Archives for posts with tag: exploration

Self-Elevating Platforms (‘SEPs’) are generally used to provide offshore support for construction and maintenance projects. These units fall within the wider ‘construction’ sector in the segmentation of the offshore fleet, and can generally operate in water depths of up to 120m. The key deployment areas for these structures exist in the US Gulf of Mexico (GoM), West Africa and the Middle East. Despite high numbers of shallow water developments in the North Sea and South East Asia, there has been relatively little deployment of SEPs in these regions, although recent contracting patterns within South East Asia suggest this may soon change.

Rising Above Regional Regimen

The Graph of the Month shows the regional breakdown of producing fields with a water depth of <100m, as well as the share of self-elevating platform deployment across these regions. South-East Asia contains the largest number of shallow water developments with 552 active fields, closely followed by the US GoM (508) and the North Sea (452). However, there is a large disparity between these regions in terms of SEP deployment, with the US GoM accounting for the deployment of 161 units compared to the North Sea and South East Asia where just 10 and 19 structures are deployed respectively.

Lower deployment numbers in these regions can be largely attributed to a major factor in each region. In the North Sea, self-elevating platform use is often restricted by harsh operating conditions. In South-East Asia an ample supply of support vessels has provided ships for use in construction and support duties in the region.

Jacking-Up Orders

The current SEP orderbook includes 24 units with a record combined contract value of almost $2bn, of which 13 are for South-East Asian owners. Of the 15 contracts agreed in 2014, 60% of these are for Asian owners. Although these units will be capable of operating internationally, indications from owners including Teras Offshore, Swissco Marine and East Sunrise Group hint at a South-East Asian target market. There is a large fleet of mid-sized supply vessels in the region and historically these units have worked similar roles to the SEP fleet. However, the mid-sized supply vessel orderbook has diminished from around 200 units in 2012 to the current total of around 70 vessels, potentially supporting future deployment of SEPs in the region.

Lifting Expectations

An abundance of shallow water fields and relatively benign conditions means that South-East Asia is a region with strong potential for the future deployment of SEPs. Despite a lack of historical deployment, the attraction of competitive day rates in comparison to support vessels has reportedly begun to attract interest, in turn leading to investment in newbuild units from Asian owners.

So, a reduced orderbook for mid-sized supply units and an expected increase in field developments within China and South-East Asia could be positive news for SEP owners. Whilst still way below levels of deployment in the Gulf of Mexico, this region could provide impetus to self-elevating platform demand in the future.

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The shuttle tanker fleet consists of a relatively modest 88 vessels, but is of critical importance to the offshore story. The sector has always played a key role in exports from fields divorced from established pipeline infrastructure. As the move offshore into deeper and more remote areas gathers pace, shuttle tankers will be required to support production, particularly off Brazil.

Exponential Growth

The fleet has a long track record of steady growth (it was just 19 vessels at the start of 1989), and has recently undergone another expansion phase, growing from 65 vessels at end 2010 to 88 currently (up 35%). There are 8 vessels on order: until the contracting of three specialised Arctic units at Samsung in July, no orders had been placed since January 2013.

This might appear, on the surface, to be a sign of a fleet sector with muted demand growth prospects, particularly when considered in conjunction with the decade-long decline in North Sea shuttle tanker transportation evident in the Graph of the Month. However, the outlook is actually somewhat brighter. Brazilian usage has gradually increased year on year. Brazilian fields are expected to be at the forefront of the sixty potential field developments identified globally which are likely to use shuttle tankers.

There are now 25 likely future field developments offshore Brazil, which are expected to need shuttle tankers, and potentially add 1.5m bpd to shuttle tanker movements off Brazil. In the pre-salt areas, pipelines are often not feasible due to deep water and long distances to shore, so fields need shuttle tanker offtake from FPSOs.

The North Sea is an established shuttle tanker region, and now one with much activity under way to halt production decline. There are 9 future start-ups expected to require shuttle tankers, including Bream and Johan Castberg. These are expected to help shore up North Sea oil transportation on shuttle tankers to above 1m bpd in the medium term.

Fleet Consolidation

Recent years have seen the fleet become more consolidated. At the end of 2004 there were over 10 companies with just one shuttle tanker to their name but as of September 2014 there are just two companies owning only a single ship. Teekay Offshore and Knutsen NYK continue to account for a large portion of the fleet, owning 32 and 25 units each. This year alone, Knutsen acquired Lauritzen’s fleet of 3 ships: these were the first recorded shuttle tanker sales for over 5 years.

