US Shale Oil: drilling productivity and decline rates


  • The EIA drilling productivity report has been used to estimate decline rates in the Bakken, Eagle Ford and Permian light tight oil (LTO or shale) plays (Figure 1). The objective is to estimate how far production will fall in these plays in light of the sharp decline in US rig count. The rationale is to calculate the production level at which new oil production capacity added will cancel the declines and equilibrium is reached.
  • The shale drilling industry is highly dynamic. While rig count has fallen by about 60% in the 3 plays since end 2014 this is in part offset by rig productivity that has more than doubled in recent years. The rig count decline has more recently stabilised. Improved productivity should help profitability, but this is cancelled by the collapse in oil price.
  • The estimated recent annual decline rates are 47% for the Bakken, 55% for the Eagle Ford and 22% for the Permian. These declines are not constant. Since year one declines are often of the order 70% and the smaller number of wells now being drilled means that the number of fast declining year one wells in the production pool is falling. Play decline rates are therefore also falling with time.
  • With these declines and current rig count and productivity levels, production in the Bakken will stabilise at around 870,000 bpd, down 330,000 bpd on current levels. Production in the Eagle Ford will stabilise at around 1,140,000 bpd, down 560,000 on current levels. The lower decline in the Permian means that production there will continue to rise. It is estimated that the net effect will be an LTO production decline of the order 830,000 bpd spread over several months.
  • It is questionable whether a  decline in LTO production on this scale will be sufficient to bolster the flagging oil price and may, for example, be offset by production gains in Iran and elsewhere. Since much of the global oil industry cannot survive at current price levels a second and more brutal round of cuts to OECD companies is to be expected. This may in part take the form of company insolvencies that are just getting underway in the US shale industry. Ultimately, a balance between global oil supply and demand must be restored and, without a production cut by OPEC, this must then occur within the non-OPEC companies and countries.

Figure 1 The main shale oil and gas plays of the USA [1]


The Energy Information Agency (EIA) of the USA publishes a monthly Drilling Productivity Report detailing the production and drilling statistics for the 7 shale oil and gas regions of the USA (Figure 1). This post presents an analysis of this data for the Bakken, Permian and Eagle Ford, that combined, account for 89% of US shale oil production. Much of this production does not actually come from shale but from “tight” formations that need to be fracked to allow the oil and gas to flow. Shale oil has therefore been re-christened as light tight oil (LTO). In this post I use both terms – they both mean the same thing.

At this point I need to add a disclaimer. There are reasons to doubt the reliability of all the data in the EIA drilling productivity report. For example some have questioned whether all the Permian wells counted are in fact LTO wells. Some may be in more conventional oil pools. The interpretations of the data presented here can only be as good as the input data upon which they are based.

For each region, for oil and gas, the EIA publishes 3 key statistics: 1) monthly production, 2) number of operational rigs  3) production added per operational rig. This data allows for an analysis of the decline rates to be made. Declines in shale are known to be extremely high, often 70% in the first year, and many estimates of play declines have already been made. Because of the collapse in US oil directed drilling, shale oil production was also supposed to collapse sending the oil price back up. Since this has NOT YET happened, I decided to take a look at the numbers myself.

If no new wells are drilled in a shale region with 50% decline rate then at the end of a year production will halve. Declines are not constant over time and tend to reduce in maturing wells. Hence production will fall by less than 50% in the second year.

In the past, new and “frenzied” drilling in the US shale patch has done three things: 1) it has compensated for declines, 2) it has added to production and 3) a certain number of wells have been drilled and not completed. Hence there is / was a stock of drilled and uncompleted wells and this makes the analysis presented here more complex and less certain. Generally there is a problem matching drilling one month directly to a production change that month. This has been partially overcome by smoothing the data.

The logic applied is that the difference between production added and production change each month equals the production decline. For both production change and production added I have used a 7 month centred moving average to calculate declines (see charts below). Information on drilled but not completed wells is not readily available and has been ignored. There is probably a better way of doing this but the results I get are similar to those produced by others. For example, Ron Paterson estimated 54% annual decline for Bakken and 62% for Eagle Ford in May of this year.

For each of the Bakken, Permian and Eagle Ford areas 5 standard charts have been produced. These charts are presented below with key observations and the discussion follows.

The Bakken

Figure 2 Raw data for the Bakken showing monthly production and rig count. Note how rig count peaked in June 2012 but that production has continued to rise steeply. The recent peak in September 2014 followed by a sharp decline in rig count has resulted in a production plateau. There are four reasons for this: 1) time lags between drilling, completion and first production, 2) a substantial improvement in rig productivity (Figure 3), 3) there are still 75 rigs drilling that helps compensate for declines and 4) old drilled but uncompleted wells are perhaps now coming on line (an accentuated version of reason “1”).

