assets 2,214 2,936 3,339 4,100Cash & others 523 555 421 525Total assets 3,593 4,629 5,428 6,687Operating liabilities 990 1,393 1,772 2,242Gross debt 522 789 789 1,059Net debt -1 234 367 533Shareholders’ funds 1,972 2,322 2,728 3,232Invested capital 2,076 2,676 3,231 3,916


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)

Revenue/IC (x) 1.1 1.2 1.2 1.3ROIC 18.7 19.8 19.9 20.3ROE 16.6 20.9 22.3 23.5ROA 11.4 11.5 11.8 12.0EBITDA margin 22.6 23.4 23.0 22.6Operating profit margin 19.9 19.4 18.9 18.4EBITDA/net interest (x) 14.8 81.7 81.5 90.2Net debt/equity -0.1 9.5 12.8 15.7Net debt/EBITDA (x) 0.0 0.3 0.4 0.5CF from operations/net debt 124.9 155.7 136.7



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


2.5

Reuters (Equity) 3337.HK Bloomberg (Equity) 3337 HKMarket cap (USDm) 1,517 Market cap (HKDm) 11,763Free float (%) 42 Enterprise value (CNYm) 9639Country China Sector OIL & GASAnalyst Thomas Hilboldt Contact +852 2822 2922

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2011 2012 2013 2014Anton Oilfield Services Rel to HSCEI

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Financials & valuation: Core Laboratories Neutral Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 981 1,083 1,196 1,285EBITDA 320 367 415 452Depreciation & amortisation -23 -26 -28 -30Operating profit/EBIT 297 341 387 422Net interest -9 -9 -11 -8PBT 288 333 376 414HSBC PBT 288 333 376 414Taxation -72 -83 -94 -103Net profit 216 248 281 309HSBC net profit 216 248 281 309




Intangible fixed assets 214 213 212 211Tangible fixed assets 125 134 145 156Current assets 297 450 714 947Cash & others 19 86 286 501Total assets 637 797 1,071 1,314Operating liabilities 215 189 252 263Gross debt 234 234 234 234Net debt 215 148 -52 -267Shareholders’ funds 184 371 581 813Invested capital 422 609 819 1,051


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)

Revenue/IC (x) 2.4 2.1 1.7 1.4ROIC 55.4 49.0 54.4 57.5ROE 119.4 89.6 59.0 44.4ROA 36.0 35.8 31.3 26.9EBITDA margin 32.6 33.9 34.7 35.2Operating profit margin 30.3 31.5 32.4 32.8EBITDA/net interest (x) 36.3 41.6 36.9 55.5Net debt/equity 114.3 39.4 -8.9 -32.6Net debt/EBITDA (x) 0.7 0.4 -0.1 -0.6CF from operations/net debt 110.7 172.6



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


.7

Reuters (Equity) CLB.N Bloomberg (Equity) CLB USMarket cap (USDm) 8,000 Market cap (USDm) 8,000Free float (%) 100 Enterprise value (USDm) 8152Country United States Sector ENERGY EQUIPMENTAnalyst Phillip Lindsay Contact

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2011 2012 2013 2014Core Laboratories Rel to S&P 500

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Financials & valuation: Fugro Neutral Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e




Cash flow from operations 93 447 606 580Capex -265 -257 -325 -317Cash flow from investment -386 648 -375 -367Dividends -62 -80 -61 -131Change in net debt 15 -906 -198 -111FCF equity -159 191 278 255


Intangible fixed assets 556 566 591 616Tangible fixed assets 1,066 1,143 1,287 1,403Current assets 1,437 1,510 1,900 2,031Cash & others 92 545 644 755Total assets 3,158 3,318 3,877 4,149Operating liabilities 683 1,182 1,393 1,617Gross debt 1,399 946 847 847Net debt 1,307 401 203 93Shareholders’ funds 1,957 2,344 2,421 2,469Invested capital 2,284 1,491 1,741 1,678


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change

Revenue -16.0 18.7 9.5 11.5EBITDA -19.6 26.6 1.1 15.8Operating profit -11.8 -0.4 5.1 29.0PBT 3.0 46.7 -36.7 28.1HSBC EPS 6.4 47.1 -43.9 28.1

Ratios (%)




Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


4.1

Reuters (Equity) FUGRc.AS Bloomberg (Equity) FUR NAMarket cap (USDm) 4,938 Market cap (EURm) 3,631Free float (%) 100 Enterprise value (EURm) 3979Country Netherlands Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

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Financials & valuation: Schlumberger Ltd Neutral Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e


Revenue 42,148 45,881 51,713 58,679EBITDA 11,153 12,208 14,399 17,693Depreciation & amortisation -3,501 -3,622 -3,835 -4,304Operating profit/EBIT 7,652 8,586 10,564 13,389Net interest -340 -407 -465 -582PBT 7,259 8,787 10,233 13,168HSBC PBT 7,341 8,215 10,233 13,168Taxation -1,739 -2,105 -2,452 -3,155Net profit 5,491 6,652 7,752 9,984HSBC net profit 5,553 6,217 7,752 9,984


Cash flow from operations 9,185 10,525 10,944 13,822Capex -5,046 -4,230 -5,164 -5,980Cash flow from investment -4,863 -4,230 -5,164 -5,980Dividends -1,432 -1,663 -1,938 -2,496Change in net debt 261 -5,204 -3,842 -5,346FCF equity 2,060 6,288 5,675 7,511


Intangible fixed assets 19,387 19,387 19,387 19,387Tangible fixed assets 14,780 15,336 16,665 18,405Current assets 24,401 29,505 35,157 42,362Cash & others 6,519 11,723 15,565 20,911Total assets 61,029 66,689 73,669 82,615Operating liabilities 11,397 12,120 13,287 14,680Gross debt 11,630 11,630 11,630 11,630Net debt 5,111 -93 -3,935 -9,281Shareholders’ funds 34,749 39,738 45,553 53,040Invested capital 40,652 40,385 42,357 44,563


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)




Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e



Issuer information


1.4

Reuters (Equity) SLB.N Bloomberg (Equity) SLB USMarket cap (USDm) 116,374 Market cap (USDm) 116,374Free float (%) 100 Enterprise value (USDm) 114305Country United States Sector ENERGY EQUIPMENTAnalyst David Phillips Contact 44 207 991 2344

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Financials & valuation: SPT Energy Group Underweight (V) Financial statements

Year to 12/2012a 12/2013e 12/2014e 12/2015e




Cash flow from operations -58 179 223 278Capex -118 -184 -231 -291Cash flow from investment -143 -184 -231 -291Dividends -13 -49 -60 -74Change in net debt -257 18 68 86FCF equity -189 -5 -7 -13


Intangible fixed assets 34 0 0 0Tangible fixed assets 355 539 676 845Current assets 2,106 2,014 2,283 2,617Cash & others 659 540 473 387Total assets 2,495 2,553 2,959 3,462Operating liabilities 521 485 574 688Gross debt 320 219 219 219Net debt -339 -321 -254 -167Shareholders’ funds 1,582 1,793 2,101 2,479Invested capital 1,315 1,527 1,912 2,388


Year to 12/2012a 12/2013e 12/2014e 12/2015e

Y-o-y % change


Ratios (%)

Revenue/IC (x) 1.7 1.6 1.7 1.7ROIC 25.4 22.5 22.6 22.1ROE 20.2 17.9 18.9 19.7ROA 13.8 12.7 14.1 14.8EBITDA margin 23.0 23.0 22.5 22.0Operating profit margin 19.9 19.9 19.2 18.6EBITDA/net interest (x) 18.4 34.9 42.5 51.8Net debt/equity -20.8 -17.5 -11.7 -6.6Net debt/EBITDA (x) -0.8 -0.6 -0.4 -0.2CF from operations/net debt



Valuation data

Year to 12/2012a 12/2013e 12/2014e 12/2015e

EV/sales 2.4 1.9 1.5 1.2EV/EBITDA 10.3 8.2 6.8 5.6EV/IC 3.3 2.8 2.3 1.9PE* 16.7 15.2 12.5 10.2P/Book value 2.6 2.6 2.2 1.9FCF yield (%) -4.1 -0.1 -0.2 -0.3Dividend yield (%) 1.5 1.3 1.6 2.0


Issuer information

Share price (HKD)3.81 Target price (HKD)3.20 -

16.0

Reuters (Equity) 1251.HK Bloomberg (Equity) 1251 HKMarket cap (USDm) 751 Market cap (HKDm) 5,827Free float (%) 41 Enterprise value (CNYm) 4326Country China Sector OIL & GASAnalyst Thomas Hilboldt Contact +852 2822 2922

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2011 2012 2013 2014SPT Energy Group Rel to HSCEI

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The third quarter this year saw two of the main

biennial offshore conferences take place (although

actually one biennial event – the ONS – became

annual, with a mid-sized Norway-specific event). In

this section of the report, we list our feedback from

these events – we have reported our feedback on

these previously in our ‘special edition’ In it to win

it reports in August and September.

ONS Norway, Stavanger, 19-21 August 2013

Who was there – most suppliers (although more

of an effort from smaller names, less from the

likes of NOV, AKSO, FTI and CAM), some

Asian yards and some operators.

Whom we met/heard from – Statoil, Det Norske,

Aker Solutions, GVA/KBR, Rosneft, Samsung

Heavy Industries, Hyundai Heavy,

Daewoo/DSME, Petrofac, INTSOK, Exxon,

Total, FMC, Halliburton, HitecVision, Kvaerner

and Infield.

Summary – what stood out from our discussions

Statoil taking its foot off the gas with major

greenfield work (eg, Johan Castberg), less

glamorous brownfield/MMO work remains a

NOK16-18bn per year market (globally a

NOK40-50bn market).

But its drilling needs are substantial (almost

double the number of wells planned in

2015/16 versus 2012); the NCS rig market

fever isn’t going away (Cat D, Cat J, and

Cat I drillships to come).

What the NCS needs to grow – more

discoveries (Barents, Arctic & the Lofoten

Islands, although environmental issues mean

“the fish come first”) also continued high oil

prices, stable fiscal terms.

Australian LNG key for the supply chain,

specifically the shift to FLNG; 10 vessels on

the horizon.

Appendix: Event feedback

Feedback from two important industry conferences in Q3 – the

Norwegian ONS in Stavanger and offshore Europe in Aberdeen

Greenfield work slower but drilling plans imply no cure for North

Sea rig fever; supply chain focusing on working with Korean

yards, FLNG and more & more global alliances

Decommissioning legislation a boon to an already active UKCS;

industry struggling with costs but new competition emerging

across several value chains

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Norwegian suppliers are positioning more and

more with the Asian (Korean) yards if they’re

not there already; there’s ‘pushback’ from the

EPC players on the trend of big-ticket

fabrication awards going to the Far East, but

the value chain is taking a view that this is

here to stay.

And this mix of work is causing headaches

for the Korean yards (bespoke offshore

platforms more challenging than drillships);

supply chain management key (Norwegian

quality good but often late).

Contracting models more and more global –

EPC players have to be the bridge to link

suppliers, fabrication yards and engineering

(see more alliances and longer-term vessel

frame agreements).

New technology – clear focus on saving costs

(including new equipment on rigs/vessels to

recoup ‘lost’ energy (like braking to recharge

batteries in hybrid cars); also more and more

projects mentioning using OBC/OBS (ocean

bottom seismic; roughly 12-13% of the

market this year).

And our feedback from the ONS Norway in more detail

Views on the ‘big picture’ – macro issues, E&P

spend, contracting structures

Seeing the NCS and the NCS-driven supplier

industry in context – the attractiveness of

producing oil fields in stable & accessible parts of

the world is clear (as seen in recent news, with

OMV happy to pay over USD8/boe for stakes in

the Gudrun and Gullfaks fields, as well as in two

other fields and some exploration exposure). The

oil services export value from Norway is put at

around NOK160-180bn (sounds substantial but to

put this in context Norway gets over NOK50bn

from fish exports!).

Offshore spending – the overall message (from

INTSOK) is still that offshore is seen as the place

to be for structural growth; new work and

catching up with delayed projects. The direction

of this spending is still very much “one way”;

there’s a substantial amount from the North Sea

when you wrap in maintenance & modification

work, as well as decommissioning, but we’d note

that the overall timing of greenfield work around

the world is subject to a substantial and ongoing

level of political risk.

Overall offshore spend is seen at USD1.3trn over

2014-17; the largest single region is Brazil, then

Norway, then the US Gulf, then the UK North Sea,

then Australia, then Angola, then Nigeria, then

Mexico, then SE Asia. On this basis, the largest

single market is therefore the North Sea (Norway +

UK/Dutch); we think these numbers also reflect the

brownfield work needed (otherwise the North Sea

would not be the single largest region). Our own

work on subsea spending, as highlighted in our

‘Deep Blue III’ report in February 2013, saw

Africa growing to be the largest region in the

medium term, with the ‘Western world’ (US Gulf

plus the North Sea) in second place. INTSOK also

highlighted some “up and coming areas” for

offshore work – Abu Dhabi, some of the Central

Asian/FSU states and Mexico.

The overall subsea spend INTSOK saw was up to

USD60bn by 2017 (so a CAGR of 18-19%). This

does sound high to us; we've previously seen

subsea as a “double in 5 years” industry, so

14-15% CAGR, and recently it looks like the

CAGR may be less than this (given some major

delays – Browse, Mad Dog II – and a more

realistic view on the level of growth in regions

like Brazil and certain parts of SE Asia).

Shale, shale and shale – there was little doubt on

what the main macro question is; very much about

shale oil and the medium-term potential of

unconventional/tight oil supply to change the

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balance of global supply/demand. In the

discussions themselves, we felt there was quite a

defensive “hand-off” from offshore suppliers (as

you might expect) over the theme of E&P capex

choices and whether "shale" (specifically shale oil,

but also gas in some regions) could displace

deepwater/ultra-deepwater investments with some

operators. We’ve felt for a while that this is

actually an important and growing theme (and a

timing risk for ultra-deepwater) – partly the

resource potential and “option value” of shale

work, partly the scaleable (up and down) capex

spend versus major multi-USDbn offshore projects.

Contracting structures – there are some

divergent views here on the ideal structure of EPC

contracts, but the common theme is clear; the

contracting/procurement model is increasingly

global. Most of the larger users of the oil services

supply chain prefer to keep the interfaces between

E, P and C with the contractors (so aim to have

fewer touch points with the supply chain per

project). But there were a growing number of

discussions about newer contracting models,

particularly integrated EPC versus fabrication;

should the “C” be kept separate from the “E&P”?

This could be particularly relevant for developing

more partnerships like that between Kvaerner and

COOEC in China.

In context, these views sounded more like a reaction

to some execution/supply chain delivery problems

in the past; the dominant theme in contracting

model discussions remained the need to integrate

global procurement processes when working with

major E&P clients and the Asian yards.

There were also views that this “globalisation” of

the supply chain means the industry is likely to

see more alliances between main contractors and

key suppliers, (eg, Subsea 7 was asked by the

operator to form an alliance with ABB for the

170km AC subsea cable job for the Martin Linge

field). The other contracting theme was an

expectation of more frequent longer-term ‘frame

agreement’ type contracting for subsea vessel

usage, eg, subsea installation/construction

contracted on a basin basis (reflecting how some

IOCs plan the contracting of their deepwater

drilling capacity; one example was Statoil’s use of

the Saipem 7000 this summer for a number of

back-to-back jobs).

And some sound-bites on global sourcing from

subsea market leader FMC – around 50% of

FMC’s subsea work involves Norway (FMC

Norge as a manufacturing and service base):

USD1.2bn of direct material purchases for the

Eastern region (including Europe) have been

made up of suppliers from four regions, five

product lines, 15 key categories, 773 suppliers

and up to 30,000 different part numbers. From

another angle, FMC’s Eastern region spend by

supplier location is around 50% Norway, 30%

UK, 5% Italy and 5% from the US.

The split by type of service or component

purchased is 37% for electro-hydraulics &

other hydraulics and related equipment, 33%

machinery/machining, 9% fabrication, 4%

steel structures & piping, 4% forging and 3%

for chokes. Given capacity constraints (and

pricing) FMC and others were having to look

outside Norway for certain equipment

(challenge is to match the quality).

Statoil – not so much the big spender anymore?

It’s been a busy summer for Statoil – installing the

Asgard subsea compression, the Kvitebjorn

pre-compression units, the Kristin low-pressure

production module, the Gudrun topsides (in fact

lots of work for the Saipem 7000 in all this). But

apart from the generic push-back on cost inflation

coming from most operators and suppliers (eg, rig

rate inflation, engineering man hours 50% up on a

decade ago), one clear theme was the push-back

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from Statoil itself on certain new NCS projects

where higher costs and fiscal structure changes

imply less favourable economics (Statoil making

much of the average ROCE chart for the IOCs,

with returns at 10% in 2002, 25% in 2005/06 but

at 15% and falling in 2012) with one of the most

high-profile moves being the delayed FID on the

new Johan Castberg field in the Barents Sea.

Statoil’s procurement was worth NOK145bn in

2012 – split roughly 30% drilling, 30% opex, 30%

capex and 10% support (and out of this total, 77%

went to Norwegian or Norway-based companies).

There was a lot of discussion about what the

appropriate “focus” should be for Statoil to avoid

the cost inflation/low-return problem (citing the

usual statistics – over 50% of major projects see

over a 20% delay to schedules and over a 30%

level of cost overruns).

Statoil’s message seems to be “don't forget the

industry setting we are in”. Only a few years ago

(2009/10) the pace of NCS awards was very quiet

(ie, arguably under-investing) and it is now in a

phase of catch-up. But comments from Statoil are

that this phase might be drawing to a close (at

least in terms of the y-o-y growth in new awards,

which have in Statoil’s words been “at too high a

tempo for the supplier market to handle”). The

economics of tie-backs and satellite developments

remain very good, as do those for EOR/IOR

(enhanced/improved oil recovery – targeting 60%

recovery versus 50% in 2011) projects; it is the

large greenfield projects that are causing Statoil

concern now (and greenfield makes up 50% of

Statoil’s development spend now versus 20% a

few years ago). These comments about the

timescale for new greenfield projects would likely

not apply to projects where development plans

have been approved.

Just to put this into context, from Statoil’s overall

production ambition of over 1.4m boe/day (stated

pre the OMV disposal) from the North Sea, it sees

roughly 200-250,000 boe/day from new

sanctioned projects (Aasta Hansteen, Gina Krog,

Martin Linge, Edvard Grieg, Ivar Aasen, Gullfaks

Sør Oil, Svalin, Fram H-Nord, Åsgard SSC,

Visund Nord, Oseberg Delta 2, Smørbukk sør

extension) and similar from new non-sanctioned

projects (Johan Sverdrup, Johan Castberg,

Gudrun East, Krafla, Corvus).

What does the NCS need to grow from here?

This was unsurprisingly a keen topic of discussion

for the Norwegian-centric supplier market. The

past few years have seen capex up 8% per year on

average, but hydrocarbon production is flat/down.

There’s a need for more significant new

discoveries, stable high oil prices, stable fiscal

terms (lots of commentary on the recent changes

in Norway) and continued good licence round

availability (22nd round was “good for the

industry”, South-East Barents opening up, also

could see the Lofoten area opening up as well,

although in reference to likely environmental

issues, as Statoil said “the fish come first”). And

the importance of brownfield remains, implying

an ongoing strong market for heavy lift in

construction/removal/facility upgrade work (eg,

the Saipem 7000 has had a busy summer on the

NCS this year).

The main challenges are with costs (driving the

need to look at more economies of scale with

procurement of equipment and services, also more

standardisation and earlier decisions on project

concepts and designs), with project profitability

(especially for new greenfield platform projects;

returns for satellite fields and tie-ins are generally

“good”) and with access to quality acreage. Statoil

commented that it sees a “yet to find” estimated

resource of over 2.5bn boe in the Barents Sea,

over 2bn in the Norwegian Sea and over 2bn in

the North Sea.

Brownfield work on the NCS is still seen (by the

operators) as being under-estimated as an

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opportunity by the (non-Norwegian) market;

Statoil has secured what it needs for the next six

months or so, but this remains a NOK16-18bn per

year market with around 1,100 projects on the

horizon (and one where project returns are

strong). From Statoil’s NOK145bn procurement

budget last year around 30% (NOK44bn) went

into MMO and MMO-related areas (so not

directly comparable to the NOK16-18bn

brownfield spend mentioned before). Kvaerner

put the MMO opportunity on the NCS as slightly

higher at NOK19-25bn, with a long-term growth

rate in the 5-8% range, and with a further

NOK17-22bn from the UK North Sea and

NOK6.9bn from Malaysia.

Johan Castberg – no doubt that this is a

“strategic project” for Statoil (400-600m bbl

prospect). There is a three-well campaign

going on now in the vicinity of Johan

Castberg, but Statoil postponed the FID citing

higher costs, uncertainty about the resource

and changes in the Norwegian fiscal structure.

We’d note Aker Solutions’ recent award for

the extended concept study for Johan

Castberg; Statoil indicated this could be a

floating-production-based unit (harsh

environment semi-sub platform with a

pipeline to an onshore terminal) but

alternative concepts are being looked at.

Johan Sverdrup – this is a big discovery

“just like the good old days” (in Statoil's

words). The plan is to target a concept

decision (including capex information) and a

resource update by end-2013, FEED studies

ending early 2014, and submission of a

development plan in Q4 2014 (and first oil by

end 2018). The cost of Sverdrup was said to

have risen by more than NOK30bn (USD5bn)

versus the original estimate of NOK80bn-

90bn. It looks likely that this will be a

stepwise development over several years, and

there will be extensive use of IOR/EOR and

permanent reservoir monitoring (another case

where seabed seismic is seeing good uptake).

Also, Johan Sverdrup is in the “jacket land”

region like older fields such as Oseberg, so

the development is likely to be some

combination of WHP (well-head platform)

and subsea (with subsea the key to further

step-wise development).

Statoil’s NCS rig needs – explaining rig categories, strategies & plans

The theme isn't new – the ‘right rigs’ are in short

supply and are expensive, and most probably

close to being prohibitively so for modern units

kitted out to work on the NCS/in the Arctic. Why

is the NCS in this position? Partly high barriers to

entry (specialist kit), partly the ‘pull’ for

contractors from the attractions of the ultra-deep

market, but really it is down to the lack of

newbuild activity in this mid-water/shallow water

harsh environment segment. There was a boom in

rig building for this environment in the 1980s, but

these rigs – on which the market relies – make up

over half of the fleet and are around 30 years old

(and are set up more for exploration drilling than

production work; currently, activity on the NCS is

split 70% development drilling and workover and

20% exploration). And most newbuilds in recent

years have targeted the ultra-deepwater market

(mostly drillships, some semi-submersibles).

We also picked up some interesting comments on

the whole NCS rig market issue from a panel

discussion with Alf Thorkildsen, ex-Seadrill CEO,

now at PE firm HitecVision. The view here is that

this gap in availability of the right units has been

coming for years (half the fleet is now approaching

“old age in rig years”) and there is a clear need for

new units, both floaters and jackups. But echoing

Statoil’s comments – any long-term lease contracts

will likely have to be in line with the 20% saving

that Statoil reckons it can realise by owning the unit

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rather than leasing it (which implies unfavourable

returns for leasing versus opportunities in the wider

international market; there has been one deal like

this already). The other issue in “the world has

changed” theme is costs, particularly the substantial

cost inflation (for a rig owner/user) seen in the North

Sea and for deepwater work (eg, Smedvig’s first

deepwater unit had opex around USD50-60,000/day;

this is more like USD200,000/day for modern units).

Stepping up NCS drilling – and in the

background, Statoil's plans for the NCS see a

major step-up in drilling work – especially

completion and intervention. Statoil sees around

125 wells per year in 2015/16 versus around 70 in

2012 (and 107 in 2008). The growth in this

drilling activity has to come from mobile units

(the 125 wells in 2015/16 are split roughly into 25

from fixed platforms, 70 production wells from

mobile drilling units, where most of the growth

has to come from, and 30 for exploration work).

(And it is also worth noting Statoil’s drilling plans

outside the NCS – eg, Tanzania. The schedule for

this gas/LNG project (will be either floating

production unit to shore or subsea to shore) is for

concept selection in H2 2014, FEED mid-2015

and FID end 2016, with production drilling

2018-2021, with 12-15 wells in phase I, then up to

over 20 wells later on.)

