Energy Post papers

ONS: a conference report

Energy Post, 13-9-2018

How does the industry cope with the energy transition? How do increased geopolitical uncertainties influence oil markets? Does exploration still have a future? How do we finance the new oil and gas fields needed to satisfy demand now that banks and institutional investors are becoming more reluctant to invest in fossil fuels? These were some of the topics discussed during the recent ONS conference. Independent energyanalyst Jilles van den Beukel gives a conference report.

The 2018 edition of the ONS (Offshore Northern Seas) took place in Stavanger from August 27 to 29. What once started as a small conference aimed at the offshore industry in the North Sea has now become the largest oil and gas conference in Europe. Over 3600 people attended the conference; about 70,000 people visited the exhibition.

Eldar Saetre from Equinor announced Phase 2 of Johan Sverdrup which will take production of Europe’s largest new oil field to 660,000 b/d. Patrick Pouyanné confirmed that Total would not be investing in US shale. Scott Sheffield from Pioneer (“I started this company at 30 million, I am leaving it at 30 billion”) touted that his company still had an inventory of tier 1 well locations in the Permian for the next 20 years. At least as interesting as the CEO’s presentations were the panel discussions. The following gives an overview of the most interesting ones.

The energy transition: skepticism on the attractiveness of renewables. Very few people here doubted that the transition to a low carbon world will come and will fundamentally change the world of oil and gas. But how soon – and how to react? So far the demand for oil is still growing at about 1,5% per year (for gas this is about 3%).

Valentina Kretzschmar from WoodMackenzie showed that there is a wide range of strategies that oil and gas companies have adopted so far in response to the energy transition. Some smaller players like Engie and Ørsted are making a complete and rapid transition to low carbon fuels. For the majors oil and gas has so far remained their core business. But some of them are checking in into the energy transition. Front runners Total, Shell and Equinor are investing a few percent of their total investments into renewables and the electricity value chain. Equinor stated that by 2020 25% of their research budget is expected to go into renewables. They are aiming to build a profitable and substantial renewables business. Chevron and ExxonMobil have not followed suit and are limiting their efforts to reducing costs and reducing the environmental footprint of their core oil and gas business.

Companies like Saudi Aramco or Russian companies like Lukoil and Rosneft are assuming that oil and gas remain their core business in the long term. Their response to the energy transition has been to increase the security of offtake by increasing exposure to refining and petrochemicals. For Saudi Arabia and Russia as a whole this is accompanied by a larger focus on energy intensive industries like metal processing and airlines.

Throughout the discussions considerable skepticism emerged on the attractiveness of renewables to oil and gas companies. Rates of return for recent conventional oil and gas projects were found to be substantially higher than those of recent projects in renewables in a WoodMackenzie study. Oil and gas companies are relatively small players in renewables (owning less than 2% of global wind and solar capacity) and do not seem to have a competitive edge on other players. Many feel that the investments in renewables by the European majors are basically green washing; required to keep their investors and stakeholders happy. It was also felt that this strategy is only feasible as long as these investments remain a relatively small fraction of total investments. It was suggested that some oil and gas companies may at some stage split into a part focusing on renewables (attractive to ethical investors) and a part focusing on oil and gas only.

Financing: a shift from banks to private equity.  Financing for small niche companies that specialize in exploration has become extremely difficult according to Jeremy Low from BMO Capital Markets. The old model of funding 10 exploration companies in the hope of 1 big discovery and 2 or 3 smaller ones is no longer a tenable strategy. Investors have become more risk averse and want short term returns.

Banks (and in particular European banks) have become more reluctant to invest in oil and gas in general (due to pressure from shareholders and other stakeholders). Private equity is more forthcoming but has a clear preference for financing companies with a lower risk profile that specialize in buying and operating producing fields. Should oil prices continue to rise then IPO’s for some of the recently established North Sea companies like Chrysaor become a distinct possibility.

In general there is a mismatch between the time horizon of investors (a few years) and that of oil and gas companies (at least a decade). Investors want high dividends, share buybacks ánd limited investments. But how sustainable are the production and dividends of the majors in the long term, given their current low investments, wondered Ben Monaghan from PJT Partners? That proved reserves over production ratios for the majors have been falling and are near historic lows is currently ignored by the markets. ExxonMobil, the major with the highest reserves over production ratio that is making relatively large investments to secure future production, is currently distinctly out of favor with investors.

There was amazement among the financing panel members on the willingness to invest so much money in US shale. US investors in shale are risk on and have a high belief in technological progress in the industry – in marked contrast to investors in oil and gas in other parts of the world.

Exploration: deepwater is back.  Over the last two years the attractiveness of deepwater with respect to US shale has improved. Break even costs of new deepwater developments are now substantially below those of US shale. The conventional and deepwater service industry still has significant overcapacity and is not yet in a position to start raising prices. The service industry for US shale, on the other hand, is operating close to capacity and has regained pricing power.

With its longer cycle time, it has taken more time for new deepwater developments to reach lower cost levels. Deepwater is also high grading, with new developments focusing on the most attractive areas from a geological, cost and regulation (e.g. local content measures) point of view. This currently implies a greater focus on the Americas (Gulf of Mexico, Guyana and Brazil) and a reduced focus on West Africa (Nigeria and Angola).

The subsalt play in deepwater Brazil will be a hotspot for exploration over the coming years. All majors have acquired licenses here since Brazil opened up and Petrobras operatorship is no longer required by law. Over the past year they have done their homework and worked up the best drillworthy prospects. In the global ranking of their prospects shown by Equinor (not something that major oil companies often show in public) the Brazil deepwater prospects stood head and shoulders above all other prospects. “Drilling those prospects will be the most exciting time of my career” said Tim Dodson, Equinor’s head of Exploration.

“Geopolitics is back as a major force for oil markets” according to Helima Croft from RBR. The session on geopolitics started with a presentation by Sir John Scarlett, a former head of MI-6. Venezuela’s oil production continues to be in a downward spiral. Production from Libya and Nigeria is relatively uncertain. But the more fundamental and long term issues are the rising tension in the Middle East and the more limited capability and willingness of the western world to play a stabilizing role in global affairs. Who could have imagined Brexit and the presidency of Donald Trump even five years ago?

“Iran is out to dominate the region” said Ibrahim al Muhanna, adviser to three Saudi oil ministers. “Just like Saddam but with different methods”. It illustrates the high level of distrust between the two major forces in the region. And yet, part of the rising tension is related to internal issues in Saudi Arabia. The new crown prince’s position is not yet fully secured. His bold initiatives (whether externally in Yemen or internally with Vision2030 and the arrest of many business people and princes) do not inspire confidence. A rapidly growing population and rising youth unemployment present a major challenge.

President Trump is a major uncertain factor. The renewed Iran sanctions could result in higher oil prices. A further escalation of the trade conflict with China could have a significant impact on the global economy and oil demand, thus lowering prices. What will he do next? Whether a potential impeachment (or removal by the 25th amendment) would unhinge stock markets and the economy is at yet completely unclear.

Fu Chengyu, a former chairman of CNOOC and Sinopec stated that “the environmental situation in China is terrible.” The determination of the Chinese government to reduce pollution and improve air quality should not be underestimated. If the share of coal in the primary energy consumption is indeed lowered to 47% in 2030, as per plan, this implies major growth for renewables ánd gas. China was the major force behind the rapid growth of oil demand in 2000-2010. It may well play the same role for the growth of gas demand in the coming decennium (and again as a result of government policies).

Tighter oil markets due to Iran sanctions.  When president Trump announced the Iran sanctions it was still relatively unclear to what extent this would influence Iranian oil exports. Recent signals point to a relatively large drop in exports by the end of the year.

Waivers from the US government, needed in order to continue oil imports from Iran, have not been forthcoming. Western companies like Shell or Total can no longer buy oil from Iran now that the country has effectively been placed outside the western financial system. But also Indian refiners cannot buy Iranian oil as they are unable to insure the oil transport from Iran. Chinese companies continue to import oil from Iran but China is not willing to increase these imports in order not to give the US a pretext for further escalation of the trade conflict.

The drop in Iranian oil exports will be as large as 1,5-1,7 mb/d by the end of the year according to Amrita Sen from Energy Aspects in the session on oil markets. It could be compensated by an increase in Saudi and Russian oil production. This would result in a drop of global spare capacity to unprecedented low levels, however, which could easily give rise to oil price spikes in the case of any other supply disruptions.

US shale oil: limits to growth

published on EnergyPost, Nov. 2, 2017


US shale oil has had a major influence on oil markets. Looming oversupply due to the rapid growth of US shale oil production was the primary cause for the 2014 oil price drop (triggered by OPEC’s decision to not cut back production at the time).

Once that the oil market had found a new equilibrium, the oil price has moved within a relatively narrow range: the “shale band”. The rapid response of US shale production to changes in the oil price has resulted in a range of about 45 to 55 dollar per barrel (WTI). It is the price range in which US shale currently can operate without flooding the markets or going bust, close to the current average break-even cost of US shale.

Many analysts expect US shale to continue to limit oil price volatility – at least in the short term. But a key question here is: how fast can US shale grow? US shale is not a swing producer like Saudi Arabia that, with a spare capacity of about 2 mb/d, can open up the tabs within a matter of weeks.


Since 2014 investments in conventional oil have been significantly reduced. Yearly decline rates of existing fields have increased and a smaller number of new developments have been sanctioned. It will take until 2020, however, before the effects of this will be felt in full.

Over the coming years we will be carrying out an experiment: how long can US shale production continue to grow at a rate of about 0.5 – 1.0 mb/d (depending on oil prices)? If oil demand continues to increase at its current rate we should at some stage reach a point where a further decrease (or sluggish growth) in conventional oil and a reduced growth potential of US shale oil results in an upward pressure on prices. Many analysts expect this point to be reached in the early 2020’s. A key question here is: how far can US shale grow?

Compared to conventional oil US shale is more similar to a manufacturing industry with a higher degree of standardisation. Limits to the production of US shale come from the availability of finance, drilling rigs, fracking crews or pipeline capacity. Geology gives limits to its production as well but not so much by oil in place (which, for all practical purposes, is unlimited) but by the extent of sweet spots; those places where the recovery per well is highest and the main (if not only) areas where production can be commercially attractive.

Limits to growth


Labour shortage currently limits the rate at which US shale production can grow. This shortage is most acute in the Permian in West Texas.

During the 2015/2016 downturn oil producers and service companies cut over 100,000 jobs in Texas alone. Currently about 30,000 people have been hired again. That number could have been higher, however, would many people not have left this boom-and-bust industry in search of more job security.

Shortages are most pronounced for truck drivers and fracking crews. Combined with a shortage in fracking equipment (across the US only 12 million hydraulic horsepower is currently available with demand for about 16 million) this is now responsible for an increase in DUC (drilled and uncompleted) wells.

Shortages of labour and equipment have so far resulted in a 15 to 25 % cost rise for oil field services in the Permian.

Water disposal

Injection of produced water in salt water disposal wells is a significant part of operating expenses. Unlike conventional oil, water cannot be re-injected into the reservoir the oil/water was produced from.

Again, the issue is most pronounced in the Permian where over 5 barrels of water are produced are produced for every barrel of oil. After a period of low activity, the industry is now catching up on water infrastructure (pipelines and disposal wells) in this area.

Although not a show stopper, rising utilization rates of disposal wells are now starting to result in higher costs (e.g. due to longer distances over which water needs to be trucked to disposal wells with more remaining capacity).

Induced seismicity due to water disposal is now rapidly increasing in the Eagle Ford and Permian; a trend that will in all likelihood continue over the coming years. Again this is likely to lead to higher costs as the capacity of some water disposal wells will in future be restricted in order to reduce induced seismicity.


