The Sudden End of The MoU

On 29 June, I explained on X (link) that the Memorandum of Understanding (MoU) was really an exercise in constructive ambiguity — the Kissinger playbook of deliberately vague language so that both sides can claim victory. I called it a Memorandum of Misunderstandings. Why?

On the one hand, the MoU assigns responsibility for reopening the Strait to Iran. It states that “the Islamic Republic of Iran will make arrangements using its best efforts for the safe passage of commercial vessels” and that Iran, in consultation with regional states, will determine the future administration and maritime services of the Strait. Tehran wanted that language because it provides a commercial escape hatch from sanctions while preserving its claim to control the Strait.

On the other hand, the MoU also says that military obstacles must be cleared and commercial traffic should resume immediately. In practice that meant merchant vessels should be able to use the Omani shipping lane to escape the Persian trap at once. That is precisely what happened — for nineteen days.

Further below I will show you the day the corridor opened, how hard it was used, and the day it closed. But I am getting ahead of myself.

The consequence of the ambiguous language is that Iran’s regime lost its de facto control over the Strait, which it clearly realised. That is why, the same week, it attacked a commercial vessel in the Omani lane: to reassert control. In doing so it breached the MoU, prompting the United States to retaliate.

As I have said many times on X, neither side really gives a fig about the MoU. Iran’s regime wants time — time to refinance itself and to preserve leverage through control of the Strait. Trump wants lower oil prices going into the midterms. Once that political objective has been achieved, the odds of the shooting starting again are, in my view, materially higher. Well, it turns out we did not have to wait long. We are back in fighting mode.

The ‘Irrepressible’ U.S.-Iran Conflict

I was always convinced that there is no solution to this conflict other than (a) regime change, which requires political will on the side of the United States government, or (b) muddling through from an oil market perspective until the Strait of Hormuz is no longer the choke point it is today, because a new network of pipelines will have replaced seaborne exports through the Strait.

Neither is currently the plan of action on any side involved, which is why I expect the disruption to the flow of oil and other commodities to have significant duration.

After nearly six months of conflict with Iran in one form or another, the Trump administration still appears to underestimate the nature of the regime it is confronting.

U.S. policy should begin with a basic working assumption: Iran is unlikely to capitulate simply because military pressure increases. The key question is what Washington expects to achieve. Does it believe Tehran will abandon its missile programme, give up its right to enrich uranium, or relinquish what it sees as its strategic position in the Strait of Hormuz?

There is little evidence that the regime is prepared to make concessions on issues it considers fundamental to the Islamic Revolution. On the contrary, Tehran appears convinced that, over time, Washington’s political resolve will weaken first.

If that is the underlying assumption behind the current strategy, disappointment is almost inevitable. Iran is not going to plead for an agreement or surrender its core strategic assets. The likely consequences are continued upward pressure on oil prices and growing frustration in Washington as expectations collide with reality.

Retaliation is not a strategy, and a bombing campaign without a clearly defined political objective is unlikely to produce the desired outcome. If the goal is to force Iran back to the negotiating table in a significantly weaker position, that objective looks increasingly unrealistic.

Policymakers should be clear-eyed about the costs. A strategy centred on coercing Iran into submission risks imposing substantial economic and strategic costs on the United States and its allies without achieving its intended political objectives.

Iran is far from invulnerable. It has significant military, economic and social vulnerabilities that can be exploited. But one reality remains unavoidable: confronting Iran requires time, sustained political commitment, a willingness to absorb casualties, major economic costs and enormous military resources.

As long as the administration is unwilling to bear those costs, extending the current campaign — even if it produces tactical successes — is unlikely to bring Iran to the point of strategic defeat. If anything, a prolonged campaign without the resources or political will to achieve decisive results risks strengthening Tehran’s belief that it can simply outlast Washington.

The great Walter Russell Mead, perhaps the sharpest writer in a very good WSJ line-up, said it best in a recent article when he called this war “irrepressible”. He wrote:

The core problem is that the conflict between the United States of America and the Islamic Republic of Iran is of the kind that Adams’s boss, Secretary of State William Seward, once famously characterized as “irrepressible.” Iran wants to control the energy resources of the Persian Gulf, and there is no local coalition of states powerful enough to block it without American support. The U.S. has believed for 80 years that ensuring the free passage of Middle Eastern oil and gas to world markets is essential to America’s prosperity and security.