Figure 3 Drilling productivity as reported by the EIA based on their analysis of available data. Note how back in January 2011 a single rig added on average 200 bpd new production capacity. By mid-2015 that number has risen to over 600 bpd, a three fold improvement in efficiency in less than 5 years. Note there are 3 variables that can combine to improve efficiency: 1) drilling faster (more wells / rig), 2) drilling and fracking better – improved completion technology and 3) targeting more productive zones.

Figure 4 By combining the rig and productivity data shown in Figure 4 we can produce this chart that shows production capacity added each month by multiplying number of rigs by the production added per rig. Not surprisingly, production added has collapsed along with the rig count. But almost 50,000 bpd per month is still being added in the Bakken. Is that enough to cancel declines?

Figure 5 The monthly production increase comes from Figure 2 and the monthly production added from Figure 4. Note that both curves have a 7 month centred moving average applied.  The difference between production added and production increase is accounted for by decline (Figure 6).

Figure 6 The difference between production added and production increase is accounted for by decline (Figure 5) converted to a monthly % of the production in the prior month. The 7 month smoothed data (dark blue line) conveys decline rates that vary from 3 to 8% and a tendency for annual cycles. This variability in calculated declines almost certainly reflects in part operational dynamics. The 13 month smoothed line provides a better picture of the underlying trend. Decline rate increased when the 2009 drilling frenzy got under way – larger numbers of fast declining year one wells and has stabilised at around 5.2% per month. Note that annual decline is not 12*5.2% but is rather 47% (calculated from spreadsheet).

The Eagle Ford

Figure 7 The Eagle Ford rig count and production profiles are very similar to The Bakken (Figure 2). The Eagle Ford rig count peaked in May 2012 and has since more or less moved sideways until the late 2014 crash. Eagle Ford production began to decline in April 2015.  Note that at 1.7 Mbpd, Eagle Ford production is substantially higher than Bakken.

Figure 8 The improvement in rig productivity for the Eagle Ford is even more impressive than for the Bakken rising from below 100 bpd / rig / month to over 700. Productivity continues to rise post-crash.

Figure 9 As with the Bakken, Eagle Ford ‘production added’ has plunged, following the rig count down. But 80,000 new barrels per day per month are still being added to capacity.

Figure 10 The monthly production increase comes from Figure 7 and the monthly ‘production added’ from Figure 9. Note that both curves have a 7 month centred moving average applied.  The difference between production added and production change is accounted for by decline (Figure 11). Note how production change in the Eagle Ford has now turned negative and production has begun to decline (Figure 7).

Figure 11 The Eagle Ford decline rate rose from 4 to about 8% per month but is now clearly falling as the number of high decline year 1 wells is reduced. Using the more recent number of 6.5% per month yields an annual decline of 55%. Using the prior 8% per month figure yields an annual decline of 63%. The new well productivity of the Eagle Ford is the highest of the three regions but so are the declines.

The Permian

Figure 12 The Permian is the USA’s largest LTO producer with over 2 Mbpd production. And while the Eagle Ford had a standing start in 2009, the Permian already had 850,000 bpd in 2007. The 2008 crash somewhat surprisingly does not show up significantly in the production data. One possible explanation is that pre-2009 production was dominated by conventional wells that would not be so prone to rapid decline. The rig count pattern is similar to the other areas, but notably rose to a new high in 2014. The Permian is clearly preferred by operators to the Bakken and Eagle Ford plays.

Figure 13 The rig productivity in the Permian has also risen significantly. But the rig productivity in the Permian (220 bbls per rig per month) is markedly lower than in the Bakken (over 600) and the Eagle Ford (over 700). The Permian also has a much higher rig count. It also shows a sharp and strange uplift in very recent rig productivity. At this point I can only speculate that production has received a boost from some “old” drilled wells being brought on line. So, if the Permian has the lowest rig productivity, why is it the most popular and largest play? The answer to that lies in the decline rate.

Figure 14 Production added does in fact follow rig count quite closely but has turned up in recent months due to the “surge in rig productivity”. Production has begun to rise even with the rig count still trending down.

Figure 15 The production dynamics in the Permian are much more favourable than in the Bakken and Eagle Ford. While production change in the Bakken is now zero, has turned negative in Eagle Ford, it is still rising in the Permian, the largest play. This will have profound impact on the aggregate behaviour of the US shale oil patch.

Figure 16 Decline rate in the Permian appears to be continuously variable and subsequently hard to estimate. It peaked at over 5% but has since fallen to about 2.5% per month. The slowdown in the decline rate will again represent the smaller number of fast declining year one wells in the production pool. 2.5% monthly decline translates to an annual decline of 22%, well below the Eagle Ford and Bakken. The 230 rigs currently drilling are able to more than compensate for the declines, hence Permian production is still rising.


