Why oil prices are going up (and will continue to do so)

“a few pictures say more than a thousand words”

Oil prices have been going up over the last few months, from below 30 dollars per barrel in February to the current levels of around 50 dollars per barrel. Many short term issues of a different nature play a role here, ranging from market psychology to supply interruptions such as the Alberta wildfires. But I would argue that in the background there is a persistent upward trend, caused by the simplest of explanations: supply and demand are starting to approach a balanced situation.

On predicting future oil supply and demand no individual can produce anything close to the comprehensive analyses of organizations like the IEA or the major consultancy firms. But one can try to highlight a few processes that hopefully give some insight into the way that supply is responding to changes in the oil price.


Increased field decline of conventional oil fields is kicking in

Much of the publicity on the way that oil supply is responding to lower prices has focused on unconventional shale oil in the US. And indeed the rapid advance of US shale oil has been a key factor in the creation of oversupply. But for the response of supply to low prices the over 50 million barrel/day production from conventional (non-OPEC) fields plays a much bigger role. Small changes in the average decline rate of these fields result in large changes for oil supply in absolute numbers.

The figure below is taken from a recent (June 2016) Rystad Energy study and shows the average decline rate for mature non-OPEC oil fields. Up to 2015 these figures are actuals; for 2016 this is a prediction with limited uncertainty and for later years uncertainty increases.

Oil price rise paper fig1

Due to higher amounts of activity, the average decline rate in the 2010-2014 high oil price world was about 3 % only (without any activity this decline rate would have been about 8 – 9 %). Reduced activity in the subsequent low oil price world resulted in higher decline rates of about 5 – 6 %. In absolute terms: for 2016 this amounts to a supply decrease of 3.3 million barrels/day.

First of all: the fast response of existing field decline rates is due to the nature of the activities involved: workovers and infill drilling can be planned and executed in a relatively short time frame.

Secondly, the effects of reduced infill drilling in conventional fields will be felt for years to come; a conventional well not drilled in 2015 is still likely to result in lower production in 2020 and beyond.

Thirdly, decline rates are much less of an issue for OPEC fields. Production in a country like Saudi Arabia is capped by political decisions or infrastructure capacity rather than geology (hence their much higher reserves to production ratios).

So why do decline rates of conventional non-OPEC fields receive so little attention? I think this is simply because field decline has so far been masked by new fields coming on stream. For 2016, the added production from new fields amounted to about 3.0 million barrel per day, roughly compensating for the decline of existing fields. Many projects are still coming on line (especially in deepwater) that have been sanctioned in the 2010 – 2014 high oil price world.

New oil compensating for field decline is not sustainable, however. Hardly any new major developments have been sanctioned in 2015 and the first half of 2016. Over the coming years new oil from projects currently being built is gradually decreasing from 3.0 million barrels per day in 2016 to a much lower level in the early 2020’s (exactly how low will depend on when the sanctioning of new developments will resume). For 2017, a similar level of field decline (compared to 2016) is already expected to outstrip new developments by about 1.2 million barrels / day.


The reduction in US shale oil production is kicking in, finally

I have chosen to include a figure from a Seeking Alpha paper rather than the well known EIA figures that only give production up to the present day. Obviously the prediction beyond mid 2016 depends on future oil price (the predicted further decline is in the middle of the range for a number of forecasts from different organizations).

Oil price rise paper fig2

The time it takes for US shale oil production to respond to the low oil price oil world is much longer than often assumed. It took close to a year before peak production was reached; it took close to another year before a steady reduction (per month) of up to 100,000 barrels / day was reached. US shale oil can not take on the role of a short term swing producer (as Saudi Arabia used to do). It cannot do so timewise (it takes two years to fully respond); it cannot do so volumewise (changes in US shale oil production being too small a fraction of changes in global supply). It does play an important role, as part of a complex global oil supply system.

A shakeout is taking place in the US shale oil world with increased focus on the best plays and the best sweetspots within these plays. The Permian is emerging as the dominant play in shale oil, in the same way as the Marcellus has emerged as the dominant play in shale gas.


50 dollar per barrel is too low to be sustainable

The major international consultancy firms cover all parts of the energy business. Rystad Energy, a small independent Norwegian consultancy firm, primarily focuses on one part of the business only: maintaining a state of the art database of all oil fields (plus potential developments with timelines and oil prices needed for project sanction) on a global basis. This enables them to model future oil supply for different price scenarios. In this important niche they have become a world leader.

The figure below gives some these scenarios. These integrated models combine shale oil production, conventional field decline and new conventional developments (as well as more secondary processes such as exploration, end of field life and project delays). The gradual decrease of global oil supply in a constant 50 dollar per barrel scenario is primarily due to the combination of the continuation of significant mature field decline and the gradual decrease of oil from new developments over the coming years.

Oil price rise paper fig3

Unless more dramatic cost reductions materialize, these models imply that a long term price of the order of 70 – 90 dollar per barrel is needed to generate sufficient supply, anywhere near expected demand. The reason is simple: it is at this price level that many projects, of a different nature (onshore, shallow offshore, deepwater and shale oil), become sufficiently profitable to go ahead. Lower prices will eventually result in undersupply; higher prices will eventually result in oversupply (regardless of oil demand continuing to increase at its current rate or reaching a plateau).


Oil demand: India is taking over the role of China as a growth engine

In the meantime oil demand continues to stubbornly grow each year, at a rate of about 1.5 million barrels / day. So far any increase in efficiencies or renewables is more than offset by increasing demand in non-OECD countries. The populations of China and India (about 1.4 billion and 1.3 billion respectively) are so large that what happens in these countries simply matters most.

As the growth in Chinese oil demand abates it seems that India is taking over China’s role as the key country for oil demand growth in Asia. A recent study of the Oxford Institute for Energy Studies paints a breathtaking picture of a country where manufacturing and car ownership (and hence oil demand) are about to explode. Last year India’s oil demand grew by 0.3 billion barrels / year (compared to an average of about 0.1 – 0.15 billion barrels / year over the last decade). India is now in the position where China was about 15 years ago.

Oil price rise paper fig4

Even if India’s phase of rapid economic growth would be characterized by a greater focus on renewables this would be more of an issue for coal and gas than for oil.

One day the energy transition will take off in earnest and peak oil demand will be reached. But it will come at a slower rate than the response of oil supply to changes in oil price or changes in oil demand. The energy transition will lead to a reduction in volumes but not (necessarily) to a reduction in price. For an oil company volumes matter. But price matters much, much more.











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The ill-fated gas strategy of the majors


Major international oil companies have gradually shifted focus towards gas; to the extent that they are now sometimes jokingly referred to as Big Gas rather than Big Oil. For companies like Shell or BP gas now comprises more than 50 % of their total production.

Around 2010 this shift to gas still appeared to be very attractive. An expectation of continued high prices and demand growth (in particular in SE Asia) resulted in project sanction for a number of LNG projects, mostly in Australia. The 2011 IEA report “Are we entering a golden age of gas?” reflected the industry thinking at the time. The question mark in the title of the report was not taken too seriously; the rest of the report was.

To some extent this was done out of necessity rather than out of choice; replacing oil reserves had become increasingly difficult. Gas reserves are more accessible and have a wider global distribution. Cleaner gas was expected to take away market share from coal due to environmental concerns. As a transition fuel it should allow the majors to continue to grow without having to dramatically change their business model.

The strategy to move away from oil has now run into problems. Gas demand forecasts have been reduced. The onset of gas oversupply resulted in a dramatic drop in Asian gas spot prices in 2014. The subsequent, unrelated, drop in oil prices (resulting in lower gas prices for gas sold on oil-indexed contracts) exacerbated the situation for gas producers. At the same time a number of LNG projects, which have experienced large cost overruns, are about to come on the market. For the coming years the supply demand balance for gas and LNG looks worse than it does for oil.