Mr. Trump, a man for whom energy dominance is a central foreign-policy theme, is unwilling to give Iran control of the Strait of Hormuz. Iran may make temporary concessions under grave duress, but it will not, perhaps cannot, abandon the drive for control. Both sides seem to see more reasons to keep fighting than to throw in the towel.

I fully agree, and I expect this conflict to last far longer than markets are currently willing to price.

What Can We Learn from the Crossings of the Strait of Hormuz?

We have assessed every vessel crossing of the Strait of Hormuz reported by Kpler since the war began. We now have a sample large enough to report patterns rather than anecdotes.

Kpler gives us the vessel IMO number, the cargo, the loading port and destination, and the route taken. All of it matters for pattern recognition. We join on IMO number and never on vessel name, because names change and a rename would corrupt the attribution.

Yes, Kpler is an AIS tracking service. AIS stands for Automatic Identification System. It is an automatic tracking system used on ships and by vessel traffic services to prevent collisions and to monitor maritime traffic in real time. It also carries important information on the vessel itself, its cargo and its shipping route — which is exactly what makes it valuable for pattern recognition, and exactly why a ship that does not wish to be seen turns it off.

If a ship switches its AIS off, Kpler cannot see it in real time; only a handful of state players can do that. But Kpler updates daily and backfills history as it becomes clear that a vessel crossed dark to avoid detection by the Islamic Revolutionary Guard Corps (IRGC), the military unit that tries to control the Strait and attacks ships. So the dark crossings are in the data — we simply learn about them late.

One honest caveat before we start. Kpler tells us who owns and who commercially operates each hull, but it does not tell us who insures it. Every statement below about ownership is auditable; nothing below is a claim about insurance cover.

Let us look at the data together.

Total Vessel Crossings

Kpler reported 2,143 crossings — dark or with AIS on — for all commodities, meaning crude oil and petroleum products (together, liquids), LPG, LNG and dry cargo such as fertiliser, between 28 February and 24 July 2026.

That is 147 days, so 14.6 crossings per day across all commodities. On 28 February 2026 alone there were 77. Before the war broke out there were well over 80. In other words, the Strait has been running at roughly 19% of its pre-war rate for five months.

Between 19 and 24 July, as both sides intensified their attacks, Kpler identified 34 crossings in total. That is 5.7 per day, or 7% of the pre-war rate.

Even the most risk-friendly commercial shipping managers do not like it when rockets and drones fly over their heads. So the first learning from this excercise is straightforward and hardly surprising: when the war is hot, expect only symbolic crossings — not commodity trading.

Read more

Executive Summary

Russia’s fuel crisis has entered a new phase. What began as a logistics problem has become a volume problem. According to our analysis, refinery throughput has fallen from roughly 5.0mbpd in 2022 to just 2.9mbpd in early July 2026, leaving the country unable to meet domestic demand for gasoline, diesel and other petroleum products.

Gasoline shortages are now nationwide. Diesel has followed. Exports have effectively ceased. Rationing has spread across much of the country, and the Kremlin has quietly shifted from denial to damage control. The scale of the deterioration is best illustrated by our weekly refinery output estimates below.

Naturally, these numbers are a moving target. Some disruptions prove temporary and refinery throughput can recover sharply once damaged storage tanks, utilities or other peripheral equipment are repaired.

That distinction matters because refinery strikes have become part of the information war. A spectacular fire at a remote storage tank on a five-million-square-metre refinery site may dominate social media, yet have little lasting impact. Crude processing can often resume within hours or days.

The opposite is true when critical crude distillation units (CDUs) or downstream processing units are damaged. Modern refineries are built around these processing trains, often with only two or three at a site. Knock one out and a substantial share of the refinery’s capacity disappears. Repairs become measured in months rather than days, during which the refinery is entirely offline - a big deal.

That is precisely Russia’s problem today. Over the past twenty-five years, Russian refineries became heavily dependent on Western technology and specialised equipment, among others, to produce Euro-5 fuels. Replacing sanctioned Western technology with Chinese alternatives has proved difficult, if possible at all, while procurement lead times are always exceptionally long. Refineries are bespoke industrial systems, not mass-produced machinery.

The obvious solution is to import petroleum products. That sounds simple. It is not. Importing an occasional 50-100 thousand barrels per day (kbpd) of gasoline for a few weeks is manageable. Sustaining imports of 200-300kbpd every single day for months, perhaps years, to supply a domestic gasoline market consuming roughly 900kbpd is an entirely different challenge.

