Archives for posts with tag: oil production

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.


In 2011, Nigerian oil production stood at 2.55m bpd (of which 71% was offshore), accounting for 7.1% of total OPEC oil production (and 40% of West African offshore oil production). Since then, Nigerian oil production has been eroded by exposure to political risk factors and weaker commodity prices, dropping to just 1.54m bpd in 2016. What, then, is the outlook for Nigerian oil production in 2017 and beyond?

A Rose-Tinted Past?

Nigeria has been an oil producing country for almost 60 years and its first producing offshore field came onstream in 1965. In the following decades, Nigerian offshore E&P was focused almost entirely in the shallow waters of the Niger Delta. Even today, there remain 104 active shallow water fields in Nigeria producing via 263 fixed platforms with an average age of 25 years. It was in the late 1990s that Nigerian E&P began moving further from shore, as oil companies sought new reserves to offset decline at mature shallow water fields. Deepwater fields were also less vulnerable to the militant activity plaguing the Delta for much of the 2000s. The first deepwater discovery in Nigeria was Abo, in 1996, which was the first such start-up too, in 2003. As of March 2017, 40 fields in water depths of at least 500m had been found off Nigeria, of which 10 had been brought onstream via a total of seven FPSOs and 253 subsea trees.

A Risky Proposition?

However, were it not for deleterious influences on Nigeria’s upstream sector in the last 10 or so years, deepwater E&P in the country could now be more prevalent still. The foremost difficulty has been the Petroleum Industry Bill (PIB), which was first introduced to the Nigerian Parliament in 2008 and which has yet to be passed. An especially contentious issue is mooted changes to deepwater fiscal terms, which IOCs argue would render deepwater projects (where breakevens tend to fall in the $60-90/bbl range) unviable. An uncertain investment climate has been compounded by court cases arising from alleged improper practices, for example at OPL 245, host to the stalled ZabaZaba project(100,00 bpd). So there have been few deepwater FIDs and just three such field start-ups off Nigeria since 2009 (versus 20 off Angola). There has thus been little deepwater oil production growth to offset onshore or shallow water field decline.

Stability Or Volatility?

Uncertainty about the PIB remains, but in 2016, disruption caused by militants, notably the Niger Delta Avengers, came to the fore: attacks on oil infrastructure saw oil production dip below 1.25m bpd at times in 2016. Moreover, weaker oil prices have hit government finances and so its ability to dampen unrest. Production recovered slightly in Q4 but conditions in the Delta remain febrile. And if oil production does continue to ramp back up to over 2.0m bpd, it could imperil gains in the oil price that followed the OPEC deal (Nigeria is exempt from quotas). If prices cannot climb above $60/bbl, there is little prospect of Nigerian deepwater projects (of which there are 13 with a total oil production capacity of over 0.81m bpd yet to be sanctioned) hitting FID any time soon.

So in the short term, Nigeria could prove a key factor in the global oil price equation. And in the long term, undoubtedly the country has a great deal of deepwater potential; however, before this is likely to be realised, numerous challenges need to be overcome. Nothing is certain.


To much fanfare and accompanied by voluminous industry coverage, Mexico recently concluded Round 1.4, the country’s first ever deepwater licensing round. However, Mexico’s shallow waters may yet have a future too: Bay of Campeche reserves remain considerable and indeed, the country’s third shallow water bid round is ongoing. It is therefore worth reviewing the current state of shallow water E&P in Mexico.

Veering Off Course

Mexican offshore oil is currently produced entirely from shallow water fields, as has always been the case. The key sources of Mexican offshore oil have been several large field complexes such as Cantarell and Ku-Maloob-Zaap. As these fields and others came online, the country’s offshore oil output grew with a robust CAGR of 6.6% from 1980 to 2004, reaching a peak of 2.83m bpd in 2004. As the graph implies, four complexes accounted for 93% of this production. Decline set in thereafter at ageing fields (production at Cantarell began at the Akal field in 1979). Pemex – the sole operator of Mexican offshore fields prior to 2014 – tried to halt production decline, but with little success, given budget and technical constraints. Thus by 2013, offshore oil production at the four key field complexes had fallen to 1.31m bpd, accounting for 69% of Mexico’s offshore oil production of 1.90m bpd.