These NCS rig needs – and the perception that the

market would likely be short of the right sorts of

units – led Statoil to work towards these 'category'

designs (a deliberate effort to standardise ‘fit for

purpose’ designs for intervention and full-scale

drilling). The designs are derivatives of accepted

modern designs – eg, the Category J jackup is a

modified CJ-70 Gusto model, and the Category D

midwater semi-sub is a modified GVA 4000.

Also, Statoil's view was (and is) that it is hard to

get agreements with very long-term lease

contracts with the drilling contractors (which

would be its preference, but driven more by the

field licence structure than Statoil itself), as rig-

owners see higher return opportunities elsewhere

in the world, and also usually want the flexibility

to move a rig around the world over its lifetime.

Therefore, ownership of the units is better suited

(in some cases) to be from the operator than from

the contractor side – from one angle this looks as

simple as seeing a good market (for a buyer) from

the Asian shipyards versus a tight market in terms

of dayrates, but Statoil’s view is longer term than

that (Statoil also said it reckoned it effectively

locked in at least a 20% saving in rates by owning

versus leasing).

The ‘bespoke NCS design’ categories break

down into:

Cat A – light well intervention based on a

semi-sub or ship-shape vessel concept

(Ulstein design) – will see some news on this

in Q4 2013.

Cat B – the (infamous) unit that was cancelled

(contract with Aker Solutions) – aim is to do

light-well intervention, coiled tubing work, and

heavier intervention jobs.

Cat C – more 'conventional designs' to have a

drilling unit to do well intervention (light +

heavy) as well as some exploration/workover

drilling.

Cat D – the "workhorse" design for midwater

drilling, focusing on production work and

designed to be "Barents Sea ready" (four units

are under construction at DSME in Korea, with

Songa as contractor).

Cat F – ‘flotel’, ie, floating accommodation

(two are under construction in Singapore).

Cat I – ice-class drillship – this is the new

model, currently in feasibility studies and the

early design competition is down to three

players including Ulstein & Gusto (has to be

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able to handle 2m of ice thickness; the aim is

to have the unit delivered in 2018).

Cat J – production drilling focused jackup

rigs (based on the CJ-70 modified design),

three are under construction, two to be owned

by Statoil (being built at Samsung in Korea)

and one by Noble (being built in Singapore –

will be on a four-year contract (plus options)

with an implied dayrate of USD447k/day,

including mobilisation costs).

We think interest remains high from Statoil in the

cat B well intervention semi-submersible, but there

is a need to do more work to sort out the design

(were problems with the riser equipment/handling

– more from the Aker side – the GVA rig design

was ‘ok’) – this could come back in 2014/15.

Views on the Arctic (Rosneft, Statoil, Exxon)

Not a lot of “new news” on the Arctic – this long-

awaited move is a reality, with drilling starting in

2014, but it is gradual. As Rosneft put it “the costs

are more akin to those in space exploration than

oil & gas”!

But there are major plans ahead – 190,000km of 2D

seismic, 49,000km2 of 3D seismic and drilling plans

for two wells in 2014, seven in 2015, eight in 2016

and three exploration wells in 2015/16 (and drilling

in the East Arctic would likely be 2019 onwards –

overall long-term plans would likely need many

100s of wells). The as-yet-unmet need for

infrastructure/power/fuel and so on is immense, as is

the scrutiny the companies will be under in terms of

their environmental and broader HSE performance.

Views on Australian LNG

Two main themes (neither of which are a surprise)

– less activity over 2014/15 than expected due to

the removal of Browse, but a pronounced shift to

FLNG (a reflection of onshore cost inflation). The

other onshore gas ‘option’ is of course shale – just

starting to see work in this now (Geoscience

Australia sees 400Tcf gas) and many of the usual

suspects are already ‘in’, like Shell, Total, Chevron,

Conoco, Hess and Statoil bought in recently.

But FLNG is very much where the pre-FEED/design

interest is now from the oil companies (and the

Australian Government is setting up an FLNG

hub/centre of excellence in Perth). Currently, there

are seven to eight projects/prospects (equivalent to

10 vessels) on the horizon – the main ones are:

GDF’s Bonaparte – competitive concept

definition stage, down to TEC versus KBR,

expect FEED by year end then move to EPC;

need to set up the yard partnerships for the

construction as well (JP Kenny doing the

subsea engineering).

The 'new' Browse FLNG – following the Shell

model so TEC/Samsung, see FEED mid-2014,

taking FID mid-2015; ultimately will be three

vessels but this will be phased.

XOM's Scarborough – benefits from having a

dry gas feed so the design can handle larger

LNG topsides (will be 6-7mtpa, so 2x

Prelude’s capacity) – currently looks like

Chiyoda/Saipem for the main job and TEC’s

Genesis for the subsea engineering.

PTTEP’s cash/maple – pre-FEED at present

looks like Hoegh/KBR versus SBM/Linde –

will be unusual versus other FLNG as this is

likely be a leased vessel; worth noting SBM’s

FLNG designs for a mid-sized vessel

(effectively two LNG tankers joined side by

side and one front tank on each side removed

to make space for the LNG equipment). Also,

Hoegh LNG announced recently that it had

won a pre-FEED study on a FLNG project for

an "un-named" Asian client (with full FEED

likely in H1 2014).

Sunrise – actually was on the board pre-Prelude

but was delayed due to (ongoing) border/scope

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of work disputes with East Timor (which wants

onshore LNG to boost employment, not FLNG).

Echuca Shoals (early stage) – in the Browse

basin, 100% owned/operated by Nexus

Energy; Nexus said in June this year that

Echuca plus other prospects under the same

permit gave enough potential gas volumes to

support FLNG (total of just over 5Tcf).

There’s also the Crux field that Nexus saw as a

potential FLNG project (FID for this is more

like a 2015-17 timeframe).

Arnhem/Pinhoe (early stage) – 50/50

ownership between Shell and Chevron, these

fields are seen by Shell (comments from

Q1 2013) as potentially large enough to

support a FLNG development.

Views from (and about) the Asian shipyards

One clear theme from many of the Norwegian

contractors was how to handle the ongoing (and not

decreasing) challenge from low-cost Korean

fabrication yards securing ‘big ticket’ work from

the NCS (and the non-Norwegian North Sea as

well) – specifically Samsung (SHI), Hyundai (HHI)

and Daewoo (DSME). There’s unsurprisingly

strong push-back from local/European fabricators

to this trend (which, given Statoil's ongoing cost

focus, may fall on deaf ears), but there's also a clear

move by suppliers to be more established in Korea

near the yards if they are not over there already (so

the supplier industry seems to have taken a view

that this theme is here to stay).

We thought it was also interesting to note who

attended ONS Norway from the Asian supply

chain – less of the Chinese yards than usual (but

expect these to turn out in force for Offshore

Europe in September in Aberdeen), but the

Koreans and also the Japanese (targeting FPSOs

and offshore-gas-related vessels, rather than

drillships/floater rigs, although we’d note awards

of subsea and seismic newbuilds to Japan).

The key focus from the yards with their

suppliers – quality, managing the supply chain and

also “project change management”, so no real

surprise here (bearing in mind a large share of the

audience was, in fact, current and future suppliers

to the yards); the emphasis in the discussions was

more on managing change orders (need to get as

much as possible fixed in the initial design) and

managing sub-suppliers in general (eg, many small

companies tend to over-promise). Delays are an

ongoing theme with the offshore fabrication work

(not drillships/floaters), eg, as seen with BP’s

Skarv, now with Goliat and Valemon.

Some ‘sound-bite’ data on the yards and their

suppliers:

HHI’s view was that over six major recent

offshore projects, the number of approved

suppliers per country was Europe (79

suppliers; mostly UK + Norway), Korea (24),

Americas (23), Asia (11), the Middle East (2)

and Africa (2).

Again based on this list of six recent projects,

the Norwegian suppliers were 40% late (ie,

delivery time was 40% longer than expected)

and non-Norwegian suppliers were over 50%

late (the worst were from Italy and France) – in

fact, most yards commented that the

Norwegian suppliers were good on quality but

were generally late on delivery.

DSME's view on suppliers over 2009-11

ranked them (in order of decreasing size) from

the US, UK, Germany, Japan, Norway,

Singapore (and others). DSME has 150

suppliers on its database from the UK and 95

from Norway. In terms of companies, the main

suppliers (by USD amount) were the drilling

equipment makers (USD1.9bn from NOV,

Aker MH and Cameron), then Rolls-Royce,

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Framo/SLB, ABB, Hamsworthy, Kongsberg

and others.

Measured over a large number of projects – the

main delays are caused by design changes and

re-approvals (48% of delays), sub-supplier

issues (43%), testing issues (8%) and

fabrication (1%).

Change orders can be surprisingly large (and

can appear quickly) – the Goliat project has (at

present) USD38m of additional costs due to

change orders.

Which requirements of suppliers are growing

now? The need for full life-cycle info on parts

and equipment (reflecting the greater emphasis

on HSE from customers) – this can be a major

and often overlooked additional cost for

smaller suppliers – could cost

USD700,000-1,000,000 to build up this level

of information for a key new component.

And cultural issues are often under-estimated –

the Korean yard work ethic is pretty much 24/7

and based on exact timelines/delivery

deadlines. This can be a clash with Western

suppliers who, as well as being late with

deliveries, are hard to contact at certain times

of the year (eg, holiday seasons and often not

enough technical support staff).

Offshore Europe, Aberdeen, 03-06 September 2013

Who was there – the majority of suppliers (from

industry giants to smaller/niche providers), several

operators (IOCs plus NOCs), some Asian yards,

some government bodies and various consultants.

Whom we met/heard from – Subsea 7, AMEC,

Wood Group, Hunting, Aker Solutions, Aibel,

Heerema, GE, Shell, Total, WorleyParsons,

Acteon, Foster Wheeler and FMC.

Summary – what stood out from our discussions

Decommissioning legislation – UK

government guaranteeing tax relief frees up

capital, encourages asset churn and should be

a significant boon to UKCS services sector.

North Sea competitive environment – threats on

the horizon for the ‘Big 2’ of Subsea 7 and

Technip for installation/construction work (and

potential for some M&A); threats to Aker

Solutions/Aibel for brownfield modification

work in the NCS; threats to Wood Group/

AMEC for engineering/operations &

maintenance work; threats to Hunting/

Vallourec/Tenaris/Sumitomo for OCTG.

UKCS/Canada active, NCS quieter – UKSC

and Canada very active for large greenfield

contract award momentum; but a lull in NCS

as Statoil slows as major greenfield projects.

‘Pure’ engineers face challenge managing

cost base – as we move into a period of lower

activity, how aggressively does the industry

cut manpower with recovery on the horizon in

H2 2014 and 2015.

Blame the service sector – a lot of oil company

‘finger pointing’ at the services industry

regarding costs; big efforts from all parties to

reduce costs and improve project economics.

UK losing competitiveness as a basin in the

international arena. Industry needs to reduce

costs, embrace technology and enhanced

recovery techniques, increase spending in R&D,

reduce people intensity offshore and make more

efficient use of skilled resources, etc.

Subsea technology – the evolution of

migrating technologies to the seabed

continues; early-mover advantage key – the

race to develop first commercial projects.

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And our feedback from the Offshore Europe in more detail

Opened by the ‘Right Honourable’ Chancellor of

the Exchequer, George Osborne, Offshore Europe

opened with a supportive message from the UK

Government in support of the UK oil & gas sector

by introducing the first-ever national Oil & Gas

strategy. This aims to support investment across

the UKCS and remove barriers to development by

the introduction of tax incentives to extract ever

more complex hydrocarbons and, crucially,

provide guaranteed tax-relief on future

decommissioning costs (a world first) where the

UK Government will enter into legally binding

contracts with oil companies.

Decommissioning

What are the implications of this

decommissioning legislation? Previously,

significant bonds required to cover

decommissioning liabilities were effectively

locked away in perpetuity on company balance

sheets – this restricted deal flow. The new rules

should free up swathes of cash from oil company

balance sheets (existing decommissioning

liabilities convert to cash), it should make UKSC

assets more saleable (so expect more M&A, and

perhaps accelerate the theme of IOCs transferring

assets to smaller E&P companies) and has

potential to drive at least GBP17bn of incremental

investment. This could drive a surge in asset

integrity, technical upgrade and brownfield

tieback work in the region.

Freed up capital may also promote a more active

maintenance market (positive for brownfield

contractors: AMEC, Wood Group, PSN, etc) – we

note the recent programmes by Statoil and Shell

were effectively preventative or proactive

maintenance. There are ongoing studies around

improving the future economic hydrocarbon

exploitation to halt the worsening production

efficiency trend. The added certainty around

decommissioning may perversely delay the onset

of actual decommissioning activity as increased

asset churn will inevitably drive increased

investment in extended field life using EOR

techniques, etc. This should also extend the

producing life of the UKCS as a major oil-

producing province.

Ultimately, we think this decommissioning

legislation is a significant boon to the services

sector in the UKCS.

Shale drilling in the UK continues to attract its

fair share of bad press, but the government is

doing its best to promote it, citing a worsening

competitive environment for UK industry, the

prospect of materially higher energy bills relative

to other countries and reduced employment

opportunities. Again, the tax regime for shale gas

exploitation is generous to encourage investment

and the industry has committed to providing

community benefits. The environmentalists,

however, are unlikely to go down without a fight.

North Sea competitive environment

Several new comers targeting North Sea SURF.

If all ‘potential’ newcomers enter and bid

effectively for projects, the incumbents are likely to

have a real problem. Experience counts for a lot,

and we wouldn’t expect all newcomers to ‘cut the

mustard', and we could see a situation where the

strong balance sheet companies prey on the weak,

particularly if the market entered a cyclical

downturn, but it’s clear the industry is encouraging

new competition. The larger players will continue

to benefit from their size, broader capability,

execution track record and technology. While

newcomers will inevitably imitate existing

technologies (pipeline bundles, pipe-in-pipe, plus

pipelay techniques), we believe the chance of them

securing large EPIC projects remains remote for

now. But ‘bread and butter’ tieback work could

prove a happy hunting ground for the newcomers.

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The incumbents’ biggest fear is Asian player

EMAS (Ezra), which is increasingly visible on bid

sheets in the North Sea, notably in Norway with

Statoil/DNO but also in the UKCS, and its

developing a spoolbase in Norway from which to

execute projects. And EMAS continues to make

progress on the international stage, particularly

Gulf of Mexico and, more recently, Africa, where

its flagship Lewek Constellation vessel has been

contracted for its first job in Gabon. So EMAS

appears to be building a decent portfolio of pure

installation and transport and installation (T&I)

work. However, its current market offering has

limitations – it still can't offer full EPIC capability

(plus progress may be hampered by balance

sheet), but the company has clear ambitions to

develop this. It is not clear at this point whether

the Lewek Constellation (currently under

construction) will target North Sea work as the

market is dominated by specialist vessels that

move from job to job.

Elsewhere, the Oceaninstaller/McDermott JV has

been dissolved following a relationship

breakdown/disagreements over strategy. On its

own, Oceaninstaller can't perform pipelay,

therefore it is naturally excluded from a lot of

bids. McDermott has not given up on the North

Sea and it does have capable vessels that could

effectively compete – indeed McDermott is

currently evaluating possible sites for a pipeline

spool base in the UK. Private company Ceona

remains on the periphery but with ambitions to

enter the market. Recent North Sea bidding

activity from the company has been quiet, but it is

engaged in some work in the Gulf of Mexico (we

note Ceona’s CFO Stuart Jackson recently left the

organisation). Korean contractors may harbour

ambitions to enter this market, and we suspect

M&A (buying in experience) will be the preferred

route to market.

Brownfield modifications market in NCS. In

February 2013, WorleyParsons acquired

Rosenberg, a fabrication yard in Norway, and

Rosenberg WorleyParsons AS will offer a range

of services from conceptual/FEED work to

maintenance, modification and topsides. In

addition, in collaboration with IntecSea,

WorleyParsons’ subsea engineering division, it

plans to bid for EPCI jobs. Rosenberg, which was

part of Aker Solutions until 2004, has been

building EPC capabilities and has ambitions to

become a key provider of EPC services to the

NCS targeting brownfield modifications, pure

construction and subsea work (its first job was

secured with Subsea 7 for tie-in spool fabrication

on BG’s Knarr field. Management has ambitions

to become a strong market no.3 (behind Aibel and

Aker Solutions) through expanding its market

offering and increasing market share. However,

its biggest challenge currently is ramping up

capacity and being competitive – local

engineering capability in Norway is already

stretched and high cost and so alternatives are

being explored.

The collaboration between Aibel and AMEC has

not secured any work to date (several projects

were lost to Asian competition) with limited

prospects in the remainder of 2013. However,

2014 should offer significant opportunities with

the combination adopting smarter bidding

strategies, particularly around costs (incorporate

low-cost resources from Asia, engineering outside

of Norway, etc). Aibel’s overall position in the

NCS remains strong with 40-50% market share of

onshore terminals and offshore facilities.

Engineering and brownfield market in UKCS.

Many global engineers are now encroaching on the

UK North Sea. WorleyParsons opened its first

office in Aberdeen in September 2012 (adding to its

six sites in England, with its UK head office in

London), and although progress to date has been

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slow (25 people currently versus the planned 40 at

the time of opening), management has long-term

ambitions to expand into the market will a focused

market offering including its subsea engineering

business Intecsea. In addition, Foster Wheeler also

has ambitions increasingly to target engineering and

operations and maintenance work in the North Sea.

The recent acquisition of upstream consultancy

company, Ingen Ideas, is planned to be a

springboard to offer a wider range of services into

the UKCS market where the likes of Wood Group

and AMEC currently have strong market positions.

However, we note the 'no-poaching' gentleman's

agreement in place between the main engineering

houses effectively means growth into new regions if

often a long game.

North Sea OCTG. Spot market pricing appears

steady for OCTG supply, although OCTG suppliers

continue to be willing to offer material discounts

(10-20%) to secure long-term agreements (we note

Hunting recently secured additional contracts with

Apache and Taqa). ‘Dopeless’ connection

technologies continue to increase market

penetration and premium connections remain the

key differentiator – difficult to compete without

this capability. The medium-term threat on the

horizon is Russian player TMK, which has

ambitions to gain a foothold in the European

market, although there’s uncertainty around

perceived quality and anti-dumping regulations.

North Sea project outlook

Overall, the UKCS is very busy tendering

development projects right now (and with 120

developable projects on the horizon in the next 5-10

years, this has potential to be a very healthy

medium-term market), whereas Norway appears

somewhat slower (a project manager at Statoil talked

of another round of "project evaluations") after a

strong period of awards (Martin Linge, Knorr, Aasta

Hansteen, Mariner, etc) – 2014 should see a return to

large project awards in Norway. Canada appears

very busy, particularly with developments for

Exxon/Suncor (several jobs in the USD100-150m

range) and there’s potential for a sizable contract

with Maersk in the Danish sector.

What to look out for near term:

Rosebank (deepwater West of Shetland):

SURF equipment (including flexibles), SURF

installation, plus an export pipeline job.

Edradour (Total project West of Shetland) is a

tieback to Laggan Tormore (SURF installation).

Kraken (EnQest): SURF equipment

(including flexibles), SURF installation.

Catcher (Premier): SURF equipment

(including flexibles), SURF installation.

Bressay (Statoil): SURF equipment (including

flexibles), SURF installation. We think this is an

option job for Subsea 7, which secured Mariner.

Engineering cost base challenges

The ‘Pure’ or independent engineers (AMEC,

Wood Group, WorleyParsons, KBR, etc) appear to

be facing a challenging six to 12 months. Market

volumes have been growing through 2011-13,

fuelled by an increase in industry capital

expenditure and project sanctioning. However,

momentum has stalled in the rate of project

sanctioning (indeed, there have been several

high-profile project cancellations this year) and as

large-volume projects in current backlogs begin to

roll off, the engineers run the risk of declining

utilisation unless cuts are made. However,

managing the cost base is trick – many engineering

businesses are ‘quick to cut’ in a downturn, but with

a potential recovery on the horizon (based on the

volume of earlier-stage conceptual/FEED work in

the market today), the industry may be minded to

keep hold of its people and take the hit for a quarter

to two. This is a clear margin risk in 2014 – careful

manpower management is required to navigate the

temporary lull in activity levels.

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Industry cost inflation

The oil industry has always had a real problem

controlling costs – about 25% of E&P capital

projects suffer cost overruns of 50% or more. There

appears to be a higher level of ‘finger pointing’ at

services companies from the oil companies

industry – "the cost of SURF services has doubled

in last 10 years" cried one oil company. People and

wage inflation have been a real problem – the

industry is still feeling the effects of years of

chronic underinvestment in the 1990s and early

2000s – and it’s difficult to see what changes this

– the industry moving to exploit ever-more

complex geological structures (deeper, further,

harsher, etc) requires more people to exploit each

barrel of oil. While a higher oil price would clearly

soften the blow, the brutal fact is the oil industry

repeatedly and systematically fails to control costs

and returns on investment are below target.

Andrew Gould, Chairman of BG and former CEO

of Schlumberger, claimed a marked reduction in

costs is crucial for the UKCS basin to remain

competitive on the international stage. The

industry needs to embrace more willingly new

technology (Norway ‘light years’ ahead of the UK

on technology development, ie, subsea

processing, modern drilling techniques, etc), as

well as moving to more remotely managed/

maintained facilities, reducing offshore personnel

and making more efficient use of skilled resources

– the strive to 100% uptime is crucial if the

industry is to deliver on its promise.

Learning lessons from the last cycle where the

balance of power lay firmly with the oil services

sector, oil companies have proactively addressed

the cost-inflation threat in order to safeguard

returns – we’ve seen a lot more framework

agreements awarded (security of volume for the

contractor, security of price for the oil company),

more lower-value-added work transferred to the

services sector, and oil companies encouraging

competition (Petrobras is well known for this but

there’s evidence of this ‘practice’ occurring

outside Brazil). And oil companies continue to

‘go into battle’ with the services sector when

procuring for major projects (we note Total’s

well-documented attempts to bring all parts of the

value chain down on costs for its Kaombo project

in Angola). These issues appear to be intensifying

in the current environment.

Subsea technology – ‘developing the next wave’

There's not a huge amount new here: many of

the 'new' subsea technologies of many years ago

are still the same today, just a little further into

their evolution. Its well-known subsea is growing

faster than the overall industry, and the future will

see a greater proportion of hydrocarbon production

from subsea developments. But the sector is not

without its challenges: low recovery rates –

typically 25% versus global averages closer to

35-40% and high cost inflation given a shortage

of specialists. And developing new technologies

and materials to deal with ever-more complex

geological formations in deeper waters and

harsher environments take years if not decades.

Through combining well intervention and subsea

processing, there is potential to drive significant

improvements in recovery factors. Understanding

the condition of equipment (asset integrity) and

being better able to predict future performance

should all drive increased capital and production

efficiencies – the ‘industrial internet’ or digital

oilfield will see increased sensoring, increased

monitoring and increased data flow – and will

allow for lower production disruption/greater

equipment uptime.

The industry is increasingly of the belief subsea

processing and subsea compression is “the

perfect solution” to brownfields (by increasing

production plus extending the life of the well

through reducing wellhead pressure and

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improving flow) and a real “enabler” for

greenfields (access to stranded reserves,

minimising impact on topside installation leading

to vastly improved project economics) and the

difference between an economically viable project

and no project at all. The industry also sees

subsea-to-beach as a viable option to removing/

reducing surface facility costs.

The market leaders in this space are FMC for

subsea processing (its Marlim Sul project in

Brazil is now operational and is well placed for

contracts with Total and ENI) and Aker Solutions

for subsea processing (working on first

commercial project – the Asgard development for

Statoil). GE and Cameron are some way behind.

Both have a common preference for

modularisation of these complex units (minimises

disruption if ‘components’ or modules can be

retrieved for maintenance/replacement rather than

whole processing/separation unit) and having full

system integration capability is hugely beneficial.

These technologies remain in their infancy, and

we don't see them as near-term growth drivers for

the main players. However, long-term growth

potential is significant now and early positioning is

crucial for longer-term success. Significantly, more

technology development is still required in order to

exploit developments with larger step-outs, greater

water depths and simplified/more compact systems

will be required for smaller fields. Power

transmission (transporting AC power over long

distances with low frequency) and power generation

remain key challenges, and there are ongoing

programmes to develop 'gravity' and 'cyclonic'

separation technologies.

Ultimately, significant R&D (we note GE has a

USD1bn R&D budget) and increased industry

collaboration (JIPs, etc) are required to overcome

these challenges – there are several building

blocks required for Statoil to realise its vision for

a subsea factory – separation, power, pumping,

processing, storage, etc, all on the seafloor.