Tread With Caution

Of course, shuttle tankers are not immune to the usual cyclic problems of the offshore industry. In the past 18 months, delays in field start-ups in Brazil and the North Sea have led some companies to let charter options expire or fail to renew existing timecharters. This may limit ordering (typically orders are placed with an initial charter in mind). Over the longer term, however, further fleet expansion will be required to service additional demand. Whilst the graph no doubt shows the ‘best-case’ scenario, and some field start-up slippage will no doubt intervene, the shuttle tanker sector looks positioned for a relatively bright future.

OIMT201409

‘Pre-salt’ is usually a term associated with Brazil, where giant offshore field discoveries in the Santos and Campos basins have been grabbing headlines since 2007. Now oil companies are looking across the ocean for their pre-salt game. Conjugate basins offshore Gabon, Congo and Angola could be as juicy as the Santos and Campos pre-salt plays have proved. Following a number of recent scores by Cobalt, Eni, Harvest, Maersk and Total, the hunt is on.

Gearing Up

As the Graph of the Month shows, 16 wells targeting West African pre-salt reservoirs have been drilled since start 2011 with a success rate of 75%: 9 offshore Angola, 6 off Gabon and one off Congo. Oil from West African pre-salt was in fact first found in 1968. Its prospective yield was not appreciated though, as only recently did seismic imaging become able to give an accurate picture of the pre-salt. The ultra-deepwater of Angola’s Kwanza Basin also inhibited pre-salt exploration before sixth generation floaters. But, as Brazil has shown, operators now have all the technology they need to pursue the pre-salt.

Hunting Elephants

Some 27 future pre-salt wells are reportedly planned by oil companies or are anticipated through to end 2015, as the Graph of the Month shows. Four of these wells have been spudded. Often smaller E&P companies play a vital role in opening up new frontiers. In West Africa though, supermajors and other large players are already loading up. Conoco has 4 planned wells; Repsol, 3; Eni, 2; Shell, 2; and Total, 2. Of the 27 wells, 70% are offshore Angola and will therefore be in water depths ranging from 800-2,000m. The remainder are to be spudded off Gabon, likely in water depths up to 300m. In either case, companies will be hoping to hit world-class finds, like Cobalt’s Cameia discovery, which is expected to be brought onstream at 80-120,000 bpd in 2017.

Fieldcraft

So, the West African pre-salt play is still in the early stages of exploration and appraisal. If it proves prolific though, and if operators can bring it to fruition, a pre-salt bonanza would more than offset production decline from West Africa’s mature fields. With less stringent local content requirements and more international oil company control, development may be less fraught than in Brazil. Cobalt have already announced plans for 3 multi-field pre-salt hubs centred around the Cameia, Lontra and Orca fields offshore Angola. Given that the average water depth of Angolan pre-salt wells is 1,274m, MOPU solutions are likely to be favoured. The previous caveats noted, the FPSO ordering boom in Brazil could be replicated in Angola, which already accounts for 23% of world FPSO deployment (second to Brazil). In the shallower waters off Gabon, fixed platform solutions are probable, if finds reach the development stage.

In the near term then, the pre-salt safari offshore Africa looks to be an exciting campaign, with potential to generate even more interest in the region and hence opportunities for survey vessel and rig owners. Out towards the end of the decade, Angola could be the new Brazil, with pre-salt development contracts abounding.

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Natural gas demand and onshore and offshore production data is now available in Offshore Intelligence Monthly, split out by region and country on pages 3, 6-7 and 20-25. Analysing this data, it is apparent that the offshore hydrocarbons cake just keeps on getting bigger.

Since 1993, world combined offshore oil and gas production has increased by 58%, to 43.7m boepd in 2013; and between 2013 and 2023, it is forecast to increase by a further 35%, to 58.9m barrels oil equivalent per day (boepd). While oil is playing its part in this, gas is proving an even more potent rising agent in the offshore mix, of which it is taking an increasing share.

Measuring the Ingredients

As the Graph of the Month shows, growth rates for offshore oil and gas production have moved more or less in line y-o-y, with gas consistently ahead of oil as hitherto undeveloped historical offshore gas discoveries are brought onstream. While offshore gas production grew with a 3.8% CAGR from 1993 to 2013, oil exhibited a 1.4% CAGR. The spread between gas and oil production is forecast to continue 2013-23, with gas and oil production CAGRs of 4.2% and 2.0% respectively. It is thus expected that offshore gas production will almost achieve parity in volume terms with offshore oil by 2023, accounting for over 49% of offshore hydrocarbons output (versus 32% in 1993).