Getting Back On Track

This situation prompted President Peña Nieto’s government to initiate energy sector reforms in 2013, opening up the country’s upstream sector to foreign companies for the first time since 1938. Pemex was granted 83% of Mexican 2P reserves in “Round Zero” in 2014. The first shallow water round, Round 1.1, followed in December 2014. Only two of 14 blocks were awarded though, reportedly due to unfavourable fiscal terms inhibiting bidding by oil companies. The authorities then improved terms before launching Round 1.2 (shallow water), Round 1.3 (onshore) and Round 1.4 in 2015. Round 1.2 was better received than 1.1: as per the inset, 60% of blocks were awarded (75% of the km2 area on offer). One of the round’s victors, Eni, has already been granted permission to drill four appraisal wells on Block 1.

Turning Things Around?

In light of these positives, there are high hopes for Round 2.1, a shallow water round launched in July 2016. Indeed, 10 out of the 15 Round 2.1 blocks are in the prolific Sureste Basin, home to the Cantarell complex. Eight of these ten areas are unexplored, so there is sizeable upside potential, and have been mapped with 3D seismic, so operators could begin drilling promptly. Moreover, the surface area of the blocks in Round 2.1 are twice that of Round 1.1. It should also be noted that according to a 2016 IEA study, Mexico’s shallow waters still account for 29% of the country’s remaining technically recoverable oil resources. Finally, with rates for a high spec jack-up in the GoM assessed at about $85-90,000/day in January 2017, down 45% on three years ago, some oil companies might be tempted to make a move on a round that could offer a relatively low cost means to grow oil reserves and production.

So arguably, Mexican shallow water E&P is on the road again. There are potential hazards of course, such as oil price volatility or Mexico’s relationship with the US. But it is not implausible to think that Mexican shallow water oil production might speed up again in the coming years.


In the first film in the Bridget Jones series, 32 year old single Bridget soon ends up in the middle of a love triangle with the sensible Mark Darcy and charming Daniel Cleaver. The second sequel, released last year, sees Bridget finding herself unexpectedly expecting a baby. But Bridget Jones hasn’t been the only one battling tricky relationships and a rising headcount, as tanker owners will attest.

Happy Couple

The tanker market has certainly had some tumultuous times of late. Crude tanker earnings picked up in 2014, averaging nearly $27,000/day, and surged to an annual average of around $50,000/day in 2015. Things started to cool off into 2016, but in the full year average earnings were still fairly healthy at just under $30,000/day. They say two’s company; and these positive conditions did seem to have been brought about by the fortuitous lining up of two key factors.

Firstly, limited tanker ordering in the years after the global economic recession led to a spell of very muted growth in the tanker fleet. By the start of 2015, tanker fleet capacity was just 3% larger than at the start of 2013 (in the same period, the bulkcarrier fleet grew 10%). Secondly, the oil price crash in mid-2014 kick-started a period of unusually firm growth in seaborne oil trade. The ensuing low oil price environment supported healthy refinery margins and a build-up in oil inventories in key regions, whilst price pressures also dampened US oil production and boosted US crude imports. Overall, seaborne crude oil trade grew on average by a healthy 3.5% p.a. in 2015-16.

Delivery Record

However, a resurgence in contracting (1,278 tankers were ordered in 2013-15, up from 577 in 2010-12) has seen tanker fleet growth accelerate, to around 6% in 2016. The tanker supply surge has continued, with deliveries in January 2017 reaching an all-time monthly record of 6.7m dwt. With these new additions, tanker fleet capacity has already grown by 1.1% since the start of 2017, a similar rate of growth to that seen in full year 2014, with more tonnage delivered last month than in some whole years in the 1980s. In full year 2017, tanker fleet growth looks set to reach around 5%.

