Before we begin discussing current oil market fundamentals, we would like to discuss an important project that we have working on for some time. As we discussed in the introduction of this letter, for the first time in at least 75 years, the world is now consuming more oil than it is adding to conventional reserves. Global conventional field discoveries are slowing precipitously, and without new field discoveries, conventional gross reserve additions are rapidly de-accelerating. The only practical way to add new reserves will be through unconventional sources of oil, most notably through the shales. The US has discovered approximately 100 billion barrels of recoverable oil from the shales or approximately 10 billion barrels per year for the last 10 years. Over the same time period, global gross conventional reserve additions have slowed by approximately 13 billion barrels per year (from 39 billion barrels in 2006 to 26 billion barrels in 2015) with no sign of re-accelerating. We are now consuming 35 billion barrels of oil per year, so clearly we are not replacing consumption with new conventional reserves. While the US shale plays have had a large impact on today’s supply-anddemand dynamics, they simply are not enough on their own to change the longer-term depletion issues now challenging the global oil industry. According to the BP Statistical Review, global oil reserves now stand at 1.7 trillion barrels, implying the US shale reserves represent less than 6% of total global reserves. It is clear that unless we can “export” the shale oil success from the US to the rest of the world, the US shale are simply not be enough to offset the collapse taking place today in conventional reserve replacement.
Most analysts simply assume that the techniques mastered in the US (most notably directional drilling and hydraulic fracturing) will soon be used to develop the rest of the world’s shale basins with similar results, much in the same way that conventional production techniques were exported from the US to the Middle East in the 1930’s or deep-water drilling was exported from the US to the North Sea in the 1960’s. The EIA estimates that there is over ten times as much shale acreage in the rest of the world as in the US. Once the industry begins the successful development of the international shales, global reserves and related production will surge, or so goes the consensus opinion.
However, we believe there is a problem with this logic. Success in developing the global shales assumes that the rest of the world’s shales will be as productive as the US shales, despite the fact that little (if any) research has been undertaken on the subject. In an attempt to answer the question: “Can we export the oil shale revolution to the rest the world?” we have carried out an in-depth geological assessment of 160 global oil-bearing shale formations outside of the US in an attempt to assess their potential commercial development using today’s drilling and completion technologies. In our research, we have tried to identify which global shale basins possess the geological qualities needed to make them commercially productive. We then built a model that ranks the shales from the best prospectivity to the worst, to try and predict which international shale basins have the highest probability of being commercially developed. We believe the results are interesting, extremely important, and will have a significant impact on global oil prices as we progress through the end of this decade. Before we start, please note that data is sparse for several Middle Eastern shale basins (most notably Saudi Arabia, Iran, Kuwait, and Iraq), and the shales located in these countries have been excluded from our study. We will update our models as soon as this country data becomes available. Also please note that our analysis today pertains only to the global oil-bearing shales. There are approximately 230 significant gas shales in the world, but assessing their prospectivity will only impact global gas fundamentals, and will have little impact on global oil supply.
As a starting point for our research, we used the EIA’s “Technically Recoverable Shale Oil and Shale Gas Resources” report--last updated in September 2015. While we are neither geologists nor geochemists, we do have a large amount of knowledge and investment experience regarding what factors have led to successful development of shale plays here in the US and Canada. For example, we were very early in identifying the potential of the Barnett, Fayetteville, Marcellus, and Montney (Canadian) gas shales as well as the prolific Permian Basin family of stacked oil shales. Combining this real-time investment experience with the many discussions we have had with geologists, engineers, and exploration and production company executives over the last 15 years, we believe there are eight extremely important geological factors needed to make an oil shale productive.
Our index’s most important input factor is the shale’s clay content. If there is one characteristic that everyone agrees on, it is that a shale reservoir must have a low clay content. Why is clay content so critically important? Since shale reservoirs lack natural permeability, artificial permeability must be created in the reservoir by “fracking”-a process in which huge amounts of energy is injected into the shale. The “fracking” forces apart the micro-fractures in the shale and the resulting pathways, kept open with sand and artificial proppant, allow oil to flow.