Energy Hunger

The strength of gas in the offshore production mix in part reflects faster historical and anticipated growth in gas demand. Since 2009, oil demand growth has stagnated in OECD countries whereas gas demand growth has remained firm, averaging 3.0% p.a. 2010-13 with a rate of 2.1% projected for 2014. In non-OECD countries, gas demand growth averaged 4.7% over the 2010-13 period, compared to 3.9% for oil demand. Similarly, 2014 demand growth is forecast at 3.7% for gas and 2.7% for oil. As non-OECD countries continue to industrialise, demand growth for natural gas is likely to remain firm.

Let Them Eat Cake

Given this scenario, it is likely shale gas will meet only a portion of future demand. Conventional gas will still have a role in feeding world energy hunger, and the offshore gas element of this increasingly so. In 2013, 30% of world natural gas production was offshore; in 2023 this is forecast to reach 36%. Accordingly, the offshore gas field investment outlook is positive. Offshore field operators are initiating schemes to utilise associated gas at mature oilfields. Moreover, development of offshore gas fields is increasingly perceived as economic. Gas fields account for 51% of fields under development and 48% of undeveloped offshore discoveries.

More so than oil, offshore gas growth is driven by mega-projects. Current examples include nine South Pars phases off Iran, Leviathan off Israel and Shah Deniz II in the Caspian, due onstream in 2015-17, 2017 and 2019. Major LNG projects planned offshore East Africa and Australia, entailing extensive subsea production systems and deployment of the world’s first floating liquefied natural gas (FLNG) vessels (like Shell’s “Prelude”), are also responsible much of the forecast growth in offshore gas. All in all then, gas looks to be quite a tasty slice of the offshore cake. Bon appétit!

OIMT201407

The impact of lower levels of vessel ordering on the size of the global shipbuilding industry has been a hot topic. It’s clear that shipyard capacity has reduced, and global output is down by as much as 20-30% since its peak in 2010. This week we take a closer look through the data archives to see what the characteristics of the industry were both before and after the shipyard capacity surge.

Eastern Delight

By the 1990s shipbuilding had largely shifted to the East. Japan commanded the top spot amongst builders but competition from Korea was mounting. Globally, around 300 yards had units on order (for vessels 1,000 GT and above), with the vast majority concentrating on a traditional marine product mix. During this period Japan had almost twice as many yards as China whose shipbuilding industry was very much in its infancy.

A New Dawn

The ‘size’ of the shipbuilding industry remained relatively steady in the first years of the new millennium. However there were notable changes in the location of available capacity. The Korean shipbuilding industry started to take the largest share of orders and more meaningful levels of commercial capacity were opening up in China. The great ordering boom of 2005-08 saw the shipbuilding industry undergo a major shift. Analysis of the orderbook data published in World Shipyard Monitor over the years shows that more than 400 extra yards came online during the period with the vast majority opening in China. By 2010, 40% of the total number of yards was in China.

Sunset Already?

As the boomtime orderbook was digested and the economic downturn kicked in, the number of yards with conventional tonnage on order reduced quite rapidly. At the start of 2012 the number of yards with an orderbook had decreased by around 20% compared to the peak in 2009. By the start of 2014, the total was 422, bringing the industry, at least in size, back towards pre-boom levels.

Survival Of The Fittest

However, whilst the merchant orderbook was falling, offshore investment was on the up. This was good news for many yards who began to shift their attention towards the offshore sector. As a result, the proportion of yards with an orderbook building ‘ship-shaped’ offshore units jumped from 17% in 2005 to 40% at the start of 2014. The growth in the offshore sector also meant greater demand for ‘non-ship shaped’ units and fixed structures, and some of the surplus traditional marine capacity has also been soaked up by this (or indeed by the growing repair market). Useful survival tactics, although this year investment in the offshore sector as a whole is down about 30% y-o-y, and last year contracting in the marine sector returned to more significant levels.

So there you have it. A look back in time provides some context to where the shipbuilding industry might be today. After a meteoric rise it’s finding its way back towards a more realistic position. Demand for offshore units has helped some yards weather the cycle, but recently they have had a better chance to return to what they know best. Have a nice day.