In addition to this typical boom and bust cycle (be it one with what now looks like a prolonged bust) there are a number of more fundamental reasons why I feel that gas (and in particular high cost LNG) is systematically less profitable than oil and why the strategy of the majors to increasingly focus on gas is ill-fated:

  • Gas is a global free market; oil is not (and hence oil trades at a premium)
  • Gas is expensive to transport. Gas transport cost is often higher than the cost of feed in gas
  • Gas faces stronger competition than oil
  • Shale gas is a stronger competitor to gas than shale oil to oil


Gas is a global free market, oil is not.

Oil prices are higher than what they would be in a global free market. OPEC may be an organization whose members are often not able to reach an agreement but even a poorly functioning cartel is better for oil prices than no cartel.

Low cost Middle East producers are not producing to their full geological potential, whether due to political instability or due to a policy to maximize revenue rather than volume in the long term. As a result their reserves over production ratios are relatively high. Additional oil can still be developed in a country like Saudi Arabia at a cost way below that of deepwater oil or shale oil. They chose not to do so as gaining a substantial amount of market share will result in a much longer period of low oil prices than merely defending market share.

For gas, there is no such thing as a gas OPEC. Russia may not produce gas to its full potential but its role in gas markets is a far cry from the role that Saudi Arabia has played in oil markets for decades. The painful last 2 years in oil markets are the long term normal for gas markets.

Gas transport is expensive (especially when it requires liquefaction), oil transport is cheap

Due to its low energy density, gas is much more expensive to transport than other fossil fuels. Transport of gas requires pipelines (for shorter distances) or liquefaction (for longer distances). It is especially LNG that incurs high costs. Only 30 % of LNG cost is related to feed-in gas; the bulk of the cost is related to liquefaction, transport and regasification. The total cost of transporting gas in the LNG chain is at least twice the cost of transporting via pipeline.

In any country where sufficient other sources of gas are available (whether conventional or unconventional) that can be transported by pipeline LNG faces an uphill battle. In Europe, US sourced LNG will have difficulty competing with lower cost Russian gas. In China, Australian sourced LNG will have to compete with Russian sourced gas and (in future) with locally sourced shale gas. LNG is the high cost gas that faces the most pain in periods of oversupply and low gas prices (equivalent to oil sands or Arctic oil in the world of oil). It used to be profitable – at a time when it functioned as a niche gas supplier to countries (e.g., Japan) that had no alternative options.

Gas faces stronger competition than oil

The most important use for oil is transport. Alternatives for oil are less readily available in the short term. Even for light vehicles a transition to electric vehicles will take considerable time. It remains to be seen if (and when) the use of electric vehicles can compensate for increased road transport on a global basis. Decades of increased fuel efficiency, for any form of transport, have as yet not resulted in peak oil demand. For heavy vehicles, airplanes and shipping a transition is even more difficult.

The most important use for gas is power generation, where coal and renewables are strong competitors. The low cost of coal remains a strong advantage, limiting the rate at which especially non OECD countries will move away from coal. Reduced costs and climate concerns result in renewables now making significant inroads – which is more of a concern for gas than for oil.

The only place where gas has a high and increasing share in power generation is the US. This is solely due to low cost shale gas – which does not help the majors in any way. In Europe gas is being squeezed in between coal (which still enjoys significant political support in Eastern Europe) and renewables. European gas demand is 20 % lower than what it was a decade ago.

Countries like China and India have so far chosen cheap coal for the bulk of its power generation. By now, should  they want to start reducing the share of coal, they may move straight to renewables, bypassing gas. The IEA now expects gas to be responsible for only 8 % of Chinese power generation in 2040, up from the current 4 % but still way below a global average of about 23 %. Gas (and especially high cost imported LNG) is simply not the best compromise between cost, emissions and energy security for a country like China.

The majors are not making much progress in selling gas as a transition fuel. It is cleaner than coal and yet it remains a fossil fuel and methane emissions are subject to increasing public scrutiny.

Shale gas is a stronger competitor to gas than shale oil to oil

The BP long term scenarios have shale gas providing for about 25 % of the total gas supply on a global basis in 2035. Shale oil is only expected to provide for about 10 % of the total oil supply by that time. Other scenarios, such as those provided by the IEA, paint a similar picture.

The situation in the US, the only place where shale oil and gas are mature industries, provides the background for this. US shale gas is firmly established at the lower end of a gas cost curve. Since 2009, when shale gas took off in earnest, it has completely outcompeted conventional gas in the US. Shale oil, on the other hand, faces more of a struggle. Shale oil projects have a significant cost range but on average US shale oil is situated in the middle of the global oil cost curve.

Given the knowledge and efficiency of the US oil (service) industry any non US shale oil will be at a higher cost (and will struggle to reach the level of activity needed to bring down costs and establish sweet spots). Long term scenarios like those created by BP or the IEA expect non US shale gas to have a higher chance to take off than non US shale oil. For any place in the world where shale gas can overcome the technical issues in the early phase as well as public acceptance issues it may outcompete conventional gas (and in particular high cost LNG) as it has done in the US. This may be unlikely to happen in Europe but has a real chance of happening in China or Argentina.

The current LNG oversupply is more severe than the current oil oversupply

 For oil, the difference between supply and demand over the last two years has not exceeded 2 million barrels / day (close to 2% of the total production). By now (June 2016) supply and demand are starting to approach a balanced situation. In anticipation of a further reduction of supply (related to the investment cuts over the last two years), oil prices have started to pick up and the lowest prices seems to be behind us.

For LNG, the length and intensity of the bust period of low prices is expected to be much more severe. By 2014, a well supplied LNG market became a buyer’s market, resulting in a significant drop in e.g. Asian spot prices in 2014. What is the most worrisome at the moment is the number of LNG projects that are now coming on the market. Global LNG exports are increasing from 233 m tonnes (2014) to 306 m tonnes (2016). The bulk of this increase comes from Australian projects – all destined for Asian markets that are at this moment hardly growing (by about 2 % per year only – much less than foreseen 5 – 10 years ago when these projects were sanctioned). This oversupply is of such magnitude that it is likely to lead to a prolonged period, at least to 2020, of LNG oversupply and low prices. Following large costs overruns, a recent Australian LNG project such as Gorgon runs the risk of becoming one of the worst projects from a financial point of view in the oil and gas industry since a long time. US LNG projects are having a significant cost advantage compared to greenfield Australian projects due to lower construction costs and lower costs of feed in gas (more than compensating for longer transport); with e.g. Japan delivery costs estimated to be about $ 11 / MMBtu versus $ 14.5 / MMBtu.

For the future, much will depend on how much output has been tied to the oil price (and of course how oil prices will evolve). In the present world of low oil prices gas spot prices tend to be relatively close to those of long term contracts. I would expect the outlook for oil prices to be better than that of LNG spot prices. More than 75 percent of all Asian gas import are priced at levels contractually linked to oil prices (versus less than 50 percent of European gas). In the long term there is a tendency to move away from oil linked prices to spot prices or hybrid pricing. At this stage Asian consumers are reluctant to sign any new oil-indexed NLG contracts. Part of the contracts that are being signed go to portfolio players rather than destination specific end users.

