Archives for category: oil company

Venezuela has the world’s largest proven oil reserves and is one of the founding members of OPEC. Despite this, their 2.5m bpd of oil production accounts for only 3% of global output. Venezuelan oil production declined over the last decade owing to complex geology and a difficult investment climate. However, several large IOC-operated gas fields offshore Venezuela could now offer some positivity.

The Hydrocarbon El Dorado

Venezuela’s 300bn bbl of oil reserves account for 18% of current global reserves. But 220bn bbls of these reserves are onshore in the Faja, or Orinoco heavy oil belt, which has produced around 1.3m bpd in recent years. Venezuelan heavy oil grades are a key part of world oil supply: many US refineries were designed to take its heavy grades of oil together with lighter Arab crudes, meaning the country is also important for the tanker market. But production from the Faja is expensive and technically challenging, and heavy crudes sell at a discount.

Making Heavy Work Of It

After the election of Hugo Chávez in 1999, Venezuela’s oil industry came under strain as social policies were funded by oil revenues, and reinvestment declined. After the 2003 general strike, 19,000 PDVSA employees were fired and replaced with government loyalists. Furthermore, in 2007, the government looked to capitalize on the high oil price environment by nationalizing international oil companies’ (IOCs’) assets.

Offshore production was always the minor fraction of Venezuela’s output (23%). However, lack of investment in maintenance hit it hard. This was particularly true of the very shallow water production in Lake Maracaibo, which has seen drilling for more than a century. Issues of pipeline leakage and even oil piracy on the lake helped production there decline. In total, output from the Maracaibo-Falcon basin (not exclusively offshore) fell 35% between 2008 and 2015. In total, offshore production is estimated to have dropped by about 38% to 0.57m bpd.

A Brighter And Lighter Future

The current political and fiscal situation in Venezuela offers little suggestion that it will be easy to arrest decline. However, a more permissive attitude to foreign investment may help. In October, agreements were signed to allow Chinese and Bulgarian investment to fund repairs offshore Lake Maracaibo. Perhaps more significant is the promise of gas, where greater IOC participation is permitted.

Trinidad, Venezuela’s very close neighbour, tripled their offshore production from 1998-2005. Venezuela has begun to make moves in the same direction, firstly via the Cardon IV project. The first field here, Perla, started up in 2015 run by an Eni-Repsol joint venture. As the graph shows, this has already had a small, but visible effect on Venezuelan gas output. Perla has reserves of 2.85bn boe and by Phase 3 is set to be producing 1.2 bcfd. This is likely to be added to from 2019 by up to 1 bcfd of output from the long-delayed Mariscal Sucre fields.

So, Venezuela has vast reserves but production has been falling. The political situation, combined with low oil prices, is likely to hinder any rapid turnaround in oil output. However, although progress has been slow, IOC involvement has at least provided some positive impetus for gas production offshore Venezuela.

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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.

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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.

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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.

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Global excess oil supply still looks likely to average 0.5m bpd in 2016 – sufficient, it would seem, to stop oil prices rising much above $50/bbl and therefore to forestall a recovery in E&P activity and the offshore markets. On the supply side of the equation, US shale production and Saudi policy tend to be seen as the key “swing factors”. However, an appreciable degree of relief could also come from elsewhere.

Taking A Swing At Production

West Africa, a fairly mature oil producing region, accounted for 6% (5.3m bpd) of global oil supply in 2015, including 17% (4.4m bpd) of world offshore oil production. To put this in context, world oil oversupply in 2015 stood at around 1.7m bpd – 2% of total supply, i.e. 95.8m bpd, to which the US contributed 12.6m bpd (13%) and Saudi Arabia 12.4m bpd (13%). Saudi Arabian production so far in 2016 has been stable, while US shale oil production in May 2016 was down just 8.9% on May 2015, representing a far slower decline than many observers anticipated. It follows, then, that a severe disruption to West African oil production could have significant implications for the global oil supply-demand balance. Such a scenario seems to be unfolding in Nigeria, which in 2015 produced an estimated 2.3m bpd – 43% of West African oil production. In a series of high-profile attacks, the Niger Delta Avengers (NDA, a new permutation of the old militant group MEND) have sabotaged pipes and wells in the Niger Delta, crippling onshore and shallow water output. At the same time, only 12,000 bpd of offshore capacity (from the Antan field) is set to start up in 2016, and even fixed platforms further from shore, like “Okan NWP PRP”, have come under attack. As a result, Nigerian oil production reportedly fell to 1.1m bpd in May, and 2016 production is projected to average 1.8m bpd – a production loss equivalent to 28% of oversupply in 2015.

In Full Swing No Longer

Political risk is thus one reason West Africa can be a “swing factor” in oil production; another is project economics, especially over the medium term. Angola, for instance, accounts for 43% of West African offshore oil production and 33% of projects in the region yet to reach EPC. However, most of these are deepwater FPSO hubs with high breakevens. In fact, the last project sanctioned off Angola was the $16bn Kaombo Ph.1 project in April 2014, with a reported breakeven of $74/bbl. Given the dearth of project FIDs since 2014, a paucity of start-ups is expected in 2018-21, which would feed into weaker world oil supply growth.

The Swinging Sixties

In the long term though, West Africa has the potential to act as a swing region for (offshore) oil production in the opposite direction. Given stronger oil prices, c.$60-$80/bbl, prolific projects such as Chissonga (Angola, 150,000 bpd) could be feasible again, while an oil price of c.$90/bbl would unlock the potential of many of the 39 Equatorial Margin frontier fields discovered offshore since 2010. West Africa could thus, in a favourable price environment, make an important contribution to world oil supply growth once again.

Of course, political risk and costly projects make West Africa a challenging region at present. But taking a macro view, that could actually be positive for oil prices. West Africa is clearly one among a range of important swing factors in the world oil supply-demand balance.

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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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