Peak Oil Deferred

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In 1956 Marion King Hubbert, The Chief Geology Consultant (some say it is more correct to refer to him as a research geophysicist) to Shell Oil, shocked the World by proclaiming that the production of U.S. crude oil would soon peak and then rapidly decline. His projections for U.S. oil production proved to be accurate and a legend was born. Associated with these projections were two assertions:

  1. Production in a given geographical area would follow a particular pattern somewhat resembling a normal distribution but slightly skewed into the future presumably because certain applications for oil would support the higher prices required for production as the resource depleted.
  2. The peak would occur roughly when half the recoverable resource had been extracted.

It is this second assertion that has always bothered me for two reasons:

  • How does one know in advance the size of the resource? The answer is one does not.
  • Although a finite resource has limits with respect to production increasing over time, why should the peak occur at approximately the point where half the recoverable portion of the resource has been recovered. Hubbert claimed this was a universal production curve for any exhaustible resource but he did not apply it to natural gas or coal in his presentation. My guess is he needed to make that assumption to make the Texas and U.S. data on cumulative production and the projected remaining economically recoverable resource fit, and he got lucky. It was not dumb luck, it was being lucky to be giving his presentation at a time that the historical production and projected recoverable resource were close to being equal. He had no choice but to produce the analysis that he produced. The data forced him into it.

Another increasingly relevant consideration is the definition of “oil”. A significant percentage of what is currently defined as oil is a synthetic product produced from what in Hubbert’s time would not have been considered to be oil although Hubbert was aware of all of this and had estimates of these resources but they were not included in the diagram that has become so famous and is associated with Hubbert and the term Peak Oil.

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The production from Canadian Oil Sands is a good example of this and even very heavy oils may not have been considered part of the recoverable oil resource by Hubbert. And then there is the wide variety of liquids that are recovered from natural gas extraction. In many cases these liquids (propane especially) are not oil refinery feed stocks, so are they oil?

Generally, Hubbert depended on estimates of existing proved oil reserves prepared by others and also estimates of remaining to be found oil. Today almost sixty years later the current estimates of proven reserves are very different than the 250 billion barrel estimate used by Hubbert. Here are two estimates[1]:

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Source: British Petroleum
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The above two estimates represent the amount of oil expected to be economically recovered, but they clearly include unconventional oil so they do not match up exactly with the data Hubbert was using. But as you can see, the estimates continue to increase even as production increases.

At current production/consumption of 93 million barrels a day or 34 billion barrels a year, the above is a 48 year supply. It is my understanding, and I could be wrong, that the above only includes what is considered economically recoverable today. So it does not include the technically recoverable which is not yet economically recoverable which would be mainly the higher cost technically recoverable resource. This is likely to be a large quantity. So that is another reason to believe that economically recoverable reserves are likely to continue to increase as some technically recoverable but not yet economically recoverable oil is reclassified.

To that one has to add undiscovered oil. As you can see this estimate was 910 billion barrels of oil back in 1956. For conventional oil, one current estimate of yet undiscovered recoverable “conventional oil[2]” is 562 billion barrels. This estimate does not even include shale oil let alone oil from tar sands or even heavy oil. The recoverable heavy oil from Venezuela is estimated by some as equal to the conventional oil. The above estimate is technically recoverable oil so an economically recoverable fraction has to be applied. But also remember this is the estimate of only undiscovered conventional oil and the growth in the available resource is coming mainly from the unconventional sources. The already discovered portion of these unconventional sources to the extent they are economically recoverable are included in the OGC and BP estimates of reserves which highlights the problem of trying to assemble a complete picture. But clearly estimates of the available economically recoverable resource have been increasing more than enough to be a net increase after annual consumption (depletion).

Here it is useful to talk about definitions.

