Is Peak Oil Demand in Sight?

Most lifestyle improvements of the past decades have been facilitated in some way or another by hydrocarbons. From long-haul transport and refrigerated goods, to medical equipment and telecommunication devices, all the way to home heating and electricity generation have been made possible by reworking the hydrocarbon molecules into the myriad of usable products. Along the years, not just have hydrocarbons helped upgrade our standard of living, but they have become an integral part of our lifestyle. We have become increasingly attached to hydrocarbons, and particularly crude oil.

Crude oil is part of most things we conveniently use daily. The uptake of oil in consumption took off in the period post 1965 as global economies expanded. It passed the 30Mb/d mark in 1965 and nearly doubled within a decade. The pace of the uptake has not been matched since. From 1980 onward consumption grew more steadily as economic development reached developing and underdeveloped nations. It passed the 70Mb/d mark in late 1990s and it has settled in the range of 90Mb/d in after 2010. The declining number of additional barrels consumed daily can be interpreted as maturing demand for crude oil, which opens speculation about peak-oil demand.

The first aspect which needs clarification is what does peak-oil mean? Peak-oil is a hypothetical point in time when crude oil consumption attains structurally a maximum level, thereat demand will gradually decline.

The second aspect which needs to be explained is the supporting evidence which sustains the peak oil debate. Two aspects are emphasized: the decoupling of GDP from energy consumption (and crude oil respectively) and the shift in the paradigm of oil market functioning.

Decoupling of GDP from energy consumption

The first piece of evidence signaling a structural is the decoupling of energy consumption from global GDP. Since 1990, the average annual GDP growth was 2.8% while average energy growth in consumption was 0.6% and crude oil 1.5%. The gap between the two indicators, which used to follow each other prior to the fall of the Soviet block, grew wider. The decoupling of economic value from the energy used to generate it, is also reflected in the energy intensity of the global economy which came down 30% from 7.5 MJ/$2011 ppp GDP in 1990. The main reasons for the decoupling are associated with structural removal of inefficient energy consumers from the market, fuel switch and the adoption of energy efficiency measures. As the map below depicts the aggregate energy intensity figure conceals a disproportionate reality (both by country and by fuel).

world bank energy intensity 1990

Energy Intensity Level of Primary Energy  (MJ/$2011 PPP GDP) in 1990 |Source: The World Bank

Shift in the paradigm of energy market functioning

Three energy market paradigms have been challenged: (i) energy sources and markets operated separated from each other; (ii) the business model based on long-term investments was disproved; and (iii) technological development can be disruptive.

For decades, the energy sector and commodity markets operated dislocated from each other. In oil markets, investments required long-term financing, predictable off-take volumes underlined by a wide spanning production curve of conventional assets. That has changed with the emergence of the US shale which reduced financing needs because of shortened production cycle.

The US shale revolution shook up another oil industry paradigm, that technology in this conservative industry can be disruptive. Technological innovation in the oil and gas exploration and production has generally followed an incremental path. It emerged from an existing techological solution into another following procedural upgrade. The learning curve of fracking showed how quickly alternative exploration and production techniques can take off, backed by the prospect of sufficient returns.

Peak oil demand to 2040

The decoupling of crude oil consumption from GDP is a gross indication that global economies are close to demand maturity. Further inroads into energy efficiency as well as fuel switch will absorb most of the increased demand in peripheral markets. An additional limits to growth will come from the paradigms shifts that have settled into the oil markets, especially the financing aspect of short-cycle oil production. Given the legacy it is safe to say that further expansion of oil consumption will not stop, only largely decelerate.

If oil market circumstances were to stay put, the discussion about peak oil would not yet be opened. What the peak oil debate builds on, aside from the mentioned legacies, are changes in at the structure of oil demand with permanent downward consequences. They are:

A. Electric vehicle penetration

B. Efficiency gains reinforced by slow economic growth

C. Crude oil substitution in heavy transport and chemical industry

Academics, consultancies, policymakers and industry participants are splitting hairs about the magnitude and impact of each of the three potential developments. There is yet no consensus, but some common ground is evident from their assumptions.

