Natural Hydrogen: The Fuel Drillers Spent a Century Discarding

In 1987, a crew drilling for water near the village of Bourakébougou in Mali hit gas instead. The borehole produced a stream that measured 97.4 percent hydrogen, with 1.2 percent nitrogen and traces of everything else, and it was capped as a hazard. Two decades later the same hole was connected to a generator, and it has been powering the village ever since.

That field is still the only natural hydrogen site in the world producing commercially. It is also why a quiet corner of geology has turned into an energy story. Hydrogen, the gas that oil and mining engineers spent a century venting, flaring, and treating as a contamination risk, turns out to collect underground in some places.

Two documents changed the conversation. The Royal Society published a policy briefing on natural hydrogen in June 2025, and a German national academies’ project followed in April 2026 with a discussion paper that is far more cautious than most headlines. Read together, they separate what is measured from what is modeled, and what is modeled from what is hoped. This article works through that evidence, the wells now being drilled in France, Spain, Kansas, and Australia, and the single number that will decide whether any of it matters.

A Water Well That Found the Wrong Gas

Bourakébougou is a small field with an outsized reputation. Twenty-five wells have now been drilled into it, some as shallow as 100 meters, and the gas is remarkably clean: no meaningful carbon dioxide, almost no methane. The reservoir is carbonate rock, and an intruded igneous body is thought to form the seal.

The flow rate is the part that rarely makes the headline. The 1987 discovery well produced about 1,500 cubic meters of hydrogen a day. A good production well in a conventional North Sea gas field moves more than two million cubic meters a day. Natural hydrogen, at least at this site, arrives in volumes that suit a village rather than an economy.

There is a puzzle attached. No pressure decline has been observed at Bourakébougou despite years of production, which some researchers interpret as hydrogen being continuously generated somewhere nearby to replace what is drawn off. The Royal Society’s briefing treats that reading as speculative. Slow reactions and a tapped interval fed from a deeper accumulation could both produce the same flat pressure trace.

What Mali proves is narrower than it looks: hydrogen can accumulate in a trap, and it can be extracted without anything exotic. What it does not prove is that the same thing exists at a scale worth building supply chains around.

The Map Is a Map of Where People Looked

Natural hydrogen was never really hidden. A well drilled on Kangaroo Island off South Australia in 1921 returned gas that was 50 to 70 percent hydrogen, and it was written up in 1933. Mines in Canada, Finland, and South Africa have recorded hydrogen for decades. The reason the resource went unexplored is bureaucratic as much as geological: hydrogen was not part of routine gas analysis, so most of the data simply was not collected. As Australia’s national science agency notes, the standard simplified gas chromatography used in hydrocarbon exploration from the 1960s onward left hydrogen and helium effectively undetectable, and wells drilled for oil and gas typically sampled at 1,500 to 3,000 meters while the Mali hydrogen sits shallower than 500 meters, so the datasets were skewed from both ends at once.

Millions of oil and gas wells drilled over a century detected nothing beyond trace hydrogen, and the reasonable-looking conclusion drawn from that was that economic accumulations did not exist. The flaw is that nobody was measuring it. Published maps of natural hydrogen deposits show where people have looked, not where hydrogen is. Eastern Europe and parts of Asia look unusually rich partly because the Soviet Union ran systematic hydrogen surveys, and regions with no dots may have no data rather than no gas.

Prospectors are borrowing the oldest trick from the oil industry: working backward from surface seeps. Researchers have used high-resolution satellite imagery to map circular vegetation features, sometimes called fairy circles, that have been tentatively linked to hydrogen leaking upward, and explorers in South Australia are already using them to pick drill sites. Others are mining the history books for hydrogen shows in old wells. A third approach skips occurrences entirely and maps the geology instead, rating regions on whether source rock, reservoir, and seal are all present. None of these methods has yet delivered a second producing field, which is why exploration remains a hypothesis business.

There is a second reason the signal is faint, and it is biological. Hydrogen is food. Microbes in soils and deep rock consume it, and microbial communities have been found kilometers down in the continental crust. A seep at the surface can look negligible precisely because a reservoir below is being digested on the way up. The Royal Society lists both false positives, from microbial hydrogen production or drilling artifacts, and false negatives, from microbial consumption, as live problems for anyone prospecting with soil gas.

That changes how the exploration map should be read. Absence of evidence is unusually weak evidence here, which is exactly the kind of gap that makes a resource easy to miss and hard to price.

Where Natural Hydrogen Comes From

Two reactions do most of the work, and neither requires anything rare.

