oil equipment & services-in it to win it – the ‘aberdeen...

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Our feedback from Offshore Europe conference in Aberdeen

Decommissioning legislation a boon to an already active UKCS; industry struggling with costs but new competition emerging across several value chains

Companies we cover mentioned: Aker Solutions, Subsea 7, Technip, Hunting, AMEC, Wood Group, FMC, EZRA

Opened by the Chancellor of the Exchequer, George Osborne, the conference began with strong government commitments to the UK oil & gas sector and some positive news regarding decommissioning in the UKCS, a market currently experiencing record levels of capital expenditure. Despite some bullish opening remarks, we thought the overall industry ‘mood’ was upbeat with a tinge of caution/restraint. We didn’t meet anyone who was overly bullish on the market, and in a conference heavily populated by sales people, this perhaps tells its own story – there’s undoubtedly growth in the industry in the coming years but it’s not booming, and oil companies are doing their utmost to contain costs/restrict service sector margins.

Offshore Europe, Aberdeen, 3-6 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.

Who we met/heard from – Subsea 7, AMEC, Wood Group, Hunting, Aker Solutions,

Aibel, Heerema, GE, Shell, Total, WorleyParsons, Acteon, Foster Wheeler, FMC

A postcard from Aberdeen - wish you were here? Maybe, but the exhibition hall wasn’t nearly as picturesque

Source: HSBC

9 September 2013

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

David Phillips* Analyst HSBC Bank plc +44 20 7991 2344 [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

Natural Resources & Energy Global Energy Equipment Equity – Global

Flashnote

Oil Equipment & Services

In it to win it – the ‘Aberdeen Special Edition’

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Oil Equipment & Services Global Energy Equipment 9 September 2013

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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 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 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

Our feedback from the Offshore Europe in more detail

Hot on the heels of the ONS Norway conference (we include our summary from page 8), we’ve also

attended the Offshore Europe conference in Aberdeen. Offshore Europe opened with 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, providing

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 recent the programmes by Statoil and Shell were

effectively preventative or proactive maintenance. There are ongoing studies around improving the future

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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 newcomers targeting North Sea SURF. If all ‘potential’ new-comers 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 new comers to ‘cut the mustard' and we could see a situation where the strong balance

sheet companies prey on the weak, particularly if market entered 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. Although newcomers will inevitably imitate

existing technologies (pipeline bundles, pipe-in-pipe, plus pipelay techniques), we believe the chances 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.

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 is developing a spoolbase

in Norway from which to execute projects. 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 as 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 currently

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 many 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 remain 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 expect M&A (buying in experience) will

be the preferred route to market.

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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 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 Norway, etc). Aibel’s overall market

position in the NCS remains strong with a 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 slow (25 people

currently versus the planned 40 at the time of opening), management has long-term ambitions to expand

into the market with a focused market offering including its subsea engineering business Intecsea. In

addition, Foster Wheeler also has ambitions to increasingly 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 spring board 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 a 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 continue to be the key

differentiator – it is difficult to compete without this capability. The medium-term threat on the horizon is

Russian player TMK, which have 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 (and with 120 developable projects on the

horizon in the next 5-10 years, this has the 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

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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.

Industry costs 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. It is difficult to see what

changes this as the industry is moving to exploit ever more complex geological structures (deeper,

further, harsher etc), which requires more people to exploit each barrel of oil. Although a higher oil price

would clearly soften the blow, the reality 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 new technology more willingly (Norway ‘light years’ ahead of the UK on technology

development, ie subsea processing, modern drilling techniques), as well as moving to more remotely

managed/maintained facilities, reducing offshore personnel and making more efficient use of skilled

resources – the strive to reach 100% uptime is crucial if the industry is to deliver on its promise.

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Learning lessons from the last cycle where the balance of power lied 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 add 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. It’s 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 takes 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 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 it is well placed for contracts with Total and ENI) and Aker Solutions for subsea

processing (working on its 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 it as a near-term growth driver for the main

players. However, long-term growth potential is significant now and early positioning is crucial or 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 a key challenge, and there are ongoing programmes to develop

'gravity' and 'cyclonic' separation technologies.

