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 on saw 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.


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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.



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Record high US oil stocks mask falling global stocks

In spite of all the short term noise due to hedge fund trading: in the end it are supply and demand that determine the price of oil. Reliable estimates of oil stocks are essential to determine where supply and demand are going.

And here we face a dilemma. The oil market is a global market. But accurate and up-to-date estimates of oil inventories are only available for the US. After the first oil crisis the US government established the EIA and its weekly reports are closely watched by traders across the world. The IEA reports for other OECD countries are published on a monthly basis and are less accurate. Even less accurate are the estimates for non-OECD countries (countries that often regard these data as confidential).

But what is the relation between US inventories and global inventories? It seems the extent to which US inventories are representative for global inventories has been diminishing over the years.

Rising US oil stocks

Over the last few weeks the EIA has reported relatively small drops for US oil inventories. At this moment these inventories are still at record levels, close to 530 million barrels (about 30 million barrels higher than last year at this time of the year). As a result, WTI has difficulties staying above 50 dollars per barrel – especially during the last few weeks.

How to reconcile the high OPEC compliance to the agreed cuts with these record high levels of US inventories?

US 5 yr crude stocks

Falling global oil stocks

Oil traders are increasingly looking at recent start-ups that, using satellite tracking of tankers,

are trying to get a better picture of worldwide oil inventories and transports. On the basis of data from one of these companies (Vortexa), the Financial Times reported that the total amount of oil in supertankers (both stored and in transport) had diminished by 16 percent since the beginning of the year.

According to Bloomberg, oil stocks in the Caribbean have diminished by about 10 percent since February. The picture that emerges is one where oil from poorly (or not at all) reported stocks in producing countries, supertankers and from more remote locations (Caribbean, South Africa) has now started to move to major refinery centers (where they are accurately reported).

OPEC production cuts

It seems the OPEC cuts are now starting to influence global oil stocks. Influencing the most visible and accurate US stocks (which have the largest bearing on oil prices) takes longer.

Within OPEC, compliance to the agreed cuts has reached levels close to 100 %. For the non-OPEC countries contributing, compliance has reached about 60 -70 %. Even Russia is sticking to the deal (not that much of an achievement given that Russian production tends to fall at the end of the winter).

As a result the IEA now expects global supply to fall below demand  by about 1 mb/d in Q2 (assuming a continuation of the current measures).

IEX April 2017

OPEC will continue its current cuts

In my view the high US stocks have been masking falling global stocks. Large US storage facilities are efficient and low cost (and not the first locations where one takes oil out of storage). Non-OPEC supply outside the US is now falling, whereas US supply is rising.

The following appears to be the most probable scenario for the coming time:

  • OPEC continues its current cuts on the next meeting on May 25th. Stopping now implies not only a severe oil price drop (something they can ill afford) but also a lasting loss of influence and credibility. One day Saudi Arabia (the country bearing the largest burden) will no longer be able to bear the free riding of countries like Russia but that moment has not been reached yet.
  • The transition from oversupply to undersupply will gradually become more clear and will eventually result in falling US oil stocks as well.
  • Which opens the door to a gradual and limited rise in oil prices (the average expectation of a large number of experts: 60 dollar in 2018; 70 dollar in 2020). It will be a difficult and tortuous road.

From every nook and cranny oil is now coming out of storage. That implies that rebalancing of the oil market takes longer. But it does not imply that it will not happen.



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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.

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Oil markets: a turbulent 2016, an uncertain 2017

After two and a half years of opening up the taps (or rather: not closing them) OPEC has changed course in what is looking to be a gamechanger for the oil market. Market sentiment has shifted and the oil price has gone up by some 20 %. We can look back at a turbulent 2016 and look forward to an uncertain 2017.

OPEC defeated?

Some say OPEC’s decision to cut was a defeat. Was it really? OPEC (and most of all: Saudi Arabia) over the last two years has been trying to deal as good as possible with the difficult situation that the 2009-2014 high oil price world had created for them.

Would they, from 2014 onwards, have defended price instead of market share US tight oil production would have risen by about 2 mb/d by now (instead of the reduction of about 1 mb/d that actually materialised). The decline from non-OPEC conventional fields would have been 3 mb/d (instead of the 6 mb/d that materialised). For Saudi Arabia it would have been a repeat of the early 1980’s when they did defend price, resulting in a reduction of their production to a level as low as 2.5 mb/d before they gave up.