The first is serpentinization. When water reaches iron-rich ultramafic rock, mainly peridotite built from the mineral olivine, the iron is oxidized and hydrated. The rock turns into serpentine and magnetite, and molecular hydrogen comes off as a by-product. The reaction runs fastest between roughly 200 and 350 degrees Celsius, temperatures found seven to ten kilometers down in many continental settings, and it can sustain itself by cracking the rock as it goes, opening new surfaces for water.

The second is radiolysis. Rocks rich in uranium, thorium, and potassium, including granites and some salt deposits, emit enough natural radiation to split water molecules apart, releasing hydrogen. The process is far slower than serpentinization, but it has run for geological time, and it produces helium alongside the hydrogen. That detail turns out to matter commercially.

A third route, thermal cracking of organic matter in deep sedimentary basins, appears in the literature but carries less weight in the national academy assessments. At temperatures of roughly 250 to 500 degrees Celsius, buried organic material breaks down and can release hydrogen alongside methane or nitrogen, which is one reason some natural hydrogen arrives mixed with gas that must later be separated.

Both processes are also constantly undone. Hydrogen is the smallest molecule in existence, so it diffuses through rock, dissolves in groundwater, and escapes along fractures. Much of the planet’s hydrogen is not free gas at all but chemically bound, including water locked inside minerals deep in the mantle. Generation is common. Accumulation is not.

This is also where natural hydrogen separates from a cousin that often gets confused with it. Some companies do not search for hydrogen at all; they make it, by pumping fluids into oil reservoirs and reacting them underground. That is stimulated geologic hydrogen, and the German academies’ paper estimates the natural reaction rate would need to accelerate by a factor of about 10,000 to make it work at scale.

What Has to Go Right for It to Stay Underground

The German academies’ paper lays the problem out as four stages: generation, migration, accumulation, and extraction. Each one has a way of failing.

Generation needs the right rock, water, and temperature. Migration needs pathways that lead somewhere useful rather than to the surface. Accumulation needs a porous reservoir sealed by something tight, such as rock salt or a dense igneous body, and it needs that seal to have held for a very long time. Extraction then depends on whether the gas will flow at a rate that pays for the well.

The microbiological problem runs through all four. Hydrogen that escapes a source rock can be consumed before it ever reaches a trap, which means a perfectly good generation system can produce nothing worth drilling. The German review is blunt: how much hydrogen microbes eat along the way remains one of the largest unknowns in the field.

What the Academies Concluded

The Royal Society’s briefing is the most useful single document in the field because it puts numbers on the uncertainty instead of around it.

• On volume: reviewing the literature, it estimates continental geological hydrogen flux at less than 0.74 million tonnes a year, or less than 1.74 million tonnes if volcanic emissions are included. Recent modeling papers have proposed figures around 20 million tonnes a year. Both are estimates, but they differ by more than an order of magnitude.
• On plausibility: it concludes there is currently not enough public data to give an accurate figure for hydrogen stored in specific reservoirs and that no resource or reserve figures exist for any current project.
• On the deep-Earth story: published data does not support the idea of an endless supply migrating from the mantle into accessible near-surface traps. Coupling hydrogen measurements with noble gas tracers has found little evidence for economically useful mantle-derived accumulations.
• On national readiness: the UK has geological settings that could generate hydrogen and no coordinated national assessment, which is why the British Geological Survey was commissioned to produce one.

The German academies’ discussion paper, produced through the Energy Systems of the Future project that involves acatech and the German National Academy of Sciences Leopoldina, is more skeptical still. Its first conclusion is that no large-scale, economically viable natural hydrogen deposit has been identified anywhere in the world. It notes that much of the available data comes from company reports rather than peer-reviewed studies. It also warns that the hope for natural hydrogen should not distract from building out electrification and green hydrogen, which are needed regardless.

Its most quotable judgement is about scale. Most experts consulted saw the realistic near-term use as decentralized supply, for instance, powering remote mining operations where hydrogen-generating rock and valuable minerals sit in the same place. A role as a pillar of the global hydrogen economy was considered unlikely. In the paper’s phrasing, natural hydrogen is more plausibly one piece of the puzzle than a real gamechanger.

The resource number that launched a thousand investor decks comes from the US Geological Survey. A modeling study published in Science Advances in December 2024 put the most probable global in-place resource at about 5.6 trillion tonnes. The authors were careful: this is not a reserve estimate; most of it is likely too deep, too diffuse, or too far offshore to recover, and the same agency’s prospectivity mapping, released in January 2025, is explicitly a map of where the ingredients might coexist rather than where hydrogen is. Even so, roughly two percent of that in-place figure would contain about twice the energy of the world’s proven natural gas reserves.

France adds a fourth voice. In July 2026 the parliamentary office for scientific and technological assessment published a note on native hydrogen that acknowledged the country’s promising subsurface while listing the unresolved questions and recommended faster research rather than rapid licensing.