With the Bakken, Eagle Ford and Permian we are dealing with about 89% of US LTO production. The production dynamic differs substantially between the three plays as summarised in Figure 17. Hence it is difficult to make general statements about US shale oil production. Observations made today will be different in 6 months time. In particular, decline rates vary a lot with time making prediction difficult.

Figure 17 Summary production and drilling data for the main US shale oil  plays.

In the Eagle Ford and Permian, decline rates are tending to fall as the number of fast declining year one wells reduces in the production pool. Hence what I have to say now based on most recent declines may prove to over-estimate the actual decline in US LTO production. The annualised most recent declines are as follows:

  • Bakken: 47%
  • Eagle Ford: 55%
  • Permian: 22%

The other key statistic is that the oil directed rig count in the USA has stabilised, currently 31 oil directed rigs higher than the low point reached on 26th June. IF we continue with the current rig count, rig productivity and declines then Bakken production  will stabilise at about 870,000 bpd, down 330,000 bpd on current (in 6 months time).

This is calculated by taking recent production of 1,200,000 bpd and applying a 5.2% decline per month and observing that this will take production down to 871,000 bpd after month 6. At that production level the Bakken lost 48,000 bpd between months 5 and 6 equal to the amount of production added in June 2015. That is the equilibrium point where applying current declines and drilling dynamics results in production added cancelling declines. The calculation is subject to many assumptions and uncertainties.

Eagle Ford production will stabilise at around 1,140,000 bpd, down about 560,000 bpd on current (in 6 months time). Permian production will continue to rise by perhaps 10,000 bpd per month (60,000 bpd in 6 months time). Then, a new equilibrium will be reached in the shale patch where drilling compensates for declines at a production level very roughly about 830,000 bpd below current levels. If declines continue to fall, productivity continues to rise and rig count starts to rise then the production fall will be less (whilst noting that more new wells drilled will accelerate the aggregate decline rate).

So is this good news? With US production riding high at 12,910,000 bpd I suggest that the rout in the shale patch will merely take this back towards 12 Mbpd. And then we need to consider what is happening in the conventional US production portfolio. Current 12.9 Mbpd production is split roughly 5.4 Mbpd in shale and 7.5 Mbpd conventional. In the North Sea the record high price of the last 5 years is feeding through to future production increases. The same may happen in the USA.

Hence, the main message from this post is that a precipitous fall in US production in the months ahead, upon which most analysts are depending upon to send the oil price higher, may not materialise YET. This is simply the end of round one of the current oil price crisis and the standoff between US shale and OPEC.

The Future

Is it good news or bad news that US oil production may not collapse (yet) under the weight of low oil price? It’s certainly good news for US energy security. And if US production does not collapse, it will in the short to medium term likely lead to a further decline in the oil price, great news for consumers and the economy as a whole.

The picture from the producer side of the fence is rather different. Sub-$60 will mean that many conventional oil producers are in great difficulty. Many shale producers are arguably already insolvent. High debt levels are secured against assets, i.e. oil and gas reserves. Reserves in turn vary with oil price and as the price goes down so arguably does the volume and value of those reserves. It is widely believed that for the oil price to recover, OECD companies must pump less oil. Pumping less oil for lower price will be route 1 to bankruptcy for many highly leveraged companies producing high cost oil. I believe the industry may face a crisis unparalleled in recent decades.

The future is just about to begin.

[1] EIA: Drilling Productivity Report

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39 Responses to US Shale Oil: drilling productivity and decline rates

  1. Heinrich Leopold says:

    The real test for shale is coming now, when collapsing share prices and the end of hedges above 70 USD, do not allow many new drills. Rail traffic for petroleum is already down this week by 20% for AAR and 27% for BSNF. The World has not yet seen a shale correction, yet in my view it will be precipituos – especially for natgas.

  2. Glen Mc Millian says:

    This question is one I intended to post a couple of days ago but I forgot to do so when the discussion was focused more on storage and inter connectors.

    Is there a pumped hydro facility anywhere that uses sea water pumped into a valley located near the sea coast?

    If not, does anybody know of such a pumped storage project that is proposed?

    It seems likely that there are steep sided valleys in mountainous areas in various countries close enough to the sea coast that such pumped hydro reservoirs could be built. If built they could be used to store off peak power from any existing nuclear power plants and coal plants as well- thus reducing the need for more peak generating capacity.

    And of course any available wind and solar power could be used as well to help keep such a reservoir topped off.

  3. Glen Mc Millian says:

    Off topic at the moment but relevant to the general discussion here.