Europe is unlikely to absorb excess LNG on a significant scale. Gazprom is unlikely to cede market share. As a low cost producer they can undercut on price and they have significant spare capacity (cost levels of about $ 3.5 / MMBtu for existing Russian spare capacity, $ 5.5 / MMBtu for incremental Russian capacity versus approx $ 8 – 10 / MMBtu for US LNG). European LNG needs strong political support (for environmental or energy security concerns) in order to be successful.


Concluding remarks

In the long run, gas seems to be systematically less profitable than oil. In the short term, the current low LNG prices are expected to last a lot longer than the current low oil prices. In hindsight the majors would have been better off accepting a shrinking business with a more limited focus on gas and a much more limited focus on high cost LNG.

For a different perspective (but arriving at quite similar conclusions) I would recommend Karel Beckman’s paper on the 2015 World Gas conference. It contains some interesting observations on the oil and gas industry’s groupthink.


Gas paper 21


Gas paper 22

Gas paper 23


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Saudi Arabia needs realism – not a 2030 vision

The recently published economic reform plan for Saudi Arabia, Vision 2030, is heavy on aspirations and light on ways to achieve them. It is completely unrealistic. As for other recent bold initiatives (e.g. the Saudi intervention in Yemen), it should be seen in the light of Mohammed bin Salmans grab for power. The deputy crown prince is currently the de facto ruler of the country but has a limited time span to solidify his power base, given the frail health of his father the king.

A country unlike any other

Saudi Arabia plays a pivotal role in the world of energy. Over 10 % of global oil production originates from Saudi Arabia and it possesses a much larger share of global oil reserves. It’s spare capacity implies that it can (but not necessarily will) act as a short term swing producer. It’s oil policy has a key influence on the oil price – as was demonstrated once more in 2014 when it decided to defend market share rather than price.

It is a country unlike any other. Absolute power resides with the Al Saud royal family that has by now grown to include thousands of princes. The country’s name is derived from the family name – not the other way around. Oil is virtually its sole source of income in spite of decades of official policy to diversify.

For its security it relies on two pillars: oil money buying internal and external support as well as the Wahhabi religious establishment, legitimising the Al Saud regime. Both these pillars are under threat. No one knows how long the global energy transition will take but it has become increasingly clear that relying solely on oil money is unsustainable. The measures enforced by the religious establishment (e.g., women not allowed to drive) are becoming an increasingly heavy price to pay for their support.


The issues are overwhelming and threaten to destabilize the country in the long term

Culturally, Saudis are not being asked to be competent or successful. They are asked to comply; to their family, tribe, religion, the Al Saud regime, and to their husbands or father / brothers (if they have the bad fortune to be female). An excellent overview of Saudi society can be found in a recent book by Paul Aarts and Carolien Roelants: Saudi Arabia: a kingdom in peril.

Saudis have got used to handouts, whether it is the form of easy government jobs or subsidies. A large public sector has a workforce that is about 90 % Saudi. Its inefficiency is legendary. A much smaller private sector (with a workforce that is about 10 % Saudi) offers much lower wages, has a better record regarding efficiency, but is very much reliant on government contracts.

A fundamentalist religious force has traditionally been in charge of education. Not only does it do a poor job in preparing students for the labour market but it also instils a deep distrust in the outside world.

A religious division exists between the Sunni majority and the Shiites (about 15 % of the population, living primarily in the oil-rich eastern part of the country). The government deeply distrusts the Shiites and treats them as second class citizens. Many government jobs are out of reach for them.

Geopolitically, the country is becoming increasingly isolated. Upon the death of king Abdullah caution has been thrown into the wind. The country now has difficulty disengaging itself from an ill fated military intervention in Yemen. It sees its influence in the Arab world diminishing whilst its main competitor (Iran) is increasing its influence now that it is coming out of a prolonged period of isolation.

The special relationship with the US has been eroded. The US is gradually moving towards energy independence and is increasingly reluctant to back a fundamentalist regime. They will not forget that most of the 9/11 hijackers were Saudi and are only too well aware of Saudi efforts to export Wahhabism. “It’s complicated” was Obama’s answer to the Australian prime minister asking: “aren’t the Saudis your friends”? The Saudi government has been taken aback by the Iran nuclear agreement, the Obama administration’s lack of support for their long time Egypt ally and their limited support for regime change in Syria. They feel the US lacks an in-depth understanding of the Middle East and does not appreciate the magnitude of the threat of the Shiites and Iran to Saudi Arabia.

Economically, the country is not competitive in any industry, except for oil or industries (petrochemicals, metal processing) that benefit from cheap oil and power.

In this rentier state, handouts buy passivity rather than loyalty or gratitude. In the long run, the size of the pie is getting smaller whilst the population grows. It is estimated that 25 % of the population is living in poverty. The middle class is struggling. House prices are high and rising. Saudi graduates, unless they have good connections, are either unemployed or employed in meaningless, not very well paid government jobs. They live in a prison – but one that has full internet access. A struggling middle class and mass youth unemployment rather than jet setting superrich princes is increasingly becoming the image of Saudi Arabia.

It is the lack of coherence within the country that should be the most worrying to the Saudi rulers and most threatening to the status quo. Empires tend to fall due to the rot from within. The most dangerous moment will be when reforms are being implemented, after a long period of stagnation and oppression.


Vision 2030 does not stand a chance

Vision 2030 is the latest bold initiative from deputy crown prince Mohammed bin Salman (universally known as MbS). The combination of sweeping aspirations and the complete lack of discussion on how these aspirations are to be met is mind boggling. No consideration whatsoever is given on the reasons why earlier initiatives for economic reform and to diversify from oil have failed.

Among the aspirations are:

– To close the gap between education and the requirements of the job market

– To lower the rate of unemployment to 7 % by 2030

– To establish a thriving manufacturing industry, including a defense industry that can be responsible for over 50 % of military equipment spending by 2030

– To create a tourism and leisure industry of the highest international standards

– Subsidies for fuel, power and water to be eliminated

The entire document is based on a December 2015 McKinsey report: Saudi Arabia – Beyond oil. A study that looks at Saudi Arabia from an economic angle without consideration for the cultural and religious constraints. A study that looks at the country in the way that McKinsey looks at a western company that has issues with its business model.

How realistic is it to expect that a complex military industry can be built up in a little over 10 years? How realistic is to expect tourists to come to a country where alcohol is prohibited? Do they really expect a population that has lived in a rentier state for decades to change their behaviour overnight?

At least they have given some thought on how to fund these new industries: by selling a part of Saudi Aramco, probably the only Saudi enterprise that does perform to a level that is anywhere near to western standards. Have they really thought through the detailed disclosures required for such a listing? The listing of the company will be a feast for consultants and banks but is it really in the interest of the country?

Surely the fundamental issues need to be addressed. But not by such an unrealistic plan that is heavy on aspirations and light on ways to achieve them.

This country has been singularly uncompetitive in any non-oil related industry. It needs to be changed with a stepwise approach, starting with a realistic assessment of what is possible in the current situation rather than a grand vision of the future. Allowing women to drive, greatly helping their participation in the economy, would be much more beneficial than all these grand plans.

Perhaps a prince with a bachelor degree in law at King Saud University can be forgiven for thinking that he can change a country in the way that he can implement change in his royal household: by ordering it. But the McKinsey consultants should know that such a plan cannot work and should do more to justify their royal fees.


MbS’s grab for power may destabilize the country in the short term

MbS’s position as deputy crown prince is solely based on him being the favourite son of the king. His father is over 80, in poor health and reported to be in the early stages of dementia. MbS has a short window of opportunity to solidify his power base. He reaches out, over existing power structures, to a young population in a bid to become too popular to be deposed.

Since that he became deputy crown prince in April 2015 he is seen as the de facto ruler of the country. He is now minister of defence and chairman of the council for Economic and Development Affairs. But most importantly he is chief of the royal court, controlling all access to the king.