At 300kbpd, Russia would need to source roughly 7.5% of the entire global seaborne gasoline trade while simultaneously overcoming sanctions, unfavourable economics, limited export availability, shipping constraints, port logistics and, increasingly, maritime security risks. That is a “champions league”-type undertaking, not minor league.

Belarus and India can provide partial relief. But Belarus is also the most obvious refinery target outside Russia for Ukraine. President Zelensky has already warned Lukashenko, expressis verbis, that Belarusian refineries could be next if they continue supplying fuel to the Russia. China, meanwhile, is unlikely to come to the rescue for reasons I explain below. None can replace the lost domestic production at the required scale.

Imports may cushion the shortages. They cannot eliminate them. The consequences extend far beyond empty filling stations. Fuel is the bloodstream of a modern economy. In a country spanning eleven time zones, every missing barrel eventually ripples through trucking, agriculture, food prices, freight markets, inflation, military logistics and, ultimately, political stability.

In the final chapter, What’s the Trade? (paywall), I explore the most obvious ways to position for this new, structural imbalance in global fuel markets.

This report also builds on my earlier Substack from October 2025, Running on Fumes: How Refinery Strikes and Urals Economics Threaten Russia’s Oil Output – and Its Regime. I recommend reading it first if you want a thorough Russian oil industry warm-up (paywall).

I will keep this report free until the Investment Section. I have spent more than twenty years investing in commodities and believe deeply that capital markets ultimately rest on something far more important than markets themselves: freedom, private property and the rule of law. Those are precisely the values Ukraine is defending today.

If this research helps journalists, OSINT researchers, policymakers, investors, or anyone else better understand what is happening inside Russia's refining system, while separating fact from propaganda, then making it public has been worthwhile. I hope you agree.

If you find it useful, please share it. Reliable, timely data on Russia’s fuel system are expensive to obtain, painstaking to verify and increasingly difficult to assemble. I hope this report makes a small contribution to understanding how the refinery campaign is reshaping Russia’s economy, military logistics and, ultimately, its ability to wage this war.

Enjoy.
Alexander

Share

Unpopular Methods

You do not have to take the President of Ukraine’s word for how bad the Russian fuel supplies situation has become. Take the Kremlin’s.

That same day, Vladimir Solovyov, the Kremlin’s wannabe Goebbels, who has spent four years insisting night after night on Russia’s main state television channel that everything was under control and victory inevitable, finally admitted reality. The shortages are real. Deputy Prime Minister Alexander Novak’s assurance that there is “enough fuel” is a lie. “Everyone,” he conceded, “understands the real situation.”

For once, the propagandist and the petrol queue agreed. Then he showed us how the Kremlin thinks: “War is not about popularity,” he declared. “It is about victory.” In the very next breath he warned his own people that “unpopular methods” were coming. That single sentence is the key to the entire regime.

Listen to it yourself. I believe this is the single most important clip to emerge from Russia since the full-scale invasion of Ukraine began in February 2022, back when it was still called a “special military operation” and supposedly measured in days.

Today Russia is running short of something far harder to replace than missiles: men. Ukraine is reportedly inflicting casualties faster than Russia can replenish them, roughly 35,000 killed or wounded every month. Sooner or later, the Kremlin will have to reach for the most unpopular measure of all: general mobilisation. That, too, is what Solovyov means when he speaks of “unpopular methods”.

Not since reservists were first mobilised in September 2022 have Russians felt so uneasy. On 2 July, the Public Opinion Foundation (FOM), a pollster closely aligned with the Kremlin, reported that 55% of respondents believed their relatives and colleagues felt anxious, up from 40% a year earlier (link).

Russia’s post-Soviet social contract, whereby citizens stayed out of politics and the authorities largely left them alone, has broken down. The war has come home and become everybody’s problem. Drone attacks, once confined to border regions such as Kursk and Belgorod, now reach deep into the Russian interior (link). On 6 July, Ukrainian drones struck Russia’s largest refinery in Omsk, some 2,500 kilometres from the front line - a most remarkable achievement.