If a shale contains a high level of clay, the energy introduced in the shale by “fracking” will be absorbed by the clay, the micro-fissures in the rock will not be forced open, and the oil molecules will not flow. Also, if a shale has a low clay content, it will have by definition a high silica/carbonate content. Clay and silca/carbonate contents are inversely related in a shale. High silica and carbonate contents are critically important for a shale to be productive. High silica/carbonate content shales are brittle and fracture easily. Every oil (and gas) shale play successfully developed to date had low clay-content (and by extension a high silica content). Although the technology needed for the successful development of high clay-content shales might be developed in the future, our research suggests we are still long way off.
One of the biggest factors determining clay levels in shales is whether the shale was deposited in a marine or a lacustrine setting. In a marine setting, the shale is formed as marine organic matter dies and is deposited on the seabed floor. The nature of the organic matter (i.e., dead marine organisms) tends to be higher in silica and lower in clay, which often results in a very brittle source rock that shatters extensively when the well is completed. On the other hand, lacustrine depositional environments are the result of organic matter that is deposited into ancient rivers and lakes. The organic matter in a lacustrine environment is typically plant-based, and is often “waxy” with a resulting high clay and low silica content. Therefore, a lacustrine shale is less responsive to the energy introduced in the hydrological fracturing process, and is less likely to produce. In fact, not one of the major US shale basins (either oil or gas) developed to date has been lacustrine—all have been marine.
After clay and silica composition, the shale’s total organic content (TOC) is the next most important factor in the construction of our index. After deposited organic matter is compressed into shale, the shale is “cooked” under the earth’s high temperature and pressure, and is converted into hydrocarbons. If the shale lacks enough organic content, it simply will not be able to produce hydrocarbons. Since all of the hydrocarbons are produced directly from the source rock itself, if the TOC of shale is low, few hydrocarbons will be produced.
The thickness of the shale is also critically important. Shale wells tend to be drilled using horizontal drilling techniques, where a well-bore is steered underground and then extended laterally for several thousand feet in order to access the maximum amount of source rock. The thickness of the shale layer, (along with the stimulation techniques employed) determines how much actual shale is accessed per foot of lateral leg drilled. The net thickness of a potential shale deposit can vary tremendously and often makes the difference between an economic play and one that will never be produced.
Another important factor is the estimate of original oil in place per acre. This metric is a function of several other geological variables, including the porosity of the shale, the organic content, the thickness and the thermal maturity (another very important variable). In summary, it is an attempt to estimate the amount of hydrocarbon in place per acre of surface aerial extent, and is critical in assessing the estimated ultimate recovery (EUR) of hydrocarbons per well. This, in turn, is used to determine the economics of the well.
The aerial extent of the shale is also very important. While the shale’s prospective area does not directly impact the economics of a given shale well, it will clearly determine the ultimate size of the potential field, once the economics have been shown to be attractive. The last factor we consider is the depth of the shale. If the shale is too shallow, it may lack the thermal maturity necessary to convert the organic matter into hydrocarbons. If the shale is too deep, it may have been subjected to excessive heat and pressure, resulting in a gas-prone shale. Furthermore, an overly deep shale can be excessively overpressured, making for a more challenging (and expensive) drilling environment.
Based upon these weighted factors, we created an “index” score for every shale play included in the EIA’s report and ranked them based on this score. For the 160 shales included in our study, the average score was 50, while the top 10% had a score of 70 or greater. Next, we used our knowledge of all the US shale basins to estimate the “cut-off” score that would delineate a productive shale from a non-productive shale. Based upon our research, we estimate for a shale to be economically productive, it must have a clay content of 30% or less, total organic content of 3% or greater, a net thickness of approximately 100 feet, oil in place of approximately 45,000 barrels per acre, an aerial extent of approximately three million acres, be marine-based and have a depth of approximately 9,000 feet. This hypothetical shale would generate a score of 65, and represents our best estimate of the “cut-off” value between a good quality and poor quality shale.
With our index constructed, and our “cut-off” shale identified, we can immediately make two very important conclusions. First, almost 90% of the 160 oil shales assessed in the EIA report do not make the “cut-off” grade, and second the shales in the United States are all amongst the best in world. If our modelling is correct, one can easily conclude that almost none of the international shales will ever produce as prolifically as the shales here in the US.
