Archives for category: offshore structures

Offshore is quite a project driven sector in the sense that work at offshore fields drives much of the demand for offshore vessels. But offshore is also project driven in the sense that offshore output growth is linked to field project start-ups. And since 28% of global oil production is offshore, the aggregate of individual offshore start-ups can potentially have significant implications for wider energy market trends…

For the full version of this article, please go to Offshore Intelligence Network.

The mobile offshore orderbook reached its lowest level since 2005 at the start of August. Furthermore, a significant portion has been on order for a number of years, with a large share of these units having already been launched. As uncertainty continues to cloud the future for many of these vessels, this month’s Analysis investigates the nature of the offshore orderbook in more detail.

For the full version of this article, please go to Offshore Intelligence Network.

Expectations at the start of the year that 2016 would be a tough one for the oil industry, and in particular for offshore, were on the whole fulfilled. Overall upstream E&P spending globally fell for the second successive year, and was down by in the region of 27% year-on-year in 2016. Cost-cutting has been a key focus, whether that be through pressure on the supply chain, M&A activity, job cuts or other means. OIMT201701

Lower Spending

Offshore spending has been particularly reined back on exploration activity such as seismic survey and exploration drilling, although 2016 saw weakness spread further to areas such as the subsea or mobile production sectors which had initially shown some degree of protection from the downturn. This was not helped by a 32% year-on-year decline in sanctioned offshore project CAPEX in 2016, despite a small number of encouraging project FIDs, such as that for Mad Dog Phase 2 in the Gulf of Mexico in Q4.

Dayrate Weakness

Dayrates and asset values in those offshore sectors with liquid markets showed further signs of weakening in 2016. Clarksons Research’s index of global OSV termcharter rates declined by 27% in 2016, whilst that for drilling rigs was down by 25% year-on-year. Potential for further falls are, in general, limited, given that rates levels in many regions are close to operating expenses. Owners are doing what they can to control the supply side: just 81 offshore orders were recorded in 2016: for context, more than 1,000 offshore vessels were ordered at the height of the 2007 boom. Slippage has also remained evident, either due to mutually agreed delays with shipyards, or owing to owners cancelling orders. Offshore deliveries were 34% lower y-o-y in 2016.

Despite the severe industry downturn, the oil price actually firmed during the year. Brent crude began 2016 at $37/bbl, before briefly dipping below $30/bbl. However, the price ended 2016 at $55/bbl, helped by a slow firming in mid-year, and then more rapid gains after the 30th November announcement of a concerted oil production cut by OPEC countries.

This is clearly positive news for oil companies’ cashflow, and marks the abandoning of Saudi Arabia’s policy of targeting market share by accepting low prices as a means to hinder shale oil production in the US. However, US onshore companies were already feeling more comfortable with slightly improved prices in Q3 2016. Early surveys of intentions for E&P spending suggest that onshore spending in the US could increase by more than 20% in 2017. It is likely that offshore spending will decline further in 2017.

Some Way To Go

Nonetheless, it is important to stress that the offshore sector is far from dead. The expected multi-year downturn is occurring. However, important cost-control and consolidation has taken place. IOCs continue to consider strategic investments such as Coral FLNG or Bonga Lite. This shows that these companies are planning for better times. Decline at legacy fields will help to correct the supply/demand balance. Meanwhile, optimism is building in the renewables and decommissioning markets, with for example, announcements even in the first few days of 2017 that China is to make an RMB2.5 trillion investment in renewables over five years, whilst another North Sea decommissioning project plan has been submitted.

Nevertheless, the supply/demand imbalance in many offshore vessel sectors will take time to recalibrate. However, the weakness of 2016 also put in place many longer term trends which could lay the groundwork for an eventual change in market fortunes.

The African continent accounts for 16% (490) of active offshore fields and 17% (535) of offshore fields that are either under development or are potential developments globally. It is also home to key offshore exploration frontiers. However, the nature of E&P activity varies widely across the continent, as is clear from analysing the offshore areas into which Africa can be divided: North, South, East and West Africa.

North Africa: Old Fields?

A total of 217 oil or gas fields are located offshore North Africa, of which 112 are in production (95% in shallow waters). In this mature area, offshore oil production is projected to stand at 0.34m bpd in 2016, down 37% on the area’s peak of 0.54m bpd in 1991. Bar the possible restoration of offshore oil production lost in the “Arab Spring”, decline is set to continue. However, North African offshore gas production still has significant growth potential, forecast as it is to grow with a CAGR of 8.4% from 4.29bn cfd in 2016 to stand at 8.86bn cfd in 2025. This projected growth is driven by gas projects such as Zohr Ph.1 ($3.5bn; 1bn cfd) and Ph.2 ($10bn; 7bn cfd). The Zohr field, a frontier find in a water depth of 1,450m in the Levantine Basin, exemplifies the ongoing rise of deepwater E&P in the area.

South Africa: Few Fields

South African offshore production is minute in a global context. The area is home to just 17 offshore fields (only seven active, two having shut down in 2013). Although not without potential, E&P in the area has stalled in the downturn, as IOCs have cut and reprioritised E&P spending.

