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In the years since 1959, 7,367 offshore fields have been discovered globally, with 4,173 of these having been brought onstream (3,062 are still active). The average water depth of discoveries and start-ups is now far deeper than a few decades ago. But contrary to what might be expected, this appears to be not the result of gradual trends in E&P activity. Instead, deepwater activity has surged in distinct waves…

Shallow Water Drift

Offshore E&P activity began, quite naturally, in shallow waters close to shore, as a logical progression from exploiting onshore oil and gas fields in locations such as Texas and Saudi Arabia. This also reflected technological barriers: the capability did not exist to exploit deepwater fields. So from 1960 to 1996, the annual average water depth of offshore discoveries and start-ups was 94m and 59m respectively. Depths did drift slightly deeper from 1960 to 1996 as for example North Sea E&P activity moved from the Southern to the Central North Sea. But even in 1996, the mean offshore discovery water depth was just 212m. The first ever deepwater discovery was the MC 113 field in the US GoM in 1976 but this was atypical: just 4% of 3,062 offshore fields found from 1976 to 1996 were in such depths.

Deepwater Heave

The first wave of sustained deepwater E&P ran from about 1997 to 2006. It was heralded by the 1997 Neptune start-up in the US GoM in a water depth of 568m. This was the first ever Spar development and showed that US deepwater fields could be economically exploited, contributing to a rush of deepwater E&P in the GoM against a backdrop of faltering US onshore oil production growth and gradually rising oil prices. Some 440 fields in depths of at least 500m were found from 1996 to 2007; 38% of these were in the US GoM. This period also saw the internationalisation of the offshore sector, with oil companies making deepwater finds in areas like West Africa, which accounted for 26% of the 440 discoveries. Here the key enablers were subsea trees, which helped reduce field breakevens to viable levels. All told, the average depth of offshore finds from 1997 to 2006 was 402m.

Ultra-Deepwater Upsurge

A second wave of deepwater E&P has been ongoing since about 2007. Oil companies have pushed into ultra-deepwater frontiers, notably in the Santos Basin off Brazil, helped by advances in pre-salt seismic imaging, but also in the KG Basin off India, off East Africa and off countries such as Guyana or Senegal. Since 2006, with oil prices generally high, there have been 392 finds in water depths of at least 1,500m (67% of such discoveries made to date). The average water depth of discoveries in this period so far is 628m.

Ebb And Flow?

However, offshore start-ups have lagged in terms of water depth. Since 2006, the average depth of 1,032 start-ups has been just 326m (with large variance from the mean). Several factors are at play but key are high breakeven oil prices at frontier projects (especially in the downturn) inhibiting FIDs, and political risk factors.

So given current offshore markets and long term trends in start-up water depths, a tsunami of deepwater start-ups looks unlikely at present. That being said, field discovery water depths – lifted on tides of regionalised E&P activity and new technologies – have clearly risen in waves.


The Indonesian government has been trying to reinvigorate investment in the country’s upstream oil and gas industry in the last few years. However, tough market conditions persist and political uncertainty remains a challenge. With oil companies seemingly losing interest in acreage offshore Indonesia, could offshore drilling demand in the country be running out of steam?

Ageing Problems

Indonesia is an OPEC member state and accounted for 16% (0.25m bpd) and 23% (3.67bn cfd) of offshore oil and gas production in SE Asia in 2015. However, oil and gas production off Indonesia declined by 4.7% from 2010 to 2015. In part this decline is because there have been few major discoveries to offset dwindling reserves at the country’s mature fields. Recently, operators have also been less willing to conduct additional development drilling on these depleting fields. As the Graph of the Month illustrates, offshore development drilling fell by 27% y-o-y between 2014 and 2015 and exploration drilling has also been subdued, with just two wells drilled in 2015, compared to 24 in 2014. Moreover, exploration has yielded only seven offshore discoveries since 2014, indicating that future development drilling demand could suffer as well.

Losing Interest

Problematic energy market fundamentals aside, political uncertainty has exacerbated the situation. The implementation of controversial Regulation 79/2010 in 2010 ended previous “assume and discharge” rules, meaning that new Production Sharing Contracts (PSCs) could be subject to varying and arbitrary levels of tax previously “dischargeable”. Operators recoiled strongly, denting interest in PSCs, as demonstrated by lacklustre participation in the 2013 Licensing Round. Corrective actions have since been taken, but it created crippling uncertainty in Indonesia’s upstream sector. Looking ahead, low oil prices and a 30% downwards revision to the level of tax oil companies can offset with costs, operators could become even less willing to commit to offshore acreage. Only 6 out of 11 offshore PSCs were awarded in the 2014 tender round. Moreover, Total and Chevron intend to relinquish the Mahakam and East Kalimantan blocks, which will expire in 2017 and 2018 respectively. Of 115 offshore PSCs held as of end 2015, 39 are undergoing termination, and operators might opt to reduce or end drilling activity if they intend not to renew these PSCs.