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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 1994-1998 but only in the last 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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ONS Norway, Stavanger, 19-21 August 2013

Now when a biennial conference becomes annual it is usually a sign that the cycle is near a peak,

although this ‘mini’ ONS is the NCS-focused cousin of the main ONS next due in August 2014. We met

a wide range of oilfield suppliers, Asian shipyards, private equity, consultants and a few operators; we list

our feedback in this short report.

Who was there – most suppliers (although more of an effort from smaller names, less from the likes of

NOV, AKSO, FTI, CAM), some Asian yards, some operators.

Who 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 vs 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

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)

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).

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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 USD1.3 trillion over 2014-2017; 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 five 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 the main macro question; very much about shale oil and

the medium-term potential of unconventional/tight oil supply to change the 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 thought 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 and 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 that 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

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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 soundbites 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 4 regions, 5 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 the 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 (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 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 2005/2006 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 vs. 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 roughly200-250,000 boe/day from new sanctioned projects

(Aasta Hansteen, Gina Krog, Martin Linge, Edvard Grieg, Ivar Aasen, Gullfaks Sør Oil, Svalin, Fram

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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 last 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

license round availability (22nd round was “good for the industry”, South-East Barents opening up, also

could see the Lofoten area opening up, 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 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 pear year market with around 1100 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 3 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).

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Statoil's NCS rig needs – explaining rig categories, strategies and 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 – which the market relies on – 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 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 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 “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).

(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 rigs’ 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 this (Statoil also said it

reckoned it effectively locked in at least a 20% saving in rates by owning versus leasing).

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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" (4 units are under construction at DSME in Korea, with Songa as contractor)

Cat F – ‘flotel’, ie floating accommodation (2 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 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), 3 are under

construction, 2 to be owned by Statoil (being built at Samsung in Korea) and 1 by Noble (being built

in Singapore – will be on a 4-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)

There was 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 2 wells in 2014, 7 in 2015, 8 in 2016, and 3 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 is 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 see

400Tcf gas) and many of the usual suspects are already ‘in’, like Shell, Total, Chevron, Conoco, Hess,

and Statoil bought in recently.

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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 7-8

projects/prospects (equivalent to 10 vessels) on the horizon – the main ones are:

GDF's Bonaparte– competitive concept definition stage, down to TEC vs 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 3 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 vs SBM/Linde – will be unusual

vs other FLNG as this is likely be a leased vessel; worth noting SBM's FLNG designs for a mid-sized

vessel (effectively 2 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 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 2015-2017 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 – fewer

of the Chinese yards than usual (but we 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 note awards of subsea and seismic newbuilds to Japan).

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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 ‘soundbite’ data on the yards and their suppliers:

HHI's view was that over 6 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 6 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) – most yards commented that the Norwegian suppliers were good on quality

but generally late on delivery

DSME's view on suppliers over 2009-2011 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,

Framo/SLB, ABB, Hamsworthy, Kongsberg and others.

measured over a large number of projects – the main delays are caused by design changes & 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 which, 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).

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Ratings summary for companies mentioned in this report

Company Current price Target price Rating

Aker Solutions (NOK, AKSO.OL) 91.50 125.00 Overweight (V) Subsea7 (NOK, SUBC.OL) 122.90 155.00 Overweight (V) Technip (EUR, TECF.PA) 88.49 105.00 Overweight (V) Hunting (GBPp, HTG.L) 838.00 1050.00 Overweight AMEC (GBPp, AMEC.L) 1057.00 1130.00 Neutral (V) Wood Group (GBPp,WG.L) 792.00 860.00 Neutral FMC Technologies (USD, FTI.N) 55.08 56.00 Neutral(V) EZRA holdings (SGD, EZRA.SI) 0.84 1.25 Overweight

Pricing date: 5 September 2013 Source: Thomson Reuters Datastream, HSBC estimates

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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: Phillip Lindsay and David Phillips

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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.

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