For those who believe the US shales are only the beginning of the global shale revolution, this is going to be very disappointing news. Instead of having ten times the potential reserves of the US shales (based upon acreage), our models, which incorporate geological constraints, indicate that much of the potentially recoverable resource falls away. For example, the 19 potentially productive international shales that score above 65 have a combined prospective area of 265,000 square miles and an estimated risked recoverable resource of 130 billion barrels of oil, a figure only slightly greater than what exists here in the US. To put this number in perspective, if these 130 billion barrels of potential reserves were included today, they would increase world proved oil reserves by only 8%.
Even more incredible is how high quality the US shales are compared with the rest of the world. For example, of the 19 potentially productive international shales, only three have scored higher than the average US shale. Looking only at the world’s best shales basins, the US makes up five out of the top 10 , and represents 50% of the risked recoverable resource of this select group. The only shale with comparable size and quality to US is the Bazhenov shale in Russia. With an estimated 75 billion barrels of recoverable reserves, this is a huge, high-quality shale which we will discuss in a minute. Except for the Bazhenov shale, one can make the case that instead of standing on the dawn of a global shale revolution, most of the world’s top-quality shales have already been put into production.
What makes the US shales so prolific? First off, all of the major US shale oil basins (i.e., the Eagle Ford, both the Midland and Delaware basin of the Permian, the Bakken and the Woodford) have low clay contents (less than 30%). Furthermore, they have very high total organic content, averaging 7.27% compared with the global average of 3.87%. The top decile of ranked shale plays outside of the US only averages 4.6% TOC (36% lower than the average productive shale in the US). None of the US shales are lacustrian, while all are approximately 9,000 feet deep and (with the exception of the Bakken) all have an average thickness of ~500 feet versus 240 feet for the rest of the world’s shales and ~430 feet for those in the top international decile.
Simply put, our analysis strongly suggests that we are massively overestimating the potential of the global shales. Having said that, there are indeed certain plays that we believe will be world class. For example, the La Luna shale in Colombia ranks as highly as the Permian basin or Eagle Ford. It has a low clay content (17% clay), organic content of 5%, 400 feet of net thickness and a depth of 10,000 feet. Its porosity is very good, which along with its organic content has resulted in an elevated oil-in-place estimate. Estimated recoverable reserves approach 20 billion barrels of oil. Similarly, the Vaca Meurta shale in Argentina has a very high score on all of the geological criteria we have listed. Total recoverable reserves are estimated to surpass 15 billion barrels. While Argentine political hurdles have slowed the development of the Vaca Meurta shale, it appears that some of these issues are now improving. We believe the Vaca Meurta will ultimately be productive over the next several years.
Perhaps the single largest source of shale oil outside of the US comes from the Bazhenov shale in Russia. As mentioned earlier, the Bazhenov shale contains an estimated 75 mm barrels of recoverable reserves. The Bazhenov shale served as the source rock for the massive conventional West Siberian oil and gas fields. These conventional fields include many super-giant fields such as the Samotlor field, the Middle Ob region and the Urgengoy gas field. Sections of this shale play have organic content as high as 10% (although the sections most likely to produce oil are around 5%), over a massive total prospective area of 120 million acres. Clay content is very low at less than 20%. Furthermore, the shale layers are interbedded between fractured carbonate layers that lend themselves particularly well to hydrological fracture stimulation. Average depth is 8,200 feet. Declining conventional production in the region means that there is already existing gathering and transportation infrastructure that is currently under-utilized. While several super-major international oil companies initially signed agreements to help develop the Bazhenov shale, there has been no major progress to date due to explicit sanctions against western companies engaged in Bazhenov’s development. Another problem is the Russian taxation regime that favors conventional oil production, however if either of these political hurdles were resolved, it could accelerate the development of the basin.
Perhaps even more interesting, our analysis suggests that many of the global shale formations making headlines today do not have the geological characteristics required to be productive. For example, while there was much hype surrounding the Polish Llandovery gas shales after several major oil companies acquired acreage positions in 2010, our models told us that the relatively high clay content (as high as 40%) combined with relatively-low organic content (between 3-4%) made these shales unattractive. We were not surprised to see all drilling plans abandoned after initial disappointing drilling results.
Det finnes mye potensielle olje- og NG-ressurser låst inne i skifer-mineraler på alle kontinentene.
I noen finansmiljø er disse promotert å være så store at det skal kunne holde både olje- og NG-prisene lave for "all fremtid" (eller inntil fossile ressurser blir faset ut av annen teknologi og energikilder, i.e. "peak demand"?)