    Solar power in the right places is soon going to be cheap enough to stand on its own feet just on the basis of saved fuel costs alone. Oil, gas and coal are sure to be going up if for no other reasons than monetary inflation alone as time passes.

    Depletion never sleeps.

    Environmental considerations aside I believe PLENTY of spots suitable for building pumped hydro exist and that they will be seized via eminent domain procedures and used when the time comes that oil and gas are getting to be scarce and prohibitively expensive.

    My good buddy who is also my attorney tells me his two daughters, both graduates of snooty private universities and well paid young professionals, are as green as new spring grass and perfectly willing for EVERYBODY ELSE to live in tiny houses and take mass transit to work but THEY are not giving up THEIR accustomed lifestyle.

    Once the first blackout hits them, or the first oil crisis of their young lives hits them, he tells me they will morph into republicans in a flash when it comes to energy issues.

    No doubt he is correct. Pumped storage WILL be built in a lot of places that are currently on anybody’s radar.

      • Lars says:

        Glen (old Farmer?), yes the Irish have (had?) plans to build one or more pumped storage stations using valleys close to the sea as the upper reservoir, and the sea as the lower one. There are good opportunities it seems for such a scheme especially in the south-west.

        Ireland of course has excellent wind conditions and it seems they think 2-300 Gwh would provide enough storage for a safe operation if they have a coal fired plant or two in reserve, or sufficient interconnectors to import when necessary and export a surplus.

        In my opinion this could make a lot of sense if they are willing to sacrifice a couple of valleys. Having a small population and a relatively modest electricity consumption it could leave them self-sufficient in terms of electricity and even being a small net exporter perhaps.
        I read about this a couple of years ago and I have no idea how far it has come in the planning process or if it is pursued at all. Maybe other readers know.

        • Peter Lang says:


          I was at Ireland’s only pumped storage scheme, Tullock Hill, pumped storage scheme in 1975, just after it was completed; I was taken all over it by one of the senior engineers involved throughout construction. But i don’t remember much of it. However, more relevant is I know quite a bit about the wind and pumped hydro. In short, pumped hydro cannot be anywhere near to economic if it has to rely on and buy energy from intermittent energy sources to store and then resell. Pumped storage needs to be used to near its full capacity nearly every day of the year. It needs to buy cheap power in the early hours of the morning for around 6 hours and then sell it during the periods when prices are at peak. Therefore it is ideally matched with baseload power such as nuclear or coal.

          Readers might be interested in this excellent analysis of the CO2 emissions abated by wind farms in Ireland: “Quantifying CO2 savings with wind power:

          The Energy Policy Journal paper is here:
          and a comparison with a Sustainability Authority of Ireland modelling study (for a different year and for RoI + NI) is here:

          • Peter Lang says:

            The key take away message is that wind power in Ireland in 2011 provided 17% of electricity and was just 53% effective at CO2 abatement per MWh of wind energy supplied to the grid.

            The policy relevance of this result is that the CO2 abatement cost of wind power is actually nearly two times higher than economists’ estimates because they do not take effectiveness into account. The CO2 abatement effectiveness declines as wind penetration increases, so the CO2 abatement cost increases.

          • Lars says:

            Peter, thanks for that interesting comment. I am aware that more intermittent energy in the system makes more “wear and tear” overall and that CO2 emissions do not decrease proportionally to the energy production from intermittant renewables (btw. I don`t see CO2 as a problem).

            I will study your links thoroughly when I have the time, I am here to learn mainly from people far more proficient in the energy theme than I am.

            You said “Pumped storage needs to be used to near its full capacity nearly every day of the year. It needs to buy cheap power in the early hours of the morning for around 6 hours and then sell it during the periods when prices are at peak. Therefore it is ideally matched with baseload power such as nuclear or coal.”

            That`s an interesting statement and as far as I know a couple of PSPs in Germany for instance have already closed down because they are not profitable. But in this case I will quote a statement from Euan in this post which I agree 100% with:

            “The government support idea is an interesting one. Its an area where I reserve the right to hypocrisy – generally feel that commerce should be run by capitalism but that energy may be supported by the state. Bottom line it is so important it can’t be allowed to fail.”

            I am inclined to think that perhaps this should go for a scheme like this one in Ireland too. Energy self-sufficiency (in terms of electricity) has its price, but perhaps it`s worth it?

          • Peter Lang says:

            Hi Lars,

            “I am inclined to think that perhaps this should go for a scheme like this one in Ireland too. Energy self-sufficiency (in terms of electricity) has its price, but perhaps it`s worth it?”