A. Electric vehicle penetration. [1] Status quo numbers 2million electric vehicles on the road, most of which are in Asia. If the electric vehicle fleet were to increase by 1million vehicles/yr to 2040, most of which would take place in OECD countries, and battery price falls below $100/kwh then peak oil demand can be expected between 2025 and 2030. Transport accounts for more than 65% of crude oil consumption meaning that any change in the sector’s demand can have a large impact in absolute terms.

B. Efficiency gains reinforced by slow economic growth. [2] The IMF has been revising downwards the global economic growth projection 5-times-in-a-row. This is to say that the 3% posted figure that currently circulates in economic models is short lived, and expected to be replaced by a less promising prospect. Considering 3% as a starting point and compounded by energy efficiency gains consequent to tough regulatory standards, could bring demand for oil to peak soon after 2025.

C. Crude oil substitution in heavy transport and chemical industry. Natural gas, a hydrocarbon energy and feedstock resource more abundant than crude oil, whose price has been pegged to a basket of oil-products is gradually breaking free. Benefiting from a larger resource pool, a freely traded gas would be structurally cheaper than the oil-indexed volumes. US produced gas is a case in point as the US hub marker Henry Hub trades at a structurally lower price than the European hubs which partly trade oil-indexed contracts.

Feedstock and industrial oil consumption represents about 25% of the global oil demand. A switch from naphtha (crude oil derived feedstock) to ethane (natural gas derived feedstock) is contingent to the ethane-naphtha spread. In case gas remains at an advantage for a prolonged period it can lock-in a structural effect which plateaus oil demand around 2025.


After browsing over the main qualitative and quantitative estimates for global peak oil demand it is apparent that the peak is near. In the narratives presented, each development has been analyzed individually but synergies, for example, between efficiency and substitution could emerge and generate exponential effects. Additionally, the impact of pricing, not just of oil, but alternative energy sources and technology, are important considerations where one can only speculate looking towards 2040.

Despite the uncertainties that such an exercise surfaces, a few implications are undeniable.

a. Adaptation to a new demand environment will cause business models to change.

b. Resource competitiveness maximization will shift the positioning of market shareholders along the supply curve. Effects will be visible in their investment focus, oil versus gas portfolio optimization and non-fossil fuel diversification.

c. (hydrocarbon) Resource rich nations will favor domestic interests and national development. This can contribute to geopolitical shifts in managing the transition and create new avenues for collaboration.

Overall, there are multiple avenues that could lead to peak oil before 2040 but demand for the hydrocarbon resource will continue to remains between 70 and 80Mb/d. Global economies remain attached to crude oil for at least three decades on, particularly in oil producing countries. The effectiveness of policies aimed to reduce oil demand is contingent on their socio-economic impact.

[1] Electric vehicle fleet translates mostly into passenger cars and a small share of heavy transport. Plug-in hybrid trains are not included in the analysis, although they could be more disruptive than electric trains only.

[2] Regulatory standards are reflective of vehicle fuel consumption, which are considered to halve current fuel use. The most impactful fuel consumption curtailment would be on passenge vehicles, but heavy dusty trucking would make up a significant share of the absolute fuel use curtailment.



Who is hungry for LNG?

In early 2000s, gas markets were flooded with optimism towards what was then called ‘the golden age of gas’. The rising demand in East Asian markets alongside high prices on long term contracts spurred enthusiasm amongst venture capitalists. This stopped abruptly in 2012-2013 when coal underwent an unexpected ‘renaissance’, displacing gas in power generation across a number of domestic markets. The cheap and plentiful US coal supplies took advantage of the ETS’s (EU carbon permits trading scheme) collapse, which allowed for CO2 to be emitted without being taxed. Currently gas markets are experiencing hard times with LNG (liquefied natural gas) suffering most.