Iflg. denne artikkelen er ikke realitetene like enkle.
Som alle andre mineralforekomster, er det store forskjeller mellom ulike forekomstene.
De faktorene som er viktige for å vite om en skifer-ressurs er kommersiell utvinnbar, er:
- Hydrokarbon (organisk karbon) innhold,
- Tykkelse på skiferlagene
- Av disse 2 faktorene kan man anslå den avledede størrelse: antall fat olje-ekv. pr. kvadrat-km eller kvadrat-mile
- Utbredelse (areal)
- Dybde (grunne ressurser produserer tyngre komponenter = råolje, dypere ressurser produserer lettere komponenter = NG/tøø/våt-gass)
- og sist, men ikke minst, mineral-sammensetningen i skiferen. Og av disse er leire, karbonat og silika viktige.
Høyt silika/karbonat-innhold er en forutsetning, mens høyt leire-innhold er en "show-stopper".
Og slik jeg tolker artikkelen, er det på;
- lavt organisk- og
- høyt leire-innhold
de fleste skifer-ressurser feiler for å kunne bli kommersielt produserbare.
Det er enkelt å forstå at dersom hydrokarbon-innholdet i skiferen er for lavt, blir produksjonen for lav, og feltet ulønnsomt.
Når det gjelder høyt leire-innhold, så tolker jeg artikkelen slik at ressurser med høyt leire-innhold ikke responderer godt på fracking'en, slik at det ikke er mulig å sprekke opp berget og danne porer som hydrokarbonene kan strømme gjennom - til brønnen.
Leire er et "plastisk materiale", og vil "absorbere" energien fra frackingen (som en "støtdemper"), når det pumpes borevæske med høyt trykk ned i brønnen. Slik får man ikke sprukket opp berget skikkelig.
Hvis dette er realiteten, så er de fleste av verdens skifer-områder av mindre verdi, og som råolje-ressurs teller lite i det store bildet.
Sett bort ifra at EIA ikke har fått data fra skifer-ressurser i AG (S.Arabia, UAE, Kuwait etc.), så er den viktigste skifer-ressursen utenfor N.Amerika den enorme Bazhenov-området i Russland, som er kildebergart for noen av de største olje- og NG-feltene i Sibir som russisk olje-industri har levd på de siste 50+ årene.
Dersom dette er en korrekt oppfatning av skifer-ressursene, er det kanskje ikke lenge til industrien igjen vil diskutere peak oil, og om "peak supply" vil komme før "peak demand"?]
Legger inn hele artikkelen, den er bak en betalingsmur.
Hey investors! The death of petroleum is greatly exaggerated
Eric Reguly, Globe and Mail, Report on Business
Jan. 29, 2018
The end is nigh for oil. You read this everywhere, so it must be true. Sales of electric cars are taking off. A few countries—the United Kingdom, France and India among them—have announced plans to ban the sale of new vehicles powered solely by internal combustion engines. Fuel economy in cars powered by gasoline or diesel is climbing, which will put another crimp in petroleum demand.
Even Norway's $1-trillion (all currency in U.S. dollars) sovereign wealth fund wants to ditch its oil and natural gas investments. Its managers haven't been fully clear about the reasons, but it's likely not because of a moral problem with fossil fuels. Rather, they apparently fear the world is about to enter an era of declining oil consumption and permanently low prices.
If they're gambling on a trend, they're not alone. By late December, the oil and gas sector of the benchmark European Stoxx 600 index was down about 3% on the year, even though oil prices had climbed by close to 15% and the overall index was up more than 8%. The big performance gap suggests oil investors are cashing out.
At least some are probably stampeding into shares of electric-car maker Tesla. Its stock price soared by about 60% in 2017, giving the company a stock market value of $56 billion, on par with General Motors.
If the tech industry is enamoured with one word, it is "disruption," and oil markets certainly seem rattled as the electric revolution gains momentum. The problem with the vision is that there is no electric-inspired disruption, at least not yet.
Global oil demand continues to climb, while the percentage of electric cars on the road is negligible. Relatively speaking, it should remain negligible for many years, unless there is a great technological leap that would see battery prices plummet and the range of the cars they propel double. But there is no sign that such a breakthrough is imminent. Old-fashioned lithium-ion batteries, which have been in commercial production since the 1990s, still power even the newest e-cars.