            Even public funded projects must be justifiable on a rational economc basis. Pumped hydro is rarely economic even for baseload now days, and almost never with intermittent unreliable renewables. The taxpayer funding wasted on an uneconomic pumped hydro scheme could be far better spent on other projects with greater return to the taxpayer. Wasting money on uneconomic pumped hydro is not better than wasting it on subsidising wind and solar power.

            If you want energy selfsuffiency, you’d go for nuclear every time. Fuel costs >10% of the electricity cost and fuel can be bought and stored for many years until needed. The volume needed for years of storage is miniscule.

  4. Euan: The current indebtedness of the shale producers is, what? Something like $200 billion I think. And some of them can’t service their debt, or soon won’t be able to. Now if you are one of the creditors, what do you do? Do you foreclose and take cents on the dollar, or do you keep priming the pump in the hope that oil prices will recover and that eventually you will be paid in full? (Rhetorical question. I don’t know the answer).

    • roger in florida says:

      Mr. Andrews,
      Yes, many shale producers (probably most) are insolvent, banks are frantically trying to maintain their (shale producers) liquidity and thus maintain the viability of the bank’s investments, these companies seem to be 100% debt financed. There is tremendous pressure to keep this financial pantomime going. Many pension and hedge funds are heavily invested in this “fracking revolution”, there is definitely the potential here for a major financial crisis:
      A very problematic aspect of this is that these problems are matched by other equally serious issues in commodities generally:
      Everything is debt, we are down the financial rabbit hole to a place where money has lost its traditional meaning. It appears that many assets have actually been used as collateral for multiple debts, and many of these debt instruments have been themselves purchased with 100% debt. We saw this in the mortgage meltdown.
      But our situation here is not all bad, if this financial freak show can be kept going it may be that much worse pressure will be felt by other producers (Saudi Arabia, Russia, Venezuela, etc) where high oil prices have kept social revolutions at bay or in check. Of course Iran and Iraq, amongst others will be ramping up production no matter what the price is.

      • It occurs to me that a case can be made here for government support. The US shale industry is now of vital strategic importance, it’s a key player in the fight against global warming (the replacement of coal with shale gas has been the major contributor to the recent decrease in US CO2 emissions) and it’s much too large to be allowed to fail anyway. So how about some government loan guarantees? If nothing else they would give the greens some real fossil fuel subsidies to complain about.

        • roger in florida says:

          I am sure that is happening, it is inconceivable that JP Morgan and the other financial institutions have not been consulting the Fed about this situation. The precedent is well established by the TARP program, certainly the Fed has agreed to backstop the liquidity requirements. The economic and therefore political ramifications of a collapse of this industry are huge. The problem for Obama is how to do this covertly, the greens are very adept at using the legal system to obstruct such policies, they have essentially kept Keystone in permitting for 14 years.

          • Peter Lang says:

            Roger in Florida,

            “The problem for Obama is how to do this covertly, the greens are very adept at using the legal system to obstruct such policies, they have essentially kept Keystone in permitting for 14 years.”

            That’s good. It provides a great opportunity to set a precedent that can then be used to remove the subsidies renewables’ subsidies. Any time there is an opportunity to set such a precedent it should be taken advantage of.

            What Obama, if he was wise, should to is to copy relevant parts of the legislation for renewables subsidies so that if they are blocked for fossil fuels they will alos have to be repealed for renewables.

            Nuclear is a separate issue because subsidies for nuclear are required to offset the massively damaging impediments that 50 years of regulatory ratcheting have caused. These impediments will need to be offset by subsidies until all of their long term effects have washed out of the system. 🙂

        • Euan Mearns says:

          I’ve been trying to get to the bottom of shale finances but the production dynamic is very complex and the economic dynamic even more so. The fact that the whole industry hasn’t gone tits up (yet) is a source of wonderment. Exchanged many emails over the weekend with Arthur Berman who remains adamant that the day of reckoning is bearing down.

          The government support idea is an interesting one. Its an area where I reserve the right to hypocrisy – generally feel that commerce should be run by capitalism but that energy may be supported by the state. Bottom line it is so important it can’t be allowed to fail. Note that one of my self devised ethics is that hypocrisy is allowed if one acknowledges it.

          Can the USA run on shale oil and gas? The thermodynamic limit is ERoEI and by most accounts it is sufficiently energy positive for the answer to be yes. I have made the argument before that capitalism is founded on growing supplies of cheap FF and energy. We are on the back side of Hubert’s peak where we clearly still have growing supplies but the energy is more expensive to get.

          Arthur argues that most shale companies have never really turned a profit hence expansion is funded by debt and more recently by equity (share issues). I think nationalisation of many OECD energy industries is likely inevitable. Governments could of course help by stopping their deliberate efforts to put them out of business.