Indeed, "game changing" technologies tend to

have a very long gestation period – for example,

the industry’s first JIP on FLNG was 1994-98 but

only in the past few years have we had

developments sanctioned based on this technology

– Shell’s Prelude, and we note it also looks to be a

viable solution for the Browse field in Australia

(up to three vessels may be required here – positive

for Technip/Samsung JV) and a multitude of other

projects globally plan to use this technology.

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Natural Resources & Energy Global Energy Equipment 15 October 2013

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Stocks covered

CGG (GEPH.PA)

PGS (PGS.OL)

TGS Nopec (TGS.OL)

China Oilfield Services (2883.HK)

Transocean (RIGN.VX)

Seadrill (SDRL.OL)

Amec (AMEC.L)

Ezra Holdings (EZRA.SI)

Lamprell (LAM.L)

Kentz (KENZ.L)

McDermott (MDR.N)

Petrofac (PFC.L)

Technip (TECF.PA)

Subsea7 (SUBC.OL)

Saipem (SPMI.MI)

Sinopec Engineering (2386.HK)

Wood Group (WG.L)

Aker Solutions (AKSO.OL)

Cameron (CAM.N)

FMC Tech (FTI.N)

Honghua Group (0196.HK)

Hunting (HTG.L)

National Oilwell (NOV.N)

Schoeller Bleckmann (SBOE.VI)

Bourbon Offshore (GBPN.PA)

BW Offshore (BWO.OL)

Bumi Armada (BUAB.KL)

SBM Offshore (SBMO.AS)

Anton Oilfield (3337.HK)

Core Lab (CLB.N)

Fugro (FUGRc.AS)

Schlumberger (SLB.N)

SPT Energy Group (1251.HK)

Valuations & risks

Our valuation approach and investment risks for all the stocks

under our research coverage mentioned in this report

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CGG – maintain Overweight (V), target price EUR23 (from EUR27)

For CGG, our EUR23 target price is based on an

equally weighted average of DCF and sum-of-the-

parts valuations. We base our forecasts on

EUR/USD of 1.35 (from 1.325).

Under our research model, for stocks with a

volatility indicator, the Neutral band is 10

percentage points above and below the hurdle rate

for eurozone stocks of 9%. This translates into a

Neutral band of -1% to +19% around the current

share price. Our target price of EUR23 provides a

total potential return of 49.1%, which is above the

Neutral band of our model; therefore, we maintain

an Overweight (V) rating. Potential return equals

the percentage difference between the current

share price and the target price, including the

forecast dividend yield when indicated. CGG does

not screen as Volatile under the HSBC

methodology, but we keep the “V” tag to reflect

the underlying business uncertainty.

Downside risks to our Overweight (V) rating –

these include further development project

emphasis from oil companies driving less spend

on exploration work, lower oil prices, which could

drive lower levels of E&P investment, a higher

level of competitive pressure from new industry

entrants, too highly priced acquisitions and

unfavourable moves in the USD/EUR, given

CGGVeritas’ exposure to an EUR cost base

(EUR400m exposure for the group, of which 50%

is for Sercel).

CGG: Valuation summary

Sum-of-the-parts model (USDm) 2013e EBITDA 2013e sales EV/EBITDA multiple (implied EV/sales) implied EV Implied EV (2014e)

Land/Airborne 73.7 491.3 4.5 0.7 331.7 289.1Offshore contract 491.3 1,965.0 5.3 1.3 2,579.1 2,542.4

Acquisition 565.0 2,456.3 5.2 1.2 2,910.7 2,831.6

Multiclient 640.2 800.3 4.5 3.6 2,880.9 2,676.8Imaging & Reservoir 166.3 715.5 7.0 1.6 1,163.8 1,215.1

GGR 806.5 1,515.8 5.0 2.7 4,044.7 3,891.9

Equipment 379.5 1,185.9 7.6 2.4 2,882.2 2,882.2

other 0.0 0.0 0.0 0.0 0.0 0.0eliminations -405.8 -899.0 5.9 0.0 -2,402.7 -2,208.9

Total 1,345.1 4,259.0 5.5 4.1 7,435.0 7,396.7

net debt -1,963.1 -1,694.1 minorities 250.8 250.8 implied market value (USDm) 5,722.7 5,953.4 number of shares (m) 177.4 177.4 implied value per share (EUR) 23.9 24.9

DCF valuation (USDm) beta risk premium LT growth WACC

Assumptions 1.25 6.0% 5.0% 7.9% (USDm) EV 2012e net debt / associates / minorities market value per share (EUR)discounted to end-2013 7,011.1 1,963.1 5,048.0 21.1(USDm) EV 2013 net debt / associates / minorities market value per share (EUR)discounted to end-2014 7,339.7 1,694.1 5,645.5 23.6

SUMMARY (EUR per share) 2013e 2014e Average Previous Change

DCF 21.1 23.6 22.3 26.8 -16.6% SOTP 23.9 24.9 24.4 27.3 -10.9%

Overall average (equally weighted) 23.3 27.0 -13.7%

Source: Company data, HSBC estimates

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CGG: Divisional DETAILS AND KEY RATIOS

(USDm) 2012a 2013e 2014e 2015e

Equipment Sales 1204 1186 1275 1434

% growth -1% 8% 13%EBIT 380 326 338 409

% growth -14% 4% 21%margin 31.6% 27.5% 26.5% 28.5%

Acquisition Sales 1878 2456 2655 3040

% growth 31% 8% 15%EBIT -28 160 266 456

% growth -662% 66% 72%margin -1.5% 6.5% 10.0% 15.0%

GGR Sales 950 1516 1654 1862

% growth 60% 9% 13%EBIT 183 349 389 456

% growth 91% 12% 17%margin 19.3% 23.0% 23.5% 24.5%

Profit & loss Revenue 3410 4259 4613 5239

% growth 7% 25% 8% 14%EBITDA 1024 1345 1470 1811

margin 29.6% 31.6% 31.9% 34.6%EBIT 365 526 692 981

margin 10.7% 12.3% 15.0% 18.7%Other income (JVs &

assocs)37 58 25 43

Net Finance -176 -207 -194 -171HSBC PBT 246 381 523 852

Tax -99 -105 -149 -243Minorities 17 19 20 19

HSBC PAT 130 257 354 591Diluted shares (m) 163.4 177.4 177.4 177.4HSBC EPS (USD) 0.80 1.45 2.00 3.33

DPS (USD) 0 0 0 0 Cash flow Oper. Cash Flow 921 857 976 1244

Capital Expenditure 733 768 707 625Free Cash Flow 95 88 251 577Net Debt (Cash) 785 1963 1694 1076

Valuation metrics P/E 26.1 14.4 10.4 6.3

EV/EBITDA 4.4 4.2 3.7 2.6EV/Sales 1.3 1.3 1.2 0.9

P/B 0.7 0.8 0.7 0.6 FCF Yield 2.5% 2.3% 6.1% 14.1%


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PGS ─ maintain Overweight (V), target price NOK101 (from NOK111)

For PGS, our NOK101 target price is based on an


parts valuations and a USD/NOK level of 5.95

(from 5.90).




for Norwegian listed stocks of 11.0%. This

translates into a neutral band of 1% to +21%

above the current share price for PGS. Our target

price of NOK101 provides a potential return of

48.6%, which is outside the Neutral band of our

model; therefore, we maintain our Overweight (V)

rating. Potential return equals the percentage

difference between the current share price and the

target price, including the forecast dividend yield

when indicated. PGS does not screen as Volatile

under the HSBC methodology, but we keep the “V”

tag to reflect underlying business uncertainty.


these include further development phase project

emphasis from oil companies, driving less spend

on exploration work; lower oil prices, which

could drive lower levels of E&P investment; a

higher level of competitive pressure from new

industry entrants; too highly priced acquisitions,

particularly in data processing (a stated target area

of expansion for PGS) and new technologies, and

delays with planned newbuild seismic vessels.

PGS: Valuation summary

Sum of the parts model (USDm) 2013e EBITDA 2013e sales EV/EBITDA multiple

(Implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Marine (contract) 385.2 802.5 6.5 3.1 2,503.8 2,531.1 Marine (MC) 467.1 671.1 4.3 3.0 1,985.1 1,945.6 Processing / other 28.0 174.8 8.0 1.3 224.0 210.0 Marine Geophysical (total) 880.3 1,648.4 5.4 2.9 4,712.9 4,686.7 eliminations -12.4 0.4 5.4 0.0 -66.2 -64.4

Total 867.9 1,648.7 5.4 2.8 4,646.7 4,622.3

net debt -696.5 -789.1 minorities / other 128.1 128.1 implied market value (US$ m) 4,078.2 3,961.2 number of shares (m) 216.6 216.6 implied value per share (US$) 18.8 18.3 implied value per share (NOK) 112.0 108.8


Assumptions 1.00 8.0% 5.0% 9.2% (USDm) EV 2013e net debt / associates /

minoritiesmarket value per share (USD) per share (NOK)

discounted to end-2013 3738.6 572.2 3166.4 14.6 87.0 (USDm) EV 2014e net debt / associates /

minoritiesmarket value per share (USD) per share (NOK)

discounted to end-2014 4232.8 664.8 3568.1 16.5 98.0

SUMMARY (NOK per share) 2013e 2014e Average Previous Change

DCF 87.0 98.0 92.5 101.4 -8.8% SOTP 112.0 108.8 110.4 120.8 -8.6% Overall average (equally weighted) 101.4 111.1 -8.7


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PGS: Divisional details and key ratios

(USDm) 2012a 2013e 2014e 2015e

Marine (contract) Sales 624 802 1026 1208

% growth -1% 29% 28% 18%EBIT 100 233 333 465

% growth 300% 132% 43% 40%margin 16.1% 29.0% 32.5% 38.5%

Marine (MC, other) Sales 895 846 844 651

% growth 43% -5% 0% -23%EBIT 214 220 232 146

% growth 61% 3% 5% -37%margin 23.9% 26.0% 27.5% 22.5%

Profit & loss Revenue 1519 1649 1870 1860

% growth 21% 9% 13% -1%EBITDA 778 868 1007 1031

margin 51.2% 52.6% 53.8% 55.4%EBIT 294 432 542 588

margin 19.3% 26.2% 29.0% 31.6%Other income / (loss) -4 -3 -5 -8

Net Finance -61 -35 -42 -44HSBC PBT 259 394 495 537

Tax -43 -88 -116 -138Minorities 0.0 -0.5 -1.0 -0.5

HSBC PAT 208 306 380 400Diluted shares (m) 217.5 217.5 217.5 217.5HSBC EPS (USD) 0.96 1.41 1.75 1.84

DPS (USD) 0.40 0.60 0.70 0.75 Cash flow Operating Cash Flow 753 692 824 851

Capital Expenditure 656 868 657 677Free Cash Flow 89 -179 163 167Net Debt (Cash) 527 789 881 859

Valuation metrics P/E 11.9 8.1 6.5 6.2

EV/EBITDA 3.7 3.7 3.3 3.2EV/Sales 1.92 1.93 1.75 1.76

P/B 1.29 1.18 1.07 0.97FCF Yield 3.3% -6.8% 6.2% 6.3%


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TGS ─ maintain Overweight (V), target price NOK220 (from NOK242)

For TGS, our NOK220 target price is based on an


parts valuations and a USD/NOK level of 5.95

(from 5.90).




for Norwegian-listed stocks of 11.0%. This

translates into a neutral band of 1% to +21%

above the current share price for TGS. Our target

price of NOK220 provides a total potential return

of 49.2%, which is outside the Neutral band of our

model; therefore, we maintain our Overweight (V)

rating. Potential return equals the percentage



when indicated. TGS does not screen as Volatile

under the HSBC methodology but we keep the “V”

tag to reflect the underlying business uncertainty.


these include further development-phase project

emphasis from oil companies, driving less spend

on exploration work; lower oil prices, which

could drive lower levels of E&P investment; a


industry entrants; and new technologies.

TGS Nopec: Valuation summary

Sum-of-the-parts model (USDm) 2013e EBITDA 2013e sales EV/EBITDA multiple (implied EV/sales) Implied EV (2013e) Implied EV (2014e)

Multi-client 688.2 791.0 5.0 4.4 3,441.0 3,460.0Contract 19.6 53.0 4.0 1.5 78.6 122.6eliminations 0.0 0.0 0.0 0.0 0.0 0.0

Total 707.8 844.0 5.0 4.2 3,519.5 3,582.5

net cash (debt) 385.2 381.3 minorities 0.0 0.0 implied market value (USD m) 3,904.7 3,963.8 number of shares (m) 104.6 104.6 implied value per share (USD) 37.3 37.9 implied value per share (NOK) 222.2 225.6


Assumptions 1.23 5.0% 5.0% 9.1% (USDm) EV 2013e net debt / associates / minorities market value per share (USD) per share (NOK)discounted to end-2013 3336.2 -385.2 3721.3 35.7 212.6(USDm) EV 2014e net debt / associates / minorities market value per share (USD) per share (NOK)discounted to end-2014 3484.9 -381.3 3866.2 37.1 220.9


DCF 212.6 220.9 216.8 229.8 -5.7% SOTP 222.2 225.6 223.9 254.6 -12.1%

Overall average 220.3 242.2 -9.0%

Source: HSBC Estimates

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TGS Nopec: Summary financial data

(USDm) 2012a 2013e 2014e 2015e

Multi-client seismic Sales 832 728 827 897% growth 66% -13% 14% 9% Geological products Sales 70 63 67 74% growth 5% -10% 8% 10% Contract Sales 30 53 61 67% growth -27% 75% 15% 10% EBIT (group) 402 363 415 431% growth 67% -10% 14% 4%margin 43.2% 43.0% 43.5% 41.5% Profit & Loss Revenue 932 844 955 1038% growth 53% -9% 13% 9%EBITDA 802 708 810 864margin 86.0% 83.9% 84.8% 83.2%EBIT 402 363 415 431margin 43.2% 43.0% 43.5% 41.5%Other income / (loss) 0 0 0 0Net Finance 5 1 8 10HSBC PBT 407 369 423 441Tax (implied) -123 -113 -129 -134Minorities 0 0 0 0HSBC PAT 284 257 294 306Diluted shares (m) 105 105 105 105HSBC EPS (USD) 2.72 2.45 2.81 2.93DPS (USD) 1.01 1.34 1.51 1.68 Cash flow Operating cash flow 663 593 671 725Capital expenditure 509 447 537 524Free cash flow 110 163 115 195Net debt (cash) -342 -385 -381 -427 Valuation metrics P/E 8.9 10.0 8.6 8.3EV/EBITDA 2.8 3.1 2.7 2.5EV/Sales 2.4 2.6 2.3 2.1P/B 2.2 2.0 1.8 1.7FCF yield 4.3% 6.3% 4.4% 7.5%ROIC 34% 28% 28% 26%


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China Oilfield Services (COSL) – maintain Neutral rating and HKD19.60 target price

Valuation: Our target price of HKD19.6 is derived

using SOTP methodology. We use DCF to value its

drilling business with 8.5% WACC, 3% terminal

growth rate. We apply a 7x EV/EBITDA to 2013e

EBITDA of the well services and marine services

business, and 6x EV/EBITDA to the 2013e

EBITDA of the geophysics business.

Under our research model, for stocks without a



for China stocks of 9.5%. At the time we set our

target price, it implied a potential return that was

within the Neutral band; therefore, we rate the

stock Neutral. Potential return equals the

percentage difference between the current share

price and the target price, including the forecast

dividend yield when indicated.

Upside/downside risks: higher/lower realised

dayrates; more/lack of new rig purchases.

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China Oilfield Services: Summary financial data

2012a 2013e 2014e 2015e

Drilling Sales 11,252 14,925 16,300 16,741 % growth 18.3% 32.7% 9.2% 2.7% EBIT 3,714 5,153 5,939 6,597 % growth 8.2% 38.7% 15.3% 11.1% margin 33.0% 34.5% 36.4% 39.4% Well services Sales 4,858 5,344 5,878 6,466 % growth 23.0% 10.0% 10.0% 10.0% EBIT 766 766 857 948 % growth 29.8% -0.1% 11.8% 10.7% margin 15.8% 14.3% 14.6% 14.7% Marine support & trans Sales 2,945 3,092 3,247 3,409 % growth 16.2% 5.0% 5.0% 5.0% EBIT 545 573 599 624 % growth 5.4% 5.1% 4.6% 4.1% margin 18.5% 18.5% 18.5% 18.3% Geophysical Sales 3,050 3,507 3,858 4,244 % growth 25.6% 15.0% 10.0% 10.0% EBIT 836 765 801 841 % growth 35.3% -8.5% 4.7% 5.0% margin 27.4% 21.8% 20.8% 19.8% Profit and loss Revenue 22,279 26,869 29,283 30,860 % growth 20.2% 20.6% 9.0% 5.4% EBIT 5,862 7,257 8,196 9,010 margin 26% 27% 28% 29% EBITDA 9,035 10,508 11,555 12,513 margin 41% 39% 39% 41% PBT 5,437 7,036 8,117 9,035 Tax (867) (985) (1,461) (1,626) PAT 4,570 6,051 6,656 7,409 EPS 1.02 1.35 1.48 1.65 Cash flow Operating cash flow 8,739 11,225 9,886 10,966 Capital expenditure (5,000) (5,000) (6,000) (6,000) Free cash flow 323 6,225 3,886 4,966 Net debt (cash) 19,601 14,769 12,699 9,730 Valuation metrics P/E 15.9 12.0 10.9 9.8 EV/EBITDA 10.7 8.7 7.8 6.9 EV/Sales 4.3 3.4 3.1 2.8 P/B 2.2 2.0 1.7 1.5 FCF yield 4.4 2.9 5.2 6.2


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Transocean – maintain Overweight (V) rating, target price CHF62/USD67 (unchanged)

For Transocean, our target price of

USD67/CHF62 per share is based on the average

of a company DCF model and replacement value

model. We use a USD/CHF exchange rate as

0.925 (unchanged).




for US stocks of 7%. This translates into a Neutral

band of -3% to +17% around the current price for

Transocean. Our target price of USD67/CHF62

provides total potential return of 53.4%, above the


our Overweight (V) rating. Potential return equals



forecast dividend yield when indicated.

Transocean does not screen as Volatile under the

HSBC methodology, but we keep the “V” tag to

reflect the underlying business and uncertainty

related to Macondo trial.


these include further development project delays

from oil companies driving a lower annual spend

on development work, delays in starting work

with new vessels due to lack of crews or

operational problems, lower oil prices, which

could drive lower levels of E&P investment, a


industry entrants (especially in the jack-up drilling

rig category), credit cycle problems that could

delay its refinancing potential and, given

Transocean’s involvement in the GOM oil spill,

any adverse decision by the authorities and

subsequent penalty imposition on the company.

Transocean: Valuation summary


Assumptions 1.25 4% 1.0% 7.6% (USDm) EV 2012e net debt / associates /

minoritiesmarket value per share (USD) per share (CHF)

Discounted to end-2013 30,401.5 7,325.0 23,076.5 65.1 60.2 (USDm) EV 2013e net debt / associates /

minoritiesmarket value per share (USD) per share (CHF)

Discounted to end 2014 34,878.8 10,695.6 24,183.2 68.2 63.1

Replacement cost valuation (USDm) Replacement cost 35,602.5 Net debt 10,695.6 Value per share 58.7 Trading premium 130% Typical trading premium versus replacement/market value Value per share (USD) 76.3 (pre-Macondo cost adjustment of USD8.6/shr)

SUMMARY (USD per share) 2013e 2014e Average Previous Change

DCF 65.1 68.2 66.7 66.7 0% Trading replacement cost (adjusting Macondo liabilities) 67.7 67.7 0% Overall average (equally weighted) 67.2 67.2 -


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Transocean: Divisional information and key ratios

(USDm) 2012 2013e 2014e 2015e

High-specification floaters Sales 6780 7152 7621 8218 % growth 18% 5% 7% 8% EBIT (excl one-offs) 3641 3958 4240 4683 % growth 41% 9% 7% 10% margin 53.7% 55.3% 55.6% 57.0% Mid-water floaters Sales 1573 1721 2295 2413 % growth 8% 9% 33% 5% EBIT (excl one-offs) 706 829 1271 1346 % growth 13% 17% 53% 6% margin 44.9% 48.1% 55.4% 55.8% Jackup and others Sales 378 557 594 600 % growth -67% 47% 7% 1% EBIT (excl one-offs) 65 205 158 183 % growth -77% 216% -23% 16% margin 17.2% 36.9% 26.6% 30.5% Profit & loss Revenue 9196 9658 10734 11464 % growth 1% 5% 11% 7% EBITDA (excl one-offs) 2808 3616 4444 4902 margin 30.5% 37.4% 41.4% 42.8% EBIT (excl one-offs) 1685 2506 3263 3641 margin 18.3% 25.9% 30.4% 31.8% Other income / (loss) -104 -46 0 0 Net Finance -715 -634 -635 -560 HSBC PBT 1018 1872 2629 3081 Tax -91 -407 -594 -696 Minorities 8 3 3 3 HSBC PAT 927 1464 2034 2385 Diluted shares (m) 359 360 360 360 HSBC EPS (USD) 2.62 4.08 5.67 6.64 DPS (USD) 0.00 2.24 2.27 2.49 Cash flow Operating Cash Flow 2708 -270 2566 3258 Capital Expenditure 1409 2482 1540 1366 Free Cash Flow 975 -2675 1026 1892 Net Debt (Cash) 6622 9993 9780 8782 Valuation metrics P/E 16.7 10.7 7.4 6.2 EV/EBITDA 8.2 7.3 5.8 5.0 EV/Sales 2.50 2.73 2.42 2.18 P/B 0.98 1.14 1.04 0.94 FCF Yield 6.2% -17.0% 6.9% 13.0%


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Seadrill – maintain Neutral, target price NOK280/USD47.5 (unchanged)

For Seadrill, our target price of NOK280 is based

on the average of a company DCF model,

individual rig contract DCF and a replacement

value model (we also assume USD/NOK at 5.90).




for Norway-listed stocks of 11%. This translates

into a Neutral band of 6% to +16% above the

current price for Seadrill. At the time we set our



stock Neutral. Potential return equals the




Downside risks to our Neutral rating: these

include further development project delays from

oil companies driving a lower annual spend on

development work, delays in starting work with

new vessels owing to lack of crews or operational

problems, lower oil prices that could drive lower

levels of E&P investment, a higher level of

competitive pressure from new industry entrants

(especially in the jackup drilling rig category),

credit cycle problems that could delay its

refinancing potential and, given Seadrill’s

interests in M&A deals, too highly priced

acquisitions that could destroy value.

Upside risks to our Neutral rating: these

include a higher-than-expected increase in

dayrates on contract renewal, a higher oil price

leading to higher E&P spend and, thereby,

tightening the supply delays in additional rig

supplies from shipyards.