He has initiated a number of bold initiatives:

– the war in neighbouring Yemen, which has now become a stalemate. Whilst intense aerial bombardments have destroyed the country’s infrastructure and have brought misery to its population, a conclusion to the conflict is not anywhere near.

– the increased oppression of the Shiite minority, culminating in the execution of 47 Shiites, including one of their religious leaders (sheikh Nimr al-Nimr). What purpose does this serve apart from placating Wahhabi fundamentalists?

– the Vision 2030 plan for economic reform and the planned partial sale of Saudi Aramco.

Externally he has put the country on a collision course with its main regional rival Iran. Internally he has put himself on a collision course with established Saudi power structures such as the ministry of the interior and its security services (run by crown prince Mohammed bin Nayed, generally referred to as MbN).

MbN is currently taking a low profile and biding his time. Other parts of the royal family are reported to be deeply unhappy about the current developments.

Whereas fundamentals may destabilise the country in the long term (and this may be unavoidable), MbS’s grab for power and associated rash policies may destabilise it in the short term (and this is avoidable).

Saudi Arabia deserves better than Vision 2030. The fundamental issues need to be addressed – in a realistic way with achievable targets. Reducing the current dependency on oil and emulating Dubai will take decades, not years.

Libya style chaos with Wahhabi fundamentalists, Shiites, a secular opposition and remnants of the Al Saud regime all fighting each other is still unlikely but it is a more realistic vision than the Vision 2030 mirage.


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An analysis of Bakken production

Jilles van den Beukel and Enno Peters

Every month the EIA produces an update of US tight oil and shale gas production. For each major play, the key figures are the total production and the added new well oil production per rig. In this paper we try to analyse and better understand these figures, focusing on the new well oil production per rig for the Bakken.

Whilst the increase in Bakken production to over a million barrels/day is impressive (at the least), we find the increase in the added new well oil production per rig (from about 100 to over 700 barrels/day) the most impressive – and intriguing. If the oil production resulting from a month of drilling can increase by such an amount over a period of 10 years (and if oil in place figures for a single play like the Bakken indeed run in the tens or hundreds of billion barrels) then this seems to carry a great promise for the future. What chance does OPEC have to reign in shale oil production in the long term if technology can give us these kind of productivity gains?

Bakken fig 1

But is technology the key driver? The question we have asked ourselves is: what lies behind these productivity gains? To what extent is it a better understanding of geology and the location of production sweet spots? To what extent is it technology, the ability to drill longer horizontal sections that are fracked in an increasing number of stages with larger proppant volumes? Are increasing efficiencies an important component (in other words: are we just drilling faster)? To what extent does high grading play a role (reducing drilling activities to the very best areas onlyin a low oil price environment)?

We have based this work on data available in the public domain (EIA, NDIC oil and gas division), the relatively limited amount of recent overview papers on the Bakken petroleum system that we were able to find (e.g., Grau and Sterling, 2011) and have used shaleprofile.com (the website on US shale oil production built by one of us (Enno Peters)).



The main target interval for Bakken production is the silty and dolomitic Middle Bakken. This layer is situated in between two shale layers, the Upper and Lower Bakken. These shales, with high organic content, are the source rocks for the Bakken petroleum system. Additional production comes from the Three Forks member, immediately underlying the Bakken Formation.

Hydrocarbon generation in the Upper and Lower Bakken shales has resulted in overpressure generation and fracturing (more intense in the centre of the basin and gradually decreasing towards its margins; the centre of the basin having just entered the gas generating window). This has enabled updip migration of oil through the Middle Bakken towards the basin margins. Migration has for instance been taking place towards the SW (Elm Coulee area, pinchout stratigraphic trap towards the SW), towards the E (Sanish Parshall sweetspot area, diagenetic trap towards the E) and towards the N where more intense faulting and fracturing on the Nesson anticline has enabled oil to (partially) migrate out of the Middle Bakken. As a result oil in the centre of the basin is locally generated, whereas oil in the more peripheral sweetspots tends to be a mix of locally generated and migrated oil. A close correlation exists between oil production, oil saturation (inferred from the amount of water in early production) and overpressure (Theloy and Sonnenberg, 2012).

The overall distribution of oil productivity and sweetspots is given in more detail in the figure below (from Theloy and Sonnenberg, 2013 (except for annotation)). Except for the Northern part of the Nesson Anticline, the pattern is not overly complicated and most production comes from a limited number of sizeable areas. It is clear that the location of a well has a large bearing on its expected EUR. The completion of a well will obviously have an influence as well but seems unlikely to be able to fully compensate for a lack of “good geology”.

The large number of wells that have been drilled in the Middle Bakken post 2005, and the geographic spread, ensure that the overall pattern of producing areas and sweetspots must have been well known by 2009 (and probably quite a bit earlier; by the end of 2009 about 1000 wells had been drilled). A key event was the discovery (EOG’s Parshall 1-36H well) of the Parshall area in 2006 after approximately 50 wells targeting the Middle Bakken in North Dakota had been drilled. This area is the only area that is charactised by overpressures that fall above the regional trend (thus being a seperate pressure cell) and is the most prolific sweet spot.

In short: the location of a well is of key importance to its EUR. The hydrocarbon productivity pattern was already well established by 2009. Establishing this pattern (and in particular the Parshall discovery) was key in getting the play of the ground. Increased knowledge of the hydrocarbon productivity pattern/sweet spot location cannot have been responsible, however, for the major post 2009 advances.

Bakken fig 2

 Bakken fig 3

Drilling efficiency

The figure below shows the number of North Dakota wells spud, for a 30 days period, per active rig. With the recent large drop in the number of active rigs we do not want to read too much in the large swings for the last few months.

Based on these data it is clear that there has been a large increase in drilling efficiency in the 2011-2015 period, of roughly a factor 2. This period coincided with a very high level of drilling activity with about 200 active rigs. This is not surprising; increasing levels of activity result in gaining experience and increasing efficiencies in virtually every industry.

We welcome comments on more specific reasons why drilling efficiency has increased so much. Potential components we could think of are more experience on how to drill (“learning while doing”), more sharing of best practices throughout the industry, better equipment (rigs, drilling bits, motors, etc.), less time spent on keeping producing sections exactly horizontal, less time spent on hole cleaning, increased use of batch drilling from a single location, etc.

Bakken fig 4

If we now look at the average cumulative production per Bakken well (all formations, all counties) then we interpret this figure in the following way:

– the large increase in well productivity in the early years we attibute to learning the basics on the geology and the location of sweet spots. Pre 2008, during this geology learning phase, a relatively large proportion of wells was still being drilled in what we now know to be areas of low production.

– the limited increase in well productivity post 2008 (figure below) is in striking contrast with the large increase in rig productivity post 2008 (EIA figure at the beginning of the paper). The significant increase in drilling efficiency (which does influence rig productivity but has no bearing on well quality) is the main reason for this. A large part of the increase in rig productivity post 2008 is not drilling better wells but simply drilling them faster.

Bakken fig 5

Nevertheless, the figure above does show some real increase in well productivity (post 2008) as well. In the following we want to look at potential reasons for this.


High grading vs well quality

High grading we here define as focusing on the best areas and intervals in a low oil price world. An additional component may come from keeping only the best performing rigs and crews in such an environment. Well quality we here define in a narrow sense: the well productivity for a particular area and stratigraphic interval. An increase in well quality in this narrow sense is due to technological advances (such as longer producing sections, more and larger fracs) rather than geological advances (increased knowledge on where the best producing areas are located) or high grading (focusing on sweetspots out of financial considerations). In addition, depletion may result in a decrease of well productivity if some oil of the oil in the targeted area has been produced by an existing well. It may be masked by an increase in well quality; a true decrease in well productivity (for a given interval and area) must come from depletion, however.