LNG demand is barely staying afloat. In the past 3 years demand for LNG has been flat whilst prices have been steadily going down. For example, Japan the largest LNG importer, was paying at the beginning of 2015, the lowest price level since 2010. It is indeed a ‘golden age for gas’, but for gas consumers rather than producers. The newest exploitation projects of Exxon Mobil and Shell are meagerly holding up to the expectations of their venture capitalists. Since 2014 LNG market response was close to an anxiety attack, which lead to stalling all near future investments projects.

Looking ahead, the sector doesn’t look particularly dependable across a number of regions, as challenges abound. Political instability, the most critical of risks, is present in a number of LNG prospective regions across the globe. In these areas, political regimes are deemed unstable or the tactical political forces have the potential to derail the market. One such example comes from the US market where in 2012 governmental intervention temporarily limited LNG exports under claims that it negatively impacts domestic gas prices. Besides political challenges, logistics have been posing difficulties for LNG project developers. Industry history of construction delays and cost overruns have become the norm rather than the exception. This often happens because of insufficient tanking infrastructure and/or skill labour market tightness, which often push construction costs higher. An independent study by Ernst and Young (EY), a consultancy firm, argued that besides political and logistic challenges, LNG developments are vulnerable to legal ambiguities. Emerging markets are often confronted with immature legal and fiscal systems, which render the first years in the project development highly litigious.

Despite the general pessimism in the air, LNG is projected to see better days, even ‘golden’ ones by some forecasts. In 2014, EY published an extensive report on the future of LNG markets, advocating for the golden future of the fossil fuel. International Energy Agency (IEA) is sympathetic to this forecast, which projects that LNG demand will near 500 mtpa by 2030, almost double compared to the demand level of 2012. This begs the question, in this pessimistic energy climate who is hungry for LNG?

EY LNG forcasted demand

EY LNG forcasted demand

The projections indicate that LNG markets are to undergo a transformation rooted in market behaviors. There are two scales at which changes are to unfold. The first scale is national markets, and the second is international industry sectors.

A wind of change is blowing in international LNG trade. Countries such as Russia, which has maintained a strong position in LNG supply is planning to consolidate that even further till 2030. The 2014 Russian-Chinese deal to export 38 bcm/yr, alongside the investment-exploration project with the French firm Total, will tap closely to its goal of controlling almost a fifth of global LNG supply. The US, which until a few years back was building import capacity at the Louisisana LNG terminal, is now planning to use it for LNG exports. Projections are that operations will start in 2016, and the export capacity will near 75bcm/yr by 2018. Across the globe LNG terminals are planned ahead. The IEA projects that from the number of nations holding LNG facilities will almost double by 2020, reaching 50 from 29 in 2012. Among the latest nations added to the list are Israel, Singapore and Malaysia, but Poland, Croatia, Indonesia and Algeria are moving fast to catch up.

An indication of where the LNG demand is nested comes firstly from nations that are building LNG terminals, such as Indonesia, Singapore and China. In the case of Indonesia, currently a LNG exporter, supply is slowly decreasing at a time when the nation is struggling to keep up with the surging power demand. The government is pushing forward ambitious plans to build the necessary import infrastructure while at the same time ensuring long term supply contracts with the US and Eastern African nations.

The example of Indonesia is not singular in the region. Other nations, such as Singapore, Malaysia and China, are confronted with similar issues. The highest LNG imports in the region will continue though to be absorbed by Japan, who uses the fuel to compensate for its inactive nuclear capacity. This is projected to stay flat, as long term supply contracts are due to run till 2020.

Elsewhere in the world, appetite is building up. Europe is expected to gradually shift to LNG in case Russian gas threatens to run short. Lithuania, which is struggling to free itself from overpriced Russian pipeline gas, as bought a floating regasification terminal. With this, the nation paid itself for fruitful bargaining power, and other nations as such should follow. And other nations are following. Poland and Croatia are prospecting LNG terminals in the future which can bring a breath of fresh air for security of gas supply in the region.