The consequence of Ukraine’s refinery campaign over the past sixty days is that petrol is now being rationed across much of Russia. Drivers queue for hours to purchase no more than 20 or 30 litres before being turned away, while many filling stations have simply run dry. Both the rationing and the closures can be verified in real time on gdebenz.ru, a crowdsourced platform launched in late June to help Russian motorists navigate the crisis.

As one would expect in a highly centralised state, however, the shortages are far less visible in Moscow than elsewhere in the country. Mediazona has done the heavy lifting for us (link). It collected and analysed anonymised payment-card transaction data from three of Russia’s largest banks—Sber, T-Bank and Alfa-Bank—to estimate which filling stations were actually dispensing fuel.

Their work shows that between 13 and 14 July, more than 85% of Moscow’s filling stations sold fuel at least once during the preceding 24 hours. Across Russia as a whole, however, only around two-thirds of filling stations were active over the same period.

Meanwhile, the Kremlin’s preferred explanation is “panic buying”. To be sure, once shortages emerge, panic buying amplifies them. That is a feature of virtually every supply crisis. It is not the cause. The shortages themselves are real and reflect a structural deterioration in Russia’s fuel balance, as the data throughout this report will demonstrate.

The Shortages

Mikhail Khodorkovsky, the man who once ran Yukos, Russia’s largest oil company, and whose former Samara refineries are now among those now burning, puts his finger on an important part of the story in a recent post on X [link]. By volume, he argues, this is not yet a catastrophe.

The breakdown, he continues, lies less in the barrels than in the brain: logistics and decision-making. Moving fuel across eleven time zones requires pipelines, rail tankers, strategic reserves and, above all, a state capable of deciding quickly what goes where. That state no longer exists. The people who once knew how to run it have emigrated, been sidelined or simply refuse to touch it. That, he argues, explains why shortages have spread to Chita and Irkutsk, thousands of kilometres from any front line.

Logistics are undoubtedly an issue. Decision-making is too. But they are no longer the binding constraint. Volumes are.

According to our data, Russian refinery throughput has fallen to just 2.9mbpd, down from our 2022 baseline of 5.0mbpd. At those levels, petroleum-product exports are effectively off the table, replaced instead by higher crude exports as Russia ships abroad the barrels it can no longer refine at home.

Against domestic petroleum-product demand of roughly 3.2mbpd, encompassing gasoline, diesel, jet fuel, naphtha, fuel oil and everything in between, the Russian petrostate, as of the first week of July 2026, can no longer satisfy its own market.

Treat the above numbers as a moving target.

We do not, and cannot, know precisely how severe the damage is at every refinery. We simply do not possess the refinery-by-refinery high-resolution satellite imagery produced by firms such as Vantor. Even then, it would often remain impossible to determine whether a crude distillation unit was hit directly or merely caught fire as a consequence of damage elsewhere. Fortunately, we do not have to rely on satellite imagery alone.

Besides our refinery balances, we watch Russia’s exports closely. They provide an elegant back-test. If a drone destroys the CDU, the crude distillation unit, the large distillation tower that sits at the front of every refinery, the plant can no longer process crude oil. Refinery throughput falls and those barrels leave the country as crude instead. We observe exactly that.

Kpler data show seaborne crude exports exploding from 3.4mbpd in January 2026 to 4.6mbpd in June. At the same time, Russian crude discounts have widened sharply, with August-loading Urals into India trading at discounts exceeding US$10/bbl, among the widest since before the Iran conflict.

Taken together, the conclusion is straightforward. Our export back-test confirms that at least 1.2mbpd of Russian crude can no longer be processed domestically. Naturally, exports lag refinery outages by roughly two to three weeks, making the July and August export data particularly important following the latest wave of Ukrainian strikes.

Back to the refinery failure mode and its implications for product processing.

Hit the reformer and gasoline production falls while, assuming the CDU continues operating, naphtha exports rise. Hit the fluid catalytic cracker (FCC) and gasoline production falls further. Hit the hydrocracker and diesel output collapses. Many Russian refineries remain relatively simple facilities with low Nelson Complexity Index (NCI) ratings, making these relationships comparatively easy to identify through changing export patterns.

Two important additions: First, secondary processing units take far longer to repair than a CDU. Their components are substantially more complex and, under sanctions, far harder to replace. Second, restarting crude processing does not mean motorists receive more fuel. Crude throughput may recover while the gasoline and diesel units remain offline for months. Rising refinery runs therefore tell us surprisingly little about what ultimately reaches the filling station. That is precisely why we prefer measuring actual product balances rather than headline refinery throughput.