The figure below gives average cumulative Bakken well production for the Middle Bakken in the two counties with the best producing wells (Mountrail and McKenzie). In contrast to the previous figure (which showed production for all counties and intervals), this figure shows no systematic increase of well productivity with time. The production for a given area and interval seems to be relatively constant (if anything the data seem to suggest a slight decrease with time; more so for the long term production and less so for the initial production). This suggests that high grading is the main reason for the post 2008 increase in well productivity rather than technological advances.

Bakken fig 6

Well productivity for other individual areas shows varying results. In some cases there is an increase in well productivity over time – be it that this tends to be strongest in the earlier years and tends to be less pronounced than the increase in well productivity for all counties combined.

The final figure gives the number of wells spudded (as a fraction of the total) in the different counties. It illustrates the increasing focus on the best counties (McKenzie, Mountrail, Williams). The effect is not that pronounced, however, and we suspect that only keeping the best performing rigs also plays an important role in high grading.

 Bakken fig 7


The way we now look at the EIA figure of Bakken new well oil production per rig is given in the figure below.

Bakken fig 8

For the Bakken new oil production per active rig we see the following timeline:

  • The basics of the technology, horizontal wells and fracking, were developed in the Barnet shale in the 1990’s.
  • Subsequently, the potential of the Middle Bakken was recognised. By 2009 the overall picture of well productivity and production sweet spots was well established. A key milestone was the drilling of the 2006 EOG wells that established the Sanish Parshell sweetspot area. Up to 2009 increases in new well oil production per rig came primarily from increased knowledge on geology and sweet spot location.
  • Upon a brief interlude (2008-2010 oil price low and reduced drilling activity) the Bakken play took off in earnest. During 2011-2015 the active rig count was in excess of 200. During this period increases in new well oil production per rig came primarily from increased drilling performance.
  • During the subsequent low oil price world, starting in mid 2014, further increases in new well oil production per rig were primarily due to high grading (drilling in the most productive areas with the best performing rigs).


The road ahead

In our opinion there are no major further advances in new well oil production per rig to be expected. That is perhaps a bold call to make after 10 years during which it increased by a factor 7. Had the increases in new well oil production per rig over the last 10 years been due to technological advances (an increase in well productivity for a given area and stratigraphic interval) we would have been much more reluctant to make this call. But they are not. They are due to better geological knowledge, faster drilling and high grading. Here, we see much less scope for further improvements.

Geologically, the play is now well established. We expect drilling efficiencies to have reached its limit, upon years of high activity followed by two years of low oil prices and intense competition in the service industry. We see no scope for further high grading now that the active rig count is down to about 30. In short: we think that the Bakken shale oil industry is now as competitive as it can possibly be.

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US shale oil: boom and bust

The 2010 – 2014 rapid increase of US shale oil production to about 5.5 million b/d has been a game changer in the oil industry. Although still amounting to only a small fraction of global production, it was responsible for most of the growth in non OPEC supply during this period. The speed and magnitude of this increase was such that within a few years it disturbed the global oil supply and demand balance. In 2014 Saudi Arabia, facing a prolonged period of oversupply (also due to downward revisions of expected demand), decided it was in their best interest to defend market share and rein in high cost oil production. This resulted in the current low oil price world.

US shale oil production exploded because of a unique set of circumstances (a “perfect tailwind”). A knowledgeable and low cost service industry, extensive geological knowledge (more wells have been drilled in the US than in the rest of the world taken together), a legal and regulatory system supportive to the oil industry, a prolonged period of high oil prices and the availability of funding at attractive conditions to the industry all contributed. At present, non US shale oil production is minute compared to US shale oil production (something unlikely to change in the short term).

The aim of this paper is to give a concise overview of the US shale oil industry, from a geological as well as a financial point of view, and to describe how the industry is adapting to the current low oil price world. A red thread is that the financial state of the industry is much worse than the impressive production figures would lead us to believe.

Shale oil geology and fracking

Hydraulic fracturing (in short: fracking) is a well stimulation technique that involves the creation of fractures upon pressurising the fluid in the wellbore. Subsequently, hydrocarbons can flow through these fractures to the wellbore. First experiments took place in the US as early as 1947. Fracking of gas wells in tight sandstones was already commonplace in the US from the 1970’s onwards. For shale wells the first commercial application was pioneered by Mitchell Energy for gas production from the Barnett Shale in Texas in the 1990’s. It was only from about 2010 onwards that shale oil production took off in earnest, initially in the Bakken and later in the Eagle Ford and Permian. To this day these are the three main US shale oil provinces. Although usually referred to as shale oil, the tight (i.e. low permeability) formations that yield oil upon fracking can be mudstones, silts, dolomites or tight sands (tight oil being the more appropriate term).

Shale oil has different characteristics compared to conventional oil. Firstly, shale oil requires continuous drilling as the production of a well declines rapidly (with typically about 50 – 60 % of production during the first year of production).

Secondly, shale oil requires the drilling and fracking of many wells that are very similar in design. As with other industries that involve oft repeated processes, it has become very efficient at doing so. It is more similar to the manufacturing industry than conventional oil.

Thirdly, conventional oil is mostly about finding oil in the first place. With shale oil, it is not so much about finding oil but rather about finding those places where the oil can actually be produced at commercial rates (oil in the Bakken for instance was already discovered in the 1950’s). Within a single play the EUR (estimated ultimate recovery) per well is highly variable. The key to success is the definition of sweet spots, with systematically higher oil recovery. Even within a single sweet spot area well performance is highly variable, however. So far the industry has not been very successful in predicting sweet spots. As a result, it takes many wells before the location of sweet spots (which may be the only places where commercial production can take place) can be inferred with some confidence. Hundreds of wells are needed to properly evaluate; upon which many thousands of wells are needed to produce.

For each play, different areas have highly variable break even oil prices. For the Bakken, for instance, the break even oil price ranges from about $ 25 – 100 per barrel (at current cost levels). For the larger companies the average breakeven price currently ranges between about $ 40 and $ 70 per barrel. Ranges for the other plays are not markedly different. The best areas with a break even oil price below the early 2016 $ 30 per barrel price are very small, however (about 1 % of the total Bakken area), are already starting to deplete and could be depleted in approximately 5 – 10 years at current production rates. Intense drilling at increasingly smaller distance implies that wells increasingly interfere with each other. Within a few years further technological advances need to sufficiently lower the breakeven price in the next best areas. This is quite possible – but by no means a given.

Productivity gains

Throughout the years, the shale oil industry has seen impressive gains in efficiency and productivity. Two different sets of factors come into play here. The first set of factors relates to our increased geological knowledge (resulting in a better delineation of the most productive areas) and increased efficiencies and knowledge in drilling (longer horizontal well productive sections, faster drilling) and fracking (larger number of fracs per well, larger fracs). It seems that these factors, which should be sustainable in the long term (even in a future high oil price world), had reached a plateau by 2014.

The second set of factors relates to the current low oil price world in which companies are making an all out effort to survive. This involves a much more increased focus on the most highly productive areas (whilst suspending activities in all other areas), the continuation of these more limited activities with only the best performing rigs and fracking crews and the overall decrease of service industry costs and rig rates. The majority of advances in the last 2 years seem to come from this second set of factors. Upon a prolonged period of cut throat competition between service providers this second set now seems to have reached a plateau as well. EIA monthly drilling reports suggest that the added production per Bakken rig is about to reach a plateau.