Under Pressure

It appears operators are losing interest in acreage off Indonesia, which could translate into weaker drilling demand, though the government has been exploring ways to stimulate investment and may eventually broker deals to keep operators committed to major offshore PSCs and capital outlay. Additionally, the country’s NOC, Pertamina, reportedly could assume operatorship of over 50% of upstream acreage. These factors might improve drilling demand in the longer term.

At present however, Indonesia’s offshore sector is clearly challenged: against the backdrop of globally reduced offshore E&P, the country has its own regulatory uncertainties. These factors have led to reduced interest in offshore acreage and subdued drilling activity. Unless the government can intervene to revive operator confidence, the near future also does not look encouraging for drilling demand.


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.


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.


The rise of deepwater E&P constituted a boon for the offshore fleet, helping to drive, for example, 180% and 60% increases in the FPSO and floater fleets from 2000 to 2015. However, deepwater development has lagged exploration, and so the offshore sector is fairly exposed to projects with high breakevens – problematic, given the oil price. But could the downturn actually help deepwater E&P in the long term?

Deepwater Exploration

The first deepwater offshore discovery was not made until 1976, by which point 1,018 shallow water fields had been discovered and 350 brought onstream, and it was only in the late-1990s that deepwater E&P really took off. Oil companies began pushing deeper into the US GoM, while the internationalization of the industry in the 2000s saw a spate of deepwater discoveries off West Africa and Brazil. A robust and rising oil price helped sustain rising deepwater E&P until 2015, with India, Australia and East Africa becoming important frontiers too. The average water depth of global offshore field discoveries passed 200m for the first time in 1996, 500m in 2004 and 800m in 2012, and the number of deepwater discoveries averaged 55 per year from 2005 to 2015.

Deepwater Production

However, as the main graph shows, the mean water depth of discoveries rose much faster than did that of start-ups: the former stood at 734m in 2015, the latter at 377m. Indeed, by 2016, out of a total of 998 deepwater finds, just 27% had started up, with deepwater start-ups averaging 19 per year from 2005 to 2015. The divergence was in large part because technological barriers and cost overheads in deepwater production – subsea, SURF and MOPU – are more complex and expensive than in exploration, and efficiency gains seem to have been more limited to date as well. Deepwater project sanctioning was therefore relatively inhibited, and due to limited sanctioning, the backlog of undeveloped deepwater fields grew at a faster rate than that of shallow water fields, as indicated by the inset graph. Thus over time, the overall backlog of potential projects has become more costly and complex. Indeed, some reports suggest oil project average breakevens have risen by c.270% since 2003.

Deepwater Challenges

This is partly why the offshore outlook is challenged at present: deepwater fields have relatively high breakevens (usually $60-$90/bbl) yet also form a major part of oil companies’ portfolios. Some major oil companies have indicated that 2016 E&P spending cuts are to bite deeper off than onshore, where costs are lower (even for shale, in many cases). In January 2016, Chevron decided to axe outright Buckskin, a US GoM project in a water depth of 1,816m with a breakeven of c.$72/bbl. ConocoPhilips, meanwhile, is planning to exit deepwater altogether.

However, in order to make deepwater viable again, many companies are trying instead to cut project costs. Statoil, for example, has reduced the CAPEX of Johan Castberg by 48% and the breakeven by 40%. Some cost savings (in day rates, for instance) are likely to be cyclical; others, such as in subsea fabrication, yielding improved deepwater project economics, are likely to be more lasting. So while exposure to deepwater projects is clearly a challenge given the current oil price, cost cutting now could be to the benefit of deepwater E&P in the long run.


Well, 2015 was really quite a year. Brent opened in January at c.$49/bbl, the price having tumbled in Q4 2014; the subsequent rally, which saw it pass $65/bbl, was cut short, and in December, it fell past $37/bbl. Expectations of a brief correction were confounded, and with E&P cuts biting and oil still falling, offshore seems to be facing a multi-year downturn. But just how does 2015 compare to recent years?

Annus Horribilis

At the end of 2015, Brent stood at around $37/bbl, far below the $60-80/bbl envisaged by many analysts at the close of 2014. Through 2015, various factors conspired to maintain a supply glut and depress the price, including OPEC policy, the resilience of the US shale sector and the softening global economic outlook.

Oil companies reacted to weaker price expectations by cutting E&P budgets and slashing jobs. In the offshore space, oil companies cut E&P spending by around 19% on average. Exploration spending was hit particularly hard, but FIDs at offshore development projects in 2015 were also down approximately 49% y-o-y, as operators were reluctant to commit capital to long lead-time projects. Some offshore areas and fleet segments fared relatively better than others, but 2015 was a pretty bleak year overall.