Seadrill: Valuation summary


Assumptions 1.10 4.0% 1.5% 7.3% (USDm) EV 2013e net debt / associates /

minoritiesmarket value per share

(USD)per share

(NOK) Discounted to end-2013 29995.0 9306.8 20688.2 44.1 260.3 (USDm) EV 2014e net debt / associates /


(USD)per share

(NOK) Discounted to end 2014 33277.6 10732.9 22544.7 48.1 283.6 Fleet model DCF EV 2012e net debt / associates /


(USD)per share

(NOK) Discounted to end-2013 30983.3 8548.9 22434.4 47.8 282.2

Replacement cost valuation (NOKm) 2013e

Ownership cost (discounted to 2013) 135752.2 (NOKm) Average replacement cost 219.1 (NOK) Trading premium 130% Value of associates 4088.7 (NOKm) Trading replacement cost (including value of associates) 284.8 (NOK)

SUMMARY (NOK per share) 2013e 2014e Fleet-based DCF

Average Previous Change

DCF 260.3 283.6 282.2 275.4 275.4 0% Trading replacement cost 284.8 284.8 0% Overall average (equally weighted) 280.1 - -


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Seadrill: Summary financial data

(USDm) 2012a 2013e 2014e 2015e

Mobile units Sales 3718 4573 5799 7135 % growth 7% 23% 27% 23% EBIT (excl one-offs) 1474 1727 2446 3178 % growth -3% 17% 42% 30% margin 39.6% 37.8% 42.2% 44.5% Tender rigs Sales 758 370 185 197 % growth 39% -51% -50% 7% EBIT (excl one-offs) 318 154 72 79 % growth 44% -51% -53% 9% margin 42.0% 41.7% 39.1% 39.9% Profit & loss Revenue 4479 4946 5986 7335 % growth 7% 10% 21% 23% EBITDA (excl one-offs) 2405 2595 3332 4224 margin 53.7% 52.5% 55.7% 57.6% EBIT (excl one-offs) 1792 1881 2518 3257 margin 40.0% 38.0% 42.1% 44.4% Other income / (loss) -219 -4 33 87 Net finance -136 -429 -492 -589 HSBC PBT 1258 1448 2060 2755 Tax -180 -152 -227 -317 Minorities 111 140 154 95 HSBC PAT 989 1155 1679 2343 Diluted shares (m) 490.0 491.0 491.0 491.0 HSBC EPS (USD) 2.11 2.46 3.58 4.99 DPS (USD) 3.51 3.60 3.80 4.25 Cash flow Operating cash flow 1590 2001 2690 3416 Capital expenditure 1557 3476 2334 3779 Free cash flow 296 -1455 370 -349 Net debt (Cash) 10774 11750 13176 15530 Valuation metrics P/E 21.7 18.6 12.8 9.2 EV/EBITDA 13.8 13.2 10.7 9.0 EV/sales 7.4 6.9 6.0 5.2 P/B 3.54 3.83 3.84 3.61 FCF yield 1.3% -6.3% 1.6% -1.5% Dividend yield 7.7% 7.8% 8.3% 9.3%


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Amec – maintain Neutral rating, target price 1,130p (unchanged)

For Amec, our target price of 1,130p per share is

based on equal weighted average of fair values

from average of 2013e and 2014e DCFs, average

of 2013e and 2014e sum-of-the-parts analyses.




for UK-listed stocks of 7.5%. This translates into

a Neutral band of +2.5% to +12.5% above the

current share price for Amec. Our target price of

1,130p provides a total potential return of 6.5%,

within the Neutral band of our model; therefore,

we maintain our Neutral rating. Potential return

equals the percentage difference between the

current share price and the target price, including

the forecast dividend yield when indicated


include lower oil prices for a continued period of

time leading to lower annual order intake for

associated engineering work, deferment of

projects from oil companies, higher level of

competitive pressure from new as well as existing

players, overpriced acquisitions that could destroy

value and failure to achieve targets specified in its

plan through cost reductions and/or organic and

inorganic growth.

Upside risks to our Neutral rating: these include

sustainable growth in its end markets – oil & gas,

mining and unconventionals, exposure to shale

business, value-accretive mergers & acquisitions.

Share buybacks may also be welcome.

Amec: Valuation summary

Sum-of-the-parts model (GBPm) 2014e EBITDA 2014e sales EV/EBITDA multiple

EV/sales Implied EV (2013e)

Implied EV (2014e)

Americas 232.1 2,261.4 8.5 0.9 2044.0 1973.1 Europe 116.0 1,308.8 7.0 0.6 759.0 812.1 Growth regions 37.1 528.3 7.0 0.5 283.4 259.4 Other 7.0 9.8 7.2 0.0 81.9 50.4 Eliminations -34.5 -66.1 7.2 0.0 -276.2 -247.3

Total 357.7 4,042.2 8.0 0.7 2892.1 2847.7 net debt 203.1 390.3 associates 47.0 47.0 minorities 1.0 1.0 implied market value (GBPm) 3143.2 3286.0 number of shares (m) 299.0 297.0 implied value per share (GBP) 10.51 11.06

DCF valuation (GBPm) beta risk premium LT growth WACC

Assumptions 1.17 4.5% 5.0% 8.1% (GBPm) EV 2013e net debt / associates / minorities market value per share Discounted to end-2013 3042.8 -250.1 3,292.9 11.3 (GBPm) EV 2014e net debt / associates / minorities market value per share Discounted to end-2014 3137.8 -437.3 3,575.0 12.3

SUMMARY (GBP per share) 2013e 2014e Average Previous Change

DCF 11.33 12.30 11.82 11.82 0% SOTP 10.51 11.06 10.79 10.79 0% Overall average (equally weighted) 11.30 - -


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Amec: Divisional information and key ratios

(GBPm) 2012a 2013e 2014e 2015e

Americas Sales 2500 2343 2261 2358 % growth 38% -6% -3% 4% EBITA 233 234 226 236 % growth 17% 1% -3% 4% margin 9.3% 10.0% 10.0% 10.0% Europe Sales 1150 1225 1309 1378 % growth 12% 6% 7% 5% EBITA 91 98 113 121 % growth 10% 8% 15% 8% margin 7.9% 8.0% 8.6% 8.8% Growth regions Sales 531 524 528 568 % growth 20% -1% 1% 8% EBITA 32 34 36 40 % growth -30% 6% 5% 12% margin 6.0% 6.5% 6.8% 7.0% Sales other/eliminations -23.0 -52.9 -56.4 -58.4 Investments/Other 7.0 10.0 7.0 7.0 Corporate costs -33 -34 -34 -35 Profit & loss Revenue 4158 4038 4042 4246 % growth 28% -3% 0% 5% EBITDA 341 353 358 380 margin 8.2% 8.7% 8.8% 9.0% EBITA 330 343 347 369 margin 7.9% 8.5% 8.6% 8.7% EBIT 262 300 304 324 margin 6.3% 7.4% 7.5% 7.6% Net Finance -7 -7 -5 -2 HSBC PBT 329 336 342 367 Tax (implied) -79 -90 -91 -98 HSBC PAT 250 246 251 269 Diluted shares (m) 321 299 297 297 HSBC EPS (GBPp) 77.9 82.2 84.4 90.6 DPS (GBPp) 36.5 37.0 38.0 40.8 Cash flow Operating Cash Flow 242 284 332 340 Capital Expenditure

(organic) 19 21 25 20

Free Cash Flow 196 196 241 251 Net Debt (Cash) -99 -203 -390 -592 Valuation metrics P/E 13.8 13.1 12.7 11.9 EV/EBITDA 9.8 9.2 8.6 7.5 EV/Sales 0.81 0.81 0.76 0.67 P/B 3.19 2.70 2.46 2.25 FCF Yield 5.5% 5.5% 6.7% 7.0% ROIC 26.1% 26.7% 29.4% 34.4%


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Ezra Holdings– maintain Overweight rating, target price SGD1.25 (unchanged)

Our SOTP comprises a DCF estimate for Ezra’s

consolidated operations over an explicit forecast

period of 2013-22 using a 7.6% WACC and

terminal growth rate in line with long-term

inflation of 2%, plus the market value of its

associate stakes in listed entity EOC in Norway.

Our DCF estimate accounts for c97% of our SOTP.

Under our research model for stocks without a

volatility indicator, the Neutral band is 5ppts

above and below the hurdle rate for Singapore

stocks of 9%. At the time we set our target price,

it implied a potential return that was above the

Neutral band; therefore, we rate the stock

Overweight. Potential return equals the


price and target price, including the forecast


The key downside risks to our forecasts and rating

are possible delays in contract awards, project

execution, charter renewals, interest rate increases

(given more than 80% net gearing) and capital

market activity that may be dilutive to

minority interests.

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Ezra Holdings: Summary financial data

2012 2013e 2014e 2015e

Offshore support services Sales 281 242 276 302 % growth 26.9% -13.9% 14.0% 9.5% EBIT 51 24 63 69 % growth 6.6% -52.2% 162.3% 9.5% margin 18.0% 10.0% 23.0% 23.0%Marine services Sales 157 232 250 233 % growth -1.8% 47.3% 7.9% -7.0% EBIT 34 16 17 16 % growth 1.1% -53.3% 6.9% -5.5% margin 21.5% 6.8% 6.8% 6.9%Deepwater subsea service Sales 552 571 742 1,076 % growth 207.2% 3.5% 30.0% 45.0% EBIT 35 -51 59 108 % growth na na na 81.3% margin 6.3% -9.0% 8.0% 10.0% Profit & loss Revenue 984 1,041 1263 1605 % growth 76.0% 5.7% 21.4% 27.0% EBITDA 96 33 185 239 margin 9.8% 3.2% 14.6% 14.9% EBIT 51 -12 137 189 margin 5.2% -1.1% 10.8% 11.8% Net other income 36 67 -36 -41 HSBC PBT 87 56 101 148 Tax (implied) -22 10 -13 -20 HSBC PAT 65 63 86 126 Diluted shares (m) 1,020 1076 1076 1076 HSBC EPS (SGD) 0.06 0.06 0.08 0.12 DPS (SGD) 0.00 0.01 0.01 0.02 Cash flow Capital expenditure -289 -256 -159 -130 Net debt (cash) 1111 1232 1432 1512 Valuation metrics P/E 14.2 15.4 11.4 7.7 EV/EBITDA 18.9 59.5 11.6 9.2 EV/sales 1.8 1.9 1.7 1.4 P/B 0.9 0.8 0.8 0.7 FCF Yield -76.6 -37.4 -30.3 -22.5 ROIC 2.3 -0.7 5.1 6.3


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Lamprell – maintain Neutral (V) rating, target price 150p (from 160p)

For Lamprell, our 150p target price is based on an

equally weighted average of DCF, sum-of-the-parts

valuation and peer group (shipyards) book value

multiples; we assume USD/GBP at 1.60 (from 1.50).




for UK stocks of 7.5%. This translates into a

Neutral band of -2.5% to +17.5% around the

current share price for Lamprell. Our target price of

150p provides a potential return of 4.0%, within the

Neutral (V) band of our model; therefore, we have

a Neutral (V) rating. Potential return equals the




Downside risks to our Neutral (V) rating: these

include lower oil prices for a long period of time,

which could drive levels of E&P investment

down, resulting in smaller annual order intake

from new rig building and associated engineering

work; a higher level of competitive pressure from

Asian shipyards.

Upside risks to our Neutral (V) rating: these

include higher-than-expected order intake and

better-than-expected execution on contracts.

Lamprell: Valuation summary

Sum-of-the-parts model (USDm) 2013e EBITDA

2013e sales EV/EBITDA multiple

(implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Land rigs & engineering services 3.6 28.8 8.0 1.0 28.8 27.9 Jackup rig refurb / maintenance 21.6 144.0 7.5 1.1 162.0 152.0 Jackup rig / liftboat newbuild 3.2 663.9 71.5 0.4 232.4 227.3 Equipment / FPSO module newbuild 13.7 152.7 6.5 0.6 89.3 73.5 Contract 42.2 989.4 12.1 0.5 512.5 480.7 E&C and Services 14.1 122.5 7.0 0.8 98.6 96.5

Total 56.3 1,111.9 10.9 0.5 611.1 577.2

net debt(cash) 62.3 70.7 minorities 4.7 4.7 implied market value (USDm) 678.1 652.6 number of shares (m) 261.2 261.2 implied value per share (USD) 2.6 2.5 implied value per share (GBp) 162.3 156.2


Assumptions 2.25 4.5% 5.0% 12.1% (USDm) EV 2012e net debt / associates / minorities market value per share Discounted to end-2013 500.9 -67.0 567.9 135.9 (USDm) EV 2013e net debt / associates / minorities market value per share Discounted to end-2014 587.1 -75.4 662.5 158.5

Book value multiple valuation (USDm) Book Value (2013e) (USD per share) 1.55 Multiple 3.0 Premium 0% Valuation based on book value 144.8

SUMMARY (GBp per share) 2013e 2014e Average Previous Change

DCF 135.9 158.5 147.2 165.5 -11.1% SOTP 162.3 156.2 159.2 162.5 -2.0% Book Value Multiple Valuation 144.8 152.0 -4.8% Overall average (equally weighted) 150.4 160.0 -6.0%


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Lamprell: Summary financial data

(USDm) 2012a 2013e 2014e 2015e

Land rigs refurb / newbuild Sales 25 29 35 33 % growth 8% 15% 20% -5% Jackup rig refurb / maintenance Sales 152 144 149 182 % growth -10% -5% 3% 22% Jackup rig / liftboat newbuild Sales 560 664 606 770 % growth -29% 19% -9% 27% Offshore equipment / FPSO module newbuild Sales 180 153 134 147 % growth 242% -15% -13% 10% Profit & loss Revenue 1045 1112 1052 1248 % growth -9% 6% -5% 19% EBITDA -50 56 85 128 margin -4.8% 5.1% 8.1% 10.2% EBIT -85 23 51 88 margin -8.1% 2.1% 4.8% 7.1% Other income / (loss) 1 0 0 0 Net finance -22 -12 -8 -5 HSBC PBT -105 11 43 83 Tax -0.8 0.0 -0.1 -0.2 Minorities 0 0 0 0 HSBC PAT -106 11 43 83 Diluted shares (m) 261.2 261.2 261.2 261.2 HSBC EPS (USD) -0.40 0.04 0.17 0.32 DPS (USD) 0.00 0.02 0.06 0.11 Cash flow Operating cash flow 250 -9 67 89 Capital expenditure 17 28 42 47 Free cash flow 206 -37 25 42 Net debt (cash) -104 -62 -71 -84 Valuation metrics P/E NA 52.6 14.0 7.3 EV/EBITDA NA 9.6 6.3 4.1 EV/sales 0.48 0.49 0.50 0.42 P/B 1.48 1.46 1.37 1.22 P/B (excl goodwill) 1.56 3.23 2.98 2.32 FCF yield 33.9% -6.1% 4.1% 6.9%


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Kentz – upgrade to Overweight (V) from Neutral (V), target price 615p (unchanged)

Our target price of 615p per share is based on

equal-weighted average of values from average of

2013e and 2014e DCFs and average of

2013e/2014e sum-of-the-parts analyses after

adjusting for advances from customers.




for UK-listed stocks of 7.5%. This translates into a

Neutral band of -2.5% to 17.5% around the current

share price for Kentz. Our target price of 615p

implies a potential return of 28.0%, so we maintain

an Overweight (V) rating. Kentz is not seen as

“volatile” under the HSBC definition for volatile

ratings, but we class it as (V) because of its relatively

small size and regional exposure. Potential return



the forecast dividend yield when indicated.

Downside risks to our Overweight (V) rating:

these include weaker-than-expected development

activity from oil companies driving lower demand

for onshore construction/engineering services. We

also see potential regional risks from Kentz’s

exposure to business in the Middle East region

that could affect its order intake.

Kentz: Valuation summary


(implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Engineering, procurement & construction (EPC)

22.7 363.4 7.5 0.5 170.3 170.6

Construction services 37.6 939.6 6.0 0.2 225.5 233.9 Technical support service 85.1 713.8 7.5 0.9 638.1 661.2 Other 0.0 0.0 0.0 0.0 0.0 0.0 Eliminations 0.0 -11.6 0.0 0.0 0.0 0.0

Total 145.4 2,005.2 7.1 0.5 1,033.9 1,065.7 176.0 103.6 103.6 Associates/minorities -2.3 -2.3 implied market value (USDm) 1207.6 1167.0 number of shares (m) 120.1 120.1 implied value per share (USD) 10.1 9.7 implied value per share (GBp) 628.3 607.2


Assumptions 1.30 4.5% 5.0% 8.8% (USDm) EV 2012e net debt / associates / minorities market value per share (GBp) Discounted to end-2013 966.4 -176.7 1,143.1 594.8 (USDm) EV 2013e net debt / associates / minorities market value per share (GBp) Discounted to end-2014 1104.0 -104.3 1,208.4 628.7




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Kentz: Summary financial data

(USDm) 2012a 2013e 2014e 2015e

Engineering procurement & construction Sales 395 316 363 427% growth -12% -20% 15% 18% Construction Sales 759 835 940 1081% growth 7% 10% 13% 15% Technical support services Sales 409 583 714 785% growth 32% 43% 23% 10% Profit & loss Revenue 1563 1724 2005 2280% growth 14% 10% 16% 14%EBITDA 119 130 145 173margin 5.9% 7.6% 7.3% 7.6%EBIT 105 116 129 155margin 6.7% 6.8% 6.5% 6.8%Other income / (loss) 0 1 2 3Net finance 0 2 2 5HSBC PBT 105 119 133 163Tax -26 -33 -35 -42Minorities 9 4 6 7HSBC PAT 70 82 92 113Diluted shares (m) 120.1 120.1 120.1 120.1HSBC EPS (USD) 0.58 0.68 0.76 0.94DPS (USD) 0.15 0.17 0.19 0.24 Cash flow Operating cash flow 6 -25 85 120Capital expenditure 4 30 35 35Free cash flow 119 -51 54 89Net debt (cash) -221 -149 -178 -240 Valuation metrics P/E 13.2 11.3 10.1 8.1EV/EBITDA 7.7 6.0 5.2 4.0EV/Sales 0.45 0.45 0.37 0.30P/B 3.29 2.70 2.25 1.86FCF yield 12.7% -5.4% 5.8% 9.4%


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McDermott – change to Underweight (V) from Neutral (V), target price USD6.75 (unchanged)

For MDR, our target price of USD6.75 per share is

based on equal-weighted average of values from

average of 2013e and 2014e DCFs and average of

2013e/2014e sum-of-the-parts analyses.




for US-listed stocks of 7%. This translates into a

Neutral band of -3% to 17% around the current

share price for MDR. Our target price of USD6.75

implies a potential return of -5.3%, which is below

the Neutral band, so we lower our rating to

Underweight (V) (from Neutral (V)). Potential

return equals the percentage difference between the



Upside risks to our Neutral (V) rating: earlier-

than-expected rebound in the execution and margins

expansion, and an acceleration in contract awards.

McDermott: Valuation summary

Sum-of-the-parts model (USDm) 2013e EBITDA 2013e sales EV/EBITDA multiple (implied EV/sales) Implied EV (2013e) Implied EV (2014e)

-Asia Pacific 58.0 1,221.2 8.4 0.4 488.5 824.3-Atlantic -21.6 616.3 -14.3 0.5 308.1 238.8-Middle East -25.1 1,114.3 -26.7 0.6 668.6 598.9Other 7.3 0.0 7.0 0.0 51.0 42.1Eliminations 0.0 0.0 0.0 0.0 0.0 0.0

Total 18.6 2,951.7 81.3 0.5 1,516.2 1,704.1

net debt 128.6 -40.9 minorities/investments -38.0 -38.0 implied market value (USDm) 1606.8 1625.1 number of shares (m) 236.2 236.2 implied value per share (USD) 6.8 6.9


Assumptions 1.60 4.0% 5.0% 8.6% (USDm) EV 2012e net debt / associates / minorities market value per shareDiscounted to end-2013 1211.2 -192.8 1,404.0 5.9(USDm) EV 2013e net debt / associates / minorities market value per shareDiscounted to end-2014 1739.1 -23.2 1,762.3 7.4


DCF 5.9 7.4 6.7 6.7 0.0% SOTP 6.8 6.9 6.8 6.8 0.0% Peak EV/sales 22.6 22.6 Overall average (equally weighted) 6.8 - -


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McDermott: Summary financial data

(USDm) 2012 2013e 2014e 2015e

Asia Pacific Sales 1576 1221 1374 1614 % growth -17% -23% 13% 18% EBIT 242 37 69 161 % growth 19% -85% 88% 135% margin 15.4% 3.0% 5.0% 10.0% Atlantic Sales 474 616 478 513 % growth 78% 30% -23% 8% EBIT -67 -43 -7 23 % growth na na na na margin -14.1% -7.0% -1.5% 4.5% Middle East Sales 1592 1114 1198 1348 % growth 24% -30% 8% 13% EBIT 144 -56 60 101 % growth -35% -139% -208% 69% margin 9.0% -5.0% 5.0% 7.5% Profit & loss Revenue 3642 2952 3049 3475 % growth 6% -19% 3% 14% EBITDA 448 19 203 378 margin 11.8% 0.6% 6.6% 10.9% EBIT 336 -62 121 286 margin 8.8% -2.1% 4.0% 8.2% Other income / (loss) -17 -36 0 0 Net Finance 24 2 -13 -22 HSBC PBT 324 -67 108 263 Tax -129 -56 -32 -72 Minorities 11 13 15 16 HSBC PAT 191 -136 61 175 Diluted shares (m) 237.6 236.2 236.2 236.2 HSBC EPS (USD) 0.80 -0.58 0.26 0.74 DPS (USD) 0 0 0 0 Cash flow Operating Cash Flow 210 -179 151 234 Capital Expenditure 282 310 320 495 Free Cash Flow -130 -446 -163 -251 Net Debt (Cash) -557 -129 41 302 Valuation metrics P/E 8.9 -12.4 27.7 9.6 EV/EBITDA 2.6 83.4 8.5 5.3 EV/Sales 0.31 0.53 0.57 0.57 P/B 0.87 0.94 0.91 0.83 FCF Yield -7.2% -24.6% -9.0% -13.8%


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Petrofac – maintain Neutral (V) rating, target price 1,300p per share (unchanged)

We believe the best metric for valuing Petrofac is

sum-of-the-parts, where we value energy

developments using NAV and take a multiple-

based approach for the services businesses. Given

the NAV-approach for energy developments, we

do not consider DCF an appropriate measure for

valuing the group.




for UK-listed stocks of 7.5%. This translates into a

Neutral band of -2.5% to 17.5% around the current

share price for Petrofac. At the time we set our



stock Neutral (V). Petrofac is not seen as “volatile”

under the HSBC definition for volatile ratings, but

we class it as (V) as we think the volatile tag

reflects Petrofac’s business mix (risks related to

fixed-price contracts, in particular), size and likely

volatility more appropriately. Potential return




Upside risks to our Neutral (V) rating: better-

than-expected project execution leading to higher

profitability, higher oil price for a continued

period of time, leading to better-than-expected

project awards and better-than-anticipated mix;

and faster-than-expected ramp-up in IES projects.

Downside risks to our Neutral (V) rating: cost

overruns or material project delays for which

there is no contingency can affect profitability and

impact the company’s reputation. Lower-than-

expected E&P and downstream capital

expenditures by oil companies (led by lower oil

price). Slower pace of contract awards from

NOCs – Petrofac’s main customer type. Execution

difficulties on complex projects.

Petrofac: Valuation summary

Sum-of-the-parts model (USDm) 2014e Net profit 2014e net sales PE multiple (implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Onshore Engineering & Cons 388.6 4,534.6 12.5 1.07 3,832.4 4,838.3 Offshore Engineering & Cons 98.3 1,905.0 11.0 0.57 792.9 1081.6 Engineering & Consultancy 32.8 117.4 11.5 3.22 384.5 377.4 Integrated Energy Services 209.8 1,081.1 7.8 1.52 1,478.1 1,645.0 Corporate & Others 0.0 0.0 10.9 0.0 0.0 Consolidation adjustments & eliminations -28.7 -488.8 10.9 -264.4 -312.0

Total 700.9 7,149.2 10.9 1.1 6,223.4 7,630.2 net debt -238.2 -345.6 Associates/minorities 200.0 200.0 implied market value (USDm) 6,185.2 7,484.6 number of shares (m) 343.7 343.7 implied value per share (USD) 18.0 21.8 implied value per share (GBp) 1,176.2 1,423.3


Overall average 1,176 1,423 1,300 1,300 0.0%


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Petrofac: Summary financial data

(USDm) 2012a 2013e 2014e 2015e

OEC Sales 4288 4031 4535 4535 % growth 3% -6% 13% 0% Net Income 479 428 389 402 margin 11.2% 10.6% 8.6% 8.9% OPO Net sales* 1237 1732 1905 2095 % growth 21% 40% 10% 10% Net Income 61 63 98 120 margin 4.9% 3.7% 5.2% 5.7% ECS Net sales* 97 107 117 106 % growth -53% 10% 10% -10% Net Income 29 30 33 29 margin 29.9% 27.7% 28.0% 27.6% IES Net sales* 693 901 1081 1405 % growth 34% 30% 20% 30% Net income 89 149 210 302 margin 12.8% 16.5% 19.4% 21.5% Profit & loss Revenue 6240 6578 7428 7915 growth 8% 5% 13% 7% EBITDA 896 1004 1166 1392 margin 14.4% 15.3% 15.7% 17.6% EBIT 764 843 954 1134 margin 12.2% 12.8% 12.8% 14.3% Other income / (loss) -6 -2 4 8 Net finance 7 0 1 3 PBT 765 841 960 1145 Tax -135 -197 -252 -312 PAT (to company) 632 645 696 822 margin 10.1% 9.8% 9.4% 10.4% Diluted shares (m) 344 344 344 344 HSBC EPS (USD) 1.84 1.88 2.02 2.39 DPS (USD) 0.64 0.66 0.71 0.84 Cash flow Operating cash flow -457 605 792 1029 Capital expenditure 397 1000 743 712 Free cash flow -885 -396 60 326 Net debt (cash) -233 384 557 478 Valuation metrics P/E 11.2 10.9 10.1 8.6 EV/EBITDA 7.7 7.4 6.5 5.4 EV/sales 1.09 1.13 1.02 0.95 P/B 4.55 3.55 2.87 2.33 FCF yield -11.5% -5.1% 0.8% 4.2%

Source: Company data, HSBC estimates, * net sales = net of pass-through revenues

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Technip – maintain OW(V), target price EUR105 (unchanged)

Our target price of EUR105 per share is based on

an average (50% each) of fair values from the

average of 2013-14e DCFs, an average of 2013-

14e sum-of-the-parts analyses and an adjustment

to reflect contract-linked prepayments (worth

EUR1.7 per share).


volatile indicator, the Neutral band is 10 ppts

above and below the hurdle rate for eurozone

stocks of 9%. Our target price implies a potential

return of 20.5%, above the Neutral band;

therefore, we reiterate our Overweight (V) rating.