The steep rise in US shale oil production has been a major technical achievement from what has now become a mature industry. The steep part of the learning curve seems to have been climbed. Cut throat competition between service providers over the last 2 years has significantly reduced cost. After an all out effort to survive, the US shale oil industry is now as competitive as it can possibly be (at least in the short term – even for a mature industry further technological breakthroughs in the long term cannot be ruled out).


Most US shale production comes from smaller, independent companies that lack the financial robustness of the larger companies that dominate conventional oil production. Compared to these larger companies they rely to a greater extent on bonds and asset backed lending and to a lesser extent on equity. US corporate bonds in the energy sector rapidly increased to about $ 800 bn (an increase that abruptly stopped in late 2014). The rapid increase in shale oil production would not have been possible without the easy money that was readily made available during the 2010-2014 period.

Virtually all US shale producers are currently cash flow negative. Even in the 2010 – 2014 high oil price world, however, most US shale oil producers were already cash flow negative. Apart from higher costs and lower well recoveries at the time, this was primarily caused by the money that was spent on acquiring leases and building infrastructure.

For costs, a distinction needs to be made between full cycle cost (which also includes the costs of acquiring leases) and half cycle cost (including drilling and fracking costs but excluding leases). As long as oil prices stay above half cycle costs there is an incentive to keep on drilling, in order to minimise losses.

Adapting to a low oil price world

The resilience of the US shale oil production in 2015, following the dramatic fall in oil price, has surprised many analysts. It declined later and less than expected. From a peak of 5.6 mb/d in March 2015, shale oil production had fallen by no more than 0.6 mb/d by the year end. For the main plays production has been the most resilient for the Permian and the least resilient for the Eagle Ford. No massive wave of company bankruptcies has materialised.

On the technical side, there has been an increased focus on the best producing areas. Activities in poorer producing areas have been much reduced or stopped. Rigorous cost cutting has taken place throughout the industry. A significant part of the 2015 shale oil production had been hedged (for approx 50 % of production of smaller companies, for prices anywhere in between $ 60 and 100 per barrel). Hedging contributed to over 30% of revenue in US shale oil in 2015. Hedging of 2016 production at attractive prices is much less prevalent.

For many producers, in order to minimise losses, it still makes sense to drill (as long as the oil price stays above half cycle costs). In some cases, producers are forced to drill in order to keep their leases. For some companies with lower quality assets (half cycle cost greater than oil price) it makes sense to stop operations entirely. These companies (known in the industry as “zombies“) are trying to survive without any drilling or fracking of new wells, just waiting for the oil price to recover.

The key factor in the resilience of US shale oil production has been the continuation of funding, however. No additional money is flowing into the US shale industry but the existing money has not (and cannot) been taken out. During the last round of loan extensions and associated reserves re-determinations in October 2015 banks were only able to cut funding limits by a small amount (although interest rates may have risen substantially). Bankruptcies and asset fire sales are in no one’s interest in the current low oil price world. Hence the tendency to be rather lenient regarding loan extensions. Both shale oil producers and their financiers are trying to sit out the current low oil price world. Covenants for the extension of funding are being re-negotiated with minimal publicity.

Overall the financial state of the US shale oil industry is much worse than the resilience of production would lead us to believe. Few bankruptcies have materialised so far but share prices have gone down significantly (often by as much as 90%). The yield of the Bank of America Merrill Lynch US energy high yield bond index has climbed to close to 20%. The average high yield US energy bond has slid to 56 cents of the dollar.

Easy money enabled the rise of the US shale oil industry in the 2010 – 2014 period. It kept it alive in the following low oil price world in 2015. Now, what will happen next?

Looking ahead

Oil prices have been close to $ 30 per barrel during the first two months in 2016. The short term outlook is highly uncertain. Global supply is only expected to become in line with demand in 2017/2018 as the drastic investment cuts in non shale oil take time to materially affect supply.

Oil prices this low will further contribute to making 2016 a much more difficult year for shale oil producers than 2015. Hedging at attractive prices is no longer possible. More companies will suspend activities. The drop in the rig count has picked up again and the 2016 drop in shale oil production could be as large as 1 million barrel/day.

Shale oil producers and their financiers are trying to sit out the current low oil price world – something that is becoming increasingly more difficult. Financially more robust larger oil companies and private equity are waiting for bankruptcies, looking to pick up the shale oil producers’ core assets in sweet spots at rock bottom prices (much more attractive than taking over financially distressed shale oil producers and having to pay off their debts in full).

The key question is whether the next phase of loan extensions and reserve redeterminations in April 2016 will be as lenient as the preceding one in October 2015. It is in the financiers’ interest to continue and aim for a soft landing once oil prices pick up. But will regulators let them? And even if regulators let them: will the current situation start to undermine trust in financial institutions? Bankers may stress that the importance of the energy industry has been diminished and that these loans are backed by assets. These assets are worth much less in the current low oil price world, however. Worldwide the level of debt of the energy industry stands at a record high of 2.5 tn $ (at a time that the value of assets backing these loans stands at a record low). The day of reckoning may be postponed but one day it will come.

shale oil boom and bust jpeg

shale oil boom and bust 2 jpeg



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A health check for the oil majors

The demise of the oil majors has, once again, been announced. NGO’s refer to them as slowly moving dinosaurs, sitting on stranded assets that cannot be (fully) produced. They maintain that their shares are massively overvalued and that the majors should rapidly change their business model or perish. Financial analysts are worried about high costs, future oil demand and low reserves replacement ratios. They point out that majors should prepare for an oil price that stays lower for longer rather than to keep on repeating that the current low oil prices are not sustainable. Are things really that bad for the majors?


Oil majors face a number of issues that they have been struggling with for a long time. They have lost their edge in technical knowledge to smaller companies, service companies and, to a lesser degree, to NOC’s. For “easy” oil NOC’s do not need them anymore. But also for more complex projects some NOC’s have made a lot of progress (e.g., Petrobras’ technical capabilities in deepwater). Service companies, working for many oil companies large and small, have the economies of scale to develop knowledge, software and techniques superior to that of the majors in many areas.

The majors have trouble replacing reserves. The lack of access to regions with low cost, easy to find oil has been a key issue for many years. There may be no shortage of oil in general but there is a real shortage of low cost (easy to find and cheap to develop) oil in countries outside the Middle East. In the exploration realm the oil majors’ track record is worse than that of smaller, niche exploration companies like Tullow, Anadarko or Lundin. Technical knowledge travels more easily these days. Specialised exploration geoscientists flourish better in smaller companies that focus on a particular niche than in larger, more burocratic organisations that tend to rotate their staff every few years.

Majors are gradually becoming gas producers rather than oil producers (some more so than others), given the much greater geographic spread (and resulting easier access) of gas reserves compared to oil. This seems a risky bet though. Gas is likely to be systematically less profitable than oil, given the lack of an OPEC equivalent for gas. Transport of gas requires pipelines or LNG; both of which are expensive. Only about 30% of LNG cost is related to feed in gas; with the bulk of the cost related to liquefaction, transport and regasification. Oil is primarily used for transport, for which there are no easy alternatives in the short term. Gas is primarily used for industry and electricity generation where coal and renewables are strong competitors. For oil the industry is expecting that the current low oil prices are not sustainable beyond 2017/2018 when non OPEC supply will start to drop in earnest as a result of the recent drastic investment cuts. For gas the long term price outlook is more bleak – given a likely more prolonged gas oversupply due to the number of LNG plants coming on stream now and in the coming years.