East Africa: New Fields

Unlike North and West Africa, East Africa has little history of offshore E&P: 88% of the area’s 41 offshore fields were discovered after 2009. The average water depth of these “frontier” finds is 1,570m and 92% are gas fields (with total reserves of more than 168 tcf). Offshore gas production in the area is projected to hit 2.82bn cfd in 2025 (from 0.13bn cfd in 2016) as fields are developed as part of LNG projects such as Coral FLNG Ph.1 ($7bn; 0.433bn cfd). However, further FID slippage at these frontier projects is a risk in the weaker energy price environment.

West Africa: Costly Fields?

West Africa constitutes one corner of the ‘Golden Triangle’ of deepwater E&P: of the 368 active fields in the area, 83% are in shallow waters (in the Gulf of Guinea and Angola) but 43% of 364 potential developments are in depths of more than 500m. The area has major deepwater production growth potential, even though it already accounted for 17% (4.35m bpd) of global offshore oil production in 2015. However, West Africa is a key offshore ‘swing’ region in terms of CAPEX and production: planned FPSO hubs such as MDA (Angola) tend to have high breakevens (c.$70/bbl+), so project FIDs have been scant since 2014. Frontier finds from Ghana up to Mauritania (39 since 2009) could yield more viable production growth though, and exploration in these waters has continued in the downturn.

In conclusion then, the African continent is home to a range of offshore field and project trends. Although there are some similarities across the continent in terms of “frontier” E&P, water depths and other factors, to get a grip on African offshore E&P, it is necessary to take the full range of available data and “drill down” into it.

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There are distinct signs that the offshore wind sector is emerging from a period of relative quiet. For the first time in several years, the number of final investment decisions (FIDs) is on the rise, while technological advances and ongoing research are making progress in improving the cost efficiency of offshore wind generated power. So, how does this potential translate into the offshore vessel sector?

Wind-ing Up Investment

Over the last few years, interest in the offshore wind industry has been on the rise, mainly due to a number of high-profile FIDs and an increase in investment levels. This theme has so far extended into 2016, which is shaping up to be the most successful year for the industry yet. At €14bn, the investment value of new FIDs reached for European projects during 1H 2016 was already greater than full year 2015 levels. The majority (74%) of this investment has stemmed from the UK, consolidating its place as the industry leader. For example, DONG reached an FID for the first gigawatt scale wind farm, Hornsea Project 1 in February 2016. DONG also gained development approval for Hornsea Project 2 later in the year. More broadly (as shown by the Graph of the Month), other countries have also made headway. A total of 3.5GW of capacity has started-up offshore Germany, Netherlands, Belgium and China since end-2014, 2.4GW of which was off Germany.

Owners Get Wind Of Demand

Increased investment levels in the offshore wind industry are likely to spur demand for related vessel types. Initial interest earlier in the 2000s focussed on turbine installation jack-ups, but more recently the focus has been on accommodation solutions, particularly those equipped with a motion-compensated gangway to allow “walk-to-work” access. At the start of October, there were over 25 traditional accommodation vessels with a known track record of working within the renewable sector. A class of vessels specifically tailored for the offshore wind industry has also been gaining interest. These so-called Service Operation Vessels (SOVs) are designed to offer accommodation, maintenance and manoeuvrability in one ship-shaped unit. At the start of October 2016, there were 12 such vessels in service and an additional 11 units on order.

Blowin’ In The Wind

Despite a slowdown in newbuild investment in Wind Turbine Installation Vessels (WTIVs) following a peak of 13 units contracted in 2010, future demand could be generated by turbine upsizing and a move to deeper waters, driving a requirement for larger vessels. Since the start of 2005, the average turbine rotor diameter has increased by 39% to 110m, while the average water depth of wind farms under construction (45m) is 66% greater than the water depth of active farms (27m) as of start October 2016. There has already been one WTIV newbuild order placed in 2016 for China, plus one for Japan.

To some degree, the perception of greater offshore wind activity is only relative to the challenging backdrop in the offshore oil and gas market, and risks do still exist. However, there is no denying that investment in the wind sector is on the increase. This will ultimately result in a rise in total installed capacity and is already encouraging investment in specialist vessels to support the offshore wind industry.

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Over the course of the last 20 years, oil and gas companies have cultivated a vast metallic forest beneath the world’s oceans, consisting now of some 5,800 installed subsea trees. The growth of this artificial arboretum has supported an array of related offshore fabrication, installation and IMR industries. But how to assess the outlook for this complex sector? Well, one key metric is the subsea tree backlog…

Into The Woods

The tree ‘backlog’ is the ‘orderbook’ of subsea trees. It is constituted by trees ordered by oil companies from subsea fabricators that have not yet been installed. A tree itself is the tall array of valves that caps a well; unlike ‘dry’ trees, subsea or ‘wet’ trees are located on the seabed, rather than on fixed platforms or MOPUs. While fields can host various subsea structure types, trees are at the core of nearly all subsea developments. Hence, the backlog is a key proxy for subsea CAPEX and subsea construction vessel demand. The real boom for the subsea sector came in period of high oil prices after 2009, as innovation in the subsea sector facilitated deepwater frontier projects in West Africa, Brazil and the US GoM. The backlog grew from 647 units in Q3 2009 to a peak of 1,158 at start Q4 2014 – an increase of 79%. At this point a number of large projects utilising subsea trees had recently reached the EPC stage, including TEN (Ghana, $4.9bn, 36 trees), Egina (Nigeria, $15bn, 44 trees) and Buzios (Brazil, $2.6bn, 20 trees). The charter rate for a large (250t crane) MSV in the North Sea, meanwhile, stood at around $52-59,000/day.