Rig productivity (defined as the average monthly contribution from a rig to production from new wells) has stopped rising. Four out of the five regions that the EIA reports onsaw a decrease in rig productivity over the last 12 months.

It should be noted here that the rig count (the number of active rigs) influences rig productivity as well. A low rig count tends to give somewhat higher productivity as in general only the most efficient rigs are kept on during a downturn.

Up until 2014 rising productivity was primarily structural. Faster drilling, larger fracks and a better delineation of sweet spots all contributed. From 2014 until 2016 low oil prices resulted in further productivity rises that had a greater cyclical component. Only the best performing rigs were kept active and remaining drilling focused on the very best part of the sweet spots (“high grading”). Throughout the years the increase in initial rates has been more pronounced than the increase in estimates of total well production (newer wells tend to decline faster).

The time of rapid structural rises in productivity now seems to be behind us. And, to make matters worse, geology now gradually starts to make further rises in productivity more difficult.



US shale has made it possible for Wall Street and private equity to rapidly invest large sums of money in the oil industry. Conventional oil offered less opportunities for this (the number of conventional oil discoveries being limited).

What is now becoming more doubtful is whether a production growth success story will be followed by a financial success story. So far US shale producers have been characterised by a negative cash flow. As a result the cost of finance has gradually increased. Whether a company’s licenses are located in the very best parts of the sweet spots (on which the industry has gradually increased its focus) primarily determines break even costs and profitability (or rather: the extent of losses incurred).

Investing in US shale has so far implied banking on future profitability (by higher oil prices or future cost decreases by further technological progress). In a world of higher oil prices and oil demand growth the relatively low break even costs of US shale for non-OPEC new oil should indeed give it an advantageous position.


Over the last few months investors have become more reluctant to provide additional finance to US shale. A number of factors play a role here: the continuous negative cash burn, the limited upside potential for oil prices in the short term and increasing doubts on the long term ability of the industry to further increase well productivity. Market psychology, still positive in the immediate aftermath of the December 2016 OPEC cuts, has now become more negative. The increased potential for rising interest rates (which – should it materialise – will be a severe problem for the industry given its high gearing) has also played a role here.


Maps of the main US shale regions give an impression of extensive areas. The actual extent of the sweet spots (where the bulk of the production is coming from) is much smaller, however. The vast majority of tight oil production comes a limited number of counties only (Dunn, McKenzie, Mountrail, Williams counties for the Bakken; Karnes countie for the Eagle Ford).

The limited growth of production in the Bakken and Eagle Ford in recent years is related to the limited size of the best areas. In the Bakken, there is hardly any scope for further infill drilling in the very best Parsnell area (EOG operated). New wells have been finding slightly lower pressures and associated higher initial Gas Oil ratios (see figure below). For the Eagle Ford, the size of the sweet spots turned out to be smaller than expected. As a result, companies have, over the last 2 years, shifted resources from the Bakken and Eagle Ford to the Permian.


In contrast to the Bakken and Eagle Ford there is still ample scope in the Permian to drill new wells in sweet spots at the original spacing rather than drilling infill wells. The Permian is a larger and more complex shale oil area and production comes from different stratigraphic intervals. With the increased focus of shale oil companies it has over the last 2 years been the area with the largest production growth. Even here, however, limits to growth now start to appear on the horizon.

Over the coming years (mostly from 2020 onwards), an increasing amount of Permian wells will be infill wells at half the original spacing. A recent study by Wood Mackenzie(based on a number of technical papers at industry conferences) estimates that recovery factors for these infill wells will be 20-40% lower (due to e.g., frac hits, lower pressures and resulting higher gas oil ratios). Operators will face a choice whether to drill infill wells in the sweet spots or to drill wells with larger spacing outside the sweet spots. To what extent this will be countered by further technological advances is still unclear. In terms of maturity of the play and overall shape of the production profile the Permian lags the Bakken and the Eagle Ford by about 5 years. All the different Woodmac scenarios show a marked reduction of production growth from the Permian in the early 2020’s, however.



There is no single factor that gives a hard upper boundary for the rate at which US shale can grow and the production level that it can eventually reach. Together with the oil price it is the interplay between financial, technical and geological limits that will eventually determine this.

With the rate at which technology progresses slowing down and having reached (Bakken, Eagle Ford) or approaching (Permian) the point that well interference is starting to reduce well recoveries in earnest financiers are becoming more reluctant to provide additional funding to US shale.

As a result estimates of future US tight oil production are becoming more conservative. Whilst acknowledging that future technological progress creates a large uncertainty the prospect of US tight oil production leveling off in the early 2020’s has become a likely scenario (see also the figure below). By that time, the ability of US shale to rapidly grow and provide a ceiling on oil prices is likely to have been significantly diminished.


Total strikes

Pubished on Energy Post, (7-9-2017)

After a period of cautious investments and a focus on bringing down costs Total surprised the markets last month with its takeover of Danish Maersk Oil and Gas (MOG) for a sum of $ 7.5 billion. The deal will give Total additional production of approximately 160,000 boe per day.

MOG’s reserves are pre-dominantly located in the North Sea and are predominantly oil. Total thus choose not to invest in shale (where many US companies are directing a lot of their investments) and not in gas (touted by many companies as the transition fuel towards a low carbon world).

Whereas BP and Shell are selling North Sea assets, Total is increasing its focus on the North Sea. After the Maersk transaction is completed it will pass Shell to become the second largest North Sea producer (after Norway’s Statoil).

What kind of company was Maersk Oil and Gas (MOG)? Why did the Maersk group decide to sell after more than 50 years of profitable activity in oil and gas? And why did Total buy?

MOG: high profits from fracking chalk

The heartland of MOG is the Danish offshore chalk play that includes the giant Dan and Halfdan fields (together these 2 fields have produced over 1 billion barrels). These fields are characterised by a relatively tight, low permeability, reservoir. MOG’s great achievement and core technical competency was to develop these fields (and get relatively high recovery factors) by drilling horizontal wells and fracking them (long before this technique took off in earnest in US shale).

Maersk being such a dominant company in Denmark and the good relationship between Maersk and the Danish state have helped MOG. In 1962 the entire prospective part of the Danish offshore was granted to Maersk in a single license for 50 years. In 2002 (10 years before the license expired) the license for the core area was extended to 2042. The 2002 agreement turned out very well for Maersk as the Danish state signed a new contract that gave them relatively little exposure to a post-2002 rise in oil prices. Earlier this year tax adjustments enabled MOG to go ahead with the overhaul of the Tyra platform (now so rapidly subsiding that operations would need to be stopped around 2020 which would effectively mean the end of Danish gas production).

MOG’s other pillar was the Al Shaheen field, Qatar’s biggest oil field. Its geology is similar to Maersk’s Danish assets. MOG managed to secure the Al Shaheen contract in 1992 on relatively good conditions (other companies shying away from its challenging geology). Over the next 15 years it managed to crank up production to approximately 240,000 barrels/day. This was a real achievement, helped by MOG’s technical knowledge gained in the Denmark chalk fields.

For a long time, MOG was a very profitable oil company. Around 2010 its return on capital was about 30%; about three times as high as the average for its peer group. A significant part of the expansion of the parent shipping company was paid for by the profits from oil and gas. It was believed that oil and shipping were part of different (out of phase) cycles, thus stabilising profits of the Maersk group.

2005-2015: MOG unable to grow outside of chalk

From 2005 onwards clouds started to gather on the horizon, however. The production of the Danish assets peaked in 2006 and it was clear that the scope for new finds in the chalk play was very limited. For Al Shaheen there was scope for increasing production but the end of the Qatar license in 2017 had become in sight.

MOG’s production and high profitability were based on two assets and a single play only. Hence, from 2005 onwards, the company attempted to transform itself from a niche player into a medium size global company that would be active in many different areas and plays. An attempt that was eventually to fail.

The 2005-2015 period saw a number of relatively unsuccessful attempts to develop assets that in the long term could take over from Denmark and Qatar. A number of ventures, scattered around the world, were set up in the Gulf of Mexico, Angola, Algeria, Brazil, Kazakhstan, Kurdistan and the UK.

Despite an extensive appraisal campaign, the Chissonga discovery in Angola was never developed due to challenging economics. Maersk non-operated assets in the Gulf of Mexico were bought in 2010 at a relatively high price and new discoveries have not been developed due to poor economics. Brazil production disappointed and in 2011 Maersk made a significant $ 1.7 billion write off. Production in other areas remained relatively small. The most material project, the gas condensate Culzean field, is now being developed but profitability may be limited due to the high costs in a HPHT (high pressure, high temperature) North Sea environment and the current low oil and gas prices.

These projects often suffered from a lack of economies of scale (related to a lack of focus), trouble operating outside of MOG’s chalk comfort zone and the difficulty of growing profitably in a high oil price world with corresponding high costs and inflated asset prices. Too much good money was thrown after bad money.

The only highlight of this period was that MOG in 2009 picked up a small part of a Norwegian block that was operated by Swedish explorer Lundin. Lundin subsequently here made the spectacular discovery of what is now known as the 2-3 billion barrel Johan Sverdrup field and MOG owns 8,44 % of it. Based on Lundins market cap (predominantly determined by Johan Sverdrup) this relatively small share is now worth close to $ 2 bn.

2015/2016: Maerk oil and gas at a crossroad: grow or sell?

By 2015 a number of developments coincided creating serious issues for Maersk Oil and Gas:

  • The major drop in oil prices.
  • An accelerating decline of Danish production.
  • Unsuccessfull negotiations with Qatar on the extension of the Al Shaheen contract. Although such contracts are usually extended (it makes sense to let an established operator continue its work) this one turned out to be difficult. Over 2015 it became clear that Qatar had decided to invite offers from other companies.
  • The failure sofar in it attempts to profitably grow outside Denmark and Qatar.

By now a sale of MOG had become a serious option. Nevertheless it was decided to make a last attempt to grow and re-invent the company. It was thought that the 2014 oil price fall provided more attractive opportunities to grow; this time by acquisitions rather than organic growth. Reduced asset prices and the financial strength of the Maersk parent group should make this possible.

Late 2015 MOG acquired Energy Africa’s Kenyan assets (Tullow operated) for up to $ 800 million. Maersk at this time considered taking over a sizeable part (at a potential cost of $ 2 billion) of Shell’s UK North Sea assets (aiming to become a more dominant North Sea player).

2016: Why did Maersk decide to sell?

Over 2015 and 2016 a number of developments took place that eventually forced the Maersk group to change strategy (only a year after deciding to make a last ditch attempt to stay in the oil and gas business).

In June 2016 it was announced that Total had been selected to operate the Al Shaheen field after July 2017. Total had accepted a relatively small minority 30% share in a newly formed company running Al Shaheen. At the time this was a rather puzzling development: Total was new to the field and not known as a fracking and chalk specialist. It may be that Total at this time was already preparing a Maersk takeover (especially in case its Al Shaheen bid would be successfull). Total may have reckoned that MOG without Al Shaheen would likely be put up for sale.

In the past low oil prices had resulted in a stimulation of the economy and shipping (resulting in higher freight rates as well as low fuel prices). Over 2015 and 2016 the shipping vs oil hedge broke down and a period of simultaneous low oil prices and record low freight rates created a “perfect storm” for the Maersk group. This made MOG’s strategy to grow in a period of low oil and asset prices much more difficult and risky.

Over 2015 and 2016 doubts increased over the attractiveness of the oil and gas business in the longer term. US shale oil has resulted in an additional component of oil supply that is there to stay, resulting in the current period of “lower for longer” prices. Growing concerns on climate change and the resulting support for renewables will limit oil demand growth in the longer term.

As a result of these developments the Maersk group decided in 2016 to change strategy and put MOG up for sale. It also started to prepare for an IPO of MOG should a sale at sufficiently attractive terms turn out not to be feasible.