Technip is not seen as “volatile” under the

technical HSBC definition for volatile ratings, but

we classify it as (V) as we think the volatility tag

reflects Technip’s business mix (volatility in the

onshore/offshore backlog expansion and exposure

to subsea work), size and likely volatility more

appropriately. Potential return equals the





include project delays from customers driving a

lower annual order intake from engineering,

delays in starting work with new vessels because

of lack of crews or operational problems, lower

oil prices, which could drive lower levels of E&P

investment, problems with onshore projects in the

Middle East, a higher level of competitive

pressure from new entrants in engineering and,

given Technip’s interests in M&A, overpriced

acquisitions that could destroy value.

Technip: Valuation summary

Sum-of-the-parts model (EURm) 2014e EBITDA 2014e sales EV/EBITDA multiple (implied EV/sales) Implied EV (2013e) Implied EV (2014e)

Subsea 1,168.7 5,380.1 9.0 2.0 10,392.8 10,518.7Offshore 112.7 1,502.6 6.5 0.5 764.9 732.5Onshore 323.3 3,962.4 6.0 0.5 2,090.3 1,939.8Eliminations -94.9 0.0 8.2 0.0 -495.8 -780.2

Total 1,509.8 10,845.0 7.7 1.1 12,750.0 12,410.7

net cash (debt) 298.4 695.5 minorities -13.2 -13.2 implied market value (EURm) 13,035.2 13,093.1 number of shares (m) 125.5 126.0 implied value per share (EUR) 103.9 103.9

DCF valuation (EURm) beta risk premium LT growth WACC

Assumptions 1.05 5.3% 5.0% 7.9% (EURm) EV 2013e net debt / associates / minorities market value per shareDiscounted to end-2013 13016.8 -298.4 13315.2 107.0(EURm) EV 2014e net debt / associates / minorities market value per shareDiscounted to end-2014 13738.2 -695.5 14433.7 115.0


DCF 107.0 115.0 111.0 111.0 0.0% SOTP 102.2 102.2 102.2 102.2 0.0% Peak EV/sales 135.9 135.9 0.0%

Average (pre-prepayment adjustment) 106.6 106.6 -

Average (post-prepayment adjustment) 104.9 104.9 -


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Technip: Summary financial data

(EURm) 2012a 2013e 2014e 2015e

Subsea Sales 4048 4549 5380 6168% growth 36% 12% 18% 15%EBIT 603 703 908 1091% growth 21% 16% 29% 20%margin 14.9% 15.4% 16.9% 17.7% Onshore / offshore Sales 4156 4893 5465 5785% growth 8% 18% 12% 6%EBIT 290 337 394 438% growth 6% 16% 17% 11%margin 7.0% 6.9% 7.2% 7.6% EBIT other/eliminations -72 -83 -95 -105 Profit & loss Revenue 8204 9442 10845 11953% growth 20% 15% 15% 10%EBITDA 1017 1196 1510 1764Margin 12.4% 12.7% 13.9% 14.8%EBIT 822 957 1207 1425margin 10.0% 10.1% 11.1% 11.9%Other income / (loss) -9 3 4 6Net Finance -65 -44 -43 -25HSBC PBT 775 943 1189 1419Tax (implied) -216 -278 -350 -418HSBC PAT 560 665 839 1001Diluted shares (m) 124.4 125.5 126.0 126.0HSBC EPS (EUR) 4.50 5.30 6.66 7.94DPS (EUR) 1.68 1.80 2.29 2.75 Cash Flow Operating cash flow 445 847 1141 1340Capital expenditure 519 519 515 508Free cash flow -199 279 578 783Net debt (cash) -183 -298 -696 -1236 Valuation metrics P/E 19.4 16.4 13.1 11.0EV/EBITDA 10.5 8.8 6.7 5.4EV/sales 1.30 1.12 0.94 0.80P/B 2.70 2.47 2.21 1.96FCF yield -1.8% 2.5% 5.3% 7.2%ROIC 15.6% 16.4% 20.0% 23.1%


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Subsea7 – maintain Overweight rating, target price NOK155 per share (unchanged)

In line with our OFS valuation framework, our

target price of NOK155 per share for Subsea7 is


from average of 2013e and 2014e DCFs and

average of 2013e and 2014e sum-of-the-parts

analyses. Note for the Brazil reporting line, we

base our SOTP valuation on 2014e only.




for Norway-listed stocks of 11%. This translates

into a Neutral band of 1% to +21% above the

current price for Subsea7. Our target price of

NOK155 provides potential return of 23.2%,

above the Neutral band of our model; therefore,

we reiterate with Overweight (V) rating. Potential

return equals the percentage difference between

the current share price and the target price,

including the forecast dividend yield when

indicated. Subsea7 does not screen as Volatile under

the HSBC methodology, but we keep the “V” tag to

reflect the underlying business uncertainty.


lower level of E&P capital expenditures by the oil

& gas companies will have a significant adverse

impact on the pace and quantity of new contract

awards to Subsea 7 and the utilisation of its fleet.

Capex, in turn, is cyclical, determined by current

oil & gas prices but also oil company long-term

expectations. Other risk factors influencing

company performance/prospects include increased

competitive pressures from new entrants,

weather-related project delays (common in several

key operating areas for Subsea7), operational

problems on fixed-price projects for which there

is no contingency, lack of available/capable

engineering capacity, and integration setbacks

could push back delivery of synergies of merger

with Acergy.

Subsea7: Valuation summary

Sum-of-the-parts model (USDm) 2014e EBITDA 2014e sales EV/EBITDA multiple

(Implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

North Sea, Mediterranean and Canada (NSMC)

639.0 3,028.5 7.5 1.6 4,981.4 4,792.6

Africa and Gulf of Mexico (AFGoM) 665.3 2,760.7 7.5 1.8 4,904.5 4,990.0 Asia Pacific and Middle East (APME) 107.7 466.2 6.0 1.4 705.5 646.2 Brazil (BRAZIL) 120.2 1,035.8 3.0 0.3 360.5 360.5 Corporate (CORP) 8.3 15.0 5.0 2.8 143.9 41.7

Total 1,540.5 7,306.3 7.0 1.5 11,095.7 10,831.0 net debt -701.6 -443.7 Associates/minorities 179.3 179.3 implied market value (USDm) 10,573.5 10,566.6 number of shares (m) 394.0 394.0 implied value per share (USD) 26.8 26.8 implied value per share (NOK) 161.0 160.9


Assumptions 1.22 4.7% 5.0% 8.2% (USDm) EV 2013e net debt / associates / minorities market value per share (NOK) Discounted to end-2013 9,416.7 603.5 8,813.2 139.1 (USDm) EV 2014e net debt / associates / minorities market value per share (NOK) Discounted to end-2014 10,413.2 345.6 10,067.6 158.9


DCF 139.1 158.9 149.0 149.0 0% SOTP 161.0 160.9 161.0 161.0 0% Overall average (equally weighted) 155.0 155.0 -


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Subsea7: Divisional information and key ratios

(USDm) 2012a 2013e 2014e 2015e

NSMC Sales 2838 2611 3029 3331 % growth 38% -8% 16% 10% EBIT 364 405 469 550 % growth 103% 11% 16% 17% margin 12.8% 15.5% 15.5% 16.5% AFGoM Sales 2182 2401 2761 3202 % growth -14% 10% 15% 16% EBIT 428 408 511 640 % growth -13% -5% 25% 25% margin 19.6% 17.0% 18.5% 20.0% APME Sales 278 444 466 373 % growth 54% 60% 5% -20% EBIT 46 75 82 52 % growth 153% 64% 8% -36% margin 16.6% 17.0% 17.5% 14.0% Brazil Sales 987 1381 1036 1119 % growth 44% 40% -25% 8% EBIT -25 -386 62 89 % growth -213% NM -116% 44% margin -2.6% -28.0% 6.0% 8.0% Corporate Sales 12 14 15 15 Corporate EBIT -4 28 8 8 Profit & loss Revenue 6297 6850 7306 8040 % growth 15% 9% 7% 10% EBITDA 1139 921 1541 1790 EBIT (incl. associates &

JVs) 808 530 1131 1339

margin 12.8% 7.7% 15.5% 16.7% Net Finance 17 -51 -52 -49 HSBC PBT 736 479 1079 1291 Tax (effective) -131 -245 -332 -401 HSBC PAT 605 234 748 889 Fully diluted shares (m) 380 394 394 394 HSBC EPS (USD) 1.59 0.59 1.90 2.26 DPS (incl. Special,

USD) 0.60 0.60 0.60 0.64

Cash flow Operating Cash Flow 515 569 1152 1283 Capital Expenditure -713 -788 -658 -643 Free Cash Flow -151 -201 514 660 Net Debt (Cash) 254 702 444 40Valuation metrics P/E 13.2 35.3 11.0 9.3 EV/EBITDA 6.5 8.6 5.0 4.0 EV/Sales 1.2 1.2 1.0 0.9 P/B 1.1 1.1 1.0 0.9 FCF Yield -2.0% -2.7% 7.0% 9.0% ROIC 8.9% 3.6% 10.6% 12.2%


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Saipem – maintain Overweight (V) rating, target price EUR20 (unchanged)

For Saipem, our target price of EUR20 per share

is based on the equal weighted average (50%

each) of fair values from our DCF (average of

2013 and 2014 DCFs) and sum-of-the-parts

models (average of 2013 and 2014).


volatility indicator, the Neutral rating band is

10ppts above and below the local hurdle rate (9%

for the eurozone), or a potential return of -1-19%.

Our target price implies a potential return of

20.7%, above this band; therefore, we reiterate

our OW(V) rating. Potential return equals the





these include a cut to SPM’s dividend (current

policy is to pay out one third of profits); an

adverse ruling on the Algerian corruption probe;

weaker-than-expected development activity from

oil companies driving lower demand for offshore

drilling rigs, FPSOs and offshore/onshore E&C.

General macro uncertainty is causing some

project delays across the sector and any material

project deferrals can impact on longer-term

growth assumptions, particularly for the large

‘elephants’ SPM is targeting.

Saipem: Valuation summary

Sum-of-the-parts model (EURm) 2014e EBITDA 2014e sales EV/EBITDA (x) EV/sales (x) Implied EV (2014e) Implied EV (2014e)

Offshore 735.5 5,861.6 7.3 0.9 7,955.9 7,955.9Onshore 160.7 4,595.1 7.0 0.2 1,124.8 1,124.8Offshore Drilling 661.2 1,185.0 7.9 4.4 5,212.8 5,212.8Onshore Drilling 264.9 854.6 6.0 1.9 1,589.5 1,589.5Other 0.0 0.0 7.3 0.0 0.0 0.0

Total 1,822.3 12,496.2 7.3 1.1 13,259.2 13,259.2

net cash (debt) -4,079.5 -4,079.5 minorities -148.0 -148.0 implied market value (EURm) 9,031.7 9,031.7 number of shares (m) 441.0 441.0 implied value per share (EUR) 20.5 20.5


Assumptions 1.00 6.0% 5.0% 7.7% (EURm) EV 2013e net debt / associates / minorities market value per share Discounted to end-2013 12563.8 4991.3 7572.5 17.3 (EURm) EV 2014e net debt / associates / minorities market value per share Discounted to end-2014 13803.6 3963.5 9840.1 22.5


DCF 17.3 22.5 19.9 19.9 0.0% SOTP 20.5 20.5 20.5 0.0%

Overall average (equally weighted) 20.2 20.2 0.0%


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Saipem: Summary financial data

(EURm) 2012a 2013e 2014e 2015e

Offshore Sales 5356 5573 5862 6279 % growth 6% 4% 5% 7% EBIT 690 67 428 715 % growth 1% -90% 538% 67% margin 12.9% 1.2% 7.3% 11.4% Onshore Sales 6175 5448 4595 4033 % growth 4% -12% -16% -12% EBIT 395 -656 133 208 % growth -18% -266% -120% 56% margin 6.4% -12.0% 2.9% 5.2% Offshore drilling Sales 1088 1170 1185 1200 % growth 31% 8% 1% 1% EBIT 293 349 353 358 % growth 32% 19% 1% 1% margin 26.9% 29.8% 29.8% 29.8% Onshore drilling Sales 750 810 855 803 % growth 1% 8% 5% -6% EBIT 103 97 115 100 % growth 1% -6% 19% -13% margin 13.7% 12.0% 13.5% 12.5% Profit & loss Revenue 13369 13001 12496 12315 % growth 6% -3% -4% -1% EBITDA 2207 620 1822 2171 margin 16.5% 4.8% 14.6% 17.6% EBIT 1481 -143 1029 1381 margin 11.1% -1.1% 8.2% 11.2% Other income / (loss) 16 19 14 9 Net finance -148 -246 -241 -197 HSBC PBT 1349 -371 802 1193 Tax -393 -40 -240 -358 Minorities 54 53 52 53 HSBC PAT 956 -411 561 835 Diluted shares (m) 441 441 441 441 HSBC EPS (EUR) 2.17 -0.93 1.27 1.89 DPS (EUR) 0.68 0.00 0.38 0.59 Cash flow Oper. cash flow 231 382 1840 1786 Capital expenditure 1015 910 812 800 Free cash flow -787 -552 1009 972 Net debt (cash) 4278 5107 4080 3264 Valuation metrics P/E 7.6 NA 13.0 8.8 EV/EBITDA 5.2 19.9 6.2 4.8 EV/Sales 0.86 0.95 0.91 0.85 P/B 1.32 1.51 1.35 1.20 FCF Yield -10.5% -7.4% 13.5% 13.0% ROIC 11.5% -1.1% 8.2% 11.2%


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Sinopec Engineering – maintain Overweight (V) rating, target price HKD13.60 (unchanged)

Sinopec Engineering valuation: Weighted average

of 16x 2013e PE (45%), 2.5x PB(10%) and 5x

EV/EBITDA (45%), which are the median

multiples of nine comparable global E&C

companies with a market cap of USD4bn+. We

then apply a 10% discount, to reflect SEG’s short

listing history, reliance on Sinopec as a source of

revenue and relatively low earnings visibility.



above and below the hurdle rate of 9.5% for

China stocks, or a potential return of -0.5%-

19.5%. Our target price of HKD13.6 implies a

potential return of 43.2%, which is above the

Neutral band; therefore, we rate the stock

Overweight (V). Potential return equals the




Downside risks: shrinking capex in refining and

petrochemical projects by Sinopec and other

major clients; China slowing approvals for coal-

to-chemicals projects; cancelling the Wyoming-

based coal-to-liquids project; and China oil/gas-

industry-related corporate governance risks.

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Sinopec Engineering: Summary valuation data (in thousands RMB)

2012 2013e 2014e 2015e

ECL Revenue 4121.8 4616.4 5124.3 5636.7 % growth 20.6% 12.0% 11.0% 10.0% EBIT 1239.9 1383.8 1529.9 1676.1 % growth 19.3% 11.6% 10.6% 9.6% margin 30.1% 30.0% 29.9% 29.7% EPC Revenue 20082.4 23295.6 26557.0 29743.9 % growth 33.8% 16.0% 14.0% 12.0% EBIT 2305.3 2748.9 3080.6 3390.8 % growth -6.3% 19.2% 12.1% 10.1% margin 11.5% 11.8% 11.6% 11.4% Construction Revenue 16296.8 18578.4 20993.6 23512.8 % growth 15.4% 14.0% 13.0% 12.0% EBIT 317.9 222.9 230.9 282.2 % growth 85% -30% 4% 22% margin 2.0% 1.2% 1.1% 1.2% Manufacturing Revenue 625.0 625.0 625.0 625.0 % growth -21% 0% 0% 0% EBIT -41.4 8.1 8.1 8.1 % growth -959% -120% 0% 0% margin -6.6% 1.3% 1.3% 1.3% Profit and loss Revenue 38,526 44,170 49,988 55,824 % growth 23.4% 14.6% 13.1% 11.7% EBIT 3832.0 4363.8 4849.6 5357.2 margin 9.3% 9.3% 9.1% 9.0% Net Finance 404.7 210.5 241.3 273.1 HSBC PBT 4252.1 4583.2 5095.9 5640.1 Tax (implied) -934.8 -1008.3 -1121.1 -1240.8 HSBC PAT 3317.3 3574.9 3974.8 4399.3 HSBC EPS (RMB) 1.1 0.9 0.9 1.0 DPS (RMB) 0.2 0.3 0.3 0.3 Valuation metrics P/E 6.9 8.1 8.3 7.5 EV/EBITDA 6.2 3.0 2.4 1.7 EV/Sales 0.7 0.3 0.3 0.2 P/B 3.3 1.6 1.4 1.2 FCF Yield 11.1 5.2 5.3 9.1


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Wood Group – maintain Neutral, target price 860p per share (unchanged)

In line with our oilfield services valuation

framework, we value Wood Group using an

equally weighted average of fair values from the

average of our 2013e and 2014e DCFs and

sum-of-the-parts analyses. The parameters driving

our valuation are highlighted in the table below.





a Neutral band of 2.5% to 12.5% above the

current share price for Wood Group. Our target

price of 860p implies a potential return of 12.9%,


we have the rating as Neutral. Potential return




Upside risks to our Neutral rating: higher oil

prices for a long period of time, which in turn will

lead to a higher opex and capex from oil companies

and potential for stronger-than-expected business

performance; and significant order intake across the

group, with power solutions contracts, in particular,

offering forecast upside potential.

Downside risks to our Neutral rating: lower oil

prices for a long period of time, which in turn will

lead to a lower opex and capex, lower order intake

and execution issues with existing contracts.

Wood Group: Valuation summary


(implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Engineering 255.6 1,966.0 9.0 1.2 2,312.8 1,993.9 Wood Group PSN 273.8 4,130.1 8.0 0.5 2,203.7 2,105.4 Gas Turbine Services 109.6 1,289.6 6.0 0.5 657.7 684.2 Gas Turbine Services (to be disposed) -0.1 5.8 5.0 -0.1 -0.4 0.4 Central Costs -53.6 0.0 6.0 0.0 -321.3 -300.4 Unallocated 0.0 0.0 0.0 0.0 0.0 0.0

Total 589.0 7,385.7 8.2 0.7 4,852.4 4,483.4 net debt 12.5 240.3 Associates/minorities 10.0 0.0 implied market value (USDm) 4,875.0 4,723.7 number of shares (m) 372.6 372.6 implied value per share (USD) 13.1 12.7

implied value per share (GBp) 872.2 845.2


Assumptions 1.29 5.0% 5.0% 9.0% (USDm) EV 2013e net debt / associates / minorities market value per share (GBp) Discounted to end-2013 6471.7 -12.5 6484.2 826.1 (USDm) EV 2014e net debt / associates / minorities market value per share (GBp) Discounted to end-2014 6790.5 -240.3 7030.8 895.7


DCF 826.1 895.7 860.9 860.9 0% SOTP 872.2 845.2 858.7 858.7 0%

Overall average (equally weighted) 859.8


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Wood Group: Divisional information and key ratios

(USDm) 2012a 2013e 2014e 2015e

Engineering Sales 1787 1966 1966 2163% growth 23% 10% 0% 10%EBITA 220 244 236 281% growth 36% 11% -3% 19%margin 12.3% 12.4% 12.0% 13.0% Wood Group PSN Sales 3691 4130 4378 4597% growth 9% 12% 6% 5%EBITA 205 257 283 320% growth 17% 25% 10% 13%margin 5.6% 6.2% 6.5% 7.0% Gas turbine services Sales 1343 1290 1367 1435% growth 12% -4% 6% 5%EBITA 89 95 109 122% growth 12% 8% 15% 12%margin 6.6% 7.4% 8.0% 8.5% Central costs -53 -54 -55 -56 Profit & loss Revenue 6821 7386 7711 8195% growth 20% 8% 4% 6%EBITDA 505 589 622 719EBITA 461 543 574 667Other income / (loss) -27 0 0 0Net finance -13 -18 -16 -14HSBC PBT 448 525 558 654Tax (effective) -131 -147 -157 -184HSBC net profit 317 379 402 470Diluted shares (m) 373 373 373 373HSBC EPS (USD) 0.85 1.02 1.08 1.26DPS (USD) 0.17 0.19 0.21 0.25 Cash flow Operating cash flow 193.0 376.2 432.7 503.9Capital expenditure 127.2 130.0 98.4 99.3Free cash flow 74.1 248.4 337.5 408.8Net debt (cash) 154.5 -12.5 -240.3 -552.5 Valuation metrics P/E 13.4 11.2 10.6 9.1EV/EBITDA 8.8 7.2 6.5 5.2EV/Sales 0.6 0.6 0.5 0.5P/B 1.91 1.73 1.57 1.41FCF yield 1.7% 5.8% 7.9% 9.6%ROIC 13.8% 16.1% 16.8% 19.5%


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Aker Solutions – maintain OW (V) rating, TP NOK120 (from NOK125)

For Aker Solutions, our target price is based on

equal-weighted average (50% each) of the


2013e and 2014e sum-of-the-parts analyses.


volatility indicator, the Neutral band is 10ppt above

and below the hurdle rate for Norwegian stocks of

11.0%. Our target price of NOK120 provides a

potential return of 50.8%, above the Neutral band;

therefore, we reiterate our Overweight (V) rating.

Aker Solutions is not seen as “volatile” under the

technical HSBC definition, but we classify it as (V)

as we think this reflects its business mix, size and

likely volatility more appropriately. Potential return





lower oil prices, which could affect further

development project work; higher-than-expected

capital cost inflation; further delays to offshore

development work; a higher level of competitive

pressure from new industry entrants; and a

value-destroying acquisition.