Turbulent Waters

In terms of offshore field activity, 2015 was the worst year in over a decade. Although some 2015 offshore discoveries like Zohr and Hopkins were notable for their magnitude or fast-track potential, just 96 offshore fields were discovered globally in 2015, down 19% on 2014 and 41% on the 2005-14 average of 162 discoveries per annum.

Meanwhile, only 68 offshore fields started up in 2015, down 41% on both the 114 start-ups of 2014 and the 2005-14 average. In part, this reflected problems pre-dating the fall in the oil price, such as slippage, cost inflation and political risk in countries like Nigeria, Egypt and Brazil. However, due to the paucity of FIDs in 2015, the backlog of fields under development at start 2016 was down roughly 11% y-o-y, even with many planned 2015 field start-ups deferred into 2016 due to slippage. The subsea tree backlog also fell by around 19%, to 301 units.

Challenging Times

The fall-off in offshore field activity compounded developing supply-demand imbalances in the offshore fleet, most notably in the OSV and rig fleets, with an adverse effect on utilization and rates. Thus global rig utilization stood at 73% at end 2015, compared to 87% at end 2014 and 96% at end 2013. Day rates also diminished substantially, with high-spec drillships in the US GoM, for example, commanding $200-275,000/day at end 2015, compared to $600,000/day at the peak of the market cycle. In the OSV sector, falling rig moves and project activity helped depress rates: the North Sea term rate for an AHTS 20,000+ BHP, for instance, averaged $16,800/day, down 52% y-o-y. Moreover, many OSV owners felt compelled to lay up units – a trend still playing out. Offshore newbuild contracting suffered, too with contracting down by 68% on 2014, so that even with delivery delays, the orderbook at start 2016 stood at 1,157 units, down 26% on start 2015.

Troubling Portents

Thus in comparison to the last ten years, and the recent market peak in 2013/14 in particular, 2015 was challenging. The coming year is likely to be a tough one as well, with many energy companies set to make further E&P budget cuts of 20-40% and the oil price seemingly yet to bottom out. The halcyon days of $100+/bbl now seem like a long time ago indeed.

The North Sea is home to a dispersed mass of steel and concrete, namely: 509 active fixed platforms with a combined weight exceeding 8 million tonnes; 1,440 subsea structures; 9,370 active wells and their completions; and over 45,000km of pipeline. Under the provisions of the OSPAR Convention, field operators will be obliged to decommission and clean all this up one day. And that day is approaching.

Diamonds And Rust

Decommissioning entails plugging wells, removing platform jackets, topsides and subsea structures, and, ultimately, complete site remediation. Oil companies in the North Sea are now having to contemplate this process at fields as recoverable reserves approach depletion. Since first oil in 1967, approximately 54.1bn bbls of oil have been produced in the area. However, production in 2015 is forecast to stand at just 2.86m bpd, compared to the 2000 peak of 5.9m bpd. The value of offshore field infrastructure consists in its ability to assist in the extraction of oil and gas; for the 47% of fixed platform tonnage installed on North Sea fields that began production more than 25 years ago, the point at which this is no longer the case is getting closer. But only 88 platforms in the area have been decommissioned so far, and for good reason.

Worth Fighting For

Decommissioning can be money and time-intensive. The decommissioning of the Brent facilities is expected to take ten years. Even small projects are expected to take two years and more than $300m in CAPEX. Hence, operators are trying to stave off decommissioning through enhanced oil recovery (EOR) to extend field life, or by tying new field developments to existing structures. For example, while the 12 wells on Heimdal are being abandoned, the platforms are being kept to process gas from Vale and other fields.

However, it is thought that in the current oil price environment, OPEX is encroaching on profits at a rising number of fields. Operators striving for fiscal discipline are between the hammer and the anvil: either run fields at a loss, or shut fields down and book the decommissioning costs.

Pain And Pleasure

This choice might be painful for oil companies but there is potential upside for many vessel owners. Drilling rigs and well intervention vessels will be needed to plug many of the wells. Crane vessels, self-elevating platforms and heavy lift vessels will be needed to remove and transport topsides and jackets (indeed, part of the rationale of the “Pioneering Spirit” is that it is one of very few units capable of lifting massive structures like the 42,500t topsides of the “Gullfaks A” gravity base platform). MSVs, DSVs and ROV Support vessels can be used to assist throughout decommissioning and will be especially important for removing subsea structures and for site remediation, when dredgers will also have a part to play. These various vessels will need to be assisted throughout the process by OSVs and utility support vessels.

Oil companies active in the North Sea might prefer not to charter all these vessels just to exit dead fields. But sooner or later (quite possibly sooner) they will have little choice. This could potentially benefit many different owners, with decommissioning becoming an important driver of North Sea vessel demand.