For oil bulls, a vanishing species, one number that should give even greater encouragement is 1.8 billion. That is oil giant BP's forecast of the size of the global auto fleet by 2035, a rise of about 80% from the current level. Other forecasts are also bullish. Transportation—cars and trucks—will eat up almost half of global oil production.
Most of those new vehicles will continue to be fully or partially powered by petroleum. In a recent article in the Financial Times, Cuneyt Kazokoglu, head of oil demand at Facts Global Energy, an oil and gas consultancy, says just 10% of the global auto fleet will be fully electric by 2040, with hybrids taking up another 20% (hybrids, like the Toyota Prius, have combined gasoline and electric motors).
Kazokoglu's estimate seems reasonable. Yes, electric car sales are rising sharply, but they're climbing from a very low base. The total sales are piddling, despite often-lavish government purchase incentives, and perks such as free parking and no road taxes or highway tolls in some countries.
Global e-car production reached just 500,000 vehicles in 2016, a sliver of total light vehicle production of 70 million. Tesla, the biggest U.S. maker of electric cars, produced just 80,000 units in 2016. In 2017, the number was expected to reach 100,000. The world's bestselling e-car, the Nissan Leaf, has sold fewer than 300,000 units from its launch in 2010 to mid-2017.
Even if the market share of electric cars were to quadruple over the next decade or so, they would account for less than 3% of worldwide auto sales. That kind of increase is very doubtful, in large part because many governments are trying to roll back purchase incentives.
It's politically difficult to keep the incentives. E-cars are generally luxury items—the Tesla Model S starts at about $80,000. Critics complain that the subsidies transfer wealth from the unrich to the rich. In the United States, the sales incentives for the Leaf, which has a base price of roughly $30,000, have averaged about $16,000. But watch what happens when incentives drop off. In late 2015, Denmark announced the phase-out of some e-car subsidies. Electric car sales quickly fell by 60%.
Meanwhile, gasoline and diesel remain cheap. In the United States, gas is about $2.50 a gallon (roughly 85 Canadian cents per litre). Fuel-guzzling SUVs and crossovers are still the hottest sellers by far, and electric SUVs are virtually non-existent. Every year, global vehicle production rises by about two million units. As the auto craze hits Asia, most of the hundreds of millions of new cars and SUVs sold will run primarily on gasoline or diesel.
Far from falling, oil demand is set to rise steadily for decades, despite the undeniable environmental benefits of e-cars. Given the slowdown in oil exploration and the paucity of big oil discoveries, oil prices seem more likely to rise than fall. Pity the planet but praise the oil investors who stayed put.
En analyserapport fra S&P Platts, en seriøst medie- og analysehus innenfor råvare-industriene.
Rapporten omhandler energi, transportsektoren, fossil-transport, bensin, diesel, LNG, EV, HEV, hydrogen og batteriteknolig og forsynings-industriene til disse, og selvsagt miljø-påvirkning slik de ser det.
It’s easy to get carried away with the hype surrounding electric vehicles (EVs). Sales of battery-powered cars may be surging, but the technology is still in its infancy and batteries are by no means the only low-carbon solution for global mobility.
What’s clear is that understanding the changing face of transport in whatever form it takes is one of the big challenges facing the energy and commodities industries. This special report — bringing together the very best of S&P Global Platts news and analytics insights — will help to shape the debate and provide decision makers with the key facts and information they require to future-proof their business models.
Like any disruptive technology, there will be winners and losers in the drive for more fuel-efficient internal combustion engines, or the development of cheaper and more usable EVs. Big oil companies are already adapting fast by investing heavily into the production of cleaner transportation fuels, such as liquefied natural gas, and by installing charging points into their service station networks. Some are going a step further by investing in power generation and distribution.
Despite these new business strategies, S&P Global Platts Analytics’ current projections are that oil production will have to increase in order to meet rising demand from road transport for years to come. EVs are likely to remain a small part of the overall global vehicle fleet unless the technology improves significantly and the cost of production falls. “It is important to emphasize that oil is expected to remain the most important fuel in the global energy mix for decades to come,” says OPEC Secretary General Mohammed Barkindo in the report.