          • CoDo says:

            Ewan – for starters, im glad to see such a well managed, rational, thoughful blog. A far cry from the waning days of TOD where hysterics and apoplexy was de regiur.

            With regard to the “Day of reconing/kaboom event” many expect with the shale producers, I think it is going to be far more muted than many expect, and I say this as a transactional attorney with a background in commercial finance.

            The reason I say this is one of the best ways to mitigate a bad commercial loan is to do some sort of partial abatement, deferral, etc. which keeps the producer in place making at least SOME money even if it is not what was initially anticipated.

            Likewise, when it comes to bankruptcy, the most common method of doing this is called Debtor in Possession or DIP financing, where (again) the producer stays in place and continues to make money to the extent it can.

            It was for these reasons that unlike residential real estate where there truly was an implosion, the commercial real estate segment was a complete non-event to laymen. I thus expect to see the same thing here where the industry may indeed go tits up, but it will be with continued production in places where the physical assets and resources are best used by remaining right where they are. In other words, no real growth, but nothing along the lines of the implosion to anyone other than those closely connected to the industry.

          • Euan Mearns says:

            CoDo – I do not doubt there is truth in what you say. Companies will be able to make money if sunk costs in land and drilling are written off or partially written off. Another way for this to happen is for third parties to pick up the assets cheap following liquidations.

            The root of the problem is however, that a chunk of the non-OPEC industry has to die to revive prices that will allow the remainder to survive. I don’t think this will happen in Russia, hence we are really talking OECD.

            The industry is going through a period of dynamic adjustment riding on the back of momentum built over the last 5 years. Base costs are falling rapidly on top of expenditure cuts. So no one really knows where the equilibrium price will lie. The integrated IOCs will make money on their downstream at this time. But with more and more refining located outside of OECD, even that revenue source is pressed.

            The man on the street in NY city will not notice much, unless a few banks go under. Those that will notice most are the rig crews and the industry built around supporting them. And the investors who have fuelled the binge.

            The very curious thing is that oil directed drilling has started to rise. But at some point, many shale focussed companies must simply run out of cash and then stop drilling not through choice but out of necessity.

            The main point of this post was to convey that “the rout” so far is unlikely to be sufficient to support prices. I’m beginning to think we might see WTI going sub $20 and at that level me may see rig count go sub – 100. Part of reason for being so gloomy is on the demand side. Demand growth is very soft and that flood of oil just keeps on coming.

            If such a scenario unfolds then we really need to think about what might happen in countries like Algeria.

        • Sam taylor says:


          Some recent research has perhaps cast doubt on the widely held belief that shale was behind the decline in US emissions ( ). Instead they find that the decrease in emissions can predominantly be attributed to economic recession, with the change in fuel mixture being a rather minor player.

          • Roger Andrews says:

            The SDA in this research is based on the additive decomposition of the changes in emission determined by six multiplicative factors acting as accelerators or retardants of the emission dynamics. Each term in the decomposition is a product of the change in one explicative factor and the level values of the other five factors, and thus represents the contribution of one explicative factor to the total change in emission dynamics

            I think I’ll stick with the consensus conclusion.

  5. Javier says:

    A very fine analysis, Euan. As you say it probably approximates what may happen to shale production in the next six months. Beyond that it is no guide because it does not take into account the economic situation of the shale companies.

    We all agree that the reduction of production that you show is taking place is the effect of the oil price collapse on the shale companies, yet this effect has been muted by the first round of cost reducing measures, hedges on future oil prices and most credit conditions being kept at the April review on thoughts of a temporary situation and past 12-moth oil price being then >80 $/b. The economic conditions of the shale companies are very likely to worsen in the next 6 months due to expiration of the edges and credit problems in the October review, probably inducing more rounds of cost cutting and asset sale measures that have the potential of further impacting oil productivity. Plus it has to be taken into account what happens with oil operations from companies that go bust.

    This article has a fine description of the economic issues that you probably already know.

    The most likely effect of further economic distress for shale companies is further reduction of oil production. As such, your projections of a reduction in the order of 0.9 Mbpd are probably on the low side if we consider a longer period, like till the end of 2016.

    A possible rescue by the Government cannot be ruled out, but it is a variable difficult to include in the analysis, and its effect on production is also difficult to estimate.

    • Euan Mearns says:

      Javier, Yes. The point of this analysis is to extrapolate current rig count and efficiency into the future and in a world of uncertainty conclude that the decline in US production with current status will unlikely be enough to bolster price. IF WTI does not gain support at about $43 then as mentioned in another comment we may see $20. I think at that level everyone rushes for the exits and US oil directed rig count may fall below 100. I think we need to see at least 3 Mbpd removed from non-OPEC production and that is not going to happen in Russia.