Aker Solutions: Valuation summary

Sum-of-the-parts model (NOKm) 2013e EBITDA 2013e sales EV/EBITDA multiple

(implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Maintenance, modifications 813.0 11,614.1 7.1 0.5 5,772.2 6,280.9 Well intervention 418.1 2,323.0 7.5 1.4 3,136.1 3,012.4 Oilfield services -46.3 925.2 -112.4 5.6 5,200.0 5,200.0 Other 0.0 -62.1 0.0 0.0 0.0 0.0

FIELD LIFE SOLUTIONS 1,184.9 14,800.2 11.9 1.0 14,108.2 14,493.2

Subsea 1,444.6 13,757.8 8.0 0.8 11,556.5 10,916.8 Umbilicals -20.0 1,998.0 6.0 -0.1 -119.9 714.3 Drilling technologies 1,077.4 10,261.3 6.5 0.7 7,003.3 7,463.8 Process systems 118.6 1,976.0 6.5 0.4 770.6 855.9 Mooring & loading systems 132.8 1,062.0 6.5 0.8 862.9 797.3 other 0.0 -163.2 0.0 0.0 0.0 0.0

Product solutions 2,753.3 28,891.8 7.3 0.7 20,193.3 20,033.7

Engineering solutions 256.4 3,944.5 7.5 0.5 1,922.9 2,721.7

Other 0.0 0.0 0.0 0.0 0.0 0.0 Eliminations 241.1 587.7 8.9 0.0 2,149.3 1,835.5

Total 4,435.7 48,224.1 8.7 0.8 38,373.8 39,084.1

net debt -5,738.4 -4,729.7 minorities/assocs 695.0 695.0 implied market value (NOKm) 33,330.4 35,049.4 number of shares (m) 271.0 271.0 implied value per share (NOK) 123.0 129.3

DCF valuation (NOKm) beta risk premium LT growth WACC

Assumptions 1.47 5.0% 5.0% 9.3% (NOKm) EV 2013e net debt / associates / minorities market value per share discounted to end-2013 34597.1 4886.4 29710.7 110.0 (NOKm) EV 2014e net debt / associates / minorities market value per share discounted to end-2014 35515.1 3877.7 31637.4 117.2

Summary (NOK per share) 2013e 2014e Average Previous Change

DCF 110.0 117.2 113.6 117.6 -3.5% SOTP 123.0 129.3 126.2 131.4 -4.0% Overall average (equal weight) 119.9 124.5 -3.7%


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Aker Solutions: Divisional information and key ratios

(NOKm) 2012a 2013e 2014e 2015e

Engineering solutions Sales 4508 3945 4536 4990 % growth 39% -13% 15% 10% EBITDA 499 256 454 599 % growth 33% -49% 77% 32% margin 11.1% 6.5% 10.0% 12.0% Product solutions Sales 25291 28892 32843 35253 % growth 28% 14% 14% 7% EBITDA 2336 2753 3620 4351 % growth 106% 18% 31% 20% margin 9.2% 9.5% 11.0% 12.3% Field life solutions Sales 14320 14800 15467 16110 % growth 18% 3% 5% 4% EBITDA 1544 1185 1582 1748 % growth 51% -23% 34% 10% margin 10.8% 8.0% 10.2% 10.9% Sales other/eliminations 803 588 373 158 EBITDA other 360 241 266 283 Profit & loss Revenue 44922 48224 53219 56511 % growth 12% 7% 10% 6% EBITDA 4739 4436 5922 6980 Margin 10.5% 9.2% 11.1% 12.4% EBIT 3573 3193 4517 5492 Margin 8.0% 6.6% 8.5% 9.7% Other income / (loss) 12 -339 27 22 Net finance -628 -556 -425 -330 HSBC PBT 3082 2659 4119 5184 Tax -697 -586 -1050 -1322 Minorities 11 16 11 6 HSBC PAT 2345 1965 3058 3856 Diluted shares (m) 271 271 271 271 HSBC EPS (NOK) 8.65 7.25 11.28 14.23 DPS (NOK) 4.00 4.00 3.96 5.00 Cash flow Operating cash flow 1783 4233 4143 5140 Capital expenditure 2470 2489 2129 1978 Free cash flow -778 1889 1659 2662 Net debt (cash) 6477 5738 4730 2638 Valuation metrics P/E 9.2 11.0 7.1 5.6 EV/EBITDA 5.9 6.1 4.4 3.5 EV/Sales 0.62 0.56 0.49 0.43 P/B 1.80 1.71 1.48 1.26 FCF yield -3.4% 8.2% 7.2% 11.5% ROIC 14.8% 13.0% 17.4% 20.7%


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Cameron – maintain Neutral (V), target price USD64 (unchanged)

For Cameron, our target price of USD64 per share is

based on an average (50% each) of fair values from

the average of 2013-14e DCFs, and average of

2013-14e sum-of-the-parts analyses.





band of -3% to +17% around the current share

price. Our target price of USD64 implies a

potential return of 6.0%, within the Neutral band of

our model; therefore, we maintain our Neutral (V)

rating. Our HSBC methodology ranks CAM shares

as non-volatile, but we choose to keep the V-tag as

we believe this best reflects the underlying

volatility of the company’s business mix. Potential

return equals the percentage difference between the



Downside risks to our Neutral (V) rating: these

include lower oil prices for a continued period of

time, driving less spend on offshore projects;

further delays to offshore development work that

would delay the awards of new deepwater

contracts; weakness in the North American

onshore market due to weak gas prices; and a

higher level of competitive pressure leading to

pricing pressure from competitors in the North

American onshore exposed market.

Upside risks to our Neutral (V) rating: these

include a rebound in the North American onshore

market that is earlier than expected; major

contract awards in a short span of time.

Cameron: Valuation summary


EV/Sales implied EV Implied EV (2014e)

Drilling 368.8 2,169.5 11.0 1.9 4,056.9 4,045.4 Surface 448.0 1,991.3 8.5 1.9 3,808.3 3,772.8 Subsea 256.8 1,975.0 17.0 2.2 4,364.8 4,237.4 Drilling and production systems 1,073.6 6,135.7 11.4 2.0 12,229.9 12,055.5 Valves and measurement system 496.5 2,206.5 9.0 2.0 4,468.1 4,459.3 Compression systems 180.6 1,570.5 10.0 1.2 1,806.0 1,874.4 Other -223.0 0.0 9.0 0.0 -2,007.3 -2,297.5

Total 1,527.6 9,912.7 10.8 1.7 16,496.8 16,091.7 net debt 258.0 813.8 minorities -1,200.0 -1,200.0 implied market value (USDm) 15,554.7 15,705.5 number of shares (m) 249.4 249.4 implied value per share (USD) 62.4 63.0

DCF valuation (USDm) beta risk premium LT growth WACC Assumptions 1.25 4.0% 5.0% 7.7% (USDm) EV 2012e net debt / associates / minorities market value per share discounted to end-2013 16059.5 942.0 15117.5 61.4 (USDm) EV 2013e net debt / associates / minorities market value per share discounted to end-2014 17134.8 386.2 16748.6 68.0




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Cameron: Divisional information and key ratios

(USDm) 2012 2013e 2014e 2015e

Drilling and production systems Sales 4871 6136 7246 8119 % growth 20% 26% 18% 12% EBIT (excl one-offs) 712 890 1203 1435 % growth 4% 25% 35% 19% margin 14.6% 14.5% 16.6% 17.7% Valves and measurement system Sales 2142 2206 2372 2550 % growth 29% 3% 8% 8% EBIT (excl one-offs) 426 452 510 497 % growth 45% 6% 13% -3% margin 19.9% 20.5% 21.5% 19.5% Process & compression system Sales 1489 1570 1728 1814 % growth 21% 5% 10% 5% EBIT (excl one-offs) 147 141 225 272 % growth 27% -4% 59% 21% margin 9.9% 9.0% 13.0% 15.0% Profit & loss Revenue 8502 9913 11346 12483 % growth 22% 17% 14% 10% EBITDA (excl one-offs) 1317 1528 1973 2251 margin 15.5% 15.4% 17.4% 18.0% EBIT (excl one-offs) 1062 1225 1643 1880 margin 12.5% 12.4% 14.5% 15.1% Other income / (loss) -34 -70 0 0 Net Finance -89 -94 -78 -54 HSBC PBT 973 1132 1565 1826 Tax -188 -244 -368 -429 Minorities 0 28 102 138 HSBC PAT 779 844 1096 1259 Diluted shares (m) 248.1 249.4 249.4 249.4 HSBC EPS (USD) 3.14 3.38 4.39 5.05 DPS (USD) 0 0 0 0 Cash flow Operating cash flow 683 577 1151 1510 Capital expenditure 427 545 596 593 Free cash flow 308 91 530 867 Net debt (cash) 373 -258 -814 -1731 Valuation metrics P/E 19.2 17.8 13.7 12.0 EV/EBITDA 11.7 9.6 7.2 5.9 EV/sales 1.80 1.48 1.25 1.06 P/B 2.69 1.99 1.74 1.52 FCF yield 2.0% 0.5% 3.2% 5.2%


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FMC Technologies – maintain N(V), target price USD56 (unchanged)

For FMC, our target price of USD56 per share is

based on an average (50% each) of fair values

from the average of 2013-14e DCFs, and average

of 2013-14e sum-of-the-parts analyses.





band of -3% to +17% around the share price for

FMC. Our target price of USD56 provides a

potential return of -0.2%, within the Neutral band

of our model; therefore, we maintain our

Neutral (V) rating. Though the stock is not

volatile under the HSBC definition of volatility,

we add the V tag to reflect the current business

mix and execution-related issues. Potential return




Downside risks to our Neutral (V) rating:

Subsea margin slippage, delay in project awards,

execution issues and delayed recovery in North

American markets.

Upside risks to our Neutral (V) rating: earlier-

than-expected recovery in North American

markets, acceleration in contract awards on large

and delayed fields, and margin progression in

excess of our estimates.

FMC Technology: Valuation summary



(implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Subsea Technologies 704.8 4,606.2 15.0 2.3 10,571.3 10,592.0 Surface Technologies 304.3 1,789.9 12.0 2.0 3,651.3 3,376.8 Energy Processing 80.9 622.3 9.5 1.2 768.5 784.1 Other 0.0 0.0 0.0 0.0 0.0 0.0 Eliminations -129.4 -25.0 9.0 0.0 -1,164.4 -1,279.9

Total 960.5 6,993.4 14.4 2.0 13,826.7 13,472.9

net debt -689.0 -94.2 minorities/investments 21.1 21.1 implied market value (USDm) 13,158.9 13,399.8 number of shares (m) 239.4 239.4 implied value per share (USD) 55.0 56.0

DCF valuation (USDm) beta risk premium LT growth WACC Assumptions 1.20 4% 5.0% 7.5% (USDm) EV 2013e net debt / associates / minorities market value per share Discounted to end-2013 13806.9 651.6 13,155.4 54.6 (USDm) EV 2014e net debt / associates / minorities market value per share Discounted to end-2014 14197.6 56.8 14,140.8 58.7

SUMMARY (USD per share) 2013e 2014e Average Previous Change DCF 54.6 58.7 56.7 56.7 0% SOTP 55.0 56.0 55.5 55.5 0% Overall average (equally weighted) 56.1 56.1 0%


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FMC Technologies: Divisional Information and Key Ratios

(USDm) 2012a 2013e 2014e 2015e

Subsea technologies Sales 4005 4606 5527 6495 % growth 22% 15% 20% 18% EBIT 438 576 871 1137 % growth 29% 31% 51% 31% margin 10.9% 12.5% 15.8% 17.5% Surface technologies Sales 1598 1790 1924 2145 % growth 22% 12% 8% 12% EBIT 284 251 327 418 % growth 14% -12% 31% 28% margin 17.8% 14.0% 17.0% 19.5% Energy infrastructure Sales 576 622 700 770 % growth 14% 8% 13% 10% EBIT 49 62 81 100 % growth -1% 27% 29% 24% margin 8.5% 10.0% 11.5% 13.0% Profit & loss Revenue 6151 6993 8127 9385 % growth 21% 14% 16% 15% EBITDA 758 961 1340 1726 margin 12.3% 13.7% 16.5% 18.4% EBIT 616 759 1136 1491 margin 10.0% 10.9% 14.0% 15.9% Other income / (loss) 11 0 0 0 Net finance -27 -35 -29 -22 HSBC PBT 590 717 1107 1469 Tax -166 -190 -305 -404 Minorities 5 5 5 5 HSBC PAT 422 522 798 1060 Diluted shares (m) 240.9 239.4 239.4 239.4 HSBC EPS (USD) 1.75 2.18 3.33 4.43 DPS (USD) 0 0 0 0 Cash flow Operating cash flow 138 1029 1001 1147 Capital expenditure 406 420 406 375 Free cash flow -271 616 587 757 Net debt (cash) 1299 689 94 -678 Valuation metrics P/E 32.0 25.7 16.8 12.7 EV/EBITDA 19.5 14.8 10.2 7.4 EV/Sales 2.41 2.03 1.67 1.37 P/B 7.29 5.65 4.23 3.17 FCF YIELD -2.0% 4.5% 4.3% 5.6% ROIC 14.1% 18.2% 25.2% 30.4%


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Honghua Group – maintain Overweight (V) rating, target price HKD4.83 (unchanged)

Honghua valuation is based on PE multiple. Our

target price of HKD4.83 is derived by applying a

15x PE on 2013e EPS. We are broadly in line

with consensus on earnings and revenue for

2013e-14e.




China stocks, or a potential return band of -0.5%-

19.5%. Our target price of HKD4.83 implies a


Neutral range; therefore, we rate the stock

Overweight (V) rating. Potential return equals the




Downside risks: macro and oil price weakness;

execution risks of offshore rig building business;

and disappointing results from further industry-

wide shale gas exploration drilling.

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Honghua Group: Summary financial data

2012 2013e 2014e 2015e

Land drilling rigs – subtotal Revenue 3,751 6,300 7,029 7,815 % growth 47.5% 68.0% 11.6% 11.2% Parts and components – subtotal Revenue 989 1,377 1,537 1,709 % growth 14.7% 39.2% 11.6% 11.2% Offshore rigs and parts and components Revenue 157 700 700 1,600 % growth 96.5% 345.1% 0.0% 128.6% Oil and gas engineering services Revenue 172 600 600 600 % growth #DIV/0! 248.8% 0.0% 0.0% Profit & loss Revenue 5,068 8,977 9,866 11,724 % growth 45.4% 77.1% 9.9% 18.8% EBITDA 821 1,372 1,581 1,754 Margins 16.2% 15.3% 16.0% 15.0% EBIT 673 1,189 1,338 1,507 Margins 13.3% 13.2% 13.6% 12.9% Finance charge 29 (139) (186) (175) PBT 709 1,058 1,160 1,340 Tax (168) (212) (232) (268) PAT 529 825 905 1,045 EPS 0.17 0.26 0.28 0.33 DPS 0.05 0.05 0.06 0.07 Valuation metrics P/E 11.9 7.7 7.0 6.0 EV/EBITDA 9.1 6.8 5.5 4.9 EV/sales 1.5 1.0 0.9 0.7 P/B 1.4 1.2 1.1 0.9 FCF yield -1.4 -25.6 10.9 5.8


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Hunting – maintain Overweight rating, target price 1,050p (unchanged)

Our target price of 1,050p for Hunting is based on

equal weighted average of fair values from the


2013e and 2014e sum-of-the-parts analyses.





a Neutral band of 2.5% to 12.5% above the

current share price for Hunting. Our target price

of 1,050p implies a potential return of 33.8%,

above the Neutral band of our model so we

maintain our Overweight rating. Potential return




Downside risks to our Overweight rating:

Hunting provides sophisticated technologies that

are targeted towards harsh or complex

environments, such as shale and deepwater plays.

Any decrease in commodity prices may result in

oil & gas companies reducing their activities and

these areas will be the first to suffer from reduced

activity levels. Therefore, in cyclical downturns

its earnings may get hit faster and more

significantly than many oil service stocks.

Hydraulic fracturing (fraccing) has encountered

considerable political resistance in the US and

elsewhere on environmental concerns (impact on

local water supplies, etc) and some US states (plus

France/Germany) have banned the practice. Any

new laws or changes to existing laws could

impact drilling activity.

Hunting: Valuation summary

Sum-of-the-parts model (GBPm) 2014e EBITDA 2014e sales EV/EBITDA multiple

(implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Well Construction 67.3 313.1 8.0 1.7 527.4 541.4 Well Completion 112.4 556.6 8.5 1.7 981.6 960.8 Well Intervention 12.5 70.2 9.2 1.6 113.9 114.6 Exploration and Production 2.3 4.4 1.2 0.6 3.5 2.8 Gibson Shipbrokers 1.3 23.5 5.0 0.3 8.2 6.5 Consolidation adjustments

Total 195.7 967.8 8.3 1.7 1,634.6 1,626.1 net debt -146.0 -119.5 Associates/minorities -11.5 -11.5 implied market value (GBPm) 1,477.1 1,495.1 number of shares (m) 149.5 149.5 implied value per share (GBP) 9.88 10.00 implied value per share (GBp) 988.0 1,000.1

DCF valuation (GBPm) beta risk premium LT growth WACC Assumptions 1.30 4.5% 5.0% 8.2% (GBPm) EV 2013e net debt / associates / minorities market value per share (GBp) Discounted to end-2013 1,734.2 139.2 1,595.0 1,066.9 (GBPm) EV 2014e net debt / associates / minorities market value per share (GBp) Discounted to end-2014 1,822.9 112.7 1,710.2 1,144.0


DCF 1,066.9 1,144.0 1,105.4 1,105.4 0.0% SOTP 988.0 1,000.1 994.0 994.0 0.0%

Overall average (equally weighted) 1,049.7 - -


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Hunting: Divisional information and key ratios

(GBPm) 2012a 2013e 2014e 2015e

*Well construction Sales 279 285 313 329 % growth 44% 2% 10% 5% EBITA 46 44 55 57 % growth 60% -4% 24% 5% margin 16.4% 15.5% 17.4% 17.4% +Well completion Sales 457 506 557 575 % growth 40% 11% 10% 3% EBITA 74 84 97 100 % growth 78% 14% 15% 4% margin 16.1% 16.6% 17.4% 17.5% Well intervention Sales 57 64 70 77 % growth 7% 13% 10% 10% EBITA 7 8 9 10 % growth -14% 17% 12% 10% margin 12.0% 12.5% 12.8% 12.8% Exploration & production Sales 5 5 4 4 % growth -40% 0% -10% -10% EBITA 1 0.6 0.6 0.5 % growth -65% 2% -8% -10% margin 12.2% 12.5% 12.8% 12.8% Gibson shipbrokers Sales 28 26 24 26 % growth 6% -5% -10% 10% EBITA 1 1 1 1 % growth -35% 1% -5% 10% margin 4.0% 4.3% 4.5% 4.5% Profit & loss Revenue 826 886 968 1011 growth 36% 7% 9% 4% EBITDA 153 168 196 206 Margin 18.6% 19.0% 20.2% 20.4% EBITA 128 138 162 169 Margin 15.5% 15.6% 16.8% 16.7% Net Finance -6 -8 -7 -7 HSBC PBT 123 127 156 163 HSBC PAT 86 89 110 115 Diluted shares (m) 150 150 150 150 HSBC EPS (GBP) 0.57 0.60 0.73 0.77 DPS (GBP) 0.19 0.20 0.21 0.22 Cash flow Operating cash flow 105 119 128 144 Capital expenditure 59 70 73 51 Free cash flow 29 50 57 95 Net debt (cash) 167 146 119 57 Valuation metrics P/E 13.7 13.1 10.7 10.2 EV/EBITDA 9.4 8.1 6.7 6.0 EV/sales 1.64 1.50 1.35 1.23 P/B 1.43 1.38 1.29 1.21 FCF yield 2.4% 4.2% 4.8% 7.9%


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National Oilwell Varco (NOV) – maintain Overweight (V) rating, target price USD86 per share (unchanged)

In line with our OFS valuation framework, we value

NOV using equal weighted average of fair values

from average of 2013e and 2014e DCFs and average

of 2013e and 2014e sum-of-the-parts analyses.




for US listed stocks of 7%. This translates into a


share price for NOV. At the time we set our target

price, it implied a potential return that was above

the Neutral band; therefore, we rate the stock

Overweight (V) rating. Under our rating

methodology, NOV does not screen as a volatile

stock, but we believe applying a (V) flag to our

rating is appropriate given the company’s

underlying business volatility. Potential return





NOV provides sophisticated technologies that are

targeted towards harsh or complex environments,

such as deepwater plays. Any decrease in

commodity prices may result in oil & gas

companies reducing their activities and these

areas will be the first to suffer from reduced

activity levels. Additionally, it has significant

exposure to US markets, which is entirely driven

by shale at the moment and is volatile. Also,

Hydraulic fracturing (fraccing) has encountered

considerable political resistance in the US and

elsewhere on environmental concerns (impact on

local water supplies, etc) and some US states

(plus France/Germany) have banned the practice.

Any new laws or changes to existing laws could

impact drilling activity.

National Oilwell Varco: Valuation summary


EV/sales Implied EV Implied EV (2014e)

Rig Technology 2,467.4 10,966.1 9.5 2.1 23,440.0 23,023.3 Petroleum Services and Supplies 1,749.6 7,141.2 8.5 2.1 14,871.5 14,476.9 Distribution Services 317.4 5,203.3 6.5 0.4 2,063.1 2,048.8 other/Corporate 0.0 0.0 10.5 0.0 0.0 0.0 eliminations -483.7 -1,075.2 8.2 -3,966.1 -3,796.7

Total 4,050.7 22,235.3 9.0 1.6 36,408.5 35,752.3

net debt -1,210.2 739.6 minorities -8.0 -8.0 implied market value (USDm) 35,190.3 36,483.9 number of shares (m) 426.0 426.0 implied value per share (USD) 82.6 85.6


Assumptions 1.35 4.0% 5.0% 8.0% (USDm) EV 2012e net debt / associates / minorities market value per share discounted to end-2013 34,988.5 817.2 34,171.4 80.4 (USDm) EV 2013e net debt / associates / minorities market value per share discounted to end-2014 38,943.2 -1132.6 40,075.7 94.3


DCF 80.4 94.3 87.3 87.3 0.0% SOTP 82.6 85.6 84.1 84.1 0.0% Overall average (equally weighted) 85.7 - -


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National Oilwell Varco: Summary financial data

(USDm) 2012a 2013e 2014e 2015e

Rig technology Sales 10107 10966 12118 13026 % growth 30% 9% 11% 8% EBIT (excl one-offs) 2380 2292 2714 3081 % growth 15% -4% 18% 13% margin 8.5% 9.5% 10.0% 10.0% Petroleum services and supplies Sales 6967 7141 7570 8213 % growth 23% 2% 6% 9% EBIT (excl one-offs) 1519 1285 1457 1725 % growth 39% -15% 13% 18% margin 8.5% 9.5% 10.0% 10.0% Distribution services Sales 3927 5203 5463 5819 % growth 110% 33% 5% 6% EBIT (excl one-offs) 253 284 306 335 % growth 86% 12% 8% 9% margin 8.5% 9.5% 10.0% 10.0% Profit & loss Revenue 20041 22235 23998 25819 % growth 37% 11% 8% 8% EBITDA (excl one-offs) 4313 4051 4655 5302 margin 21.5% 18.2% 19.4% 20.5% EBIT (excl one-offs) 3688 3346 3949 4572 margin 18.4% 15.0% 16.5% 17.7% Other income / (loss) 58 63 71 63 Net finance -98 -157 -173 -161 HSBC PBT 3565 3239 3907 4534 Tax -1022 -1017 -1231 -1432 Minorities -8 -8 -8 -8 HSBC PAT 2534 2211 2665 3091 Diluted shares (m) 427.0 428.0 428.0 428.0 HSBC EPS (USD) 5.93 5.16 6.23 7.22 DPS (USD) 0.47 0.41 0.49 0.57 Cash flow Operating cash flow 212 1781 2879 2970 Capital expenditure 650 611 720 839 Free cash flow -446 1154 2119 2055 Net debt (cash) -170 1210 -740 -2627 Valuation metrics P/E 13.2 15.1 12.6 10.8 EV/EBITDA 7.7 8.5 7.0 5.8 EV/sales 1.66 1.56 1.36 1.19 P/B 1.64 1.50 1.35 1.21 FCF yield -1.3% 3.4% 6.2% 6.0%


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Schoeller Bleckmann – maintain Neutral (V) rating, target price EUR82 per share (unchanged)

In line with our OFS valuation framework, we

value Schoeller-Bleckmann using equal-weighted

average of fair values from the average of 2013e

and 2014e DCFs and average of 2013e and 2014e

sum-of-the-parts analyses.






share price for SBO. At the time we set our target

price, it implied a potential return that was within

the Neutral band; therefore, we rate the stock

Neutral (V). Under our rating methodology, SBO

does not screen as a volatile stock, but we believe

applying a (V) flag to our rating is appropriate

given the company’s underlying business

volatility. Potential return equals the percentage



when indicated.

Upside risks to our Neutral (V) rating:

improvement in North American onshore drilling

activity, thereby driving the company’s new

bookings, would prove positive.

Downside risks to our Neutral (V) rating: lower

oil prices for a long period of time, which in turn

would lead to a lower opex and capex, lower order

intake and execution issues with existing contracts.