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OIMT201405Russia is forecast to account for 13% of world crude oil production and 18% of world natural gas production in 2014. While its prodigious Siberian flows tend to receive most of the credit for this feat, fields located off the country’s 16 million km of coastline are nonetheless projected to produce 390,000 bpd oil and 2.64 bcfd gas in 2014. So where exactly is Russian offshore production to be found? And what is the outlook?

Mastering the Arctic

As the Graph of the Month shows, offshore oil and gas production in Baltic & Arctic Russia stagnated after the break-up of the USSR, declining to 0.03m boepd in 2013, when it accounted for 4% of Russian offshore production. This trend was thrown into reverse when the Prirazlomnoye field came onstream in December 2013. Located 23km from shore in the Pechora Sea, the field is exploited via a ice-class platform and production is scheduled to reach 120,000 bpd by 2019. New technologies and robust oil prices are thus unlocking reserves hitherto stranded, and by 2023 Arctic oil and gas is forecast to constitute 11% of Russia’s offshore production.

Caspian and Crimean Conquests

Russia’s southern offshore fields, mainly in the Caspian, accounted for 9% of Russian offshore production in 2013. In the Caspian, as in the Arctic, harsh conditions have limited field development and disincentivised efforts to halt production decline. However, as in the Arctic, decline is now forecast to be arrested. Lukoil, for example, are planning substantial investment over the next four years at fields like Khvalynskoye and Yuri S. Kuvykin, where ice-class jack-up production units are likely to make development feasible. By 2023, the area is forecast to account for 24% of Russian offshore oil and gas production (excluding gas produced by fields off the Crimea, over which Russia now has de facto control, and which produced 410m cfd in 2013).

Expanding Eastwards

The Russian Far East is a relatively new area of offshore E&P. The Sakhalin-2 project started up in 1996 but offshore activity is still geographically limited, even if production volumes, at 0.78m boepd, are significant. The area accounted for 88% of Russian offshore production in 2013. Moreover, the Far East is Russia’s window on the developing economies of the Asia Pacific region, so companies are seeking to increase activity there, particularly with regards to LNG. In October 2013, the first Sakhalin-3 field, Kirinskoye, a subsea-to-shore development, began ramping up to 580m cfd. Further such field developments are planned out to 2023, when the area is projected to produce 0.95m boepd, its share falling to 65% despite new Capex due to faster Arctic and Caspian growth.

Thus production is forecast to grow in each of Russia’s offshore areas, driven largely by investment in high-spec jack-up, fixed platform and subsea field solutions. Total offshore oil production is projected to grow with a CAGR of 8.9% from 2014 to reach 890,000 bpd in 2023, and gas production likewise at 2.5% to reach 3.36 bcfd. Offshore would then account for 6.7% of the country’s oil and gas production, a far cry from the 2% nadir of post-Soviet decay.

How fast will ship demand grow? It’s the ultimate question for serious shipping investors. Today’s global economy relies on owners stepping up to invest in the ships that will be needed in the future ($115 billion was invested in new contracts last year). With so much cash on the table, the future trade growth issue cannot be ignored. But it’s tricky and even experienced analysts fall back on “rules of thumb”.

Faster Than World GDP

When they worry about the future most shipping investors have the world economy at the back of their minds. But although world GDP is the obvious starting point for analysing sea transport, the relationship between the world economy and seaborne trade growth needs handling with care. Unfortunately things do not always turn out the way investors expect.

For example, over the 50 years since 1963 these two key ship demand variables have increased by a not too dissimilar amount. GDP grew on average at 3.7% p.a. and sea trade grew at 4.5% pa. Overall trade volume increased 722% and GDP by 501%. If the relationship had been steady, the ratio of trade to GDP would have followed the path shown by the dotted line on the graph, moving steadily up from 100% in 1963 to 137% in 2013 (i.e. the sea trade index 37% higher than the GDP index, both of which were 100 in 1963). Interestingly today’s GDP forecasts are close to the 50 year trend, with projected growth of 3.6% in 2014 and 3.9% in 2015. So does that mean about 4.5% trade growth?

Sea Trade Multiplier?

That’s not always how things happen. The red line shows that the “sea trade multiplier”, which compares the cumulative year by year growth in the sea trade and GDP indices since 1963, was all over the shop. In the 1960s trade shot ahead of GDP and the multiplier reached 160% in 1974. Then the relationship reversed and in the period 1980-88 sea trade growth averaged only 0.4% pa compared with 3.2% pa for GDP. Again in 2005-09 trade lost ground as GDP growth averaged 3.5% pa and trade only 2.4%.