Graphic Supplied by WikipediaClick to enlarge

The three main categories of any resource including crude oil are:

  1. In place i.e. that which exists. Of course usually such estimates tend to increase over time but sometimes they are adjusted down. Oil in place is an educated guess.
  2. Technically recoverable. This depends on the characteristics of the resources and technology. Technology usually improves over time.
  3. Economically recoverable. This also depends on technology but also on product prices. If there were no substitutes, presumably ultimately all of a technically recoverable resource would become economically recoverable as prices increase due to the depletion of the lower-cost fraction of the resource as long as the increasing cost does not exceed the benefit. But there are substitutes so the process of traveling up the cost curve may not and probably will not extend to the full portion of the technically recoverable oil resource.

So the sources Hubbert relied on were dramatically underestimating even the conventional oil resources let alone the now available shale oil (and gas). So in a certain sense Hubbert was not wrong in his analysis. He was simply relying on faulty information provided mainly by Lewis George Weeks who at that time was working for Standard Oil of New Jersey (now Exxon) with respect to foreign oil and information from the U.S. Geological Survey with respect to U.S. oil. Hubbert actually upped some of those estimates as he considered them too low.

Basically Hubbert assembled the data and related the existing production history estimate he was provided with his adjusted estimates of the remaining recoverable resource and attempted to fit a reasonable production/extraction curve to this data. If I was fitting a production curve to that data and had 100% confidence in the estimates, I probably would have developed a similar curve. Also Hubbert was compromised in a sense due to his faith in nuclear power. In fact his famous report is titled “NUCLEAR ENERGY AND FOSSIL FUELS”[3]. He also was expecting nuclear energy and coal to play a major role in the energy equation.

So in a sense, attributing Peak Oil to Hubbert makes Hubbert somewhat a historical victim as Hubbert was mainly saying that the conventional oil role in the energy picture would peak in 2000 not that fossil fuel use would decline after 2000 or that the planet would run out of energy.

But of course Hubbert was wrong in a multitude of ways.

  1. He relied on estimates of conventional crude oil remaining to be discovered which were simply too low.
  2. He thought improvements in secondary and tertiary recovery would extend the tail of the production cycle but not allow the peak to occur higher and later. He was wrong about the rate of improvement in oil and gas technology.
  3. He tended to ignore natural gas and other oil-like liquids not because he was unaware of them but thought they would continue to have a constant and fairly small ratio to conventional crude. So here he was not seeing the potential for shale gas with its substantial associated natural gas liquids.
  4. He was not optimistic about Canadian tar sands although he was using a large number for the size of this resource but did not include that resource in his analysis of crude oil.

So in a way Hubbert has been given a bad rap since with data: garbage in garbage out, his input sources were essentially garbage. With correct inputs, his analysis would have been better but it is presumptuous to claim to know what exists in the ground which will be economically recoverable. Until we experience peak innovation, Malthusian attempts to predict Peak anything are likely to be shown later to be silly.

An Alternative View

Although a finite resource must ultimately reach a level of extraction that in the future is not exceeded, it may be that for a long time the level of extraction/production matches the level of demand. The rationale for such an analysis is that price clears the market i.e. the level of production is that where the most expensive unit produced is still attractive to some user. So supply and demand are always in balance with above ground inventories being part of the supply. The following is a recent forecast of production and consumption supplied by BP.

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Notice it shows crude supplies increasing but the definition of crude used is broader than the definition used by Hubbert. Never-the-less, the forecast is for crude not peaking prior to 2030.

Energy Efficiency

One of the major reasons that Peak Oil has been pushed out in time is the declining ratio of energy use required per unit of GDP growth. This has occurred for two reasons:

  1. We are using energy more efficiently for example the MPG for vehicles has been continually increasing and structures are being designed to be more energy efficient.
  2. Service industries and government are not high-energy users and those are the sectors with the highest growth rates.

The following graphic comes from a BP Publication so I do not know the ultimate source of this information but there have been similar analyses published. It covers all energy not just crude oil but it illustrates the trend which appears to be fairly uniform globally.

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In this graphic, energy includes all forms of energy not just crude oil but the concept is a general recognition that energy requirements will increase more slowly than GDP which is also a way of saying that energy requirements may not scale with population because of the counteracting impact of declining energy intensity. This is very important.