      The IEA June public data tables are now published. Global total liquids supply up 500,000 bpd. US production down about 50,000 bpd (clouded by revisions). 2Q stock change is +3.3 Mbpd – at some point we must run out of storage tanks.

  6. D Nevin says:

    Found your article on seeking alpha and left the following comment/question. Figured it might be better to communicate with you on your actual site, apologies for the duplication.

    Really nice thorough work, and a great add to the conversation on the topic. I wanted to bring up one issue I see, which is that I believe the recent up tick in production/rig is being driven by two factors.

    1.) The reduction in rig count being more focused on fringe areas. This is the well acknowledged phenomenon of operators focusing on the sweet spots during the price downturn, and its impact should be reflected in the data you have used in your analysis above.

    2.) The “fracklog” or lag-time between wells being drilled and completed. Since the reduction in drilling rigs is what is being measured here, I believe we are seeing a false signal in the increased production/rig numbers. Once this fracklog is worked through and the number of wells being completed begins to match the number of wells drilled at this new lower rig count, I expect we will see the production/rig numbers return to earth.

    My question to you is, have you run any sensitivities on the stabilization rates assuming lower production/rig numbers. For example, if you reduced the recent (last 6 months) increase in production/rig numbers by 25%/50%/75% what would be the impact on play stabilization rates? I am not sure the data exists to estimate the actual percentage, but I wouldn’t be surprised at a 50% or greater impact on the production/rig numbers.

    Thanks again for the nice work.

    Best Regards

    • Euan Mearns says:

      1) Yes, focussing on sweet spots will improve rig productivity. One of the variables I do mention in the post.

      2) Building the “fracklog” will result in past efficiencies being underestimated and as this unwinds it will result in a temporary apparent increase in efficiency that will disappear once the unwind is complete. Its possible this is what is happening in the Permian now.

      On this basis I believe the efficiencies I have used here will be underestimates and these will continue to rise into the future until the “fracklog” is cleared. That oil is just going to keep on coming for a while yet. I don’t have access to the fracklog numbers or history to do or say much more.

      • Dean F. says:

        Hi Euan, the latest frack-log for North Dakota by Enno Peters is here:

        as you see, given the current trend, at least 3-6 months (in the optimistic case) will be needed to reach a level of 400 uncompleted wells, which is considered the normal working level there.

        • Euan Mearns says:

          Many thanks! The pessimistic view would be that new spuds in Bakken running at 100 / month and 1050 uncompleted wells gives an inventory of 10 months already drilled wells. A monster has been created here that cannot readily be switched off.

  7. Hi Euan,

    what you describe as “unparalleled crisis” (and I tend to agree), is welcome by some bloggers in climate community as a change for long-term survival of humanity and a sign of (exponentially?) cheaper renewables and investor’s “enlightment”. Well, who am I to decide:

    “It is perhaps for these combined reasons and due to the encroachment of ever-more inexpensive and accessible renewable energy sources that has led to a massive flight of capital away from fossil fuel based energy.”

    Climate Change Changes Everything — Massive Capital Flight From Fossil Fuels Now Under Way



    • Javier says:

      There’s no shortage of fools in the world.

      Spain is a country that is in a post-peak oil situation due to the peak in global oil exports and debt saturation impairing its oil-bidding capability. It has lost 25% of peak oil consumption and the surprising result is that we have an excess energy capacity. We consume less electricity than in 2005 and so we have an excess of renewable energy production that is making our electric bills more and more expensive. The result of peak oil for Spain is that hunger and misery had made a come-back. Public schools are opening their canteens during the summer so many children can have at least a good meal a day. Of course poor people produce less CO2 and if they die they stop producing CO2.

      I would warn those fools: “Be careful what you wish for. You might get it.”

  8. Wm Watt says:

    1. Drilling is a seasonal activity, moreso in the north where transportation relies on frozen ground, so completing and tying in well is too, and stats need to be annual or have a seasonality correction.

    2. In the introduction global production is mentioned. That depends not only on cost but on national current account balances, ie producing countries sell oil to buy food so must continue to sell regardless of price unless they have massive foreign currency reserves on which to draw. Massive foreign currency reserves can encourage supporting the US dollar and it gets more complicated than supply, demand, and price of oil. Most oil deposits are nationalized so government owners can produce without regard to royalties and drilling licences, ie they can and will continue to produce at low prices unlike US domestic producers. I guess that brings in the US government to offer subsidies as suggested above if it wants US production, or just enjoy the low price of imports and forego production royalties.

  9. Jim says:

    Euan, my understanding is that the productivity gains are due to longer and longer horizontal sections. 10,000 ft has gone to 20,000 ft. There are hydraulic reasons for thinking this is at or near the limit.
    But this also means that per well costs have gone up. The real question is what is happening to DD&A/bbl, which can be seen from the income statement. Has anybody looked at this?