The verdict is clear. Gasoline is short. It was already heading in that direction before the latest drone campaign. Exports fell from 136kbpd in 2023 to 102kbpd in 2024, then to just 46kbpd in 2025, before collapsing to effectively zero under the 2026 export ban.

The more interesting story is diesel. Russian diesel exports have now collapsed as well. Combining diesel and gasoil, exports have fallen to roughly 400kbpd from around 910kbpd as recently as January. Those exports are now effectively banned too.

Naphtha has proved the most resilient product so far, declining only modestly from 427kbpd during 2025 to 397kbpd in June. Even there, however, exports continue to move lower. The damage is therefore no longer confined to one refinery or one product stream. It is broad-based across the entire clean-product barrel.

Freight Volumes Fall Off a Drone Cliff

To triangulate the severity of the shortages, we performed one final cross-check: rail freight volumes in June.

Over the decades, Russia’s oil industry has evolved into a highly specialised system. Transneft owns and operates the country’s vast pipeline network, stretching well beyond Russia’s borders. It moves crude oil from the oilfields to refineries and, just as importantly, to the major export terminals on the Baltic, Black and Pacific seas.

Petroleum products are different. Pipelines are poorly suited to transporting gasoline, diesel and other refined products across Russia’s enormous distances while handling dozens of different fuel specifications.

Instead, that task falls largely to Russian Railways. It distributes refined products from refineries to regional wholesale terminals, from where specialised road tankers complete the final journey to filling stations. Rail also transports a smaller volume of crude oil.

That makes Russian Rail freight an excellent proxy for the physical movement of petroleum products across the country. IPEM, the Institute for Natural Monopoly Problems, tracks these rail volumes. Its June data complete the picture of a refinery system in distress.

In June 2026, Russian Rail transported 16.7% less crude oil and petroleum products than a year earlier. Since crude typically accounts for only around 15% of these rail shipments, the overwhelming majority of that decline reflects collapsing volumes of refined products. The fuel simply is not there.

Share

Gasoline - A Volume & Behavioural Issue

As at 7 July 2026, Russia’s refinery system was short roughly 320kbpd of gasoline against domestic demand of around 880kbpd.

The number of Russian federal subjects experiencing shortages and fuel rationing has climbed steadily since mid-June. Regional governments and filling station operators responded by imposing gasoline and diesel purchasing limits in an attempt to contain the inevitable panic buying. Here is what that looks like. Social media is full of similar reports, some quite funny, others less so.

According to ISW, approximately 78 of Russia’s 83 federal subjects have now experienced fuel shortages, while authorities in 48 have imposed official gasoline or diesel purchasing limits.

There is no doubt panic buying is now amplifying the crisis. But that is not a bug of a supply crisis. It is a feature of every supply crisis. Once households lose confidence that fuel will be available tomorrow, they buy more today. No government has ever managed to legislate that psychology away.

But the key takeaway is this: The panic is a consequence, not the cause. Russia has a gasoline shortage because it lacks gasoline.

Back-test - GdeBENZ: Where Is The Benzin?

In June 2026, Russian programmer Evgeny Chudov launched GdeBENZ, a crowdsourced “people’s map” of Russian filling stations. Drivers report whether stations are open or empty and estimate queue lengths in five categories, ranging from fewer than five vehicles to more than one hundred.

The site exploded in popularity, reportedly attracting more than 812,000 unique visitors and generating around 100,000 station reports within forty-eight hours, according to Vedomosti Ural. Naturally, the data are imperfect. No registration is required and Ukrainian activists quickly began submitting false reports through VPN connections. This is, after all, an information war as much as a conventional one.

Individual station reports should therefore be treated with caution. The aggregated city-level picture, however, is surprisingly robust. Janis Kluge scraped the data, or at least published the aggregated results, and they tell exactly the same story as our refinery balances. The problem is volume.

Other services are now emerging as well, including Yandex. They would not exist if, as the Kremlin continues to insist, everything were under control. Feel free to try them yourself.

Notice the 30-litre purchase limit shown in the screenshot above. Every station I checked displayed the same restriction. That independently confirms what local media have been reporting for weeks.

We have now launched our own automated data scraping across roughly 200 Russian cities and will report the results as they become available. Whether these services remain accessible from Western IP addresses is another question entirely.