The additional LNG demand is argued to serve nations chiefly for power generation, but sectorial dynamics are bubbling up. The most significant one is the shipping industry which is making efforts to green itself. Maritime transport could greatly benefit from GHG emission cuts by replacing the heavy fuel oil with cleaner LNG. A first notable attempt in this direction comes from the CLEANSHIP project, a Baltic Sea shipping group which pleads for a switch in shipping fuel.

In conclusion, future LNG demand is rooted in Asia, but Europe and African nations could account for a portion of the additional demand if the political climate alters security of supply for oil, and the infrastructure developments incur some degree of urgency. Until then, Asian nations are prone to bring about most of the additional LNG demand. It is reckoned that the fuel will be mainly used for power generation, but also the shipping industry could slowly shift gears to replace oil for LNG as fuel.

Despite all this I reckon that there are important aspects two aspects to be aware of when looking forward at LNG markets. First is that although the share of LNG in natural gas trading has increased in the past decade, the fuel is still mostly traded in long term contracts. For this commodity to start running a viable market there is an increased need for spot trading, as volume is already catching up. Second aspect relates to the over optimism of the forecasts in some markets such as Japan. It is my opinion that some shadow should be casted on the Japanese LNG demand forecasts, as the nation has recently announced that it is planning to soon restart some of its cheap nuclear capacity.

Framing the Russian Gas

EU Energy Consumption of Russian Natural Gas

EU Energy Consumption of Russian Natural Gas

The tense situation in Ukraine these days can be attributed to a series of causes as they are discussed at large on a variety of media outlets worldwide, but it is beyond the scope of this post to identify them and even further develop on them. This post aims to put into perspective what the Ukrainian crisis means for the EU from an energetic perspective, and question how the general state of the situation is going to unfold for EU-28 in the coming years.

Generally, in the context of the international resource dispute the EU-28 countries have started to change their long term energetic strategies by diversifying their energy mix and resource partners. For example, in the wake of the Fukushima nuclear disaster Germany and Sweden have started decommissioning their nuclear reactors; while Denmark is progressively pushing for an ever higher share of renewables in its energy mix.. France and UK are making a move towards gas being it conventional or unconventional. At large, European nations are moving towards less carbon intensive fuels.

The position of the EU countries in the Ukrainian crisis is delicately linked to the EU-Russian relations in a variety of aspects among which the geo-resource position of Russia as a coal, oil and gas exporter. This position is arguably of strategic importance for the EU importing countries especially in areas concerning gas. The dependence on Russian gas can be historically traced back to the end of World War II, but more recent events (the end of the Cold War) have tighten the strings and lead to bilateral cooperation. After the Cold War, European powers envisioned to unify the energy market in the same manner they’ve done with the Coal and Steel Community after the World War II, and thus further strengthen their position as a unified economic power in the international markets. By intending so, France made the first move and engaged Denmark and Germany alongside in a dialogue with Russia about building a gas pipeline extending from Russia all the way to France. This pipeline would feed-in the energetic needs of the transit countries and France, in the context of an increasing energy demand in the West European nations in late 1970s. At the time when this project was initiated it was rather ambitious and risky for Europe, which is why eventually it did not take off. In the coming years France moved on in building a nuclear fleet and Germany exploiting its coal resources, but mid 1990s brought back the need for cheap and reliable fossil resources in Europe. This reopened the EU-Russian dialogue for the Russian gas pipeline (Nord Stream) which was launched in 1997 and inaugurated in 2011. This pipeline accounts for about 20% of the European gas imports from Russia, a share which is prone to increase year by year (CIEP, 2013).

With the expansion of the Nord Stream pipeline in late 2013 the Ukraine transit gas pipeline is facing pressure. Even if absolute imports via Ukraine have changed little over the past years, the share of Russian gas imports in Europe via Ukraine has decreased (CIEP, 2013). This means that the Ukraine transit gas pipeline is feeding less gas into Europe via Romania and Bulgaria, than it used to; and this downward trend is expected to continue in the coming years mainly because of the gas hub associated with Nord Stream and the tense situation in Ukraine. A CIEP report (CIEP, 2013) on the issue argues that the Ukraine transit Russian gas pipeline renders vulnerable Eastern EU Member States such as Romania and Bulgaria which import 25% and respectively 100% of their gas needs via this route (Financial Times, 2014). These nations are faced with the challenge of ensuring gas security of supply because of their relative weak integration of transmission systems with the rest of Europe.