Majors are not well suited (company culture, strengths) to compete in the US shale oil / gas boom. This is all about standardisation and cut throat efficiency. It requires a different way of working than the one off, complex, large technical projects that the majors excel in. The entry hurdles for new players are relatively low (technically given an efficient and knowledgeable US service industry and financially given the access to cheap financing).

In short, majors have trouble competing with niche players (whether it is in shale oil, near end-of-field-life assets or greenfield exploration). Large new opportunities (their niche area) that are accessible to them are increasingly rare and located in increasingly difficult areas (ultra deepwater, arctic, etc).


In many of the areas where they operate the majors have been the first movers. With the biggest oil fields typically found during the early phases of exploration and with advantageous license terms dating back a long time to periods of lower prices, the majors often have a systematic advantage to later entrants. Throughout the last 20 years the majors have tended to spend a relatively large part of expenditure on existing developments rather than greenfield exploration (in contrast to smaller companies), simply because it provided them a better return on capital. The heartlands of the oil majors have given them a systematic tailwind – enabling them to better withstand periods of low oil prices and to refrain from overly ambitious and costly growth projects in times of high oil prices.

The majors’ downstream assets greatly improve their financial performance in periods of low oil prices.

The majors’ financial strength remains unsurpassed in the industry. With their low gearing and high rating they can obtain funding – when needed – at much better terms (whether to keep up dividends or make acquisitions).

The majors have the technical, financial and organisational capabilities to execute projects that are beyond the capabilities of many smaller players. This is not just about certain areas or plays (deepwater, arctic) but also about (floating) LNG or gas to liquids projects. The scope for such large scale, capital intensive, long term projects may be shrinking but it has not disappeared.

Smaller niche players indeed have made inroads on the oil majors’ turf. But have they made much money out of it? Many US shale companies have been cash flow negative for a long time. They are like house owners whose house is of substantially less value than their mortgage. They are still able to pay for their mortgage (by rigorous cost cutting or more worrisome by reducing or even stopping activities) but the shape of the shale oil industry is much worse than the still impressive production figures would lead us to believe. The rigorous capital spending procedures for the majors may have have resulted in some missed opportunities. But their financial performance has benefited and the performance of their stock has, in general, been far superior to that of smaller players in the current downturn. Oil majors are not out there to produce more oil. They are out there to make more money, in the long term. In that respect they may be more similar to OPEC than expected (with whom they have a relationship that could be described as symbiotic).


Concerns on global warming, resulting in a renewed push to reduce global CO2 emissions, limited economic growth and the long term reductions in energy intensities will all result in a downward pressure on oil demand. Limited economic growth and the reduction in energy intensities are long term trends that are relatively well established. What is less clear is to what extent climate policies following the Paris agreements will result in a reduction for oil (and fossil fuels in general) demand. To what extent will electric vehicles and energy storage take off? No reduction in the fossil fuel part of the global primary energy mix whatsoever was achieved in the last 20 years (post Kyoto). This time is likely to be different given the dramatic reduction in cost for power generation by renewables and the much increased awareness of the downsides and costs of climate change. But to what extent? The 2040 fossil fuel fraction of the global primary energy mix ranges from as low as 60% (450 scenario) to 75% (new policies) to 80% (business as usual) for different IEA scenarios.

Should the oil industry as a whole plan for 60% we may face issues with security of supply (in a world of higher oil prices and oil majors’ profits). Should the oil industry as a whole plan for 80% we may see oil prices lower for longer for real. Luckily for the oil industry their shareholders, financial analysts and NGO’s may enforce the capital discipline on them that they are less well capable of when left to themselves.

What is clear though is that the majors’ oil producing assets can be produced to the full. The production from global developed reserves falls far short from the oil demand projected for the 450 scenario. What is at risk of not being produced are undeveloped oil reserves (more so for NOC’s, less so for the majors) rather than developed reserves. It is the oil majors’ business model that is at risk in the long term; not their existing producing assets where they have made the bulk of their investments. With oil major valuations primarily based on their proved reserves (not the same as, but similar to, developed) I cannot see the case for a bubble in the valuations of the majors (or at least not a bubble caused by stranded assets). The low reserves/production ratios and the current low oil price environment are much more important for the valuation of the majors than stranded producing assets. Doubts about the longevity of the oil majors business model have been around for a long time (be it primarily driven by the majors’ lack of access to new low cost reserves, rather than by long term reductions in oil demand due to climate concerns) and have been the driving factor for relatively cautious valuations (with a relatively low value attached to possible reserves).

It is the expectation in the industry that, barring major demand shocks or geopolitical events, the current low oil prices below $50 per barrel are not sustainable in the medium term. US shale oil is likely to see a more significant drop in production in 2016 compared to 2015 but the major non OPEC supply drop will only take place in 2017/2018 and beyond, as the effect of the ongoing major investment drops in non shale oil take time to kick in. On the other hand, prices above $80 per barrel do not seem sustainable in the long term either, given the expected resulting increase in global shale oil production and lowered oil demand forecasts.

Political support for oil companies is diminishing. Although most governments realise all too well that the energy transition will take time and that a secure supply of fossil fuels is indispensable, they also know that the tolerance for pollution and risk (whether perceived or real) amongst their voters is minimal. Oil companies need not be concerned that their assets will be closed down (as happened to utility companies during the Energiewende) given the large amounts of money that oil and gas assets contribute to governments. Carbon taxes will actually be welcomed by the industry as they provide a more level playing field than subsidies and will help gas taking away market share from coal. But what about extra taxes on the profits of the oil and gas industry? In a time when oil prices and oil majors’ profits have returned to higher levels and when the adverse effects of global climate change have become more pronounced the majors may become an easy target, especially during times of economic downturns.

In general, the unpredictability of government measures (resulting in an inconsistent stop start approach) remains a risk. Massive subsidies and “leading by example” can follow CO2 pricing and “let the market do its work” in rapid succession. Different countries may make radically different choices.


The majors are adapting, although not in the way as envisaged by the NGO’s. They are not completely changing their business model. Their strengths after all are in finding and producing oil and gas. They expect oil demand is there to stay, be it at lower levels than envisaged 10 years ago. They expect the energy transition to take the better part of this century rather than the 25 years as envisaged by some NGO’s. They expect demand for fossil fuels to continue shifting away from the developed world. The new engineers and geophysicists they hire are increasingly from India or China.

They are, and will continue to be, more reluctant to go ahead with new developments, focusing on developments at the lower end of the cost curve. The ability to manage cost and a flawless project execution are more critical. Given the larger uncertainties on future oil price and demand they are more reluctant to go ahead with large, complex projects with long lead times. No more Kashagans! Every major has been going through a ranking process of potential developments and only the best of deepwater (e.g., Appomattox) and the best of non US shale oil (e.g., Vaca Muerta) and hardly any oil sands projects have survived; at least in the short term.

They are looking into acquisitions. Their financial strength and the much reduced share prices of smaller and midsize companies enables them to cherry pick, aiming for companies that have existing or new developments at the lower end of the cost curve. This is the time to address the low reserves replacement ratios from the last 10 years. Again, every major will have gone through a ranking process. At this stage companies like Tullow and Lundin look like takeover targets. At the moment, Middle East and South East Asian NOC’s do not seem to be in the market; a situation that is unlikely to last forever. The main challenge is timing. No one wants to blink too early as Shell did in the BG takeover (how easy to say in hindsight). No one wants to finance acquisitions by having to sell assets in the current market.