For now, the picture is already remarkably clear. AI-98 is effectively unavailable across most major Russian cities. Diesel is becoming increasingly difficult to obtain as well, despite what various Russian commentators on X continue to claim.

The situation is not “manageable.” It is exceptionally bad.

Diesel - A Volume & Behavioural Issue

Diesel has now become the more complicated story and, arguably, the more dangerous one.

Historically, Russia has been a major diesel exporter. In a normal year, its refinery system produced roughly 1.8mbpd of diesel against domestic consumption of around 0.9mbpd, leaving a comfortable export surplus. That is no longer the case.

So far in July, diesel production has averaged just 1.0mbpd, while our latest weekly estimate stands at only 886kbpd, marginally below domestic consumption. Again, these numbers may prove temporary as damaged refineries recover. But for now, that is the physical diesel supply available to the Russian economy.

Moreover, unlike gasoline, diesel is not a single market. It splits into low- and high-sulfur grades serving very different parts of the economy. Low-sulfur diesel powers most modern trucks, agricultural machinery and heavy equipment. High-sulfur diesel still finds its way into older machinery, locomotives, power generation and marine applications. Understanding that distinction matters because Russia is now running short of both.

As the table below shows, our latest balances indicate that domestic diesel supply has now fallen roughly 30kbpd below demand. Beneath that headline number, however, the picture is considerably worse. Low-sulfur diesel is running a deficit of around 93kbpd, only partly offset by a surplus of roughly 63kbpd of high-sulfur grades that cannot simply be substituted.

Diesel has therefore crossed the same line gasoline crossed weeks ago. The shortage is now real. Manageable for the time being, perhaps, but real nonetheless. That assessment also excludes any seasonal uplift in demand, where our visibility is effectively nil.

The current diesel supply of 886kbpd looks manageably close to average domestic consumption of roughly 920kbpd. Set priorities, economise a little and, at first glance, the system copes. No big deal.

The problem is that diesel demand, unlike gasoline, is highly seasonal. Harvesting is now beginning across southern Russia, precisely when agricultural fuel consumption accelerates.

Once adjusted for seasonality, Russian diesel demand may well exceed 1mbpd during July and August, perhaps even into September. It could be higher still. We simply do not know because the Ministry of Energy stopped publishing monthly consumption data years ago.

On that straightforward assumption, the market could already be running a physical deficit of roughly 200kbpd (see the weekly diesel supply chart below, currently at just 813kbpd).

We assume inventories accumulated during the winter are now bridging much of that gap. But this is Russia. It is equally possible that those inventories were more virtual than physical, as traders maximised export revenues while few anticipated shortages on today’s scale.

Either way, the margin for error has disappeared. Even if inventories prove sufficient to carry Russia through this harvest season, I struggle to see how they will be rebuilt before the next one if refinery throughput remains anywhere near current levels.

Meanwhile, tightening creates incentives. And in Russia, incentives matter even more than in the West. Once diesel becomes scarce, behaviour changes. Traders begin withholding supply. Middlemen ration access. Buyers pay whatever it takes because they have no alternative. Farmers panic. And so on.

Add the usual layer of corruption and coercion that has become a defining feature of Putin's Russia, and the diesel shortage may be very real indeed, not merely psychological or a problem of “logistics”.

Nowhere is that more visible than in the agricultural regions of southern Russia. According to the independent Russian outlet Pole Zreniya (”Field of View”; link), farmers increasingly report that diesel exists, but only for those willing to pay the panic price. One representative of a federal farming association summarised the situation succinctly:

“There is diesel. But they want to sell it dear. Purely on panic. A cartel agreement. They withhold volumes and release them through selected commercial intermediaries. Just like masks during COVID. Just like buckwheat. Just like sugar.”

As expected, the state’s response has been largely theatrical and as impotent as that of every corrupt post-Soviet regime. The Ministry of Energy insists supplies fully satisfy agricultural demand. The Federal Anti-Monopoly Service recommends “responsible pricing”. President Putin says he understands the difficulties and orders delivery schedules to be respected. None of those statements puts diesel into a tractor.

And the economics deteriorate rapidly. Fuel costs that previously amounted to roughly 5,000 roubles per hectare have doubled towards 10,000, while grain prices have barely moved. As one farmer observed, production costs are rapidly converging with selling prices. Yet they continue buying. They have no choice. Harvest waits for nobody.