Two years of defending market share instead of price has resulted in a non-OPEC supply 6 mb/d lower compared to what it would have been otherwise. The large investment cuts in non-OPEC oil will reduce non-OPEC supply for years to come. That is major progress for OPEC. It has brought supply and demand close to equilibrium in 2017. Now a cut became a realistic option in order to bring higher oil prices forward. A 2014 cut would only have postponed the inevitable and increased the length of the subsequent painfull rebalancing period.

They will be disappointed by the resilience of US tight oil. US tight oil has been saved by drilling in the very best spots only, increased efficiencies and reduced service industry costs. Furthermore it has been saved by their investors and financiers – for whom accepting severe losses was a better alternative than to let them go bankrupt and cease operations.

OPEC has regained market share and, more importantly, some of their ability to move markets. US tight oil has survived with break even costs in the very best areas that are now at the lower end of the global non-OPEC cost curve. They have both paid a heavy price. But it is high cost non-OPEC conventional oil that has lost the most in this battle.

Why cut now?

First and foremost, markets have done their work and supply and demand have been approaching a balance, enabling a meaningful cut.

Budget deficits have troubled all producers. A country like Venezuela has been desperate for a deal. Unfortunately for Venezuela it has no clout whatsoever in OPEC. The defining push for the agreement has been given by Mohammed bin Salman (Saudi Arabia’s de facto ruler) and Vladimir Putin. The situation within their countries is such that both have good reasons to do so. MbS is aiming to solidify his grip on power. For that he needs to limit hardship for the Saudi middle class and provide hope for the rapidly growing (and increasingly unemployed) number of young Saudis. Saudi Aramco’s planned IPO will benefit from higher oil prices. Putin as well wants to limit hardship for the Russian population. He can not be as indifferent to the wellbeing of the Russian population as Stalin once was; his grip on power is more secure if he keeps the Russian middle class happy.

Saudi Arabia needed to see pledges from other producers (Iran and Russia in particular) to go ahead. These other producers needed to have confidence that limited cuts will give a substantial increase of the oil price – something that the initial market reaction in September upon the Algiers talks provided to them. Reaching a Vienna agreement became a must; not reaching it would have implied a substantial price drop, something they could ill afford.

OPEC spare capacity is at its lowest level since 2008. Iran is back at its pre sanction level of production and cannot raise production any further in the short term. Russian production is at a record level. Even if producers do not fully live up to their pledges, their ability to cheat and take away market share from Saudi Arabia has become limited. Saudi Arabia can be satisfied that cuts are shared. Iran and Russia can be satisfied as well; their pledges are not a great hardship for them.

What has changed?

Saudi Arabia has lost clout within OPEC. Iraq and especially Iran are challenging its dominant position. Their combined production starts to approach that of Saudi Arabia. Both have large undeveloped oil reserves, which can be developed at low cost, and are still producing way below their potential. In the long run they are likely to further ramp up production. After having been sidelined for a long time due to wars and sanctions both are now reclaiming their natural position in the OPEC pecking order. In the long term, reaching an agreement within OPEC will not become any easier.

Iran in particular by now seems in a better position to overcome periods of low oil prices than Saudi Arabia. Its economy, hardened by years of sanctions, is better equipped to do so and is less reliant on oil income. Saudi Arabia’s pivotal role in OPEC was based on its being the largest producer by far, its maintaining a substantial spare capacity and its large financial reserves that (in combination with a relatively small population) enabled it to better sit out a prolonged period of low oil prices. Some elements of this dominance are now starting to fall away and Saudi Arabia is no longer the sole pivotal nation within OPEC that it used to be.

Oil has always been linked to politics. Saudi Arabia has lost political clout in the Middle East. They are struggling to deal with a Shia encirclement. Their economy is solely dependent on oil and and is not performing well in comparison with countries like Dubai. The religious establishment is a blocker when it comes to reforming education and increasing the role of women in the economy. Their special relationship with the USA is deteriorating now that the USA is moving towards energy independence and more reluctant to prop up fundamentalist regimes. In the meantime Russia has gained influence, by intervening in Syria and by playing a key role in brokering the recent OPEC agreement.