The MOG of the past, a niche player with a competitive technical edge, with a substantial part of its assets in Denmark, operating in a relatively profitable oil and gas world was a valuable part of the Maersk group.

The picture of the MOG of the future was a different one: a global player without a competitive technical edge, operating in a systematically less profitable environment. Selling to an established larger operator that should be able to get more value out of its existing assets was a logical choice.

Why did Total buy?

If a company has the financial resources and believes in a long term future for oil and gas, this may well be a good time to buy. Eventually the current low investments in oil and gas are likely to re-balance the markets (be it that it will take a lot longer than initially expected).

Total’s decision to buy a company focused on oil and focused on the North Sea rather than a takeover in gas or in US shale may turn out to be an astute one. With a stream of new LNG projects coming online up until 2020 the gas oversupply may last longer than the oil oversupply. For gas the worst is still to come. US shale has sofar failed to deliver profits. None of the majors has been successful with acquisitions here and apparently Total decided it could not do any better.

Statoil’s cost reductions on Johan Sverdrup have brought costs down to approx 25 dollars per barrel. With these low costs it will be a very profitable project in a politically secure area.

For many areas MOG assets are situated close to Total’s assets which will help synergies. Total estimates cost savings due to synergies at $ 400 million per year. The key region here is the Central North Sea where MOG’s Culzean is located in the immediate vicinity of Total’s HPHT Franklin and Elgin developments. Other areas with significant synergies are Angola, East Africa and the Gulf of Mexico. Total’s experience as an operator in Angola implies it is in a better position to get a Chissonga development off the ground. MOG’s Kenyan assets fit in well with Total’s neighbouring Uganda assets. East Africa now has the potential to become a major growth area for Total.

Finally, MOG’s knowledge and excellent technical track record on Qatar should be a real help for Total in increasing Al Shaheen production.

The changing world of oil and gas invokes different reactions. Companies like DONG and Maersk have decided to leave the oil and gas business altogether and other smaller players may follow. None of the majors are anywhere near such a point but they are focusing their new investments on very different areas. Total and BP are focusing on low cost oil (conventional onshore and shallow offshore). ExxonMobil and Chevron are focusing on deepwater and US shale. Shell is betting on gas and deepwater Brazil. The future will tell which of these upstream strategies will turn out to be the most successful one.


The rapidly declining production of small Dutch gas fields

The rate at which gas production from Dutch small fields declines is much faster than the rate at which Dutch gas consumption declines. Dutch gas is effectively being replaced by Russian gas. This is not in the best interest of the Netherlands, neither from a financial nor from an environmental point of view. Current policies will not be able to preclude a rapid and near complete collapse of gas production from Dutch small fields.

Introduction.  Dutch gas production has two components: the production from the giant Groningen field and the production from numerous small fields. The rapid decline of production from the Groningen field, due to production measures put in place to limit seismicity, has received a lot of attention. That the production from small fields is also rapidly declining, for very different reasons, has hardly received any attention.

For decades the Dutch government has stimulated the production from small Dutch gas fields. The aim of this successful “small fields policy” was to maximise revenue from Dutch gas and at the same time preserve the Groningen field as much as possible.

Prior to the year 2000 the production from small fields (both offshore and onshore) exceeded 40 BcM per year. After 2000, a gradual and slow decline started to set in, which was compensated by increasing the production from Groningen. By 2007, production had decreased to about 35 BcM and fell below that of Groningen for the first time in decades. By 2012, production had decreased to about 30 BcM. Until this time the decrease was solely due to geology. The early (larger) finds started to deplete and later finds gradually decreased in size.

A turning point for Dutch gas production: 2012.  In recent years there has been a marked change in the operating environment for Dutch gas production. Prior to this shift Dutch gas was seen as a welcome source of revenue for the Dutch government, obtained from the production of a relatively clean fossil fuel. After this shift, gas became a polluting fossil fuel which one would only like to tolerate for a limited time, awaiting the completion (sooner rather than later) of the energy transition.

A number of elements play a role in this shift:

  • The increasing realisation of the severity of the climate change problem and the increasing momentum to actually start tackling this problem, culminating in the Paris COP21 agreements.
  • The increasing magnitude of Groningen earthquakes and the plight of people affected by these earthquakes, culminating in the 2012 Huizinge earthquake that damaged thousands of houses. This damaged the public image of gas in general and the image of the largest producer (NAM, a Shell ExxonMobil joint venture) in particular.
  • The increasing unpopularity of large corporations such as oil and gas companies, perceived to make profits at the expense of local populations.

All this has been a gradual development. If I would need to pick a turning point though I would place it in 2012.

The figure below shows the production from small Dutch gas fields until 2012 and the potential scenarios for future production at this point in time. A large range of scenarios was possible (depending on future gas prices, the amount of government support for small field production and the success of several exploration plays). What has so far materialised is a scenario with a very low production from small fields. This decline is more severe than in the past and is no longer just related to geology.


Recent developments.  The last few years have seen only small additions from new fields (with 2016 being an absolute low point). Exploration for new fields is rapidly declining. It seems increasingly likely that a number of operators will cease to explore altogether. In addition to geological factors (long term creaming of the area) a number of additional elements come into play, creating a perfect storm for Dutch small field gas production:

  • Low gas prices
  • The absence of support from the Dutch government
  • Doubts on the long term future of the Dutch offshore gas infrastructure system
  • Obtaining a permit for onshore drilling has become a very tedious and time consuming procedure; obtaining a permit for a new onshore production location has become even more difficult.

For the offshore gas production this can have a snowball effect. If an increasingly smaller number of fields has to carry the operating cost of an entire offshore pipeline system, at some stage the moment will arrive that this is no longer commercially feasible – increasing the amount of gas that is left in the ground. This moment is now rapidly approaching, especially in the case of continuing  low gas prices.

Consequences for the Netherlands.  The difference between the current and the late 2012 mid-case production profiles is about 170 BcM. Depending on future gas prices this represents a value of some 15 to 30 billion € (primarily to the Dutch state). I would estimate that by now roughly half of this volume has been irrevocably lost; half could still be saved if adequate measures are now taken in a world where oil and gas prices are slowly recovering. The public discussion on this issue has been minimal.

Whilst the energy transition will be a matter of decades, with an expected gradual decline of gas consumption in the Netherlands between now and 2050, the current decline in gas production in the Netherlands has become much more dramatic. Dutch gas is now being replaced by Russian gas and/or coal. That is not in the best interest of our country, neither from a financial nor an environmental point of view. Short term targets on emissions are becoming more difficult to achieve.

Coal is the most polluting fossil fuel; something that can only be mitigated, to a limited extent, by costly additional measures. Russian gas implies both additional CO2 emissions (roughly 12 % of the gas is needed to transport gas from Russia to The Netherlands due to the low efficiency of the Russian gas transport system) and additional methane emissions (methane losses related to transport over large distances in Russia are expected to be significantly higher than methane losses related to transport over short distances in The Netherlands). Effective emissions (CO2 equivalent) are estimated to be about 20 – 25 % higher compared to Dutch gas.

In conclusion, I would advocate measures that would stimulate the production of remaining gas reserves such as a preferential tax treatment for small fields or fields with low quality reservoir. The Dutch tax regime for gas producers is significantly worse than for instance the tax regime in the UK (50 % versus 30 % direct tax take). The policies that are currently in place are grossly inadequate to preclude a rapid and near complete collapse of gas production from small fields. Part of the revenues could be used to fund a much needed, but also costly and lengthy, Dutch energy transition.

Groningen gas production and earthquakes


  1. Introduction

The giant Groningen field was found in 1959. Remaining reserves are about 800 BcM (vs. about 2800 BcM of initial reserves). The field is exploited by NAM (50 % Shell, 50 % ExxonMobil) on behalf of the “Maatschap Groningen”, a partnership of NAM (60 %) and EBN (40 %). EBN is wholly owned by the Dutch state.

Including the effect of taxes, 85 – 90 % of the profits from the field go to the Dutch state. Income from gas production (which is for about 80 % coming from Groningen) accounted for about 10 % of state income over the 1975 – 2015 period.

Over the years earthquakes related to gas production have increased in number and magnitude. The shallow depth of these earthquakes (as well as the frequent occurrence of a very low velocity layer just below the surface) implies that earthquake intensity and damage to houses are relatively large compared to the seismic magnitude. Older houses and farms built with single brick walls are especially vulnerable. A turning point was the 2012 Huizinge 3.6 magnitude earthquake which damaged thousands of houses. This was followed by the realization that the estimate for the maximum potential magnitude of 3.9 for a Groningen earthquake, assumed so far, was likely to be too low (and subject to considerable uncertainty) and that seismicity could not only result in material damage but potentially also in loss of life.

gron-earthquakes-numberNumber of earthquakes exceeding a certain threshold magnitude as a function of time (from Muntendam and de Waal, 2013). It is likely that light tremors already took place during the late 1980’s (the seismometer network has been gradually extended and is only expected to have detected all tremors with a magnitude greater than 1.5 since the mid 1990’s).

As a result the Dutch government has put in place a production cap for the field (as well as separate caps for the area’s most affected by seismicity), leading to a significant decrease in production and government income. By October 1, 2016, the production cap has been lowered to 24 BcM per year (in 2013, the last year prior to the recent production caps, yearly production was still as high as 54 BcM). The double hit from production caps and declining gas prices has resulted in a severe decrease of government income from about 15 bn Euro (2013) to little over 2 bn Euro (2016).


  1. Groningen earthquakes through time

The first registered earthquake in the Northern Netherlands related to gas production took place near Assen in 1986. The first registered earthquake from the Groningen field occurred in 1991. In 1993 a joint NAM, KNMI (the Dutch meteorological institute – which also has a section monitoring seismicity in the Netherlands) and SODM (the government entity supervising the oil and gas industry) study (in Dutch) confirmed the relation between gas production and earthquakes. Prior to 1986 no earthquakes whatsoever had been recorded in the tectonically quiet Northern Netherlands.

What has not helped the public image of the NAM in the long term is that from 1986 to 1993 they denied a relation between gas production and earthquakes. Instead of admitting that when earthquakes start to appear at producing gas fields (in an area without any recorded seismicity so far) there is very likely to be a relation (be it that the way this works is not well understood) they went into denial mode.

This denial mode continued for many years. The 1993 joint report contained a section in which an estimate was made of the maximum potential magnitude of a Groningen earthquake. This method (using a Gutenberg Richter relation between earthquake magnitude and frequency) played a key role in KNMI reports with estimates of maximum magnitudes for years to come. The problem is that deriving a maximum potential magnitude from historically observed seismicity, using the Gutenberg Richter relation, is something that can only be done for stationary situations (as is usually the case for natural earthquakes). A depleting gas field, however, is not a stationary situation at all. If anything it gave a lower bound for the maximum magnitude of a future Groningen earthquake. For Groningen, as depletion progressed, the KNMI gradually revised its estimates from an initial 3.3 (1993) to an eventual 3.9 (2006), upon which it eventually became increasingly clear that this method was not defendable.

For a long time both NAM and SODM were not proactive in starting further research (for instance to determine uncertainty estimates on KNMI’s estimates or to invite alternative views from other research organizations). The focus of the NAM was very much on subsidence rather than on seismicity. An in depth review is given in a report of the Dutch Safety Board on Groningen earthquake risks. There was a genuine expectation in NAM that earthquakes could only result in limited material damage. This was not backed up by solid research, however, and in hindsight uncertainties were severely underestimated.