Shale Oil a Possible Game Changer

Recently Leonard Maugeri who was the Senior Executive Vice President for strategy for ENI, the Italian National Oil Company the sixth largest multinational oil company, was commissioned to write first in 2012 an analysis on the overall oil situation[4] for the Belfer Center for Science and International Affairs which is part of the Harvard Kennedy School and recently a more focused analysis on U.S. Shale Oil[5].

Here it becomes useful to address what is meant by “shale Oil”, and Maugeri addresses this.

Shale oil, tight oil, and oil shale: A problem of words and substance

Shale and tight oil are conventional oils (light oils with low sulfur content) trapped in unconventional formations whose extremely low porosity and permeability makes it extremely difficult for producers to extract hydrocarbons.

Shale oil reservoirs are rich with clay and fissile, meaning they split in layers where the presence of clay stone is massive. These layers may stretch horizontally for hundreds and thousands of miles.

Unlike shale formations, tight oil formations are made of siltstone (a mixture of quartz and other minerals, predominately dolomite and calcite, but many others may be present) or mudstone without a lot of clay in the reservoir.

Despite their differences, most tight oil formations resemble shale on data logs, hence the continued reference to both as “shale” in the media as well as in more technical literature. Although most U.S. so-called shale plays are in effect tight oil formations, I will use the expression “shale” for all unconventional formations so as not to confuse the reader.

Shale oil must not be confused with oil shale, which for several decades enjoyed much higher popularity in the United States.

Oil shale is a precursor of oil called kerogen, a sort of teenage oil that constitutes the building blocks of conventional oil. Also, oil shale is trapped in rocks with low porosity and permeability, making the extraction of kerogen difficult. However, the oil shale rocks are closer to the surface than those containing shale and tight oil. Thus, both the oil shale formations that contain kerogen and kerogen itself are unconventional.

Complementary with the definition of shale oil is the definition of conventional versus unconventional. One is tempted to say that unconventional is when there is not a stratigraphic aspect to the geology which creates a “trap” for the oil or if horizontal drilling and fracking is involved. But neither of those two approaches works all the time. I have seen the term unconventional oil applied to exploration targets where the daily production is anticipated to be low but targets are anticipated to have a slower than typical decline rate and thus be economic.

One has to get used to the reality that in the oil industry, definitions are a moving object. For my purposes, I tend to define conventional oil as oil that has fully allocated production costs of $30 a barrel or less and unconventional oil as oil that has fully allocated production costs in the range of $60 to $100 with wells in the middle being hard to categorize. With this in mind the better redefinition of Hubbert’s concept would be that we have entered the age of unconventional oil with conventional (mostly Middle East) oil enjoying Ricardian profits.

At his point in time, Shale oil is mainly a U.S. phenomenon and it is significant.

U.S. Project Oil Production, 2012 – 2017Click to enlarge

As you can see this would result in a new peak for U.S. production if the natural gas liquids are included as oil production.

World energy consumption & predictions, 2005-2035. Source: International Energy Outlook 2011.
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One of the questions about shale oil is can it be extended outside the U.S.? Maugeri is not optimistic about this particularly in the short term for a variety of reasons one of which being the highly private sector development of this resource in the U.S. Part of that is the rapid increase in the number of drilling rigs deployed in the U.S. and the support services provided to the drillers.  Others are more optimistic about the potential for shale oil outside the U.S.

Worldwide Active Drilling Rigs (2012 average)Click to enlarge

But there could be geological differences which make shale oil extraction easier in the U.S. And we should not forget that targeting oil within the shale basins in the U.S. has been a result of the low price of natural gas. If natural gas prices improve, more rigs will be deployed to the natural gas areas of these basins and there will be higher natural gas production and lower oil production.

The other very important and controversial issue is sustainability. Below are the estimates made by Maugeri for three of the shale plays in the U.S. for which he had the most data.

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NOTE by Maugeri:

Year 1 decline is calculated as the average production during the 12th month of production vs. IP30 daily production. Subsequent yearly decline rates are calculated against the last month of the previous year daily average production. After Year 5, I assumed a flat 7 percent annual decline.