They will continue to promote gas and aim at gas taking away market share from coal; if necessary by promoting carbon pricing. If it is just about reducing emissions in the short term, replacing coal by gas is a much more cost efficient way than many of the measures currently put in place by governments. The dilemma for governments and NGO’s is whether to accept gas as a transition fuel. The dilemma for the majors is whether they want to get serious about CCS, not waiting for government subsidies but funding a much more substantial activity level (and hoping that the subsequent learning will bring down costs to an acceptable level – with a highly uncertain chance of success).

In conclusion

So basically majors are increasingly going into sunset mode. They will accept a gradual decline of production and safeguard their profitability by being very disciplined in spending capital. They should keep on doing what they are good at – within the limits of the law. But it will be in a more difficult environment with a long term downward pressure on oil demand and oil price. Majors have a long history of adapting. They have seen many of their assets nationalised throughout their history. They have seen the loss of control over the industry in the 1970’s and the following dramatic swings in the oil price. But their reason for being, the world’s demand for oil and gas, is still there. Their niche may be shrinking but it is not about to disappear. The majors may have entered old age but they are not dead yet.


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Keep your eyes on the stars and your feet on the ground

I can see a number of reasons why it’s turning out so difficult to reduce worldwide CO2 emissions.

Firstly, lower than expected demand for a commodity results in lower prices making a further reduction in demand more difficult. Coal is a clear example. Coal producers have for a long time overestimated demand resulting in a decade of overinvestment. Resulting low coal prices led to increasing demand (be it not as high as initially expected) and an increase in the coal market share of global primary energy (in spite of it being the most polluting fossil fuel). This is a global phenomenon except for the U.S. where abundant low cost shale gas has taken away market share from coal.

Secondly, the benefits of CO2 emission reductions are global and long term; the associated costs are local and are incurred now. This implies that there is always a strong incentive to cheat.

Thirdly, oil and gas producing countries have a strong interest in the continued use of fossil fuels and they will continue promoting and subsidising them. Energy intensive industries are migrating to low cost energy countries. A significant and growing part of Saudi Arabia’s oil production is used for local industries (petrochemicals, metal processing), generating a second income stream in addition to oil production. To some extent this also applies to the U.S. where a rapid increase in low cost shale gas production has resulted in a long term reduction of electricity prices; a significant competitive advantage for any U.S. energy intensive industry.

Fourthly, the benefits of economic progress (with an associated energy consumption increase) for undeveloped countries are real. Global warming concerns people in undeveloped countries as well but when asked to rank issues it comes out last (way below security, food, education, health and energy and transport related issues). In fact it comes out near the bottom of the list in most countries except for the most highly developed ones.

What should we do?

Let’s be realistic. In all likelihood the emission reductions needed to limit CO2 levels to those in line with the COP21 targets will not be met. It is easier to promise than to deliver – especially if deliverance is scheduled so far ahead in the future. In spite of all earlier efforts the shares of fossil fuels and renewables (hydro, wind, solar) in the global primary energy mix have remained virtually unchanged over the last 20 years (at approximately 80% and 3% respectively).

So what can we do? Global warming is too important to put all our eggs in one basket. At this early stage it is not clear which technologies will be the most successful in coping with it. There are limits to the extent to which renewables can easily replace fossil fuels. So let us subsidise technologies without being dogmatic. Whether it is solar, wind, CCS, “new” nuclear, electric or hydrogen vehicles, energy storage, ways of increasing efficiencies of conventional technologies, etc. Learning and economies of scale will reduce cost, as they have most successfully done for solar.

Let us find the best compromise between reducing emissions, security of supply and affordability. Just aiming at reducing emissions, without any consideration of the ability of our industries to compete on a global basis, may result in a lack of public support for necessary measures (doing more harm than good in the long term).

Many people in the oil and gas industry look at the Energiewende as a total failure, given that it did not make electricity generation in Germany any cleaner or more affordable (and did not make its supply any safer). The continued operation of lignite mines and the closing down of nuclear reactors that generated clean, safe and cheap (reactors being paid for a long time ago) electricity is indeed difficult to defend. It can only be understood as a necessary measure to obtain support for the Energiewende, given the German political landscape and lack of public support for nuclear power.

But the Energiewende did result in a staggering demand growth for solar panels, greatly contributing to a reduction in cost (long term cost reduction for every doubling of solar capacity has been an impressive 19%, vs. 7% for wind). This is a real and substantial long term achievement. Unsubsidised utility scale solar and wind generation of electricity is now becoming cost competitive under many conditions. There is no stronger incentive than having a clean(er) alternative that is actually cheaper.

Having said this, at this early stage, where the combined share of renewables of the global primary energy supply is still minimal, it is not about cranking it up as quickly as possible by a few percent; it is rather about developing and perfecting techniques that can bring it up to much higher levels in a cost efficient way in the long term.

We may also have to take more drastic measures. Note that whilst emissions in many developed countries have started to decline, this has more to do with a shift of industries towards undeveloped countries than an actual decline of emissions on a global basis. From 1990 to 2005 Britain’s CO2 emissions reduced by 15%, the CO2 emitted by producing all the products consumed in Britain increased by 19% however. The increasing divergence between “produced”and “consumed” CO2 is a Europe wide phenomenon (be it that for the EU 27 as a whole it tends to be less pronounced than in Britain). Given the unlikelihood of global carbon taxes we may have to resort to border carbon taxation (taxing goods imported from countries without carbon taxes). It is of no benefit to the climate if CO2 emissions in developed countries are reduced because industry is being moved to undeveloped countries.

In fact, we may well have to face the fact that the recent Paris agreements have only a chance of reaching their objectives if citizens accept that this will involve a drastic change of lifestyle. Reducing CO2 emissions in electricity generation is relatively easy (up to a certain level at least, pending advances in energy storage). For road transport it is already more difficult. Electric vehicles will take off but for mass scale usage we may well run into restrictions on the availability of certain commodities. Flying and a substantial part of industry usage offers even less scope for CO2 emission reductions. This is not about putting a few solar panels on the roof. This is about not eating meat, not flying and driving substantially less. Governments should be clear about that.


So let us do all we can without being dogmatic. This includes looking at geoengineering solutions, controversial though they may be.

Out of many geoengineering options albedo enhancement by creating a sulphate aerosol in the stratosphere seems by far the most technically and financially feasible. The limited costs imply that it will be well within reach of many countries. The seminal 2006 paper by Noble prize winner Paul Crutzen presents the case for albedo enhancement and while explicitly advocating more research I feel the implicit message was to warn people that this is the future if we do not start to reduce emissions drastically (and stir governments into action on reducing emissions – by far his preferred road ahead). An overview of geoengineering options and recent developments is given in a book by Oliver Morton (one of the Guardian’s best science books of 2015).

We are already doing this: the cooling effect of human aerosol pollution is real, its magnitude much more uncertain than the warming due to the CO2 greenhouse effect but our best estimate is that it currently cancels close to half of it (it is a much more short term effect though due to the much shorter atmospheric residence times of these aerosols compared to CO2). The recent acceleration of global warming is likely to be related to the reduction of aerosol pollution on a global basis (whereas the near constant global average temperature in the 1940 – 1970 period seems related to the rapid increase of aerosol pollution). Past major volcano eruptions have been an intermittent, natural, cause for stratospheric aerosols and associated cooling over 1 – 2 year periods. The adverse health effects of a stratospheric sulphate aerosol needed to counteract (a fraction of) greenhouse gas induced warming are minimal compared to those caused by the ongoing human created sulphate aerosols residing at much lower altitude.

The longer that we see rising CO2 emissions, people in developed countries not really changing lifestyle, people in developing countries moving to the lifestyle of people in developed countries and limited progress on CCS or nuclear power, the more likely that we will need to resort to geoengineering. If only to buy us more time for fundamental solutions.

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