    • Euan Mearns says:

      Jim, I’d agree that efficiency gains must have limits. My feeling was / is that improved efficiency combined with what must be plummeting costs would make it easier for shale companies to survive current environment. One of the people who has looked at this in detail is Arthur Berman. Art still maintains that many shale companies are insolvent and will be in breach of loan covenants as these come up for renewal in the near future since the value of reserves has fallen; smaller $/bbl * a smaller number of bbls. Recent cash flow has evidently come from new share issues, but that too has dried up. I still don’t fully understand the rise in rig count but fully expect it to nose dive again before Christmas – unless we have got the narrative completely wrong and shale oil makes money at $30.

      We’ll need to wait and see what happens. Art is well worth following:

      • Jim says:

        As you say, in the end the banks hold the key. They use low price decks and trim production and reserves. Also, companies will be breaching bank covenants. As you know, oil companies spend all their cash flow and more to chase the goal of growth. So, there will be lots of distress.
        Having said that, declines never sleep and I think there will be a shock coming…

  10. K Yamaguchi says:

    Mr. Mearns,

    Thank you very much for your detailed analysis. I was wondering what you thought of the production reduction of 150,000 from the lower 48 reported by EIA yesterday and how that might impact your analysis, and conclusions. I believe that represents a 225,000 reduction in lower 48 production since the June 26 EIA report. Is it believable and how might it impact your analysis?

    Also, as Saudi Arabia has been saying for some time that they would consider production reductions if other did the same, was it a coincidence that they announced yesterday they may cut 200,000 to 300,000 barrels by September. I understand it is because of a reduction in domestic demand as their summer demand declines, but seems some analysts were assuming they would continue production at elevated levels indefinitely.

    Your thoughts on developments regarding crude production since your article was written would be appreciated.

  11. Euan Mearns says:

    K-Y, I stopped following the EIA numbers since they are so far out of date, so I’m not sure what time frame the 150,000 bpd reduction you refer to applies to. My post assumes a 800,000 bpd decline in US lower 48 production from shale in the months ahead. So nothing here to really challenge that.

    I have a new Vital Statistics update that will be posted within a couple of hours. You ought to have a close look at that. A major message is that there is so much data uncertainty that we only really know what is happening 3 months down the line.

    I didn’t catch the announcements from Saudi about production curtailment. There is no sign in recent figures. But the poorer OPEC countries are in a world of hurt right now. This can threaten OECD security.

  12. K Yamaguchi says:

    The 150,000 reduction in lower 48 came from the report issued yesterday (7/29) morning by the EIA. Just looking at the same report from June 26, that’s down 225,000 in lower 48 production for July.

    Not long after that EIA report came out, there were reports that Saudi Arabia said they would (may?)reduce production by 200,000 to 300,000 at the end of summer (Sept.). Not yet, so wouldn’t be in the data.

  13. Pingback: Oil Production Vital Statistics July 2015 | Energy Matters

  14. K Yamaguchi says:

    Mr. Mearns,

    Not sure if you consider this data reliable either, but the EIA Monthly Supply data for May that just came out a few minutes ago (7/31) indicates that average daily production for May crude was 190,000 barrels a day lower than April. I believe some of the weekly estimates from the EIA had been showing a increase of almost the same magnitude.

    Does that make a difference in your analysis/conclusions?

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  16. W. Mason says:

    There appears to be a missing piece in the math. For example regarding the Bakken: “This is calculated by taking recent production of 1,200,000 bpd and applying a 5.2% decline per month and observing that this will take production down to 871,000 bpd after month 6. At that production level the Bakken lost 48,000 bpd between months 5 and 6 equal to the amount of production added in June 2015.”

    Yes, if drilling stopped completely the existing wells would deplete to 871,000 bpd at a 5.2% decline per month. But drilling hasn’t stopped. Eventually your conclusion of production equaling decline at 871,000 bpd is correct but it will take longer than 6 months. Maybe I am missing something but it seems to me that the production from the new drilling over the next 6 months is not being incorporated into the numbers.

    • Euan Mearns says:

      Bill, you are correct. But my narrative has sufficient caveats to cover this. To do this properly requires a vast amount of work that I do not have time to do. Rune Likvern, Eno Peters and Art Berman follow the numbers in far greater detail than I do. Art sees an LTO production decline of 400,000 to 800,000 bpd. The main message is that this is unlikely to be sufficient to restore balance to the market, hence I believe much worse still to come. Art seems more optimistic.

      PS your first comment needs to be approved before it will appear. Thereafter you should be able to comment at will.

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