Structural Changes

This analysis suggests that when looking ahead more than a year or two, the structural changes that lie ahead are more interesting than the trend. The 1960s boom was driven by the OECD countries adjusting to global free trade by importing massive quantities of bulk commodities like iron ore and oil. Then the trade collapse in the 1980s was a structural response to high oil prices. And the trade slowdown in the late 2000s shows that the slowing OECD economies (less growth and more services) were important enough to shave the top off the Chinese mega-boom.

Brave New World

So, demand trends are all very well, but structural changes may matter more. Today high energy prices are squeezing the oil trade and the non-OECD world, which is increasingly important, seems to be moving into a different phase of growth. Although the 4.5% trade growth “multiplier” scenario looks convincing, remember that it is during structural changes that shipping fortunes are often made and lost. Have a nice day.

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OIMT02The floating LNG or “FLNG” concept has existed for decades; however it was not until 2011 that a long term solution was officially cemented with the signing of the $3bn build contract for ‘PRELUDE FLNG’. Following this, the FLNG sector has seen a new wave of activity, and contracts for 2 further units were placed in early February. Early estimates suggest as much as $85bn could be invested in FLNG technology by 2020, making it an exciting growth area.

A Demand Story

The Graph of the Month displays the cumulative potential FLNG requirement of 36 mooted FLNG projects with targeted delivery dates up to 2020. Of course, it is highly unlikely that all of these projects will actually come to fruition, with those rated ‘possible’ significantly more speculative than the more ‘probable’ units. However, if all those FLNG projects currently deemed ‘probable’ are ordered, then the number of operational units could be as many as 10 units by 2018 and 16 by 2020.

The major reason for the interest in FLNG is the desire to exploit ‘stranded’ gas fields far from existing infrastructure, given the strength of future gas demand expectations (BP’s Energy Outlook puts gas demand growth at 2.2% p.a. in the period to 2025). Accordingly, offshore gas output is expected to grow at a compound rate of 4.5% per year to 140bn cfd by 2020. FLNG could become a key part of this.

The major focus of growth in projects which could utilise FLNG will be Asia Pacific, notably off Australia. Close to half of potential FLNG locations are in the region, many in the Browse, Carnarvon and Bonaparte basins off north west Australia. While the Asia Pacific region remains a key area of growth, the Americas and Africa also hold opportunities for the positioning of potential units, with 17% apiece.
At the start of February, 2 further FLNG orders were placed. Petronas took the final investment decision (FID) for Rotan gas field off Malaysia, and awarded the contract for the hull to Samsung H.I. Meanwhile, Exmar have added a second moored barge unit to the order already under construction for use on Colombia’s Caribbean coast.

Not Yet Tried and Tested

Although this demonstrates the continued positivity surrounding the FLNG sector, it remains untested, with FLNG technology yet to enter operation. The first FLNG unit is slated for delivery in 2014, and will be the first of the Exmar barge-shaped units for Colombia. However, until the first LNG cargo is loaded (2015), it is unclear what technical challenges may be faced. Furthermore, the FLNG sector also faces risk from commodity prices. Should the US start to export shale gas on a large scale, this may produce downward pressure on gas prices, potentially making FLNG solutions less attractive to investors.

Fuelling the Future

So, the FLNG sector is still in its infancy and the outcome of the first projects could have a big impact on future investment. Ultimately, such a nascent sector faces technological and economic challenges. However, with offshore gas output set to increase substantially, it is likely that requirements for FLNG vessels will continue to progress.

OIM08In 1947, the first offshore oil discovery was drilled out of sight of land. Albeit only 29km away from the Louisiana coastline, and in water depths of just 4.3m, this achievement began an new era of offshore oil production. The movement of offshore operations into deeper and more remote regions has been previously documented by Clarkson Research, and as this trend continues we take a look at how the industry has prepared for this development.

Deeper and Darker

The Graph of the Month shows the trend in the characteristics of all known offshore oilfields against their year of discovery. As the more accessible fields became less available and less productive, companies moved further offshore and into deeper waters. In 1970 the average distance from shore of known oilfields stood at 60km, with the average water depth being 54m. By 2013 the average distance to shore had more than doubled to 134km, and the average water depth was 15 times deeper at an impressive 876m.