Notice the declines compound so for the Permian Basin as an example, by the 24th month production (or the second year average production depending on how one interprets Maugeri’s footnote) would be 30% (1-0.5)X(1-0.4) of the first month’s production. By the 36th month, 21% ((1-0.5)X(1-0.4)X(1-0.3). So the wells last a long time but the first two or three years must return the capital and provide the profit given that the costs are large and front loaded and the expected rate of return is high for risky projects.

After the fifth year, Maugeri assumed a 7% annual rate of decline in production which seems like a discontinuity from Year 5 but by then production has declined to under 15% of the initial 30 day production level so the tail of the production curve has relatively little impact on the IRR.

Questions have been raised on the individual well decline rates Maugeri has used in estimating the rate of production increases in the U.S in his 2012 paper on the broader topic of oil production and this is typical of that critique[6]. Time and space do not allow me to critique this very vehement critique but to some extent these critiques tend to attempt to make the argument that the oil producers do not know what they are doing and lose money on every well but attempt to make it up with the volume of new wells. Thus many of the critiques essentially are saying that oil drilling is a Ponzi scheme. Ponzi schemes and natural resources are not strangers but the spot data I have seen (I don’t have a database of 4,000 wells like Maugeri) seems to suggest that many of these wells are providing a more than acceptable IRR for the investors and break-even well within two years. But the critiques are also saying that the rate of decline of wells in production may not allow for the growth in new production to make up for the decline in existing production.

The shale oil paper just came out so I am not aware of the critique that is specific to this new analysis that focuses on shale oil but I assume it is similar. It is early in the history of extensive use of horizontal drilling and fracking and one assumes that producers are looking to the extent that they can to develop the most promising areas first. So the jury is still out on what the life of this spurt in oil production will turn out to be in the U.S. and where else it may be significant.


To say that Peak Oil has not yet happened and is not likely to happen within the next twenty years is not to say that Peak Oil will not eventually occur. It is inevitable. But the Hubbert explanation of depleting the resource is probably not going to be the reason that oil production will peak. I offer two other more likely scenarios.

  1. The declining intensity of oil use per unit of GDP or alternatively the amount of GDP able to be generated per barrel of oil may decline to a point that consumption will peak. If consumption peaks, production will peak.
  2. For a long time technology was winning the race with respect to maintaining the constant dollar costs of oil even as the difficulty of extracting a barrel of oil increased. With shale oil there appears to have been an increment in the cost of oil from perhaps $30 a barrel to $60 a barrel. Although that level is likely to be maintained for a while or even decline, eventually there will either be a step increase or a gradual increase. As an aside, the increase in production costs means Ricardian profits for those who own resources that have lower costs usually the prior generation of resources. Also the costs of alternatives are likely to decline because they are early in their development cycle. So over time one expects alternatives to replace oil in certain applications. It has already occurred with respect to electric power generation. Oil competes with natural gas in certain applications and may lose ground to natural gas in transportation applications. I will not discuss the chemical uses as I just do not know enough to do that. But when you have a product with rising real costs, it would not be surprising to see peak consumption caused by substitution. And in this regard, the question of political decisions by governments to favor or disfavor various energy resources impacts the evolution of the process.

As I have written this paper, I have noticed that there are far more predictions on levels of production than there are estimates of reserves. Thus it seems that today’s prognosticators may be risking falling into the same pitfall trap as Hubbert. Do we know enough to predict production out to 2030 and even 2040 as some have done.

My final observation is that the concept of Peak Oil is a fairly useless concept. It is hard to see the usefulness of this concept other than with respect to planning for refineries, pipelines and other oil industry infrastructure. To the extent a peak in production is related to reduced demand resulting from efficiencies or substitution it does not present a significant threat to consumers. It is mainly a threat to producers.