Crunching the numbers shows in fact how little the Russian gas incoming through Ukraine actually accounts to the overall EU-28 energy consumption. In 2013 the Russian gas imports transiting Ukraine represented about 15% of the total gas consumption of the EU-28 Member States, which in absolute terms represented about 80 Bcm/year (2013). Of the total volume of gas import incoming through Ukraine, only 53 Bcm/year are under security of supply ‘threat’, and of meager concern for EU-28. This volume represents a marginally 2.3% of the total energy consumption of the EU-28 (2013) and can be compensated for by the diversification of pipeline routes and the reliable storage levels put in place after the 2006 and 2009 shocks. At large, the Russian gas transiting Ukraine is a sensitive issue when there are no alternatives to address this supply, but alternatives could be set-up through joint efforts. Rough estimates argue that EU-28 can survive without Russian gas cca 300 days/year (2013), an estimate which has improved greatly since the first gas shock in 2006.

When factoring in the recent developments of the EU-28 energetic infrastructure one might argue that Europe is an energy shocks free region. With EU 2030 Climate and Energy Framework ambitions ahead, the European nations are making progressive steps towards achieving the 40% CO2 reductions (1990 base year). The means to achieve this is through peak shaving and switching to less carbon intensive fuels; the combination of both is LNG in NGCC. The existing 28 units (2012, incl. under construction units) are expected to be enforced by the additional 32 projected units. This impels for a Europe wide effort to unify the gas network for an increased energy security in the region.

In conclusion, the EU-28 has reasons to be concerned about the security of gas supply of its Eastern Member states in the context of the Ukrainian crisis but the bigger picture shows a unified strong European energetic market, which could easily tackle gas shortages via the storage capacities available and the diversified pipeline routes. As pointed out above, the dependence on the Russian gas transiting Ukraine, is marginal in absolute terms and the diversification of pipeline pursued in the last decade (Nord Stream, Blue Stream) softened the risk of transit related supply disruptions

Framing Fracking


Public risk perceptions can fundamentally compel or constrain political, economic and social action to address particular risks. It is argued that feelings are not mere epiphenomena, but often arise prior to cognition and play a crucial role in subsequent rational thought. Cultural theorists argue that hierarchists, individualists, egalitarians and fatalists each identify and define different risks. Each worldview thus represents a different ‘rationality;’ a set of presuppositions about the ideal nature of society which leads each group to perceive different risks and prefer different policy responses. It is them that call for the active management of risk by ‘experts’ whom they trust. For individuals, the strongest constrain is that of autonomy which mainly comes from government regulations. For private actors the constrain is that of common pool resources viewed with injustice in their distribution and bearing risk costs and benefits.
When looking at environmental problems, Fisher argues that different parties understand the same environmental problem differently, and within these different parties, there are generally divergent opinions of what the problem actually is. I will take the next few lines to go over the process of hydraulic fracturing and point to the different risks that this unconventional method for natural gas extraction possess. Ultimately I will explain the way it is currently framed and where the largest risks actually are. The process currently in use for hydraulic fracturing is rather simple in terms of technical stages, with the entire drilling process taking no more than three months on site.