  1. Understanding Groningen earthquakes: differential compaction related to faults

The Groningen gas is contained in Rotliegend sandstone reservoir (in the pores in between the sandstone grains). The gas originates from deeper Carboniferous coals. As these coals experienced increasing pressure and temperature (while gradually being buried deeper over geologic time) they started to expel gas which moved upwards (due to its low density) to the overlying sandstones. The sandstones in turn are overlain by Zechstein salt which is impermeable. As a result gas accumulations exist in those places where the Top of the Rotliegend sandstones is at a relatively shallow depth (i.e. more shallow compared to surrounding areas) so that the gas, which cannot move upward through the salt, cannot escape laterally.

groningen-3d-view3D view (from the SW) of the Top Rotliegend. Colors denote depth (red is highest); blue plane denotes the Gas Water Contact; red lines denote wells. Source: NAM MMax workshop.
groningen-xsE-W cross sections across the Groningen field, illustrating how faults offset the Rotliegend reservoir layer (in yellow). Red layer denotes the Ten Boer shales above the Rotliegend. Zechstein salt immediately above the Ten Boer; Carboniferous below the Rotliegend sands. Source: NAM MMax workshop.

As gas is being produced, the pressure in the gas decreases and the overburden of about 3 km thickness starts to exert a greater pressure on the sandstone grains. As a result, the sandstone starts to compact. For the Groningen field the total amount of reservoir compaction due to gas production is expected to range up to about 50 cm (for a layer that is up to about 250 m thick). If compaction were to take place homogeneously over the field significant seismicity would be unlikely to arise and the main adverse effect of gas production would be the gentle subsidence bowl that we see developing in the Groningen area since the 1960’s. Unfortunately it does not. The Groningen field is affected by numerous faults and these faults can lead to strong local variations in compaction. As differential compaction over a fault increases, shear stresses on the fault plane build up and at some stage the strength of material at the fault (a zone of weakness) is overcome after which rupture takes place on (part of) the fault plane.

There are a number of ways in which faults can lead to differential compaction. The most straightforward one is that faults offset the gas bearing reservoir vertically. As a result compaction at a given depth varies laterally (shown schematically in the figure below).

groningen-fig-1-schem-extraSchematic representation on how earthquakes can be triggered in a compacting, faulted reservoir. The actual situation for Groningen is much more complicated. The thickness of the Rotliegend reservoir sands varies considerably over the field (from about 80 to 250 m) and over the field area some 1600 faults have been mapped (a few large ones and many small ones).

In addition faults can be baffles (if not hard boundaries) to flow. As a result pressure differences across faults may arise which can result in differential compaction and seismicity. Reservoir simulation models of the Groningen field point to some faults that are indeed sealing. Regionally, the NW-SE trending strike slip faults are often observed to be sealing faults. Until recently NAM’s production philosophy has been to minimize pressure differences across the field (helped by the excellent permeability of the Rotliegend reservoir). As a result it seems unlikely that pressure differences between major compartments make a large contribution to differential compaction and Groningen seismicity.

Finally, faults should not be seen as sharp boundaries. A larger fault tends to be surrounded by many smaller ones as well as a zone (“damage zone“) where reservoir quality is impaired and porosities are substantially reduced. For faults in similar, smaller Rotliegend fields in the Dutch offshore such damage zones are observed to be about 50-100 m wide, with an average porosity reduction of about 3 p.u. (ranging up to about 5 p.u.). With compaction being strongly, non-linearly, dependent on porosity such a reduction in porosity can easily result in a reduction of compaction by roughly a factor 2. Damage zones may be the most pronounced for strike slip zones which have experienced major displacements (but do not necessarily stand out on seismic as their vertical displacement may be limited).


  1. Key observations on Groningen seismicity

Significant progress on our understanding of Groningen earthquakes has been made over the last few years. The network of seismometers has been extended and now includes seismometers at depth, reducing the uncertainty of earthquake locations. We can now be more confident that earthquakes are taking place at (or in the immediate vicinity of) the Rotliegend reservoir. Two key empirical observations are listed below.

Seismicity (initially) increases with total reservoir compaction. A threshold exists of about 10 – 15 cm of reservoir compaction before the onset of seismicity. Beyond this threshold seismicity starts to increase in both number and magnitude.

Apparently this is the amount of compaction needed to bring shear stresses on faults (or at least on some locations, on some faults) to the critical level required for rupture. Initially, stresses on faults (at least at Rotliegend level; likely also at e.g. deeper Carboniferous levels) are not anywhere near the level required for rupture. This is in accordance with the complete absence of natural earthquakes in the Northern Netherlands.

 groningen-time-series-b-en-oTime series of M > 1.5 earthquake magnitudes versus reservoir compaction at the origin time and epicentre of each event (from Bourne and Oates, 2014).

What is less clear is how (if at all) this trend will continue in the future. As long as most earthquakes are related to the first slip event on a fault (segment) seismicity is indeed expected to continue to increase with the total amount of compaction. But once most earthquakes become related to a second or later slip event on a fault (segment) the increase of seismicity with compaction will start to diminish and we may even start to approach a stationary situation.

The figure below shows the fraction of energy related to compaction that has been released seismically (“partitioning fraction”) as a function of the total amount of compaction. Although far from being conclusive (the highest amount of compaction has been reached in a relatively small area only) it cannot be excluded that the partitioning factor is levelling off at a total compaction greater than 20-25 cm. The absence of earthquakes during the first 20 years of production turned out to be no guarantee that earthquakes would remain absent over the entire field life. In the same way, the increasing intensity of seismicity as observed over the 1991-2012 period is no guarantee for its continued increase in future. Our predictions on future seismicity are to a disappointing extent still based on statistics and extrapolation of known trends (rather than a complete understanding and geomechanical modelling of the actual physical processes).

groningen-fig-partitioning-2Partitioning fraction (seismic moment divided by total reservoir compaction moment) for different compaction classes. Green line (NAM) and dashed blue line (TNO) denote relations between the partitioning fraction and reservoir compaction for different models. Note the large amount of uncertainty for the future partitioning fraction in the forthcoming late stage of the Groningen field life. Source: TNO report R11953(December 2013, in Dutch). It is quite conceivable that the partitioning fraction continues to increase (at a similar rate as observed so far). It is also quite conceivable that the partitioning fraction is levelling off at a value of about 10-4.

Seismicity increases with fault intensity. Within the area of high compaction at reservoir level, seismicity is the most pronounced in areas with a high intensity of faulting. The intersection of numerous NW-SE trending faults with the high compaction area near Loppersum experiences the highest seismic intensity. In comparison, an area with a similar high amount of compaction and a low fault intensity further towards the N experiences a much lower level of seismicity. There is no obvious relation between seismicity and fault throw.

static-model-mapCompaction (denoted by color; color scale ranging from 0 to 0.4 m). Black lines denote faults from the NAM static model. Red line denotes outline of the field. Seismicity is denoted by symbols (size of the symbol indicates event magnitude). Location uncertainty of seismic events is about 1 km.  Highest seismic activity takes place in a region of high compaction and high fault intensity. Source: TNO report R10755 (based on the NAM 2013 static model).

These observations (and in particular the observation that there is no clear correlation between fault throw and seismicity) indicate that fault damage zones may play an important role in Groningen seismicity. The Groningen field is intersected by zones of anastomosing faults, indicative of strike slip faulting (in particular in the Loppersum area and in the Eemskanaal area). Elongated damage zones in these areas (with a much lower amount of compaction) can account for the observation that seismicity is distributed over a larger area (rather than being concentrated on the few large throw boundary faults) and is associated with faults that often do not have a large vertical displacement.

Wells in these areas do sometimes intersect such a damage zone (the clearest example being the EMK-2 well). When incorporated in a static model such wells may erroneously influence the reservoir properties in the model over a large area (resulting in a pronounced mismatch between modelled and observed subsidence).

The observation that there is no clear correlation between fault throw and seismicity critically depends on the correctness of KNMI’s estimate of earthquake location uncertainty of about 1 km. If this uncertainty is severely under estimated it could be that events in reality do primarily take place on the large throw faults. Future work, based on the recently extended network of seismometers, should enable us to better delineate Groningen earthquake locations.


  1. Time dependent processes such as creep play an important role.

There is a clear correlation between production and seismicity on a seasonal basis. There is a certain time lag (of about 3 – 6 months) in between, however, and time dependent processes such as creep play an important role.

groningen-seasonalityMonthly Groningen gas production (gray dashed line) and smoothed earthquake event rates (black solid line). Event rates clearly correlate, with some time-delay, with the seasonal pattern in production rates. From Bierman et al., 2015.

Already during the early phases of production it was recognized that subsidence initially took place at a much lower rate than expected (based on laboratory compaction experiments). This effect was only properly understood upon Hans de Waal’s work at Shell’s research lab (and following thesis at Delft University) on rate dependent compaction of sandstone reservoirs. To date, this work is still the basis for most of the Groningen subsidence models.

As a result of time dependent deformation of the Rotliegend it is not clear to what extent production measures will result in an additional reduction of seismicity. In other words: will a reduction in production rate by a factor 2  result in an end member reduction of seismicity by a factor 2 only, per fixed time interval, or (and to what extent) will there be an additional reduction as creep reduces the partitioning factor?


  1. Uncertainties are there to stay

In spite of all the advances in recent years, both regarding observations and modeling, our understanding of earthquakes related to gas production – and in particular our ability to predict future earthquake intensity – remains limited.

Maximum potential seismic magnitude.  A workshop on the maximum potential magnitude of Groningen earthquakes was held in March 2016. The outcome from this workshop is a range that is larger than ever before; spanning from 3.8 to 7.25. Not all values within this range are equally probable though and the key question is whether fault rupture will be (mostly or completely) contained within the Rotliegend reservoir or whether rupture can take place over much larger surfaces in the underlying Carboniferous (whether tectonic or triggered by Rotliegend earthquakes).

Should earthquakes remain (largely) confined to the Rotliegend (which is likely – but exact how likely is something for which estimates differ) then the range for the maximum potential magnitude is estimated to be about 3.8 – 5.0. The dimensions of the Groningen field, the thickness of the Rotliegend and the maximum expected pressure drop imply that in this case a Groningen earthquake is unlikely to exceed a magnitude of 5.0.

groningen-mmax-logic-treeExample of a logic tree for the maximum potential magnitude of a Groningen earthquake, as presented at the MMax workshop (from the ExxonMobil contribution). For different contributions the exact ranges and probabilities may differ. The final range of 3.8 – 7.25 represents the full range of all individual contributions. Personally I would put in a much lower probability for Groningen earthquakes to propagate significantly into the Carboniferous.

Effect of recent production measures.  The production caps that have been put in place contain 2 different elements: an overall production cap and specific production caps for the Loppersum and Eemskanaal areas.

For the overall production cap the key question is whether such a production rate decrease will merely result in the same amount of seismic energy now being released over a longer period (which is what the models in the NAM winningsplan tend to predict) or will also result in a reduction of the total amount of seismic energy to be released (which is what is suggested in the SODM reaction to the NAM winningsplan).

For an area production cap such as the one for the Loppersum area the key question is whether this only buys this area a temporary reprieve (and seismicity resumes once that the pressure decline resumes – something that will happen within about a year given the good overall connectivity in the area) or whether a more gradual pressure decline in the Loppersum area will result in a long term reduction of seismicity as well.

TNO expects that for a more gradual pressure drop (primarily due to a smaller seasonal variation in production; for the Loppersum area also due to production taking place at a larger distance) seismicity will be reduced. As yet this is an expectation – which may or may not be confirmed by observations.


  1. How to deal with Groningen earthquakes?

Regardless of the eventual outcome I would argue that the uncertainties mentioned abovecan be managed:

– seismic intensity and maximum observed magnitudes have been observed to increase gradually. Although it cannot be completely excluded an event with a magnitude much greater than what has so far been observed (e.g. including a significant slip component in the Carboniferous) seems quite unlikely.

– production measures work. Local production caps in a high risk region have a marked effect on seismicity within months.