For a long time Saudi Arabia has been a source of stability in the region and Iran a source of instability. That is changing now.

Where do oil prices go from here?

All ingredients seem to be in place to keep oil prices in 2017 at a systematically higher level than in 2016. Compliance will vary among the different producers. But the over 700,000 b/d cut from Saudi Arabia and other members of the GCC (Kuwait and the UAE) in itself is sufficient to bring supply and demand approximately into balance. Even if the level of compliance of other producers is as low as 50 %, the cuts will still lead to a meaningfull reduction of oil inventories.

As oil producers see that the deal delivers the promised rise in oil prices, they will be less likely to cheat – at least initially. The pledged, gradual cut from Russia involves little more than natural decline and a reduction or freeze of short term projects. Russian oil production has been maximised as much as possible over the last few months in 2016, to a level that may be difficult to sustain anyway in the first half of 2017.

Volatility will be there to stay as stories of cheating, outages and potential production increases from uncapped Nigeria and Libya abound. Notes to refiners about shipment reductions will be duly leaked to the media (something that has already started). But throughout the year we will be seeing a return to oil prices that are closer to the long term sustainable price of oil: that of the marginal non-OPEC barrel, somewhere near $ 60 – 80 per barrel.

And let us put things into perspective. The oversupply frequently described as a glut was no larger than about 2 % of global production, at its worst. OECD oil inventories have hovered around 65 days of supply in 2016; little more than 5 days above the long term average. It does not take that much oversupply to send oil prices plummeting. In the same way, it does not take that much undersupply to send them through the roof. One should not blame analysts too much for not being able to predict the oil price. But a bit of blame for underestimating uncertainties might be justified.

How will US tight oil react?

A main source of uncertainty is how US tight oil will react to higher prices. Tight oil’s shorter cycle time and a faster reaction to changes in oil price compared to conventional oil may keep a lid on oil prices. But to what extent?

If we compare a recent global cost curve of oil projects with a 2014 cost curve there are two developments that stand out. Firstly, the average breakeven cost has decreased substantially, from about $70 per barrel in 2014 to about $50 per barrel today. Secondly, over the last two years US tight oil has seen the biggest cost decreases and it has shifted towards the left (more competitive) side of the global cost curve.

For those US tight oil companies that have survived and that have quality acreage there now seems to be a great promise for the future: break even prices near the lower end of the global spectrum of opportunities and huge in place volumes. This is the background for the recent outperformance of share prices for companies active in the Permian (the US region with the lowest break even prices). Break even prices for the very best areas have dropped to about $30 – $40 per barrel. As a whole the US tight oil industry is estimated to need about $55 – $60 per barrel to maintain a flat production level.

There is one snag: break even prices quoted above are for current cost levels of the service industry, widely seen as being unsustainably low. How much will these costs increase once that activities pick up in earnest? Rystad Energy estimated that for the Bakken about 40 % of cost savings were structural (faster drilling, better well production) and about 60 % of cost savings were cyclical (primarily lower service industry costs, to a lesser extent drilling in the very best sweet spots only). When activities pick up significantly, break even costs are expected to increase by about 65 %. Current break even costs for the very best sweet spot areas would be expected to increase from $ 30 to $ 50 per barrel. Non core areas (that currently see little activity) could see an increase from $ 50 to $ 75 per barrel. Other studies have reached similar conclusions.

Quoting from a recent SPE panel discussion: “If oil prices stay below USD 55/bbl, equipment availability can be relatively smoothly managed in the Permian. But at prices from USD 60/bbl to 70/bbl all of a sudden all of the other plays come back, and then for sure we reach the threshold of equipment not being available”.

I feel that many analysts overestimate the ability of US tight oil to act as a swing producer. Firstly, things take time. Hiring drilling crews to man the often less efficient rigs that have now been cold stacked takes time. Hiring fraccing crews takes time. Getting permits takes time. It took two years before the effect of low oil prices on US tight oil production had materialised in full. Secondly, costs of drilling and fraccing follow the oil price. US tight oil will indeed keep a lid on oil prices. But to a smaller extent than what is often assumed.

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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 above can 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

A 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.


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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

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