Schoeller- Bleckmann: Valuation summary

Sum-of-the-parts model (EURm) 2013e EBITDA 2013e sales EV/EBITDA multiple (implied EV/sales) Implied EV (2013e) Implied EV (2014e)

High-precision components 79.2 357.7 9.0 2.0 712.7 726.1Dowhole tools 37.9 171.1 9.0 2.0 340.9 347.3Oilfield services 20.7 93.3 9.5 2.1 196.3 202.1Holding & consolidation adjustments -5.0 -163.4 7.5 0.2 -37.5 -43.5

Total 132.7 458.7 9.1 2.6 1,212.3 1,232.0

net cash (debt) 6.0 39.4 Associates/minorities -1.7 -1.7 implied market value (EURm) 1,216.6 1,269.6 number of shares (m) 16.0 16.0 implied value per share (EUR) 76.2 79.5


Assumptions 0.78 9.0% 5.0% 9.2% (EURm) EV 2013e net debt / associates / minorities market value per share (EUR)Discounted to end-2013 1,320.0 -6.0 1,326.0 83.1(EURm) EV 2014e net debt / associates / minorities market value per share (EUR)Discounted to end-2014 1,367.6 -39.4 1,407.0 88.2


DCF 83.1 88.2 85.6 85.6 0.0% SOTP 76.2 79.5 77.9 77.9 0.0%

Overall average (equally weighted) 81.8 - -


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Schoeller-Bleckmann: Summary financial data

(EURm) 2012a 2013e 2014e 2015e

Europe Sales 263 281 309 343 % growth 33% 7% 10% 11% EBIT 64 62 68 77 % growth 69% -4% 10% 14% margin 24.4% 22.0% 22.0% 22.6% North America Sales 344 280 333 384 % growth 7% -19% 19% 15% EBIT 57 32 48 62 % growth 9% -43% 50% 28% margin 16.5% 11.5% 14.5% 16.1% Other regions Sales 56 62 71 79 % growth 34% 10% 14% 12% EBIT 7 8 11 12 % growth 65% 15% 32% 16% margin 12.4% 13.0% 15.0% 15.6% Intersegment sales -151 -163 -173 -181 EBIT Adjustments -8 -8 -8 -8 Profit & loss Revenue 512 459 540 624 % growth 25% -10% 18% 16% EBITDA 160 133 163 191 margin 31.2% 28.9% 30.2% 30.6% EBIT (recurring) 120 94 119 144 margin 23.5% 20.5% 22.0% 23.0% Net Finance -10 -7 -6 -8 HSBC PBT 112 87 113 135 HSBC PAT 77 60 77 93 Diluted shares (m) 16.0 16.0 16.0 16.0 HSBC EPS (EUR) 4.85 3.73 4.85 5.83 DPS (EUR) 1.50 1.22 1.52 1.73 Cash flow Operating Cash Flow 103 120 102 114 Capital Expenditure 53 50 40 34 Free Cash Flow 50 80 64 83 Net Debt (Cash) 34 -6 -39 -84 Valuation metrics P/E 17.6 22.9 17.6 14.6 EV/EBITDA 8.7 10.2 8.1 6.7 EV/Sales 2.73 2.97 2.45 2.05 P/B 3.75 3.46 3.01 2.61 FCF Yield 3.7% 5.9% 4.7% 6.1% ROIC 22.8% 18.5% 22.4% 26.1%


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Bourbon Offshore – reiterate Overweight (V) rating, target price EUR28 (unchanged)

For Bourbon Offshore, our target price of EUR28

per share is based on the weighted average of a

company DCF model (average of 2013e and

2014e) and a replacement value model (average of

2013e-15e).





Neutral band of -1% to +19% around the current

price. Our target price of EUR28 implies a



our Overweight (V) rating. Bourbon does not

screen as volatile under the HSBC methodology,

but we keep the “V” flag to reflect the business

volatility and its high debt. Potential return equals





these include further project delays from oil

companies driving a lower annual spend on


new vessels due to lack of crews or operational

problems, lower oil prices, which could drive

lower levels of E&P investment, credit issues,

which could hamper its new-build programmes,

and oversupply of vessels in the medium term.

Bourbon Offshore: Valuation summary


Assumptions 1.15 6.0% 5.0% 8.5% (EURm) EV 2013e net debt / associates / minorities market value per share Discounted to end-2013 2,746.8 1,105.2 1,641.5 25.4 (EURm) EV 2014e net debt / associates / minorities market value per share Discounted to end-2014 3,024.7 1,191.3 1,833.3 28.4

Replacement cost valuation (EURm) 2013 2014 2015

Replacement cost 26.7 30.4 31.3 Average replacement cost 29.4 Trading premium 0% Trading replacement cost 29.4


DCF 25.4 28.4 26.9 26.9 0% Trading replacement cost 29.4 29.4 0% Overall average (equally weighted) 28.2 - -


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Bourbon Offshore: Summary financial data

(EURm) 2012a 2013e 2014e 2015e

Marine services Sales 972 1176 1468 1710 % growth 23% 21% 25% 16% EBITDA (excl one-offs) 305 389 465 523 % growth 38% 28% 19% 12% margin 31.3% 33.1% 31.7% 30.6% Subsea services Sales 190 205 274 335 % growth 10% 8% 34% 22% EBITDA (excl one-offs) 73 80 85 96 % growth 8% 9% 7% 12% margin 38.4% 38.9% 31.2% 28.6% Profit & loss Revenue 1187 1398 1760 2063 % growth 18% 18% 26% 17% EBITDA (excl one-offs) 382 473 554 623 margin 32.2% 33.8% 31.5% 30.2% EBIT 139 214 359 453 margin 11.7% 15.3% 20.4% 21.9% Other income / (loss) 24 89 224 0 Net finance -87 -90 -53 -31 HSBC PBT 52 124 307 422 Tax -22 -36 -53 -42 Minorities 11 33 34 35 HSBC PAT 26 70 242 344 Diluted shares (m) 67.7 71.6 71.6 71.6 HSBC EPS (EUR) 0.39 0.98 3.38 4.81 DPS (EUR) 0.82 0.40 1.24 0.96 Cash flow Operating cash flow 347 287 369 476 Capital expenditure 376 454 448 330 Free cash flow -124 -125 -46 181 Net debt (cash) 2061 1748 635 558 Valuation metrics P/E 51.3 20.5 5.9 4.2 EV/EBITDA 9.1 6.7 3.7 3.3 EV/sales 2.94 2.27 1.17 0.98 P/B 0.91 0.94 0.76 0.66 FCF yield -8.7% -8.8% -3.2% 12.6%


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BW Offshore – maintain Overweight (V), target price NOK10 (from NOK9) With BW Offshore, our NOK10 target price is

driven by the weighted average of fair values

from average DCF (average of 2013e and 2014e

DCFs) and average of backlog and book value

multiple-based valuation (see table below,

assumptions unchanged). We also use a

USD/NOK rate of 5.95 (from 5.75).




for Norwegian stocks of 11%. This translates into a

Neutral band of 1% to 21% above the current share

price for BW Offshore. Our target price of NOK10

provides a potential return of 24.5%, above the

Neutral band of our model; therefore, we have an





Downside risks to our Overweight (V) view:

these include lower oil prices, which could affect

further development project work from oil

companies driving less spend on offshore projects,

higher-than-expected levels of capital cost

inflation that could hinder FPSO technology,


would delay the awards of new FPSO contracts,

and a higher level of competitive pressure from

new industry entrants that could prove disruptive

to the market.

BW Offshore: Valuation summary

Book value based valuation Value

2013e book value 1,208.9 Multiple 0.8 Per share value (NOK) 8.6

Backlog-based valuation Current backlog 7.8 Multiple 0.5 EV based on backlog 2,875.0 Market value based on backlog 1,284.3 Per share value (NOK) 11.1


Assumptions 1.10 8.0% 5.0% 8.9% (EURm) EV 2013e net debt / associates / minorities market value per share (NOK) Discounted to end-2013 2,712.5 1586.8 1,125.7 9.7 (EURm) EV 2014e net debt / associates / minorities market value per share (NOK) Discounted to end-2014 2,778.2 1,616.3 1,161.9 10.0


DCF 9.7 10.0 9.9 8.5 16.4% Backlog-based valuation 11.1 Book-value-based valuation 8.6 9.9 9.6 2.8% Overall average (equally weighted) 9.9 9.0 9.4%


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BW Offshore: Summary financial data

(USDm) 2012 2013e 2014e 2015e

BWO FPSO Sales 475 527 492 549 % growth 6% 11% -7% 12% EBIT 25 114 120 136 % growth -70% 356% 5% 14% margin 5.3% 21.7% 24.3% 24.8% Prosafe production Sales 350 356 337 350 % growth -3% 2% -5% 4% EBIT 35 77 69 79 % growth -22% 119% -10% 14% margin 10.0% 21.5% 20.5% 22.5% Profit & loss Revenue 909 883 829 900 % growth 7% -3% -6% 9% EBITDA 247 445 428 474 margin 27.1% 50.4% 51.6% 52.7% EBIT 94 191 190 217 margin 10.4% 21.8% 23.0% 24.2% Net finance -66 -53 -64 -81 HSBC PBT 29 139 126 137 Tax -29 -31 -29 -31 Minorities 0.00 0.00 0.00 0.00 HSBC PAT 0 108 97 106 Diluted shares (m) 688.0 688.0 688.0 688.0 HSBC EPS (USD) 0.00 0.16 0.14 0.15 DPS (USD) 0.06 0.12 0.14 0.15 Cash flow Operating cash flow 210 366 353 391 Capital expenditure 228 207 290 202 Free cash flow -63 135 43 167 Net debt (cash) 1677 1591 1620 1531 Valuation metrics P/E na 8.6 9.5 8.8 EV/EBITDA 10.5 5.6 5.9 5.2 EV/sales 2.86 2.85 3.08 2.73 P/B 0.82 0.78 0.77 0.76 FCF yield -6.7% 14.5% 4.6% 17.9%


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Bumi Armada – maintain Neutral target price MYR4.20 (unchanged) Our valuation of BAB at MYR4.20 is based on

discounted cash flow (DCF) over an explicit

forecast period of 2013-20, risk-free rate of 4%,

equity risk premium of 3%, with a WACC of

6.2% and a terminal growth assumption at our

long-term inflation estimate of 2%.

We believe that DCF is the most appropriate

valuation methodology for BAB’s business due to

a variety of factors:

The long-term nature of FPSO contracts,

which make up the majority of the P&L;

The predictability of cash flow, given the

atypical bare-boat approach to chartering

contracts for FPSOs that BAB uses, should

mitigate variable cost risks of fuel,

crew, etc; and

The timing differences between revenue and

cash flow recognition in the charters with

greater working capital requirement

implications that need to be captured.


volatility indicator the Neutral band is 5ppts

above and below the hurdle rate for Malaysian

stocks of 7.0%. Our target price of MYR4.20

provides a potential return of 6.3%, which is


we maintain Neutral rating on the stock. Potential

return equals the percentage difference between

the current share price and the target price

Risks

Downside risks: project execution, charter

renegotiation, vessel downtime and foreign

exchange translation (as capex, contracts and

charters are typically USD based, while the

reporting currency is MYR). Other risks that

exist but we believe to be relatively low

include a fall in oil prices below cUSD80/bbl,

prompting large downward revisions in

planning prices, E&P capex cyclicality and

political risk.

Upside risks: materially larger-than-forecast

new order wins annually, increase in EBITDA

margins and stronger-than-expected ramp-up

of embryonic OFS division.

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Bumi Armada: Summary financial data

(MYRm) 2012 2013e 2014e 2015e

FPSO Revenue 716 737 1,114 1,337 % growth 17.5% 3.0% 51.2% 20.0% EBIT 244 196 339 414 % growth 22% -19.6% 73.0% 21.8% margin 34.1% 26.6% 30.5% 30.9% OSV Revenue 551 567 531 558 % growth 14.3% 2.8% -6.3% 5.0% EBIT 121 125 96 100 % growth 4.0% 2.8% -23.3% 5.0% margin 22.0% 22.0% 18.0% 18.0% T&I Revenue 388 507 507 292 % growth 60.3% 30.6% 0.0% -42.4% EBIT 120 259 264 155 % growth 2.9% 114.8% 2.0% -41.3% margin 31.0% 51.0% 52.0% 53.0% OFS Revenue 4 4 69 69 % growth -98.3% 10.0% 1600.0% 0.0% EBIT 4 1 17 17 % growth -89.5% -77.1% 1600.0% 0.0% margin 120.0% 25.0% 25.0% 25.0% Profit & loss account Revenue 1,659 1,815 2,222 2,256 % growth 7.5% 9.4% 22.4% 1.5% EBITDA 860 925 1,218 1,571 margins 51.8% 50.9% 54.8% 69.6% EBIT 504 581 716 686 margins 30.4% 32.0% 32.2% 30.4% Net finance (111) (78) (71) (68) PBT 469 583 728 729 Tax (81) (86) (108) (104) PAT 386 494 616 621 EPS (MYR per share) 13.2 16.9 21.0 21.2 DPS (MYR per share) 3.0 3.4 4.2 4.2 Valuation metrics P/E 30.0 23.4 18.8 18.6 EV/EBITDA 15.8 14.4 10.7 8.2 EV/sales 8.2 7.3 5.9 5.7 P/B 3.1 2.8 2.5 2.3 FCF yield -0.5 2.8 3.2 1.0


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SBM Offshore – reiterate Neutral (V), target price EUR17 (from EUR15)

For SBM, our EUR17 target price is driven by the

weighted average of fair values from average of

2013e and 2014e DCFs, and average of 2013e and

2014e sum-of-the-parts analyses. We use a

USD/EUR exchange rate of 1.35 (previously 1.30).


volatility indicator, the Neutral band is 10ppt

above and below the hurdle rate for eurozone

stocks of 9%. Our target price of EUR17 provides

a potential return of 13.6%, within the Neutral

band of our model; therefore, we reiterate our

Neutral (V) rating. Potential return equals the



dividend yield when indicated

Downside risks to our Neutral (V) rating: lower

oil prices, which could affect further project work

from oil companies driving less spend on offshore

projects, higher-than-expected levels of capital

cost inflation that could hinder FPSO technology,


would delay the award of new FPSO contracts,

further disruption to the vessel construction value

chain that could delay newbuild vessels and

tanker conversion projects, execution-related

issues for any particular project, and a higher level

of competitive pressure from new industry

entrants that could prove disruptive to the market.

Upside risks to our Neutral (V) rating: include

higher oil prices, which could accelerate

development of offshore projects, lower-than-

expected levels of cost inflation, a large number

of awards in a short span of time, better-than-

expected execution of projects under work and a

lower level of competitive pressure.

SBM Offshore: Valuation summary



(implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

FPSO Lease & Operate 540.9 968.0 6.2 3.5 3,341.0 3,341.0 Turnkey Systems 413.8 3,064.9 7.0 0.9 2,896.3 2,721.6 Turnkey Services 71.7 305.1 8.5 2.0 609.4 616.7 Turnkey Systems & Services 485.5 3,370.0 7.2 1.0 3,505.8 3,338.3 Other 0.0 0.0 0.0 0.0 0.0 0.0 Eliminations -52.3 0.0 6.7 0.0 -349.2 -271.5

Total 974.0 4,338.0 6.7 1.5 6,497.5 6,407.8 net debt -1,709.8 -1,426.5 minorities -71.3 -71.3 implied market value (USDm) 4,716.4 4,910.0 number of shares (m) 207.5 207.5 implied value per share (USD) 22.7 23.7 implied value per share (EUR) 16.8 17.5


Assumptions 1.20 6.0% 5.0% 9.2% (USDm) EV 2013e net debt / associates / minorities market value per share (EUR) Discounted to end-2013 5215.1 876.1 4,339.0 15.5 (USDm) EV 2014e net debt / associates / minorities market value per share (EUR) Discounted to end-2014 5606.0 592.8 5,013.2 17.9


DCF 15.5 17.9 16.7 14.3 16.7% SOTP 16.8 17.5 17.2 15.4 11.6% Overall average (equally weighted) 16.9 14.9 13.8%


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SBM Offshore: Summary financial data

(USDm) 2012a 2013e 2014e 2015e

FPSO lease & operate Sales 932 968 1131 1147 % growth 8% 4% 17% 1% EBIT 300 43 386 390 % growth -149% -86% 788% 1% margin 32.2% 4.5% 34.1% 34.0% Turnkey systems Sales 2482 3065 2835 2977 % growth 25% 24% -8% 5% EBIT 238 383 312 298 % growth -1% 61% -19% -5% margin 9.6% 12.5% 11.0% 10.0% Turnkey services Sales 281 305 336 378 % growth -7% 9% 10% 13% EBIT 60 64 74 85 % growth -16% 6% 15% 15% margin 21.4% 21.0% 22.0% 22.5% Profit & loss Revenue 3695 4338 4302 4501 % growth 17% 17% -1% 5% EBITDA 771 974 999 1004 margin 20.9% 22.5% 23.2% 22.3% EBIT -77 436 717 716 margin -2.1% 10.1% 16.7% 15.9% Other income / (loss) 128 1 1 0 Net Finance -87 -87 -91 -88 HSBC PBT -36 350 627 628 Tax -38 -43 -47 -47 Minorities 5 15 20 15 HSBC PAT -79 292 561 566 Diluted shares (m) 172.3 202.8 207.5 211.0 HSBC EPS (USD) -0.46 1.44 2.70 2.68 DPS (USD) 0.00 0.00 1.35 1.34 Cash flow Operating cash flow 591 334 863 857 Capital expenditure 570 525 580 475 Free cash flow 60 10 284 382 Net debt (cash) 1783 1710 1427 1185 Valuation metrics P/E NA 14.2 7.6 7.6 EV/EBITDA 7.8 6.1 5.7 5.4 EV/sales 1.63 1.37 1.32 1.20 P/B 2.28 1.96 1.57 1.33 FCF yield 1.2% 0.2% 5.6% 7.5%


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Anton Oilfield Services – maintain Overweight (V) rating, target price HKD7.22 (unchanged);

Anton Oilfield Services’ valuation is based on PE

multiple. We value the shares at a 28x PE multiple

of 2013e EPS, at the top end of the five-year

historical range given: 1) Anton’s faster-than-

expected growth; and 2) our high confidence in

Anton’s earnings power.




China stocks, or a potential return of

-0.5%-19.5%. Our target price of HKD7.22

implies a potential return of 32.5%, above the

Neutral range; therefore, we rate the stock with an





Downside risks: 1) Further industry-wide shale

gas exploration drilling yielding disappointing

results; and 2) macro and oil price weakness.

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Anton Oilfield: Summary financial data

(CNYm) 2012 2013e 2014e 2015e

Down-hole operation Revenue 856.5 1284.8 1670.3 2171.3 % growth 50.2% 50.0% 30.0% 30.0% Well completion Revenue 458.2 641.4 833.9 1084.0 % growth 43.3% 40.0% 30.0% 30.0% Drilling technology Revenue 433.0 649.4 844.3 1055.3 % growth 119.2% 50.0% 30.0% 25.0% Tubular services Revenue 256,923 282,615 310,877 341,965 % growth 50.0% 10.0% 10.0% 10.0% Profit and loss Revenue 2004.6 2858.3 3659.3 4652.6 % growth 59.2% 42.6% 28.0% 27.1% EBITDA 452.1 667.8 842.2 1053.8 margin 22.6% 23.4% 23.0% 22.6% EBIT 398.0 553.2 689.9 853.9 margin 19.9% 19.4% 18.9% 18.4% Net finance -30.6 -8.2 -10.3 -11.7 PBT 367.4 545.0 679.6 842.2 Tax -49.7 -81.8 -101.9 -126.3 PAT 302.6 448.1 562.5 700.8 EPS 0.14 0.21 0.26 0.32 DPS 0.05 0.07 0.09 0.11 Valuation metrics P/E 30.7 20.9 16.8 13.6 EV/EBITDA 20.8 14.4 11.6 9.5 EV/sales 4.7 3.4 2.7 2.1 P/B 4.7 4.0 3.5 3.0 FCF yield 1.1 -1.5 0.2 0.3


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Core Labs – maintain Neutral rating, target price USD180 per share (from USD157)

In line with our OFS valuation framework, we

value Core Labs using equal-weighted average of

fair values from the average of 2013e and 2014e

DCFs and average of 2013e and 2014e



volatility indicator, the Neutral band is 5 percentage

points above and below the hurdle rate for US-listed

stocks of 7.0%. This translates into a Neutral band of

2% to +12% above the current price for Core Labs.

Our target price of USD180 provides a potential

return of 2.7%, which is within the band, therefore,

we maintain our Neutral rating. Potential return

equals the percentage difference between the current



Upside risks to our Neutral rating: development

of more proprietary and patented technologies for

the increasingly complex hydrocarbon reserves

leading to higher profitability; and higher oil

prices for a continued period of time leading to

higher-than-expected contract awards.

Downside risks to our Neutral rating: high

volatility in commodity prices may result in

reduced capital expenditures/rig activities by the

oil & gas companies towards shale and deepwater

plays, impacting the demand for Core Labs’

patented technologies; and any new regulations or

changes to existing regulations in Core Labs’ area

of operations related to hydraulic fracturing

seriously impacting its growth prospects.

Core Labs: valuation summary


(implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Reservoir description 190.8 572.6 18.0 6.0 3,434.9 3,434.6 Production enhancement 178.2 497.5 16.0 5.7 2,881.0 2,851.2 Reservoir management 45.7 125.7 17.0 6.2 676.2 776.2

Total 414.7 1,195.8 17.0 5.9 6,992.1 7,062.0 net debt -147.7 51.9 Associates/minorities -3.8 -3.8 implied market value (USDm) 6,840.7 7,110.1 number of shares (m) 46.0 45.5 implied value per share (USD) 148.7 156.3


Assumptions 0.93 4.0% 5.0% 6.7% (USDm) EV 2013e net debt/associates/minorities market value per share (USD) Discounted to end-2013 9716.7 147.7 9,569.0 201.2 (USDm) EV 2014e net debt/associates/minorities market value per share (USD) Discounted to end-2013 10138.7 -51.9 10,190.6 214.3


DCF 201.2 214.3 207.8 176.6 18% SOTP 148.7 156.3 152.5 137.7 11% Overall average (equally weighted) (USD per share) 180.1 157.2 15% Overall average (equally weighted) (EUR per share) 136.0 120.0 13%


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Core Laboratories: Summary financial data

(USDm) 2012a 2013e 2014e 2015e

Reservoir description Sales 496 530 573 613% growth 5% 7% 8% 7%EBIT 145 159 178 196% growth 24% 10% 12% 10%margin 29.2% 30.0% 31.0% 32.0% Production enhancement Sales 404 452 497 527% growth 9% 12% 10% 6%EBIT 129 149 167 177% growth 14% 16% 12% 6%margin 31.8% 33.0% 33.5% 33.5% Reservoir management Sales 82 101 126 145% growth 23% 23% 25% 15%EBIT 26 33 43 49% growth 21% 26% 29% 15%margin 32.3% 33.0% 34.0% 34.0% EBIT others -2 0 0 0 Profit & loss Revenue 981 1083 1196 1285% growth 8% 10% 10% 7%EBITDA 320 367 415 452margin 32.6% 33.9% 34.7% 35.2%EBIT 297 341 387 422margin 30.3% 31.5% 32.4% 32.8%Other income / (loss) 0 0 0 0Net finance -9 -9 -11 -8HSBC PBT 288 333 376 414Minorities 0.5 1.0 1.0 1.0HSBC PAT 216 248 281 309Diluted shares (m) 47.6 46.0 45.5 45.5HSBC EPS (USD) 4.54 5.40 6.17 6.80DPS (USD) 1.12 1.35 1.54 1.70 Cash flow Operating cash flow 237 254 299 325Capital expenditure 31 34 37 40Free cash flow 177 221 262 286Net debt (cash) 215 148 -52 -267 Valuation metrics P/E 38.6 32.4 28.4 25.8EV/EBITDA 26.7 23.1 20.0 17.9EV/sales 8.7 7.8 6.9 6.3P/B 45.3 21.7 13.7 9.8FCF yield 2.1% 2.7% 3.1% 3.4%ROIC 55.4% 49.0% 54.4% 57.5%


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Fugro – reiterate Neutral, target price EUR50 (unchanged)

For Fugro our EUR50 target price is based on an

equally weighted average of DCF and

sum-of-the-parts valuations.


volatility indicator, the Neutral band is 5 percentage

points above and below the hurdle rate for eurozone

stocks of 9%. This translates into a Neutral band of

+4% to +14% above the current share price. At the

time we set our target price, it implied a potential

return that was within the Neutral band; therefore,

we rate the stock at Neutral. Potential return equals

the percentage difference between the current share




include further development project delays from

oil companies driving a lower annual spend on


new vessels due to lack of crews or operational

problems, lower oil prices, which could drive

lower levels of E&P investment, a higher level of

competitive pressure from new industry entrants

and, given Fugro’s stated interest in bolt-on deals,

too highly priced acquisitions.

Upside risks to our Neutral rating: these

include higher-than-expected margins and a

higher oil price for a longer duration.