Club of Rome and other Malthusian type analyses are intended to highlight threats to consumers. It is likely that there are few commodities where consumers are at risk to be seriously impacted by depletion of natural endowments. Supply disruptions are a different matter as they create shocks to economies. But the slow process of a changing portfolio of resources used by consumers is not likely to be significant although it is a popular topic for discussion among those who do not understand economics.



  1. Global Oil Production Up in 2012 as Reserves Estimates Rise Again
  2. An Estimate of Undiscovered Conventional Oil and Gas Resources of the World, 2012
  3. Nuclear Energy and Fossil Fuels
  4. The Unprecedented Upsurge of Oil Production Capacity and What It Means for the World
  5. The Shale Oil Boom: A U.S. Phenomenon
  6. Response to Leonardo Maugeri’s Decline Rate Assumptions in “Oil: The Next Revolution”


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5 replies on “Peak Oil Deferred”

  1. So reserves have increased by 60% from 2003 to 2013, and yet production has increased by a mere 13%.   Take out the growth in biofuels and NGPL and you are down to a 9% increase over 10years, clearly proven reserves are no longer an accurate predictor of flow rates.

  2. I am quite astonished by this description of Hubbert, and of oil shale.  The author does not appear to have read Hubbert’s valuable article.  The estimate Hubbert used for U. S. ultimate reserves was 150 billion barrels (his peak year for that was 1963), and he extended this to 200 billion as an outer limit to get a date of about 1970 (actually 1969 in his chart) for the peak in the U. S.  As Adam Brandt of Stanford has pointed out, a number of other authors at the time were also suggesting peak production in the 1960s or 1970s.  
    Figure 1 in Hubbert’s paper is a production curve for coal, Figure 6 is for natural gas, Figure 18 shows a projection for coal, and Figure 22 for natural gas (and there are others).  Hubbert’is assertion of symmetry of the curve came long after the 1956 article, when he applied the logistic curve for reasons he laid out at the time.  Ken Deffeyes gives a simple summary in his books on Peak oil.  
    For more than 100 years, oil shale has referred to organic rich, fine-grained, immature sedimentary rocks found all over the world that contain enough kerogen to produce shale oil (a term with equally long technical standing) in potentially economic quantities (about 10 gallons per ton, although even with the high prices of today, it requires at least 15 gallons per ton to be economic). The Estonians and Chinese have produced shale oil from oil shale for most of the 20th century.  And, while the U. S. resource remains the largest, China, Russia, Israel, and Jordan have very large amounts of oil shale.  Interest is high, but the pace is slow. 
     It would be helpful if people discussing the rise of oil and gas production from tight, generally fine-grained rocks would recognize that there needs to be a term for the rock (oil-bearing shale, gas shale) and one for the product (shale-hosted oil and shale gas), but the search for a way to use only two words leads to “tight oil” and other odd terms.  Seriously, has anyone out there seen oil that was really tight?  What they mean is tight rock oil, but what is the term for the rock in that case?
    Jeremy Boak, Director
    Center for Oil Shale Technology and Research
    Colorado School of Mines
    Golden CO
    Viewpoints are mine, not positions of the Colorado School of Mines

  3. The bad news is that oil production per capita (which is more logical, as production is used to meet consumption of a population) peaked back in 1979:

    Also, Hubbert was referring to conventional production and got it right. He predicted a peak in 1995 + 10 years:

    which was recently confirmed by the IEA:

    and BP:

    What about non-conventional production? There are problems with energy returns and decline curves:

    As well as maths:

  4. Hubbert’s theory failed simply because he underestimated URR at 1.2 trillion. He later moved that number up to 2 trillion. However, other experts have used numbers as high as 12 trillion.
    At this point in time, it should be quite obvious that Hubbert and other peak oil predictors were way off.

  5. @johnbronson
     Hubbert also predicted a peak rate of 40 billion bbl/year off an URR of 2 trillion.  We havn’t come close to that yet.   With 2T URR we have only just reached the 1T recovered resources, about 10 years later then Hubbert predicted.  Peak oil has been well documented in oil fields, states, and nations, it’s only a matter of time before the world hits peak oil.

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