This should enable us to manage production with a hand on the tap like strategy (like for the Waddenzee production) in a responsible way. Currently, the risk of a fatality is estimated to be very small (<< 1). Should risk levels stay roughly at this level the number of fatalities over the coming 30 years would be expected to be of an order of magnitude of 1. For comparison: the number of traffic deaths in Groningen over the coming 30 years is expected to be of an order of magnitude of 1000. Large uncertainties exist for these estimates. But at least we have a calibration point: the last 5 years (with a risk likely to have been greater than the risk over the coming years) did not result in any injuries or fatalities.


  1. Alternatives are more costly, less environmentally friendly

study by CE Delft (an engineering consultancy) looked into the consequences of a number of alternatives for Groningen gas for the environment and for Dutch state income. Alternative sources considered were Russian gas (capacity wise much more feasible than Norwegian gas), LNG (from Qatar) and gas from yet to be developed small Dutch offshore fields. In addition the effects of a reduction in gas consumption were studied.

These alternatives imply a substantial loss of income to the Dutch state. In addition, with the exception of a reduction in gas consumption, they are also less environmentally friendly.

Russian gas, for instance, implies both additional CO2 emissions (roughly 12 % of the gas is needed to transport gas from Russia to The Netherlands due to the low efficiency of the Russian gas transport system) and additional methane emissions (methane losses related to transport over large distances in Russia are expected to be significantly higher than methane losses related to transport over short distances in The Netherlands). Effective emissions (CO2 equivalent) are estimated to be about 25 % higher compared to Groningen gas.

From an environmental point of view a reduction in gas consumption is by far the preferred option. It is not going to happen in the short term, unfortunately. Groningen gas production has already been cut by approximately 50 %; the energy transition will take decades.

groningen-figs-2-ce-alternativesConsequences for emissions and Dutch state income of a reduction of Groningen gas production by 10 BcM per year. Alternatives for Groningen gas considered are Russian gas, LNG (Qatar) and new Dutch offshore gas fields (questionable whether they can have a substantial impact – given the limited exploration successes in recent years in the very mature Southern North Sea). In addition the effects of a similar reduction in gas consumption are studied.

Another option is to reduce seismicity by maintaining reservoir pressures at a higher level. The most straightforward method to reduce the reservoir pressure drop is by nitrogen injection. This has been studied extensively by NAM in recent years and has been rejected as:

  • This is very high cost
  • Involves a large scale industrial project that will take at least until the mid 2020’s before first injection
  • Involves major CO2 emissions and industrial activities throughout the region
  • Will result in a reduction of gas recovery, with some hydrocarbon gas being bypassed by nitrogen.
  • May well result in adverse effects; large scale injection may also lead to seismicity and it cannot be excluded that no net reduction of seismicity is reached.


  1. The number of damage claims is rapidly increasing due to people putting in claims for damage unrelated to earthquakes.

Over the past few years the number of damage claims has rapidly increased to over 500 claims per week on average. This increase is not related to an increase of seismicity. On the contrary, the total seismic energy released (per year) peaked in 2012 and has substantially decreased in the following years (see figure below). The largest earthquake in 2012 was the 3.6 magnitude Huizinge earthquake; the largest 2015 earthquake was a much smaller 3.1 magnitude event near Hellum.

groningen-figs-3a-damage-claimsa) Cumulative number of claims as a function of time. b) Average number of claims per week as a function of seismic energy released (both per year) for the 2012 – 2015 period. From the 2016 Technical Addendum to the Groningen Winningsplan.

It can thus be inferred that either a lot of actual damage in 2012 did not result in a damage claim or that a lot of 2015 claims were not related to damage caused by earthquakes. Additional data indicate that the latter explanation is by far the most likely. The figure below shows the percentage of buildings with claims plotted against PGA (Peak Ground Acceleration) for the 2012 Huizinge and 2015 Hellum events. It is expected that houses close to the epicenter and subjected to higher PGA’s have a higher chance of being damaged. For the Huizinge earthquake there is indeed a strong correlation between PGA (which in turn has a strong relation to distance to epicenter) and the percentage of buildings with damage claims. For the Hellum earthquake on the other hand no such correlation is observed and the vast majority of claims come from areas at a large distance from the epicenter with minimal PGA.

groningen-figs-3b-huizinge-hellum-newPercentage of buildings with claims plotted against PGA (Peak Ground Acceleration) for the 2012 Huizinge and 2015 Hellum events. From the 2016 Technical Addendum to the Groningen Winningsplan.

In simple words: in 2012 people put in a claim when a crack in their house appeared after an earthquake that had been felt in the area. The large increase in claims in the following years is a reflection of the intense publicity, the ease with which claims can now be submitted and the calls from NGO’s and politicians to put in claims rather than an increase in actual earthquake related damage. That situation is now becoming difficult to manage. The cumulative number of claims of over 60,000 implies a huge effort, at a significant cost to society (the cost of evaluating claims by now outweighs the cost of strengthening houses and compensating damages). The rapidly increasing share of rejected claims add to the disappointment and disillusionment that many people in the area already experience.


  1. The Dutch government now needs to rise to the occasion. 1) Make choices on the basis of a cost benefit analysis. 2) Accept that a situation that all the benefits are for the country, all the downsides are for the local gas producing region is not fair


To govern is to make choices. The Dutch government should have the courage to compare the risk that people in the Groningen area are running due to earthquakes with the risks that other people in The Netherlands are running. Flooding is a risk that many people in The Netherlands are subjected to. Risk levels for flooding are of similar magnitude as those for Groningen earthquakes. And yet we make a conscious decision not to raise our dikes to a level that gives absolute security. The reason is simple: cost. Not every medical treatment that is possible is being given – even it would extend or save lives. Again the reason is simple: cost. However difficult to accept this may be: with the limited means that we have there is simply no other choice.

I would argue that decisions on Groningen production caps need to be made on the basis of a cost benefit analysis – as is common practice for other (industrial) activities that involve risk. The cost for the Dutch state of billions of euro’s (even if the gas not produced now would eventually be produced in 20 or 30 years from now) by now seems to become disproportional to the risk to human life that these earthquakes pose (for comparison: a single investment of 120 million euro in Groningen provincial roads would be expected to save approximately 5 lives on a yearly basis). The Dutch Council for Security rightly condemned that safety did not play a role in decision making on Groningen production until only a few years ago. But by now there is a risk that we are going to the other end of the spectrum: that safety with respect to Groningen earthquakes needs to be achieved at all cost.

I would argue that the current unrest in Groningen is not just related to earthquakes but also to a long standing feeling that they are being badly treated by the central government. And here they have a point. Peripheral areas in The Netherlands, such as Groningen, tend to be under-represented in the Dutch parliament. When investments from FES, the Dutch infrastructure fund which received 40 % of Groningen gas income for the 1995-2009 period were analyzed it was found that close to 90 % went to the Randstad area (Amsterdam – The Hague – Rotterdam); only about 1 % of the investments went to the three Northern provinces combined.

In general there are good reasons why the proceeds from mineral wealth should go to a country as a whole. But for this specific case, where a single field accounts for close to 10 % of state income for a period of 40 years and where the downside to the local population is long standing and substantial, this just does not seem fair to me. It seems justified to use a part of the Groningen revenue to establish a fund that solely supports the Groningen local economy and infrastructure.


Chinese oil companies: giants on shaky foundations


Chinese national oil companies (NOCs) are not mere puppets of their political masters. Whilst adhering to the overall guidelines provided by the government they have their own commercially driven agendas.

They operate significant domestic oil production from mature onshore fields. This is their heartland and the area of their core technical expertise. Prospects for growth within China are limited and overseas investments are deemed more attractive.

Twenty years of overseas investments have seen a marked shift from a few operated ventures in conventional fields in high risk countries such as Sudan to many (often non operated) ventures in different asset classes (including deepwater and unconventional assets) spread across the globe. Overseas ventures now account for about 30% of their oil production.

By far the largest investments were made during 2009 to 2013. They have often overpaid for these acquisitions with takeover premiums significantly higher than the industry average. But the main issue for the financial performance of these acquisitions is their timing: they were made in a high oil price world with asset prices peaked.

Towards the government, the NOCs have stressed that their acquisitions contribute to China’s energy security and to their own technical expertise (helping them to achieve their long term goal to emulate the western majors). This seems doubtful. Oil from their overseas investments is traded on the global market like any other oil. As yet, the Chinese NOCs are not seen to be able to operate in different asset classes, across the globe, in the way that the majors do.

Chinese banks have been more than willing to fund the NOCs. Chinese people, with a high savings rate, have few alternatives for their money. As for other Chinese state owned enterprises: should the NOCs run into problems these problems are shifted towards China as a whole. With Chinese debt growing at three times the rate of the economy this situation is not sustainable.

The NOCs have been a key target of China’s recent anti-corruption drive. Corruption may have been no more than a welcome pretext (the government has to be seen as being tough on unpopular corruption); it can also be seen a power struggle within the party and an attempt to reign in the poorly performing NOCs (with the aim to increase their performance).


Some 15 years ago I worked for a small and well-hidden part of Shell in Central Africa. I have fond memories of living on the shores of Lake Yenzi in Gabon where my children grew up in a world of lagoons and tropical rainforest virtually untouched by mankind. To this day I miss the human warmth of Africa.

Towards the end of my spell in Gabon we would discuss among colleagues the arrival of a new competitor in country: Sinopec. We were puzzled. How could we reconcile the stories that the Chinese were taking over Africa (if not the world) with this hapless new venture, which had trouble getting to grips (both geology and country wise) with a completely new environment? What were we missing? I do not think we underestimated them; it was expected they would work hard and learn fast (and they had money to spend). But the general view was that they faced an uphill struggle.

These days the Chinese national oil companies (NOCs) have long shifted their focus from leftover assets in Africa to other parts of the world, including North America. The growth in their overseas oil production has been phenomenal. But it has come at a price. Earlier this year Moody’s estimated that the debt of Chinese state owned enterprises (SOEs), of which the NOCs form a major part, had risen to about 115 % of China’s GDP, higher than for any other country in the world.

There are a number of questions that I want to address in this paper. Where did the Chinese NOCs invest? Did they overpay? What were their objectives to go abroad and were they met? And perhaps most of all: have the Chinese NOCs now become global energy powerhouses or giants on shaky foundations?


Chinese NOCs: what kind of companies?

A heartland of mature onshore fields.  Unlike some of its neighbors (e.g., Japan or S. Korea) China has a large domestic oil production. The major fields were found in the 1950’s and 1960’s. The largest field, Daqing, has produced over 10 billion barrels and is still producing close to 700,000 barrels per day. In spite of frantic efforts, later exploration has enjoyed much more limited success. In 1993 consumption overtook domestic production and since then consumption has increased fourfold (whereas domestic production has only seen limited growth). The large dependence on oil imports (currently China imports about 62 % of its oil) is a key issue for China’s energy security.

Today, China is still the fourth largest oil producer in the world. But the bulk of its production comes from very mature fields such as Daqing, which by now experience high water cuts. It is only by intense (and costly) enhanced oil recovery methods that decline can be limited. As a result China’s onshore production is not low cost, of the order of 30 dollars per barrel on average (with a marginal cost that is much higher). Western publicity of Chinese oil companies tends to focus on their overseas acquisitions but the heartlands of these companies are mature conventional fields and their core technical expertise is maximizing recovery from these fields.

Chinese NOCs operate in a different way compared to the western majors. Their preference is to do as much as possible in house (including the use of in house service companies). If this is not possible they tend to use Chinese service companies and only as a last resort (if specialized knowledge is not available in house or in China) western service companies. Activities such as logistics and catering are done in house. Their workforces are much larger than those of western firms with similar production (e.g., CNPC employs about 550,000 people).