Troubling Trio

Another tricky element could also now be materialising on the demand side. Compliance by major oil exporters with agreed production cuts seems to have been high so far. The wider impact of these cuts on the tanker market is certainly far from clear, but there is the potential for improved oil price levels to support US oil output and undermine crude imports. At the same time, oil inventory drawdowns in some regions remain a key risk

Finding Mr Right

So, they say three’s a crowd, and the tanker market could be facing up to some real tests if the three factors of fast supply growth, changes in oil production and inventory drawdowns come together. Bridget Jones would be the first to tell you that finding the right way forward when the future’s uncertain and numbers are multiplying is tricky at the best of times, but rarely have shipowners not been up for a challenge. Have a nice day.


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 expansion of European settlement in North America – the pushing westwards of the frontier – has come to be seen as a defining part of American culture, spawning a whole genre of films and books set in the historical “Wild West”. That same pioneering spirit seems to be alive still today, at least in the US Gulf of Mexico (GoM), where 49 ultra-deepwater field discoveries have been made in the last decade.

Once Upon A Time In The Gulf

Offshore E&P in the US GoM began in the 1930s, picking up pace in the 1950s. By the end of 1975, a total of 444 shallow water fields had been discovered in the area and 256 of these had been brought into production. Gas fields predominated, accounting for 75% of discoveries and 31% of start-ups. Early E&P in the area made extensive use of jack-up drilling rigs and lift-boats. Fixed platforms were the favoured development method, with 86% of the 256 start-ups using fixed platforms. Thus were the first pioneering steps taken in exploiting the US GoM.

For A Few Dollars More

However, compelled by the need to find new reserves, oil companies active in the US GoM began pushing outwards, into deeper waters: the first deepwater discovery in the area was made in 1976. The frontier has now moved quite a way onwards since those early days. The average distance to shore of the 129 offshore discoveries in the area since start 2007 is 145km, while 72% (93) of these fields are in water depths of 500m or greater. The focus has also shifted from gas to oil: 58% of the 129 finds were oil fields, including 81% of the 93 deepwater finds. The US GoM has been dubbed one corner of the “Golden Triangle” of deepwater E&P and (supported by high oil prices until 2015) it has accounted for 16% and 19% of deepwater and ultra-deepwater finds globally since 2007. As shown by the graph, this was in spite of a slowdown in the wake of Deepwater Horizon. Floater utilisation dipped to 80% in 2011 but recovered, and a peak of 54 active floaters in the area was reached in January 2015 (26% of the active fleet).

Manifest Destiny?

So US GoM exploration was a major beneficiary of a high oil price. But how might it fare in a potential “lower for longer” price scenario? The outlook for jack-ups is bleak, with utilisation in the area standing at 24% as of December 2016. Simply put, the shallow water GoM is gas prone, and gas fields in the area are generally not competitive with onshore shale gas. At the US GoM (ultra-)deepwater frontier though, things do not look quite as bad as might be expected. On the one hand, over the last two years, floater utilisation has gradually fallen to 70%, as owners have struggled with rig oversupply, and dayrates are severely pressurised. On the other hand, there have been large finds made since 2014, such as Anchor and Power Nap, and wells are underway or planned for potentially major prospects such as Dawn Marie, Warrior, Castle Valley, Hershey, Hendrix, Sphinx and Dover. Many oil companies see the US GoM as a core area, and are prepared to invest to bolster oil reserves, even via drilling of, for example, costly HPHT reservoirs in the Lower Tertiary Wilcox formation.

As in the Wild West, at times things can be tough at offshore frontiers. Rig owners (and others) are experiencing this in the US GoM. But with some oil companies taking a long-term view, the pioneering spirit may not have been snuffed out yet.


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.