As well as increasing average water depths and distance to shore, many newly discovered fields are also in areas designated as harsh environments. Vessels operating in these frontier regions may face adverse weather conditions, longer periods of deployment and greater demand for capacity in order to maximise their efficiency.

Building for Tomorrow

In response to these more challenging requirements, the offshore industry has already altered its contracting preferences. One example of this is the trend in newbuild contracting of PSV vessels. Large PSV (>4,000 dwt) newbuild contracting in 2012 was almost 5 times higher than the number of contracts in 2009. In comparison small PSV (<3,000 dwt) newbuild contracting has decreased by 14% in the same period. The average deadweight of PSV contracted increased by almost 60% between 1990 and 2012, from 2,500 dwt to 4,000 dwt.

Another example of the offshore industry’s response to the increased water depths of newly discovered fields can be seen in the volume of newbuild orders for drillships. At present the number of drillships on the orderbook stands at 80, which is 88% of the current active fleet. In comparison to this the orderbook for Jack-Up rigs capable of drilling up to 300ft is just 13 units, a mere 4% of the existing fleet, highlighting the move from low specification, shallow water drilling units towards higher specification, deep water rigs.

Further Preparations

Whilst newbuilding of higher specification units has increased, some exceptions do remain. For example, ordering of ice class vessels has slowed in recent years despite an increase in Arctic exploration. Whilst this is still a developing sector which could fuel medium-term contracting demand, it is understandable that the recent focus of contracting has been on units intended for warmer waters. This is where the majority of deep water discoveries have occurred, and is the reason the offshore industry is gearing up for remote drilling accordingly.

201306-OIMTHistorically offshore oil and gas production has been concentrated in regions like North America and NW Europe, which together account for 52% of world active offshore fields. However, to supply growing demand and offset decline in mature fields, offshore oil and gas companies are today exploring prospects in previously untouched regions, basins and plays: hydrocarbon frontiers.

New Frontiers

The Graph of the Month illustrates the emergence of 4 such offshore frontier regions since 2008. The South Atlantic Margin, including Brazil and conjugate pre-salt basins in West Africa (Gabon, Congo, Angola and north Namibia) is the most established of the new frontiers, accounting for 13 discoveries back in 2008, rising to a peak of 27 in 2011. The Levantine Basin in the eastern Mediterranean, apportioned between Israel, Cyprus and soon Lebanon, has seen 2 discoveries in each of 2011, 2012 and 2013-to-date, though following gas finds like Leviathan and Aphrodite, explosive growth is likely.

The Equatorial Margin frontier, including French Guiana, Liberia, Sierra Leone, Ivory Coast and Ghana, mostly consists of cretaceous fan plays. The region has exhibited a rapid growth in exploration activity, with 10 discoveries in 2011 and 11 in 2012, compared to just 2 in 2008. The East African offshore frontier (Mozambique, Tanzania and Kenya) began to emerge in 2010 and 2011, with significant discoveries like the Prosperidade and Mamba gas-rich turbidite sand complexes giving impetus to exploration such that discoveries in 2012 increased by 150% year-on-year to 10. In total, the 4 frontiers in 2008 accounted for 16 discoveries, or 10% of global offshore finds; in 2012 their 46 discoveries represented 33% of world offshore finds.

Plumbing the Depths

The main thing these frontiers have in common is water depth. The mean water depth of discoveries made in these areas since start 2008 is 1,489m. Of the 173 discoveries, 86 (49.7%) were made in ultra-deep waters of more than 1,500m. These areas account for 59.7% of global ultra-deep finds in the period. Moreover, there has been a clear trend upwards since 2010. The mean water depth on a yearly basis has risen from 1,000m to 1,609m in 2012, with 2013 on track to roughly equal 2012. The only area of those featured with a significant number of shallow water discoveries is the South Atlantic Margin, with 40 (36.7%) finds in less than 500m, mostly minor Brazilian fields. East Africa, where exactly 50% of discoveries have been ultra-deep, has the highest mean water depth for discoveries in the period, at 1,533m.

Mapping the Future

Global demand for hydrocarbons continues to grow: oil demand rose 45% in non-OECD countries 2002-12, reaching 43.6m bpd. Given this trend, the evidently favourable geology and the advancing state of deepwater technology, the exploration and development potential of these 4 offshore frontiers augurs well for not only pioneering E&P companies, the majors and national oil companies who have started to work the frontiers, but also shipyards and owners of high-spec units capable of operating in ultra-deep waters.