Government owned, not government run.  Initially oil production, processing and distribution were controlled by the Ministry of Petroleum Industry (the forerunner of CNPC) and the Ministry of Chemical Industry (the forerunner of Sinopec). In the 1980’s these ministries were converted into state owned enterprises (SOEs) and they both became integrated oil companies (be it that CNPC still has a bigger focus on the upstream and Sinopec has a bigger focus on the downstream). A third major SOE was added (CNOOC, China National Offshore Oil Company) and to date these companies (generally referred to in China as “the big three”) dominate China’s oil industry. Each of them comprises a wholly state-owned holding company and a listed subsidiary for which domestic and overseas shareholders own a minority stake (e.g., PetroChina in the case of CNPC).

To date, the heads of CNPC and Sinopec are of ministerial rank in China’s hierarchy (a higher rank than the much smaller government agencies that oversee them). To date there is no formal Ministry of Energy in China. The result has been described as “ineffective institutions and powerful firms”. The NOCs are owned by the state but not run by the state. According to an IEA report, “the top executives of the NOCs are deeply connected to the top leadership of the government and the CCP (Chinese Communist Party); they must wear two hats, as leaders of major commercial enterprises and as top Party operatives. It is in the interests of both the government and the Party that the NOCs are commercially successful, and that they secure adequate oil and gas supplies. Leaders have a great deal of freedom in how they achieve these aims, and those who fulfill them have leverage in bargaining for future promotions.” An extensive overview of the structure of the Chinese oil industry can be found in a recent OIES report.

Whilst NOCs will never omit a reference to China’s national energy security it seems that their own commercial interests are as strong a driver (if not the dominant one). There is no well coordinated master plan for China’s energy policy and overseas investments. Instead there are vague overall guidelines in an opaque environment.

The limited oversight and the opaque way in which overseas assets are acquired or work is contracted out create an environment where widespread corruption is possible.


The early days of going out: Sudan

The early 1990’s saw a number of developments that were of key importance to the Chinese oil industry and enabled them to go abroad. At the 1992 14th congress the CCP announced it would institute a “socialist market economy with Chinese characteristics”. Deng Xiaoping, retired from his official functions and yet at the height of his influence, believed the economic benefits of capitalism could be combined with the CCP guidance of a centralized and technically knowledgeable political system. Part of this economic reform policy involved the concept of “going out” (zou chuqu), investing surplus Chinese capital abroad to gain access to foreign markets, natural resources and advanced technology.

In 1993-1994 the Chinese government relaxed domestic oil prices, improving the financial situation of the NOCs and enabling them to invest abroad.

For the oil industry going out arrived at an opportune moment. In the early 1990’s it had become clear that domestic production could no longer keep up with consumption. The absence of exploration success and the increasing maturity of China’s producing fields implied that better opportunities for investment existed abroad. The go ahead to go abroad presented a huge opportunity to Chinese companies but also – given their complete lack of experience in operating or investing outside China – a huge challenge. But their long term aim was clear: to become competitive global businesses and to emulate the western IOCs.

Initially they started out as operators in a limited amount of countries (e.g., Sudan and Kazakhstan) with a relatively high political risk. At this time Chinese NOCs still lacked the financial muscle that they enjoyed later on and they had little choice but to go for these risky areas.

The largest of these ventures is the CNPC development of the Southern Sudan oil fields. It is also the one that has received by far the most attention in the western media. It has become the defining story for China’s investments in Africa, generating considerable reputational damage. Luke Patey’s “The new kings of crude” gives a well documented and balanced overview of CNPC’s Sudan venture (the remainder of this section is mostly based on it). It also paints a fascinating story of the pain of Chevron’s geologists (after years of hard work and exploration success having to leave the country for political reasons), the substantial achievements in development of the Chinese (establishing oil production and export in record time) and the difficult choices that the Chinese subsequently faced (with Sudanese leaders interested in power rather than their people’s wellbeing).

Throughout the late 1970’s and early 1980’s Chevron ran a major exploration campaign in Southern Sudan. It was Chevron that found the Heglig field and started the work on an export pipeline. Then things started to fall apart. An attack by Southern Sudanese rebels on Chevron’s base camp (with three fatalities) was followed by a worsening of the political environment, forcing Chevron to put things on hold. By the late 1980’s the National Islamic Front came to power and the new central government threatened Chevron to resume operations or face expulsion. A new Chevron board turned out to be less committed to the project. Making a major additional investment in a country torn by civil war was just too risky for them (also given the low oil prices after the 1986 crash). They sold their assets to a local company for a mere pittance and walked away from a 1 billion dollar investment.

During the following years domestic and small western companies found themselves unable to make significant progress (to the frustration of the Sudanese government), lacking the financial and technical clout to develop a major new oil province at a large distance from shore.

By 1995 the Sudanese search for an operator able to unlock these major finds linked up with the Chinese search for overseas opportunities. It is easy to see why CNPC was interested: significant oil had been found and although field development required a large effort it was the kind of work (development wells, pipelines) that was well within their capabilities. Chinese banks were willing to finance with loans of (up to that moment) unprecedented magnitude. With the limited choices CNPC had it was an opportunity to good to walk away from.

Oil flowing from the Southern Sudan oil fields through a 1500 km pipeline to the Red Sea by 1999 was a major achievement for CNPC. In the preceding four years they threw everything at it that they had, sending out their best teams to their most important overseas venture. They built up an entire oil infrastructure, including a local refinery. The continuing political unrest and occasional hostage taking (or worse: killing) did not deter CNPC. In any case the grueling circumstances and low safety standards were a greater danger to Chinese workers than the Southern Sudanese rebels.

During the following years Sudan’s oil production soared (to a peak of 470,000 bpd in 2007) and the CNPC Sudan venture was by far the largest producer and profit maker of the Chinese NOCs’ overseas ventures.

But after 2005 things gradually started to become more difficult. The number of incidents started to rise and the fallout of the reputational damage of the Sudan venture started to become more clear. Sudan was becoming a major hindrance in the Chinese NOCs’ overseas investments and attempts to get access to western technology. Following the large initial investments the venture gradually went into cash cow mode. Investments in enhanced recovery, needed to crank up the recovery factors, were postponed. As a result recovery factors of these fields have remained low (e.g. 23 % for Heglig, which is considerably lower than the 30 – 50 % that has been achieved for similar high net to gross sandstone reservoirs in other parts of the world). The rapid severe water cut that these fields experienced in the 2005-2010 period suggest they have been producing too fast, maximizing profit in an unstable country that was now about to split up.

For CNPC Sudan was initially a major success story. The subsequent collapse of production after Southern Sudan’s secession in 2011 has been a major disappointment, however. To this day, Sudan and Southern Sudan are arguing about pipeline fees for the transport of Southern Sudan oil through the Sudanese pipeline. The Chinese are doing their best to keep both parties happy and remain unsuccessful in doing so (in the words of a Southern Sudan oil minister: “but Jesus said one cannot serve two masters”). Political risks (both within Sudan and the reputational damage in the western world) had been severely underestimated.


2009-2013: overseas investment explodes

Eventually, the overseas investments of the NOCs took off in earnest in 2009. The figure below (from a presentation by SIA energy) gives an overview of Chinese NOCs acquisitions in the 2005 – 2013 period. A total of US$ 123.5 bn was spent by the three Chinese NOCs during this period, primarily between 2009 and 2013.

China paper fig1

Apart from being of a much larger magnitude the nature of Chinese NOCs’ overseas investments in the 2009 – 2013 period is markedly different from the early investments in countries like Sudan, Kazakhstan and Venezuela. There is a shift from operated assets to non operated assets, from a limited set of high risk countries to investments well spread all over the world and from primarily onshore, conventional assets to a full range of asset classes (including unconventional, deepwater and oil sands).

Several reasons lie behind this shift: the scarcity of Sudan like opportunities (large amounts of relatively low-cost, onshore conventional oil), the wish to share risk (both technical and political), the wish to not make very large investments in a single high risk country like Sudan (were the total investment eventually amounted to some $ 20 bn) and the increased importance to get access to western technology (as remaining opportunities tend to be associated with unconventional, deepwater or oil sands deposits – none of which relate to the core technical strengths of Chinese NOCs).

Landmark acquisitions during this period were the $ 15 bn Nexen takeover by CNOOC in 2013 (following a 2005 failed attempt by CNOOC to take over Unocal, in spite of putting a bid on the table that was over 10 % higher than the eventually successful Chevron bid) and the Addax takeover by Sinopec.

The question whether the Chinese NOCs did systematically overpay has generated a lot of discussion. Several papers (e.g., by Derek Scissors) have maintained that this is the case, often within the context of increasing Chinese influence in general. Many reports on Chinese acquisitions contain statements that they “again overpaid wildly” but I have seen very few systematic studies. The few I have found (e.g. a very interesting paper by Anatole Pang, one of the few papers written by someone with Chinese industry experience) were academic studies that claim they found no evidence for systematic overpaying. As these studies are based on the cost of reserves I tend to doubt their conclusions. A deal where say 2 dollar per barrel of proved reserves is paid can be a deal that is worse than one where say 20 dollar per barrel of proved reserves is paid; it all depends on development costs, tax regime, etc.

I think that looking at takeover premiums for acquisitions of publicly listed companies is the best way to deduce whether Chinese NOCs did overpay. Based on this it seems likely that Chinese NOCs did indeed overpay – by an amount of the order of 20 – 50 %. Where publicly traded companies have been acquired the premiums paid by Chinese NOCs have been hefty. Premiums paid for the Addax and Nexen takeovers were 47 and 60 % respectively; significantly above the average premium in the energy sector of about 30 – 40 %.

In takeovers of assets that were not listed they have frequently outbid competitors by significant amounts (I am not aware of any examples of the reverse).

Several factors may contribute to overpaying. Chinese NOCs may feel overpaying is necessary to overcome political resistance and to preclude a long bidding competition that may generate adverse publicity. Government approval is required and, once obtained, may be an incentive to come to a successful bid. Failed takeovers may be seen as loss of face. Government policy for the NOCs was focused on volumes and growth rather than value until recently. And finally access to funding at relatively easy terms by Chinese banks may provide less of an incentive to bargain hard for a lower price.

Nevertheless, the financial performance of Chinese NOCs’ overseas acquisitions is not so much hampered by paying more than their competitors but rather by the unfortunate timing of their acquisitions. By far the greatest amount of takeover activity took place in the 2009-2013 high oil price world. A lot of money was spent on high production cost assets, such as (Canadian) oil sands or (North Sea) mature fields that were bought at the peak of the market. These assets have performed particularly poorly in the post 2014 low oil price world.

An example is the 2012 acquisition of a 49 % stake for $ 1.5 bn in Talisman’s UK assets by Sinopec. Relatively high field decline rates, a high downtime of ageing facilities and increasing estimates of future abandonment costs limited the attractiveness of these assets already in a high oil price world (many North Sea operators have been trying to divest these kind of assets for years, with few takers). With the 2014 oil price collapse this turned into a disastrous cocktail and the poor performance of its UK assets threatened to bring down Talisman as a whole (a company already weakened by low American shale gas prices). Efforts to further divest their North Sea assets were unsuccessful and in 2014 the company was taken over by Repsol. Repsol was interested in other parts of Talisman and saw little value in the North Sea assets, especially when oil prices turned out to be lower for longer. For Sinopec a $ 1.5 bn investment turned into an abandonment-related liability within 3 years. Sinopec’s subsequent legal demand for compensation from Repsol is seen as having a very low chance of success. It is a sign of their frustration, a way to put pressure on Repsol (which values good relations with Chinese NOCs with whom it cooperates elsewhere) and stakeholder management with respect to the Chinese government.