If changes to mobility are a challenge for oil producers, they represent a new opportunity for the $800 billion global mining industry. Some battery resources such as lithium exist in abundance. Data from the US Geological Survey shows 400 years of supply at current production levels. However, other vital commodities face bottlenecks. Copper, nickel and aluminum could all see prices rise from growing EV demand. Cobalt—another key ingredient in batteries—is heavily dependent on high-risk areas such as the Democratic Republic of the Congo. The possible outcomes for metals producers are also explored in the report.
The growth of EVs in developed markets such as Europe is dependent on subsidies and policies designed to push consumers into battery-powered transport, especially in urban areas. How the market for this emerging form of passenger transport will hold up once these incentives are removed is uncertain. Finally, we should recognize that EVs are also not the only solution for future mobility. Autonomous vehicles could transform the traditional model of car ownership, while hydrogen may eventually provide another alternative fuel, especially for larger commercial vehicles. The advantages of all these scenarios are considered in depth in the report, which I believe will be an indispensable guide for business to the future of mobility.
Fossil fuels have dominated transportation for the past century and are likely to continue to for the foreseeable future. However, new technologies and fuels, climate change policies and market drivers now threaten its dominance like never before.
Developments in batteries could make electric vehicles (EVs) cost competitive within a decade. Government policies and subsidies add to the pressure for change. Vehicle manufacturers are also investing tens of billions of dollars to prepare for a future that might see a growing share of EV sales.
Heavier duty vehicles, ranging from vans to long-distance trucks and buses, are also seeing a wider range of new cleaner fuel options. The transition is important for the downstream oil industry since both gasoline and diesel consumption may be threatened.
Electrification is not the only potential challenge for oil. Autonomous vehicles (AVs) could turn the world of transportation into a service industry with fewer cars on roads. Much higher utilization rates would have a wide ranging impact on fuel use, vehicle sales and even urban design. EVs are not necessarily the end game. Hydrogen could ultimately be better in terms of range and refueling, especially for heavy duty vehicles.
Europe is at the forefront of regulating the low-carbon transport revolution. The region’s policymakers are actively pushing manufacturers and consumers toward higher-efficiency loweremissions vehicles.
China’s market is the most dynamic in terms of low-carbon transport. By almost any measure, China currently leads the world in road transport electrification. Moreover, EV growth offers China an opportunity to re-write the established order in both domestic and foreign markets, potentially benefiting as a world leading EV exporter.
Change isn’t guaranteed. Refueling and range are concerns for consumers. The overall performance of EVs is well below ICEs. Currently, the lack of widespread recharging stations is a key constraint on the market. The infrastructure is being built, but there is much to be done to give consumers the comfort level provided by gasoline and diesel.
The recharging impact on the electric grid is another factor that will have to be monitored carefully. Network management of EV demand is a critical factor in the transition to alternative transport.
Costs for EVs and battery packs must come down to the point where there is no significant premium over car ownership. Niche buyers may pay more for perceived environmental benefits, but the industry must still provide clear value for wider penetration to take off. That is not yet the case for EVs.
Costs are coming down. Lithium ion battery pack costs have dropped to below $300/kWh today, from $1,000/kWh in 2010. Expansive plans for additional battery manufacturing capacity should continue to drive the costs down, potentially toward $100/kWh, where it should achieve parity with ICE’s in markets with higher fuel prices.
EV demand is already proving disruptive for the metals industry, especially for lithium and cobalt prices. Sufficient minerals and metals exist in the earth’s crust to satisfy projected demand. However, more production and mine investment is essential to minimize the impact of what most analysts see as an impending supply deficit, and to keep prices steady, especially for lithium.
The oil industry has time to adapt. EVs first have to penetrate new car sales — currently less than 2% globally — and then slowly over time replace the entire fleet, which is 10 times the size of new car sales. This is a process that will occur over decades, not years. Despite EV growth, global road transportation demand for oil should continue to rise well beyond 2030. And even if conventional road transport turns negative in the future, there will be demand for petroleum for other uses such as petrochemicals, or air and marine transportation.
Large oil producers such as Saudi Arabia and OPEC are already adapting to the changing face of transport by investing in new technology and engaging with industry stakeholders. Major upstream projects are unlikely to be affected by growing EV penetration in the near term. Oil demand could also benefit from growing use of plastics and other petrochemicals products in the construction of lighter EVs.
EV developments may capture the headlines and the public’s imagination but the evidence suggests that even after a century of road domination the engine and fossil fuels both have a big role to play in the future of transport.