Cut Down To Size

However, like other offshore sectors, the subsea sector has been adversely affected by weaker oil prices (and the paralysis at Petrobras). Initially the backlog provided a degree of insulation for fabricators and installation contractors. The backlog is eroding though, having fallen y-o-y in each of the last nine quarters by between 1% and 14%. As at start Q2 2016, it stood at 876 units, down 24% on the Q4 2013 peak. Installers have been working through the backlog while new awards have dwindled (only 59 trees have been contracted in 2016 as at start May) due to a dearth of project FIDs. True, the subsea sector has held up better than the rig or OSV sectors (in part due to IMR demand, not captured by the backlog size) but North Sea dayrates for a 250t MSV have fallen by 34% since Q2 2014, to $32-43,000/day at start May 2016.


New Spring?

Could things in subsea get as challenging as in the rig and OSV sectors? Perhaps, but that depends on the timing of the recovery in offshore project FIDs. Besides, the downturn is not all bad for subsea – in the long run. In order to reduce field development costs, companies are increasingly relying on subsea efficiency gains – Statoil’s subsea standardisation drive is a notable example of this. As costs at subsea projects fall, more such projects are likely to receive FIDs. New tree awards are expected to recover to around 300 per annum by the end of the decade.

So subsea seems to be becoming more challenged, as reflected in the falling subsea tree backlog. But subsea is likely to play a key part in the recovery too. The arrival of new awards, followed by a sustained increase in backlog, will be a good indicator of when the offshore market is out of the woods.

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As a result of weaker oil prices and E&P spending cuts, offshore exploration is severely challenged. This is reflected in the fact that discoveries are down 47% y-o-y on an annualised basis so far in 2016, global rig utilisation has dropped 22 percentage points to 73% in two years, and 29% of seismic units are inactive. But it is also reflected in a perhaps less prominent element of exploration, namely, block awards.

Block Basics

The basic framework for offshore exploration is provided by blocks. Blocks are areas in which specific oil companies (the licensees) have set E&P rights and obligations with respect to one another and the host country over a specified period. As at April 2016, oil companies hold 10,968 offshore blocks (with an average area of 996 km2) globally. As a general rule, each block will have an operator company, but also several more companies with equity in the block. This allows oil companies to spread the risks of E&P.

Blocks may be awarded to oil companies on a one-off basis but are usually awarded through well-publicised, semi-regular licensing rounds, for example Norway’s ongoing ‘23rd Licensing Round’. Indeed, at present eight offshore rounds are in progress, covering 55 blocks. However, oil company uptake is looking lacklustre and it is expected that, given low levels of interest, a very small percentage of these will be awarded. Just 102 offshore blocks have been awarded so far in 2016, down 38% y-o-y on an annualised basis on a poor 2015. By way of comparison, 1,162 offshore blocks were awarded in 2013.

Acreage Accumulation

In part, this situation reflects reduced E&P spending (exploration budgets are relatively easy to cut). But it also reflects something of a block ‘asset bubble’ in the 2010 to 2014 period, in which 5.99 million km2 of offshore acreage was awarded. Supported by a high and stable oil price, many oil companies stocked up on frontier acreage, engaging in bidding wars for key blocks, driving up prices. For example, in a battle for a 8.5% share in Area 1 off Mozambique in 2012, the block was implicitly valued at c.$14 billion (and East Africa was just one of several frontiers opened up in this period). Oil companies thus acquired a great deal of relatively costly offshore acreage in a short period.

Exploration Excesses

On the plus side, the exploration boom of 2010 to 2014 yielded 765 offshore discoveries, including many large finds that are likely to drive future offshore production growth. However, block oversupply, analogous to that in segments of the offshore fleet, built up. As the two graphs show, the peak of the latest block awards cycle coincided with a 2013 peak in ordering of rigs (117 units) and seismic capacity (104 streamers). Just as there is a supply-demand imbalance in the seismic and rig markets, so too is there in blocks. Oil companies are now sitting on a backlog of unexplored blocks, with fewer incentives to bid for new acreage (though strategic investment in Iran or deepwater Mexico might still happen).

So licensing reflects the broader exploration situation, with block awards and vessel contracting showing similar trends. This being the case, a future rise in block awards could perhaps presage a general recovery in exploration. In gauging exploration sentiment then, upcoming licensing rounds could well be worth monitoring.

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