Another example is CNOOC’s $ 15 bn Nexen takeover. Nexen, a Canadian company, is heavily exposed to high cost Canadian oil sands. Apart from its high costs, these assets suffer from being landlocked. The US blocking the Keystone XL pipeline will now result in a lower price for Canadian oil for a longer time. Even among other oil sands assets Nexen’s assets are relatively high cost and have been recently plagued by operational issues.

Many Chinese and Chinese companies lack a profound understanding of the western world (in the same way as many in the western world lack an in depth understanding of China). China should perhaps be seen as a parallel universe instead of just another country. As a result they are not optimally equipped to fully analyze the technical, political and environmental risks associated with an overseas investment.

Off course many western companies have had their share of acquisitions turned sour. But I would argue that on average they have had a better track record (paying lower takeover premiums, being more reluctant to invest in high cost mature North Sea fields or Canadian oil sands, making a better assessment of political and technical risk).


Recent developments (2014 – present)

From 2014 onwards overseas investments have decreased dramatically. The current low oil price environment definitely plays a role here. Profits have dramatically decreased as a result of the low oil price and write offs of previous acquisitions. Internal funding of acquisitions has become more difficult. Funding is still possible, however, and the current low oil price environment is not the only reason for the overseas investments drop.

Management of the Chinese NOCs is currently under intense pressure due to the ongoing reforms of SOEs (triggered by their poor performance) and corruption probes. A high publicity audit of $ 10 bn Angola investments by Sinopec revealed the shady deals with Sonangol through obscure companies known informally as the Queensway group. Angolan assets put on the market by western oil companies landed up (upon Sonangol exercising its preemptive rights) with companies such as China Sonangol, owned jointly by Sonangol and Chinese middlemen (but funded by Sinopec). When these assets would eventually be transferred to Sinopec (more likely so for the poorly performing assets) it would be at a substantially higher price. The Financial Times reporting on the Queensway group is one of the few cases were investigative journalism has been able to unravel the dealings of Chinese NOCs and their middlemen in some detail.

Over the last 2 years former presidents of both CNPC and Sinopec have been convicted for corruption. Many other high ranking managers have been placed under investigation or convicted. The most prominent case was that of Zhou Yangkang, who after his spell as CNPC president eventually became a member of the CCP standing committee, China’s top decision making body. Corruption may have been but a welcome pretext (the CCP has to be seen as being tough on unpopular corruption); the underlying reasons are more likely to be a combination of a power struggle within the CCP and the removal of people opposed to the reform of poorly performing Chinese SPE’s (as well as the poor performance in itself).

Knowing that unsuccessful overseas acquisitions can eventually result in convictions (be it for corruption rather than the acquisitions themselves) has made the Chinese NOCs much more cautious. Future acquisitions should involve smarter investments in quality assets, focusing on value rather than volume.

Cost cutting is now starting to result in a significant drop in domestic oil production (which still accounts for over 70 % of the total production of Chinese NOCs). 2015 is likely to have been the year that Chinese domestic oil production has peaked. By July 2016, production had dropped by more than 8 % from its peak.



On the positive side, I would consider the Chinese NOCs to be able operators for their domestic (primarily onshore, conventional) production. Average cost of the order of 30 dollars per barrel imply that these assets generate substantial profits.

Twenty years of overseas investments have resulted in equity production that is about 30 % of their total production, amounting to over 2 million barrels per day. But what else? Surely, if this were to be a true success story, it should not be just about growth.

If it is about energy security it should be noted that oil from the NOCs overseas assets is sold on the open market – and is going to the refinery that is best suited for this quality of oil and is willing to pay the highest price (and not necessarily to China). Control over the strait of Malacca (through which about 80% of China’s oil imports is transported) seems a much bigger issue here.

If it is about profitability than I feel that their record of overseas acquisitions is a mixed bag – at best. What hampers them in this regard is their record of overpaying and the timing of the bulk of their acquisitions, which coincided with the 2009-2014 high oil price world.

If it is about technical capabilities I note that, whereas they have massively invested in deepwater, oil sand or unconventional, they have done so mostly as non-operators. The technical knowledge acquired by being a non operating partner (or by acquiring a company that is subsequently run at arm’s length) is not of the same order as the technical knowledge needed to operate and grow organically. I do not see the Chinese NOCs operating e.g., deepwater fields across the globe, in a way that the western majors do. Their operated production is still primarily domestic conventional production.

I do not think that emulating the western IOCs in operating different types of assets across the world or emulating the US tight oil industry in Chinese tight oil are successful business models for Chinese NOCs. For China as a country I think it would be more beneficial to put a greater emphasis on conventional oil and gas within the Asian continent (in particular, Kazakhstan, Russia, Iran/Iraq), thus aiming at a greater share of conventional assets (closer to the NOCs technical strengths) in locations close to China that at least in part export oil by pipeline to China rather than by tanker through the strait of Malacca. Kazakhstan has so far been one of their more successful overseas investments.

The strength of Chinese NOCs (apart from their domestic production) is financial rather than technical. A western company with a similar record of acquisitions would be in severe financial trouble. Not so the Chinese NOCs: the absence of public shareholders with a short time horizon and the funding by Chinese banks imply that for them the rules of the game are different. So far, “China Inc” has bailed them out.

Their rapid growth has been fueled by profits from domestic production (in particular in a high oil price world) and by debt. Chinese banks have been more than willing to fund. Chinese people, with their high savings rate (and limited ability to move funds abroad) have few alternatives for their savings. It is for them to ultimately pick up the bill.

Chinese SOEs in financial trouble have so far been bailed out. This does not solve the problem though in the long term – it just shifts the problem upwards to the next level (which is basically “China Inc”). When evaluating the strength of Chinese NOCs one cannot look at these companies in isolation; one has to look at them as “part of China”.

In the long term, the strength of China and Easternisation are they to stay. How could it be otherwise? As Lee Kuan Yew, the former prime minister of Singapore stated: “Theirs is a culture 4000 years old with 1.3 billion people, with a huge and very talented pool to draw from. How could they not aspire to be number one in Asia, and in time the world?”

But in the short term: when will Chinese debt and the ability of China to bail out all its poorly performing SOEs hit a ceiling? At some stage pumping more debt into increasingly unattractive projects has to stop. At this stage Chinese debt is growing at three times the rate of the Chinese economy. With an increasing share of problematic loans the question is not if, but when, there will be a Chinese debt crises. Chinese that have the means to do so have now started to take their money out of the country.

The Chinese NOCs are giants on shaky foundations for a simple reason: they are part of an even bigger giant – on even shakier foundations.

China paper fig2

Oil Companies and Climate Change


Climate change is real. The well documented increase in global temperature levels, the link with greenhouse gases and the again well documented rise in atmospheric CO2 levels (the main greenhouse gas) should, for all practical purposes, no longer leave any room for doubt. The vast majority of earth scientists and engineers working for oil companies do not doubt and have not done so for a long time. What has changed is the perception. From one of many problems that the world faced in the 1980’s (famine, nuclear weapons, overpopulation, “waldsterben”) this one struck us a difficult problem but one that was far away, for our children and technological progress to solve. These days we have seen that the last decade was the warmest decade on earth recorded so far. The decade before that was the second warmest. It has started to affect our lives in earnest.

The major oil companies accept that climate change is real. Furthermore they do not close their eyes for technological breakthroughs such as the dramatic decrease in price for solar panels (hopefully followed by a similar development in energy storage). If oil companies have been reluctant to invest in solar power or wind power it is not that they underestimate these technologies, but rather that they feel that solar panel fabrication is not something that can become sufficiently profitable for them or that they do not want to be dependent on subsidies. Image is important if one is to be dependent on subsidies. Oil companies are not popular; something that is unlikely to change.

The major oil companies see their strength in finding, producing and refining hydrocarbons. They expect that oil and gas demand is there to stay for several tens of years. They accept that the oil and gas industry will eventually become a sunset industry (later rather than sooner, but still). They would welcome a functioning carbon tax system. In their view it would reduce uncertainties and create a more level playing field (more so than for a system of unpredictable government subsidies and other measures to promote renewables) from which gas, the cleanest fossil fuel, could profit.

Implications for oil demand and price

Population and economic growth will add to oil demand. Increasing efficiencies, higher taxes or carbon pricing and the rise of renewables will reduce demand. How exactly this will pan out over the coming decades is highly uncertain (a key uncertainty being how quickly electric vehicles will gain market share). Statoil’s recent update of their long term scenario planning exhibits a large range for 2040 oil demand from 80 to 115 mbpd (million barrels per day). For comparison: current oil demand is just over 95 mbpd. The lower end member comes from their Renewal scenario that results in CO2 emissions in line with the target to limit global warming to two degrees Celsius. This scenario requires that the recent non-binding COP21 targets are not only met but are significantly exceeded. The higher end member comes from their Rivalry scenario where a lack of thrust and coordination result in a world where security of supply and economic growth for individual countries play a bigger role, at the expense of global climate concerns. Scenarios from other companies and organisations exhibit a similar large range for future oil demand.

Even the optimistic Renewal scenario implies that significant investments are still needed to meet a 80 mbpd oil demand in 2040. Oil field decline implies that without any activity a fields production drops on average by 8-9 % per year. Thus the oft quoted red queen analogon (“one has to keep running in order to stay in the same place” from Lewis Carroll’s Through the looking glass, and what Alice found there) remains valid. The difference between Rivalry and Renewal is that for Rivalry the oil industry needs to keep running a little faster, for Renewal it can run a little slower.

The oil industry can, and will, react to changes in demand and price in a matter of years (as we are currently seeing). It is in their best interest to do so (and they have a track record of doing so – if anything of over reacting). The energy transition on the other hand will be a matter of tens of years. I would thus argue that the energy transition is likely to result in a long term reduction in volumes but not to a reduction in price (at least not beyond the usual commodity boom and bust cycles). With relatively small changes in volumes and large swings in price it is the oil price that has by far the largest influence on oil companies’ profits.

Stranded assets and carbon bubbles

NGO’s like Carbon Tracker have made significant inroads with a theory that appeals through its simplicity. Starting with the emissions associated with a two degrees global warming limit one can derive the fossil fuel reserves (“carbon budget”) that can be burnt under such a constraint. Comparing these with the reserves of fossil fuel companies shows that a significant part of their reserves can not be burnt (“stranded assets”). With fossil fuel companies’ valuations based on these reserves this implies that their shares must be overvalued (“carbon bubble”).

Lumping all fossil fuels together, regardless of their economic value and associated emissions, is a severe simplication. I would certainly hope that the carbon budget of oil (a premium fossil fuel whose high energy density makes for instance flying possible) or gas (a relatively clean fossil fuel) can be increased at the expense of that of coal.

But the main issue I have with this theory is of a different nature: it lumps together all different types of reserves (proved, probable, possible; developed, undeveloped). In reality the value of a barrel of possible reserves, in an area where exploration may or may not prove the existence of oil, that may or may not be commercially developed, is only a tiny fraction of the value of a barrel of proved reserves that has already been developed (with significant investments for development already made). It are these low value possible reserves that run a risk of being stranded, rather than the high value proved reserves.

Proved reserves typically only account for 15 – 30 % of the total resource base of an oil company and account for 80 – 90 % of the value of a company (a detailed overview can be found in a recent IHS report). That is not surprising, given that proved reserves are either developed or in the process of being developed (for most companies project sanction is a prerequisite in order to book proved reserves). These are the assets were large investments have taken place or are currently taking place. In general, the investments related to developing a field are much larger (1 or 2 orders of magnitude) than the finding costs.

With typical proved reserves over production ratios of the order of 10 – 15 the risk that proved / developed oil reserves will turn out to be stranded is very small. Production from these assets falls far short of demand, even for a scenario which limits global warming to two degrees.