The Wells Being Drilled Right Now

Away from the reviews, a small industry is drilling. The table below covers the projects that have reported something measurable, which is a shorter list than the press coverage suggests.

The French well is the most consequential. Française de l’Energie drilled PTH-2 at Pontpierre in Moselle during 2026 and reported concentrations it described as exceptionally high, with production targeted for late 2028 or early 2029. A figure of 34 million tonnes has been floated for hydrogen dissolved in the Lorraine basin, but the parliamentary note is explicit that the estimate remains unconfirmed and that no flow-rate information had been published.

France has now granted six exclusive exploration licences for native hydrogen, and the licensing dates tell their own story of acceleration: one in 2023, two in February 2025, and three more between December 2025 and March 2026.

In the United States, the action is along the Midcontinent Rift, a buried scar in the basement rock running through Kansas and Nebraska. HyTerra has drilled three wells there since April 2025 and found hydrogen and helium in all three. That is the kind of result that generates headlines, and it is why the next section matters.

A Good Number Is Not a Good Well

In August 2026, HyTerra published the results of a production test on its McCoy-1 well in Kansas. The test recorded an estimated gas flow rate of about 0.1 thousand cubic feet a day, roughly three cubic meters, with helium at 2.8 percent. The company attributed the result to low gas saturation in the tested interval and cancelled the planned second zone test.

Set that against Mali. Three cubic meters a day is roughly one five-hundredth of what the Bourakébougou discovery well has been delivering for years, in a field that powers one village. A mud gas reading of 96 percent hydrogen and a well that flows are two different achievements, and the distance between them is where most of this story actually lives.

Australia illustrates the same gap from the other direction. Gold Hydrogen drilled the country’s first wells, specifically targeting natural hydrogen, at Ramsay on the Yorke Peninsula in 2023. By October 2026 it had completed flow testing across all three wells, flowed helium to the surface, purified and bottled it on site, and scaled pumping to about 14,000 barrels of fluid a day. Project-wide helium averaged about 15.2 percent, against commercial helium projects that can operate at 1 percent. The hydrogen flow-test results were still pending.

So the field’s most advanced flow test to date is, for now, a helium story with a hydrogen option attached. That is not a criticism. It is what a resource looks like before it becomes an industry.

Helium Is Quietly Paying the Bills

Radiolysis cracks water and produces helium in the same rock, so the two gases travel together. Kansas wells have returned gas at 92 percent hydrogen with 3 percent helium, and South Australian gas at 86 percent hydrogen with 6.8 percent helium. Those helium percentages are extraordinary by the standards of the helium industry, where 1 percent is worth developing.

The economics are lopsided in a way that surprises people. Helium is used in MRI scanners, semiconductor manufacturing, and scientific research; supply is constrained, and worldwide production was around 180 million cubic meters in 2025. Per kilogram it can be worth far more than the hydrogen it sits beside.

That has two consequences. The first is that early natural hydrogen projects may be financed as helium projects with hydrogen as the upside, which makes them more robust and less dependent on a hydrogen market that does not yet exist at scale. The second is that helium is a genuine exploration tool: as a noble gas it does not react, so it traces where hydrogen came from and how much has been lost on the way, which is why the Royal Society treats it as one of the field’s most useful diagnostics.

The engineering catch is separation. Splitting hydrogen from helium is technically awkward, and the German review flags it as an unresolved cost. There is a parallel here with geothermal: drilling into a magma chamber in Iceland showed how much energy value can sit in fluids that operators were already bringing to surface. Iceland’s geothermal wells vent hydrogen today; capturing it instead is one of the cheaper ideas in this field.

The Climate Arithmetic

Natural hydrogen is not automatically clean, and the difference is measurable. It depends on what else comes up the well.

The Royal Society’s figures compare produced gas compositions on a life-cycle basis. A gas that is 85 percent hydrogen, 12 percent nitrogen, and 1.5 percent methane carries about 0.4 kilograms of carbon dioxide equivalent per kilogram of hydrogen. A dirtier gas, 75 percent hydrogen and 22.5 percent methane, carries about 1.5 kilograms. Blue hydrogen, made from fossil gas with carbon capture, sits near 8.9, and green hydrogen from solar-powered electrolysis near 3.6.

Two caveats sit under that chart. Methane leakage during extraction would worsen the natural hydrogen numbers quickly, since methane is a far more potent greenhouse gas over short timescales. And hydrogen that escapes to the atmosphere has indirect warming effects of its own, which are not yet well quantified. That makes leak-tight well design a climate issue, not just an operational one.