The initial water bore is drilled using a drill pipe. The boring continues well passed the aquifer and groundwater level. In the geologic formations, thousands of meters of rock separate shale reserves from the lowest ground water reservoirs. At this point, the drill pipe and bit are removed, and a steal tube called surface casing is set inside the well. The tube stabilizes the well sides, creating a protective barrier from fresh water reservoirs. Cement is then pumped into the well through, displacing any remaining drilling fluids, and permanently securing the casing. About 900 to 1500 m above the hydrocarbon bearing shale formations, a specific downhole drilling motor, with sophisticated measuring instruments begin the angle drilling to create a horizontal path to penetrate the targeted layer of gas or oil bearing shale. When the perforating tool is removed, a pressurized mixture of water, sand and chemicals are then pumped at a rate of 15,000 liters/minutes. The fluid generates numerous fissures in the shale thus allowing hydrocarbons to enter the stream.
By combining horizontal drilling and hydraulic fracturing the CO2 drilling footprint of shale gas is reduced, making it possible to extract oil and gas in places where previously these technologies could not. The US has already seven decades of experience with fracking, having dug “approximately one million wells” since the 9040s. What makes this technique so controversial are its associated potential environmental consequences. Among the most pressing environmental problems it can generate are: water contamination, methane (CH4) leakages and earthquakes.
Firstly, the ‘fracking cocktails’ include besides water and sand which make up a large proportion of the pressurized mixture, “acids, detergents and poisons” substances often not regulated by environmental policy neither in the US or Europe. These substances pose human health risks when entering in contact with drinking water sources. A study published in 2011 by the US Health Institute found in a survey that more than a fifth of the households in a 50km range from shale gas extraction sites in north-eastern Pennsylvania and New York were contaminated with CH4. It is a fact that methane can escape from the casing throughout the stream, but it’s at the aquifer and waterbed levels that this poses the highest health related risks. The water used in the pressurized mixture comes to the surface eventually, containing small but perceptible concentrations of “radioactive elements and huge concentrations of salt”. In cases of poor disposal of residual waters, associated environmental impacts on biodiversity can occur. In order to boost efficiency of shale gas extractions, often enough, corporations choose to not disclose the composition of the drilling and fracking compounds, thus putting environmental agencies in a difficult position.
Secondly, the production and delivery chain of natural gas extraction, through different techniques, is charged with methane release at different stages and the exhaust of other GHG in the burning process. Because of the additional emissions released when burning the gas and the mix of GHGs associated with the production of the extraction facilities, it is relevant to look at the life cycle of hydraulic fracturing and not only at the pure burning of the gas and extraction flaws. Such comparative analyses have been carried out by numerous environmental agencies in various nations. The most influential one was published last year by the National Energy Technology Laboratory in the US. This study concludes that the combined effect of GHG emissions associated with hydraulic fracturing raise the GHG potential of this technique to 32.5 (as compared with conventional extraction which is 25, and compared with coal burning which is 1).
Lastly, human induced geo-hazards are an associated effect of hydraulic fracking, but given their low probability in terms of time recurrence they are often mentioned but not addressed. Give the US progressive attitude towards shale gas extraction it can be now used to assess this technique with existing empirical evidence. From the approximately 75,000 deep injection wells that have been performed in the US alone, only about 8 sites have experienced “injection-induced earthquakes”. The next question is indeed how strong these induced earthquakes were? William Ellsworth of the U.S. Geological Survey notes on a recent study he performed, that “the change was really pronounced […] around waste water wells”. The same study features a brief statistics, showing that since the 1970s, there have been on average additional 20 low magnitude earthquakes recorded in the vicinity of shale gas exploitation sites, with no human health impacts accounted for so far.
Fisher argued that the US environmental law has been since the 1990s been labeled and conceptualized as ‘risk regulation’. But how is that shaped around fracking? A study performed by a Canadian institute argues that the largest environmental impacts associated with fracking are related to climatic impacts and underground caving. The price tag of hydraulic fracturing on climate change is approximately 15 billion dollars annually, with the industry growing. For the underground caving, the estimates come close to 12 billion dollars, but scientists argue that it is hard to quantify the extent of the damage with the poor data available from private projects. Currently the US legislation frames fracking as hazardous technique only from a hydrologic angle, related mainly to health impacts of water contamination. The quantified risks for water contamination, as evaluated by the Canadian institute, come close to 1 billion dollars/year.
One can ultimately argue in such a case that matters are complicated by the fact that the use of risk is not neutral. If risk is understood primarily in quantitative terms then only those aspects of an environmental problem which can be measured will be subject to analysis. Is that what we’ve come to believe in?