It are not the oil companies’ producing assets that are at risk but the long term continuation of their business model. But this is something that has been seen to be at risk for a long time already, be it for a different reason: the difficulties that oil companies have to replace reserves (even when spending vast amounts of money). Hence the relatively low price earning ratios of oil companies; typically of the order of 8 – 12 before the 2014 oil price drop.

A strong case can be made for carbon budgets and stranded assets in general. But those oil assets that may turn out to be stranded have been attributed a very small value. Hence I can not see a case for a bubble in the valuation of oil companies on the basis of stranded assets due to climate concerns.

All the world’s a stage and each much play a part

NGO’s like Carbon Tracker, in the words of Dieter Helm, tend to muddle up the public and the private domain. There may be a strong case for not investing in fossil fuel companies but I feel it is a case that should be based on ethical grounds rather than financial grounds (as has been done for the weapons and cigarette industries).

Aiming to reduce oil-related CO2 emissions by limiting investment in the oil industry might actually be counter-productive. Before we know it we could again enter a period of relatively high oil prices. I would much rather see high consumer oil prices due to a significant carbon tax (and using revenues for more meaningfull purposes in the OECD realm, including promoting renewables) than due to high oil prices at source level (resulting in increased revenues for Middle East producers).

NGO’s function as a lobby for renewables as well (be it a lobby that, unlike the fossil fuel lobby, has the aura of sainthood). They may well prefer direct subsidies for renewables to a carbon tax (replacing coal by gas being a very cost efficient way to reduce emissions in the short term). It is up to governments to find the right balance between a carbon tax to reduce emissions in the short term and direct subsidies to research and renewables to promote the technologies we need for a long term solution.

Oil companies have an obligation to their shareholders to maximise profits – within the limits of the law and a companies code of conduct. They are under no obligation to invest profits from oil into renewables or otherwise to contribute to solving matters that are of a public concern. It is up to governments to set the boundary conditions for the oil industry and to tax the use of fossil fuels (whether to generate revenue in general or for the promotion of renewables, to alleviate the adverse effects of fossil fuels or to discourage their use).

I feel that, from a financial point of view, oil companies will be better of by sticking to their core business and by accepting that they are likely to be in a sunset industry – in the long term. Whilst some of their assets may be stranded I cannot see the case for a carbon bubble based on stranded assets.

Black swans for the oil industry may exist but I feel they are of a very different nature. Should low cost Middle East producers change their oil policy and start to maximise volumes rather than revenue (whether due to political issues such as Saudi Arabia vs Iran tension or due to a perception that “the end of oil is near”) then this could result in oil prices being lower for longer for real. Should western governments or jurisdictions decide that oil companies should pay for the adverse climate effects of the past use of fossil fuels (something they happily allowed at the time) then this could have severe effects on oil companies profits. But let us not fool ourselves: the adverse effects of the use of fossil fuels on climate have been abundantly clear for many tens of years to governments, research institutes and companies alike. The readyness of many to demonise oil producers, whilst readily giving absolution to oil consumers, is striking.

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



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 reportSaudi 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.



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 (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.

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.

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.


Is there a carbon bubble?


Climate change is for real. The well documented increase in global temperature levels, the link with greenhouse gases and the again well documented rise in atmospheric CO2 levels (the main greenhouse gas) should, for all practical purposes, no longer leave any room for doubt. The vast majority of earth scientists and engineers working for oil companies do not doubt and have not done so for a long time. What has changed is the perception. From one of many problems that the world faced in the 1980’s (famine, nuclear weapons, overpopulation, “waldsterben”) this one struck us a difficult problem but one that was far away, for our children and technological progress to solve. These days we have seen that the last decade was the warmest decade on earth recorded so far. The decade before that was the second warmest. The decade before that was the third warmest. We are all to blame. Or at least the two billion people or so responsible for most of the CO2 emissions.

IOC’s (international oil companies) accept that climate change is for real. Furthermore they do not close their eyes for technological breakthroughs such as the dramatic decrease in price for solar panels (hopefully followed by a similar development in energy storage). If oil companies have been reluctant to participate in wind power or solar power it is not that they underestimate these technologies, but rather that they do not want to be dependent on subsidies or feel that solar panel fabrication is not something they can become competitive in. If you are dependent on subsidies it greatly helps to be sexy and popular. Oil companies are not; something that is unlikely to change.

IOC’s see their strength in finding, producing and refining hydrocarbons. They expect that fossil fuel demand, for oil and gas in particular, is there to stay for several tens of years. Population and economic growth will add to demand. Increasing efficiencies, higher taxes or carbon pricing and the rise of alternatives (more easy in electricity generation, more difficult in transport) will reduce demand. The OPEC cartel of low cost oil producers and its key member Saudi Arabia have a long term policy of keeping oil prices high, a strategy that is unlikely to change. In a true free market we would only produce low cost oil. OPEC market share would be higher but OPEC revenues would be lower, given that oil prices would be dramatically lower (even compared to the $ 40 per barrel or so that we are currently seeing in late 2015). IOC’s accept that the oil and gas industry will become a sunset industry (perhaps later rather than sooner, but still). They would welcome a functioning global carbon tax system. In their view it would reduce uncertainties and create a more level playing field (more so than for a system of unpredictable government subsidies and other measures to promote renewables) from which gas, the cleanest fossil fuel, could profit.

Fossil fuels demand

Fossil fuels market share will in likelihood decrease. To what extent is quite uncertain, fossil fuels market share in 2035 ranges from about 63 to 80 % for different IEA scenarios (from current 81 %). The lower end member number is the approximate fossil fuel share for a scenario that (likely) limits global warming to 2 degrees (450 scenario). In this scenario the 2050 market share further reduces to about 50 %. The higher end member basically reflects business as usual (noting that fossil fuels market share over the last 40 years has hardly changed).

The high fossil fuels market share in 2035 for the IEA 450 scenario is a sobering thought and illustrates the magnitude of the challenge we are facing to limit global warming to acceptable levels. Even with a dramatic decrease of solar power cost and a concerted effort in at least some OECD countries (e.g. Germany’s Energiewende) we have only just started to materially reduce fossil fuels market share. Most inroads are being made in electricity generation – yet electricity currently only accounts for approximately 20 % of the total final energy consumption on a global basis.

fig 31

Stranded Assets

Many NGO’s state that stranded fossil fuel deposits imply a “carbon bubble” for stock market valuations of oil and gas companies (e.g. the Carbon Tracker Initiative).

Are there fossil fuel deposits that are stranded? When lumped together (coal, oil, gas; proved, probable, possible) that is a no brainer. Off course we do not want to burn them all. The resulting temperature rise will be significantly larger than what is deemed acceptable. Even a large, unexpected breakthrough in CCS (making it both cost effective and socially acceptable) would probably only reduce the amount of stranded assets.

But are we talking about coal, oil or gas? In this paper I want to focus on oil and gas and on the valuation of IOC’s. Are we looking at proved reserves, probable or possible reserves? Developed or undeveloped reserves (note that developed and proved reserves for a company are not the same, although it is expected that the numbers are similar given that most companies will not book proved reserves before FID has been taken)? Are we looking at low cost OPEC oil or high cost non OPEC oil (with a much lower reserve life)? The more meaningful question is: are IOC’s overvalued because their value estimation is based on assets that cannot be fully produced. If some existing assets cannot be fully produced, or if new assets can hardly be developed, and if investors would not be aware of this and attach value to these assets late production life, or to the ability of oil companies to find and develop new assets, then there could truly be a bubble.

So how about the risk that developed oil and gas assets are stranded? The figure below ilustrates that at least the developed oil and gas reserves of IOC’s are unlikely to be stranded – even for a 450 scenario that likely limits global warming to two degrees. The reason is simply the limited reserves that oil companies tend to have. Proved reserves vs production ratios of 10 – 15 are common. That in itself is a big problem for oil companies but is does imply that at least their developed assets can be produced. Different studies exist (one can vary the amount of oil, gas and coal that can be burned under a 450 scenario, the depletion rates of existing assets, etc) but the chance that a large part of existing oil and gas assets cannot be produced seems very low. Developed coal assets run a much greater risk. So do undeveloped oil and gas assets.

The question is not whether IOC’s developed / proved reserves can be produced. They can and will be. Future demand is a much greater question mark. Will developing countries really be ready to walk away from wealth generation by a phase of energy intensive growth fueled by low cost coal (thus not following the path that China has taken for the last 20 years). Will they feel adequately compensated by the developed world?

fig 32

Oil Company valuation

Proved, probable and possible reserves all have a bearing the valuation of an oil company. Proved reserves typically only account for 15 – 30 % of the total resource base of a company but also typically account for 80 – 90 % of the value of a company (a detailed overview can be found in a recent IHS report). That is not surprising, given that proved reserves are either developed or in the process of being developed (most companies require FID to have been taken). In other words: these are the assets were large investments have taken place in the past or are currently taking place. In general, the investments related to developing a field are much (typically 1 or 2 orders of magnitude) larger than the finding costs. Much less value is attributed to undeveloped, possible reserves and probably rightly so. For a long time the market has had doubts on the long term sustainability of IOC business models. That has been primarily based on the lack of access to cheap oil provinces and the difficulties that IOC’s have to replace reserves, even when spending vast amounts of money. More recently the advance of shale oil and climate concerns have started to play a role as well.

The value attributed to possible oil and gas reserves is at risk in a 450 scenario world. Long term lower than initially expected demand may result in more limited new developments. The ability of IOC’s to find and develop new oil may have less value. Given the limited value attributed to these reserves this seems unlikely to have resulted in a major bubble, however.

A carbon bubble being unlikely does not mean that the future for IOC’s looks that good. As I put it in a previous blog, IOC’s have been facing a number of issues 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
– They have trouble replacing reserves given their lack of access regions with low cost, easy to find oil
– They are gradually becoming gas producers rather than oil producers, given the much greater geographic spread of gas reserves. Gas is likely to be systematically less profitable.
– They are not well suited (company culture, strengths) to profit from the US shale oil / gas boom.
– Many of the big oil and gas discoveries in other parts of the world have been made by smaller niche exploration companies

In addition we are now seeing that lower than expected demand (implying a downward pressure on prices) is there to stay:
– Lower growth of less energy intensive economies
– Carbon tax and other measures to reduce CO2 emissions
– Increased competitiveness of renewables, in particular solar, for power generation. Potentially further aided by developements in energy storage and fully electric vehicles

The relatively low IOC valuations suggest that many of these risks are already incorporated in the stock price. Until the recent oil price drop P/E ratios for IOC’s have been about 8 – 12. Over the last 15 years IOC stock values have been trading at an increasing discount compared to their assessed Net Asset Value (see figure below). In any case the IOC risks and issues as listed above are well known in the industry. This is hardly something that is below the radar for investors and fund managers (making a bubble less likely). That does not mean that IOC shares cannot drop significantly over the coming years. Should this happen, however, this will much more likely be caused by low demand (and resulting low prices) than by stranded assets. And of course the reverse may happen in case of high demand vs supply.

fig 33

Concluding remarks

A part of fossil fuel assets will not be produced for sure. More so for possible reserves and more so for OPEC reserves (and more so for coal in general). Less so for proved reserves and less so for non OPEC reserves. IOC valuations are primarily based on proved reserves and these are unlikely to be stranded (basically because there are so little of them, with typical IOC reserves production ratios of 10 – 15). A carbon bubble because of stranded assets thus seems unlikely.

To gradually shift to sunset mode may be the best option for IOC’s: accept a long term gradual decline of production and remain profitable by being very disciplined in spending capital (especially for exploration). Shareholder and NGO pressure as well as the current low oil prices currently enforced by OPEC will all be contributing to the capital discipline that the oil industry is not capable of when left to itself. High oil prices may be back within a few years. Consumers beware; all these stakeholders welcome high oil prices!