Then there is the question of whether natural hydrogen is renewable at all. It is only renewable if generation replenishes what extraction removes, and nobody has measured that on a producing field. The flat pressure at Bourakébougou is suggestive and nothing more. For now, natural hydrogen is better described as a finite geological resource with an unknown recharge rate, which is a different thing from a fuel that renews itself.

What Would Have to Be True

Strip away the enthusiasm, and the sector is being tested on three things.

1. Sustained flow. A well that produces at a commercial rate for months, not for a day. Mali supplies the only working benchmark, and it is a modest, village-scale one. Nothing yet drilled has clearly beaten it.
2. Trap size. A high-purity accumulation the size of a small gas field would still be worth developing, because the gas arrives already made. Making the same hydrogen by electrolysis takes roughly 50 kilowatt-hours of electricity per kilogram, more energy than the kilogram itself contains, so a working trap skips an enormous electricity bill. A high-purity accumulation the size of a shoebox is a science paper.
3. Co-produced gas. Hydrogen that arrives diluted by methane or nitrogen is a separation cost, and separation costs are what kill projects quietly. This is where helium helps and where methane hurts.

Policy is starting to move around those tests. In October 2026, more than 30 European organizations coordinated by Hydrogen Europe and initiated by the French company Mantle8 called on the European Commission to recognize natural hydrogen explicitly in its energy legislation, proposing a one billion euro program supporting around 50 exploration and appraisal wells across at least 10 member states. The European Commission has also put out a tender to map natural hydrogen resources across the bloc. Legal clarity is part of the ask, because in many countries it is still unclear whether hydrogen underground is a mineral, a hydrocarbon, or water, and that determines who can drill and who gets paid.

None of that changes the geology. It only decides how quickly the geology gets tested.

Frequently Asked Questions

Where can you get natural hydrogen?

Commercially, only at Bourakébougou in Mali, which supplies a local village. There is no retail or industrial market for naturally occurring hydrogen anywhere else. France, Spain, the United States, and Australia all have exploration projects, but none are selling natural hydrogen at scale.

How is natural hydrogen formed?

Mostly by two reactions. Serpentinization, where water reacts with iron-rich rock such as peridotite to produce hydrogen along with serpentine and magnetite, and radiolysis, where natural radiation from uranium, thorium, and potassium splits water molecules. Both are slow, and both produce hydrogen that mostly escapes unless a sealed trap catches it. A third route, thermal cracking of buried organic matter in deep hot basins, can also release hydrogen, usually mixed with methane or nitrogen.

Is natural hydrogen renewable?

Unknown. It would be renewable only if underground generation replaces what is extracted, and that rate has never been measured on a producing field. The Royal Society’s assessment found no support for the idea of an inexhaustible flow arriving from the deep mantle, so the safe assumption today is a finite resource with an unquantified recharge rate.

Is natural hydrogen better than green hydrogen?

Potentially cheaper and lower-carbon if the gas is high-purity and the well flows well, because it skips electrolysis entirely. But green hydrogen has a supply chain, a certification regime, and a cost trajectory. The German academies review argues that both should be pursued and that natural hydrogen should not slow the build-out of electrification and green hydrogen while its resource base remains unproven.

Can you invest in natural hydrogen companies?

Several explorers are listed on stock exchanges in Australia, Canada, and the United States, and most are pre-revenue. The relevant disclosures are flow rates and flow tests rather than concentration readings, and the sector’s first widely watched production test returned a rate far below the Mali benchmark. This is a description of the sector, not investment advice.

What did Elon Musk say about hydrogen?

Musk’s public criticism has focused on hydrogen fuel-cell cars, where he has argued that converting electricity into hydrogen and back again wastes far more energy than using batteries. That debate is about transport. Natural hydrogen is being pursued mainly as an industrial feedstock for fertilizer, steel, and chemicals, and as a local power source, which is a different question with a different set of costs.

The Bottom Line

Natural hydrogen is a real geological phenomenon with a real history of being ignored, and it has exactly one commercial field to its name after nearly four decades. The reviews published in 2025 and 2026 do not say the resource is imaginary. They say it is unevaluated, that the public data is thin and often comes from the companies doing the drilling, and that the difference between an encouraging gas reading and a profitable well is larger than the press coverage implies.

The next two years will settle much of it. PTH-2 in Lorraine is due to produce around 2028 or 2029, Monzón is aiming at 2029, and a dozen other wells will report flow tests before then. If one of them delivers sustained commercial rates at high purity, the map of where energy comes from changes at the edges, and a century of drilling past hydrogen starts to look like a very expensive oversight. If they deliver three cubic meters a day, the field becomes a geochemical curiosity with a helium business attached.

Either way, the honest position is unusual for an energy story: the resource is probably there, the wells are finally being drilled, and nobody yet knows whether the rock will give it up.