Fugro: Valuation summary

Sum-of-the-parts model (EURm) 2013e EBITDA 2013e sales EV/EBITDA multiple

(implied EV/sales)

Implied EV (2013e)

Implied EV (2014e)

Geotechnical 148.4 718.6 10.5 2.2 1,558.4 1,547.4 Survey 250.9 927.1 10.0 2.7 2,508.8 2,461.1 Multi-client library 152.6 179 2.5 2.2 381.5 398.0 Seabed JV with CGG -0.9 87.5 -383.2 3.8 335.3 335.3 Eliminations -46.7 0.0 8.1 0.0 -376.2 -352.3

Total 591 2,569 8.7 2.3 4,407.9 4,389.5

net debt -401.4 -203.3 minorities -118.2 -118.2 implied market value (EURm) 3888.3 4,068.0 number of shares (m) 82.6 82.6 implied value per share (EUR) 47.1 49.3


Assumptions 1.00 6.0% 5.0% 8.4% (EURm) EV 2012e net debt / associates / minorities market value per share Discounted to end-2013 4567.4 -484.9 4,082.6 49.8 (EURm) EV 2013e net debt / associates / minorities market value per share Discounted to end-2014 4760.0 -286.8 4,473.1 54.6


DCF 49.8 54.6 52.2 52.2 0.0% SOTP 47.1 49.3 48.2 48.2 0.0%

Overall average (equally weighted) 50.2 - -


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Fugro: Summary financial data

(EURm) 2012a 2013e 2014e 2015e

Geotechnical Sales 723 719 768 849 % growth 8% -1% 7% 10% EBIT (excl assocs) 99 93 98 115 % growth 1% -6% 5% 17% margin 13.7% 13.0% 12.8% 13.5% Survey Sales 835 927 1030 1176 % growth -30% 11% 11% 14% EBIT (excl assocs) 213 185 201 223 % growth -9% -13% 8% 11% margin 25.5% 20.0% 19.5% 19.0% Subsea Sales 609 625 656 % growth 2% 5% EBIT (excl assocs) 32 44 69 % growth 37% 58% margin 5.3% 7.0% 10.5% Seabed/multi-client Sales 607 314 390 455 % growth -15% -48% 24% 17% EBIT (excl assocs) 174 52 16 16 % growth 55% -70% -68% -1% margin 28.7% 16.6% 4.2% 3.6% Profit & loss Revenue 2165 2569 2812 3136 % growth -16% 19% 9% 12% EBITDA 467 591 598 692 margin 21.6% 23.0% 21.3% 22.1% EBIT (excl assocs) 308 307 323 416 margin 14.2% 12.0% 11.5% 13.3% Other income / (loss) -1 4 5 6 Net finance -15 -1 -2 -5 HSBC PBT 289 301 320 413 Tax -50 -65 -67 -86 Minorities 10 8 11 16 HSBC PAT 289 434 243 312 Diluted shares (m) 81.0 82.6 82.6 82.6 HSBC EPS (EUR) 3.57 5.25 2.95 3.77 DPS (EUR) 2.00 1.50 1.60 1.73 Cash Flow Operating cash flow 279 444 596 562 Capital expenditure 258 257 325 317 Free cash flow -159 191 278 255 Net debt (cash) 1307 401 203 93 Valuation metrics P/E 12.5 15.3 15.2 11.8 EV/EBITDA 7.1 6.8 6.4 5.4 EV/sales 2.28 1.57 1.36 1.19 P/B 1.83 1.50 1.45 1.43 FCF yield -4.3% 5.2% 7.6% 6.9%


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Schlumberger – change to Neutral from Overweight rating, target price USD98 (from USD96)

For SLB our target price of USD98 per share is


from average of 2013e and 2014e DCF, and





for US stocks of 7%. Our target price of USD98

implies a potential return of 11.4%, within the

Neutral band of our model; therefore, we have a

Neutral rating. Potential return equals the




Downside risks to our view: these include lower

oil prices for a continued period of time, which

could affect further exploration and development

project work from oil companies; prolonged

weakness in the North American onshore market

because of weak gas prices; and a higher level of

competition, leading to pricing pressure in the North

American onshore-exposed market.

Upside risks to our view: a higher oil price and

sharper-than-expected rebound in North American

Land market are significant upside risks for SLB.

Schlumberger: Valuation summary


EV/Sales Implied EV (2013e)

Implied EV (2014e)

Reservoir characterization 3,996.7 9,991.9 11.5 4.6 45,962.5 45,806.4 Drilling 4,572.1 17,568.1 10.5 2.7 48,007.0 47,556.4 Reservoir production 3,318.3 15,991.7 10.0 2.1 33,182.8 33,343.5 Distribution 0.0 0.0 0.0 0.0 0.0 0.0 Eliminations and others -174.2 0.0 10.7 0.0 -1,863.4 -1,126.0 Oil field services 11,712.9 43,551.7 10.7 2.9 125,288.9 125,580.3 Contract seismic / processing / other 445.5 1,459.4 8.5 2.6 3,786.6 2,696.9 Multi-client 738.3 1,054.7 5.0 3.5 3,691.3 3,770.6 WesternGeco 1,183.7 2,514.0 6.3 3.0 7,477.9 7,467.5 Other 0.0 0.0 0.0 0.0 0.0 0.0 Eliminations -688.2 -184.5 10.3 0.0 -7,085.0 -6,800.9

Total 12,208.4 45,881.2 10.3 2.7 125,681.8 126,246.9 net debt 92.9 3,934.6 minorities 109.0 109.0 implied market value (USDm) 125,883.7 130,290.5 number of shares (m) 1,339.0 1,339.0 implied value per share (USD) 94.0 97.3


Assumptions 1.25 4.0% 5.0% 7.7% (USDm) EV 2013e net debt / associates / minorities market value per share Discounted to end-2013 130,539.2 -92.9 130,632.1 98.2 (USDm) EV 2014e net debt / associates / minorities market value per share Discounted to end-2014 133,516.3 -3934.6 137,450.8 103.3


DCF 98.2 103.3 100.8 100.8 0.0% SOTP 94.0 97.3 95.7 91.4 4.7% Overall average (equal weight) 98.2 96.1 2.2%


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Schlumberger: Summary financial data

(USDm) 2012a 2013e 2014e 2015e

Reservoir characterization Sales 9209 9992 11241 12534 % growth 16% 9% 13% 12% EBIT (excl one-offs) 2837 3122 3653 4199 % growth 37% 10% 17% 15% margin 30.8% 31.3% 32.5% 33.5% Drilling Sales 15971 17568 19940 23230 % growth 12% 10% 14% 17% EBIT (excl one-offs) 2824 3254 3888 4994 % growth 24% 15% 19% 28% margin 17.7% 18.5% 19.5% 21.5% Reservoir production Sales 14876 15992 17831 20060 % growth 17% 8% 12% 13% EBIT (excl one-offs) 2371 2519 3120 4213 % growth -9% 6% 24% 35% margin 15.9% 15.8% 17.5% 21.0% Western Geco Sales 2215 2514 2912 3087 % growth 13% 14% 16% 6% EBIT (excl one-offs) 374 553 801 1003 % growth -3% 48% 45% 25% margin 16.9% 22.0% 27.5% 32.5% Profit & loss Revenue 42148 45881 51713 58679 % growth 7% 9% 13% 13% EBITDA (excl one-offs) 11153 12208 14399 17693 margin 26.5% 26.6% 27.8% 30.2% EBIT (excl one-offs) 7652 8586 10564 13389 margin 18.2% 18.7% 20.4% 22.8% Other income / (loss) -162 572 0 0 Net finance -299 -372 -331 -222 HSBC PBT 7341 8215 10233 13168 Tax -1723 -2105 -2452 -3155 Minorities 29 29 29 29 HSBC PAT 5553 6217 7752 9984 Diluted shares (m) 1339.0 1339.0 1339.0 1339.0 HSBC EPS (USD) 4.15 4.64 5.79 7.46 DPS (USD) 1.10 1.24 1.45 1.86 Cash flow Operating cash flow 9023 11097 10944 13822 Capital expenditure 5050 4230 5164 5980 Free cash flow 2060 6288 5675 7511 Net debt (cash) 5111 -93 -3935 -9281 Valuation metrics P/E 21.2 18.9 15.2 11.8 EV/EBITDA 11.0 9.6 7.9 6.1 EV/sales 2.92 2.56 2.20 1.85 P/B 3.36 2.94 2.56 2.20 FCF yield 1.7% 5.2% 4.7% 6.3% ROIC 14% 16% 19% 23%


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SPT Energy Group – maintain Underweight (V) rating, target price HKD3.2 (unchanged)

SPT Energy Group’s valuation is based on PE

multiple. Our target price of HKD3.2 is derived

by applying a 15x PE on 2013e EPS. We are

broadly in line with consensus on earnings and

revenue for 2013e-14e.




China stocks, or a potential return of

-0.5%-19.5%. Our target price of HKD3.2 implies

a potential return below the Neutral range;

therefore, we rate the stock Underweight (V).

Potential return equals the percentage difference

between the current share price and the target

price, including the forecast dividend yield.

Upside risks: 1) high-quality contract wins, major

order from Sinopec; 2) deeper partnership with

Halliburton; and 3) a general increase in market

risk appetite.

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SPT Energy: Summary valuation data

(CNYm) 2012 2013e 2014e 2015e

Drilling Revenue 658.9 879.1 1142.8 1485.6 % growth 46.2% 33.4% 30.0% 30.0% EBITDA 190.9 215.4 274.3 349.1 % growth 71.5% 12.8% 27.3% 27.3% margin 29.0% 24.5% 24.0% 23.5% Well completion Revenue 531.5 738.2 959.7 1247.6 % growth 49.8% 38.9% 30.0% 30.0% EBITDA 144.5 180.9 230.3 293.2 % growth 42.8% 25.2% 27.3% 27.3% margin 27.2% 24.5% 24.0% 23.5% Reservoir Revenue 631.3 681.8 784.1 901.7 % growth 22.5% 8.0% 15.0% 15.0% EBITDA 214.8 235.2 266.6 302.1 % growth 14.6% 9.5% 13.3% 13.3% margin 34.0% 34.5% 34.0% 33.5% Profit & loss Revenue 1821.7 2299.1 2886.5 3634.9 % growth 37.9% 26.2% 25.6% 25.9% EBITDA 419.4 528.1 648.6 798.6 margin 23.0% 23.0% 22.5% 22.0% EBIT 362.1 456.8 554.8 677.4 margin 19.9% 19.9% 19.2% 18.6% Finance Cost -22.8 -15.1 -15.3 -15.4 PBT 339.3 441.7 539.5 661.9 Tax -84.3 -132.5 -161.9 -198.6 PAT 247.7 301.2 368.0 451.5 EPS 0.18 0.20 0.24 0.30 DPS 0.04 0.04 0.05 0.06 Valuation metrics P/E 16.7 15.2 12.5 10.2 EV/EBITDA 10.3 8.2 6.8 5.6 EV/sales 2.4 1.9 1.5 1.2 P/B 2.6 2.6 2.2 1.9 FCF yield -4.1 -0.1 -0.2 -0.3


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Notes

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Notes

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Disclosure appendix Analyst Certification The following analyst(s), economist(s), and/or strategist(s) who is(are) primarily responsible for this report, certifies(y) that the opinion(s) on the subject security(ies) or issuer(s) and/or any other views or forecasts expressed herein accurately reflect their personal view(s) and that no part of their compensation was, is or will be directly or indirectly related to the specific recommendation(s) or views contained in this research report: David Phillips, Phillip Lindsay, Neel Sinha, Thomas Hilboldt and Tingting Si

Important disclosures

Equities: Stock ratings and basis for financial analysis

HSBC believes that investors utilise various disciplines and investment horizons when making investment decisions, which depend largely on individual circumstances such as the investor's existing holdings, risk tolerance and other considerations. Given these differences, HSBC has two principal aims in its equity research: 1) to identify long-term investment opportunities based on particular themes or ideas that may affect the future earnings or cash flows of companies on a 12 month time horizon; and 2) from time to time to identify short-term investment opportunities that are derived from fundamental, quantitative, technical or event-driven techniques on a 0-3 month time horizon and which may differ from our long-term investment rating. HSBC has assigned ratings for its long-term investment opportunities as described below.

This report addresses only the long-term investment opportunities of the companies referred to in the report. As and when HSBC publishes a short-term trading idea the stocks to which these relate are identified on the website at www.hsbcnet.com/research. Details of these short-term investment opportunities can be found under the Reports section of this website.

HSBC believes an investor's decision to buy or sell a stock should depend on individual circumstances such as the investor's existing holdings and other considerations. Different securities firms use a variety of ratings terms as well as different rating systems to describe their recommendations. Investors should carefully read the definitions of the ratings used in each research report. In addition, because research reports contain more complete information concerning the analysts' views, investors should carefully read the entire research report and should not infer its contents from the rating. In any case, ratings should not be used or relied on in isolation as investment advice.

Rating definitions for long-term investment opportunities

Stock ratings HSBC assigns ratings to its stocks in this sector on the following basis:

For each stock we set a required rate of return calculated from the cost of equity for that stock’s domestic or, as appropriate, regional market established by our strategy team. The price target for a stock represents the value the analyst expects the stock to reach over our performance horizon. The performance horizon is 12 months. For a stock to be classified as Overweight, the potential return, which equals the percentage difference between the current share price and the target price, including the forecast dividend yield when indicated, must exceed the required return by at least 5 percentage points over the next 12 months (or 10 percentage points for a stock classified as Volatile*). For a stock to be classified as Underweight, the stock must be expected to underperform its required return by at least 5 percentage points over the next 12 months (or 10 percentage points for a stock classified as Volatile*). Stocks between these bands are classified as Neutral.

Our ratings are re-calibrated against these bands at the time of any 'material change' (initiation of coverage, change of volatility status or change in price target). Notwithstanding this, and although ratings are subject to ongoing management review, expected returns will be permitted to move outside the bands as a result of normal share price fluctuations without necessarily triggering a rating change.

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*A stock will be classified as volatile if its historical volatility has exceeded 40%, if the stock has been listed for less than 12 months (unless it is in an industry or sector where volatility is low) or if the analyst expects significant volatility. However, stocks which we do not consider volatile may in fact also behave in such a way. Historical volatility is defined as the past month's average of the daily 365-day moving average volatilities. In order to avoid misleadingly frequent changes in rating, however, volatility has to move 2.5 percentage points past the 40% benchmark in either direction for a stock's status to change.

Rating distribution for long-term investment opportunities

As of 10 October 2013, the distribution of all ratings published is as follows: Overweight (Buy) 45% (33% of these provided with Investment Banking Services)

Neutral (Hold) 38% (34% of these provided with Investment Banking Services)

Underweight (Sell) 17% (26% of these provided with Investment Banking Services)

Information regarding company share price performance and history of HSBC ratings and price targets in respect of its long-term investment opportunities for the companies the subject of this report is available from www.hsbcnet.com/research.

HSBC & Analyst disclosures Disclosure checklist

Company Ticker Recent price Price Date Disclosure

AKER SOLUTIONS AKSO.OL 79.80 10-Oct-2013 2, 5, 6, 7AMEC AMEC.L 10.50 10-Oct-2013 7BOURBON OFFSHORE GPBN.PA 19.24 10-Oct-2013 6BUMI ARMADA BUAB.KL 3.95 10-Oct-2013 2BW OFFSHORE BWO.OL 7.90 10-Oct-2013 5, 6, 7CAMERON CAM.N 60.09 10-Oct-2013 7, 11CGG GEPH.PA 15.50 10-Oct-2013 4, 5, 6, 7CHINA OILFIELD SERVICES 2883.HK 20.35 10-Oct-2013 4, 6EZRA HOLDINGS LIMITED EZRA.SI 1.22 10-Oct-2013 2, 6, 7FMC TECHNOLOGIES FTI.N 55.82 10-Oct-2013 7, 11FUGRO FUGRc.AS 42.72 10-Oct-2013 4LAMPRELL PLC LAM.L 1.42 10-Oct-2013 1, 5NATIONAL OILWELL VARCO IN NOV.N 77.77 10-Oct-2013 6, 7, 11PETROFAC LTD PFC.L 13.36 10-Oct-2013 4, 5SCHLUMBERGER LTD SLB.N 87.04 10-Oct-2013 2, 5, 6, 7, 11SCHOELLER-BLECKMANN SBOE.VI 85.60 10-Oct-2013 6SEADRILL LTD SDRL.OL 268.20 10-Oct-2013 2, 5, 6, 7SINOPEC ENGINEERING (GROUP) CO 2386.HK 9.55 10-Oct-2013 1, 4, 5SUBSEA 7 SA SUBC.OL 125.40 10-Oct-2013 2, 5, 6, 7TECHNIP TECF.PA 86.24 10-Oct-2013 1, 2, 4, 5, 6, 7, 11TRANSOCEAN INC RIGN.VX 40.41 10-Oct-2013 7, 11WOOD GROUP WG.L 7.66 10-Oct-2013 4, 6, 7

Source: HSBC

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1 HSBC has managed or co-managed a public offering of securities for this company within the past 12 months. 2 HSBC expects to receive or intends to seek compensation for investment banking services from this company in the next

3 months. 3 At the time of publication of this report, HSBC Securities (USA) Inc. is a Market Maker in securities issued by this

company. 4 As of 30 September 2013 HSBC beneficially owned 1% or more of a class of common equity securities of this company. 5 As of 31 August 2013, this company was a client of HSBC or had during the preceding 12 month period been a client of

and/or paid compensation to HSBC in respect of investment banking services. 6 As of 31 August 2013, this company was a client of HSBC or had during the preceding 12 month period been a client of

and/or paid compensation to HSBC in respect of non-investment banking securities-related services. 7 As of 31 August 2013, this company was a client of HSBC or had during the preceding 12 month period been a client of

and/or paid compensation to HSBC in respect of non-securities services. 8 A covering analyst/s has received compensation from this company in the past 12 months. 9 A covering analyst/s or a member of his/her household has a financial interest in the securities of this company, as

detailed below. 10 A covering analyst/s or a member of his/her household is an officer, director or supervisory board member of this

company, as detailed below. 11 At the time of publication of this report, HSBC is a non-US Market Maker in securities issued by this company and/or in

securities in respect of this company HSBC and its affiliates will from time to time sell to and buy from customers the securities/instruments (including derivatives) of companies covered in HSBC Research on a principal or agency basis.

Analysts, economists, and strategists are paid in part by reference to the profitability of HSBC which includes investment banking revenues.

For disclosures in respect of any company mentioned in this report, please see the most recently published report on that company available at www.hsbcnet.com/research.

Additional disclosures 1 This report is dated as at 15 October 2013. 2 All market data included in this report are dated as at close 08 October 2013, unless otherwise indicated in the report. 3 HSBC has procedures in place to identify and manage any potential conflicts of interest that arise in connection with its

Research business. HSBC's analysts and its other staff who are involved in the preparation and dissemination of Research operate and have a management reporting line independent of HSBC's Investment Banking business. Information Barrier procedures are in place between the Investment Banking and Research businesses to ensure that any confidential and/or price sensitive information is handled in an appropriate manner.

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Disclaimer * Legal entities as at 8 August 2012 ‘UAE’ HSBC Bank Middle East Limited, Dubai; ‘HK’ The Hongkong and Shanghai Banking Corporation Limited, Hong Kong; ‘TW’ HSBC Securities (Taiwan) Corporation Limited; 'CA' HSBC Bank Canada, Toronto; HSBC Bank, Paris Branch; HSBC France; ‘DE’ HSBC Trinkaus & Burkhardt AG, Düsseldorf; 000 HSBC Bank (RR), Moscow; ‘IN’ HSBC Securities and Capital Markets (India) Private Limited, Mumbai; ‘JP’ HSBC Securities (Japan) Limited, Tokyo; ‘EG’ HSBC Securities Egypt SAE, Cairo; ‘CN’ HSBC Investment Bank Asia Limited, Beijing Representative Office; The Hongkong and Shanghai Banking Corporation Limited, Singapore Branch; The Hongkong and Shanghai Banking Corporation Limited, Seoul Securities Branch; The Hongkong and Shanghai Banking Corporation Limited, Seoul Branch; HSBC Securities (South Africa) (Pty) Ltd, Johannesburg; HSBC Bank plc, London, Madrid, Milan, Stockholm, Tel Aviv; ‘US’ HSBC Securities (USA) Inc, New York; HSBC Yatirim Menkul Degerler AS, Istanbul; HSBC México, SA, Institución de Banca Múltiple, Grupo Financiero HSBC; HSBC Bank Brasil SA – Banco Múltiplo; HSBC Bank Australia Limited; HSBC Bank Argentina SA; HSBC Saudi Arabia Limited; The Hongkong and Shanghai Banking Corporation Limited, New Zealand Branch incorporated in Hong Kong SAR

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In the UK this document has been issued and approved by HSBC Bank plc (“HSBC”) for the information of its Clients (as defined in the Rules of FCA) and those of its affiliates only. It is not intended for Retail Clients in the UK. If this research is received by a customer of an affiliate of HSBC, its provision to the recipient is subject to the terms of business in place between the recipient and such affiliate. HSBC Securities (USA) Inc. accepts responsibility for the content of this research report prepared by its non-US foreign affiliate. All U.S. persons receiving and/or accessing this report and wishing to effect transactions in any security discussed herein should do so with HSBC Securities (USA) Inc. in the United States and not with its non-US foreign affiliate, the issuer of this report. 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Metals and Mining

EMEA Andrew Keen Global Sector Head, Metals and Mining +44 20 7991 6764 [email protected]

Thorsten Zimmermann, CFA +44 20 7991 6835 [email protected]

Vladimir Zhukov +7 495 783 8316 [email protected]

Emma Townshend +27 21 794 8345 [email protected]

Derryn Maade + 27 11 676 4519 [email protected]

North America & Latin America James Steel +1 212 525 3117 [email protected]

Patrick Chidley, CFA +1 212 525 4915 [email protected]

Botir Sharipov, CFA +1 212 525 5150 [email protected]

Howard Wen +1 212 525 3726 [email protected]

Leonardo A Correa +55 11 3847 5433 [email protected]

Luiz G Fornari + 55 11 3847 5436 [email protected]

Asia Simon Francis Regional Head of Metals and Mining, Asia Pacific +852 2996 6620 [email protected]

Thomas Zhu, CFA +852 2822 4325 [email protected]

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Brian Cho +822 3706 8750 [email protected]

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Energy

Europe David Phillips Global Sector Co-head, Oil and Gas +44 20 7991 2344 [email protected]

Peter Hitchens +44 20 7991 6822 [email protected]

Phillip Lindsay +44 207 991 2577 [email protected]

Kirtan Mehta, CFA +91 80 3001 3779 [email protected]

CEEMEA Bülent Yurdagül +90 212 376 46 12 [email protected]

Ildar Khaziev, CFA +7 495 645 4549 [email protected]

Latam Luiz F Carvalho + 55 11 3371 8178 [email protected]

Filipe M Gouveia + 55 11 3847 5451 [email protected]

Asia Thomas Hilboldt Regional Head of Oil, Gas and Petrochemical Research, Asia Pacific +852 2822 2922 [email protected]

Dennis Yoo, CFA +852 2996 6917 [email protected]

Kumar Manish +91 22 2268 1238 [email protected]

Alok P Deshpande +91 22 681245 [email protected]

SI Tingting +852 2996 6590 [email protected]

Chemicals

Europe Dr Geoff Haire +44 20 7991 6892 [email protected]

Sebastian Satz, CFA +44 20 7991 6894 [email protected]

Jesko Mayer-Wegelin, CFA +49 211 910 3719 [email protected]

CEEMEA Yonah Weisz +972 3 710 1198 [email protected]

Sriharsha Pappu, CFA +971 4 423 6924 [email protected]

Nicholas Paton, CFA + 971 4 423 6923 [email protected]

Asia Dennis Yoo, CFA +852 2996 6917 [email protected]

Utilities

Europe Adam Dickens +44 20 7991 6798 [email protected]

Verity Mitchell +44 20 7991 6840 [email protected]

Asia Jenny Cosgrove Regional Head of Utilities and Alternative Energy, Asia Pacific +852 2996 6619 [email protected]

Arun Kumar Singh Analyst +91 22 2268 1778 [email protected]

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Latin America Sandra Boente +1 212 525 4441 [email protected]

Osmar Camilo +55 11 3847 9502 [email protected]

CEEMEA Levent Bayar Analyst +90 212 376 46 17 [email protected]

Dmytro Konovalov +7 495 258 3152 [email protected]

Alternative Energy

Jenny Cosgrove Regional Head of Utilities and Alternative Energy, Asia Pacific +852 2996 6619 [email protected]

Charanjit Singh +91 80 3001 3776 [email protected]

Gloria Ho +852 2996 6941 [email protected]

Specialist Sales

Annabelle O'Connor +44 20 7991 5040 [email protected]

James Lesser +44 207 991 1382 [email protected]

Global Natural Resources & Energy Research Team

Global Oil Services

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