Russia is simultaneously experiencing genuine physical deficits and the behavioural distortions that inevitably accompany them. The two reinforce one another. Every liter withheld by intermediaries deepens the shortage.

Rick Stainton, a friend on X who spent a decade farming and operating businesses through Zimbabwe’s fuel crises, summed it up best: “It stops being a fuel shortage and becomes a thriving black market full of middlemen.”

Exactly. The tragedy is not merely that farmers pay more for diesel. It is that they gradually stop being farmers. They become fuel traders.

When Size Becomes the Problem, Not the Advantage

Russia’s vastness is usually portrayed as one of its greatest strategic advantages: eleven time zones, almost limitless natural resources and enormous strategic depth. In a fuel crisis, however, those advantages work in reverse. Nearly everything in Russia moves by road across enormous distances, and roads run on diesel. A fuel shortage in a country this large is not merely a queue at the local filling station. It becomes a tax on every kilometre of the economy.

The trucking market is where the damage appears first. According to Kommersant [link], spot freight requests quadrupled within a single week as shippers scrambled for available capacity, while the supply of trucks contracted because drivers increasingly refused routes they could no longer guarantee to complete. Freight tariffs jumped roughly 10% in a week alone, and market participants expect further increases. The binding constraint is no longer price but availability. Carriers are reaching regional fuel purchasing limits, forcing them to reroute, postpone or cancel deliveries altogether.

The structure of the market is beginning to buckle as well. Roughly 70% of Russian road freight normally operates under long-term contracts. Those agreements are now being reopened despite cargo volumes remaining broadly unchanged. Shippers increasingly consolidate multiple customers’ goods into a single truck, while contracts that once ran for a year are renegotiated monthly simply to lock in prices for a few weeks. That is what a market looks like when it loses the ability to plan.

The disruption is spreading rapidly through the wider economy. Public transport, taxis and aviation are all feeling the strain. In some regions taxi drivers are simply leaving the road because they either cannot obtain fuel or would operate at a loss. Freight rates into occupied Crimea have reportedly increased by three to six times, reaching as much as RUB1.2 million per truck. Since transport costs are embedded in virtually every product sold, economists interviewed by The Insider [link] warn that the fuel crisis will feed directly into inflation across almost the entire economy.

Will This Normalise Quickly?

I doubt it.

What strikes me most about modern drone warfare is not the drones themselves but the economics they create. Ukraine no longer needs to destroy Russia’s refining system. It merely has to damage it faster than Russia can repair it. That is a profoundly different type of war.

A chemical engineer recently made an observation on X that caught my attention [link]. Watching footage from Omsk and several other refineries, he pointed out that the facilities were clearly operating normally when the drones arrived. Columns and pipelines were still full of hydrocarbons and the entire system remained under pressure. Under those conditions, even a relatively small drone can trigger secondary explosions and fires that destroy equipment worth hundreds of millions of dollars and take months, sometimes years, to replace under sanctions.

That should not have happened. Every refinery has emergency shutdown procedures. In the event of an imminent attack, operators can isolate processing units, stop hydrocarbon flows and depressurise the system by routing hydrocarbons to the flare. An emergency shutdown is disruptive and costly, but it dramatically limits the damage if a strike follows.

Omsk raises an obvious question. Ukrainian Fire Point FP-1 drones cruise at roughly 200km/h. A flight from the Ukrainian border to Omsk, around 2,500 kilometres, therefore takes well over twelve hours. Russia’s air-defence network does not need to shoot every drone down. It merely has to detect them early enough to warn the target refinery that an attack is coming. Yet the repeated footage suggests exactly the opposite. Refineries continue operating until impact.

Whether that reflects failures in radar coverage, command and control, communications or simple complacency hardly matters. The result is the same. The Russian state is allowing billion-dollar industrial assets to absorb maximum damage from drones carrying warheads that cost only a tiny fraction of that amount.

Ukraine has cracked the code how to hurt Russia were it hurts and Moscow remains completely unprepared. Ukraine is destroying refining capacity faster than Moscow can repair it. Why would it stop? That is why I do not expect this crisis to disappear anytime soon.

Remember Khodorkovsky’s comment about “decision making” (link)? Russia’s brightest minds either left long ago, were imprisoned, silenced or killed. For twenty-six years this regime has systematically rewarded loyalty over competence. That may be an effective strategy for preserving power and loot Russia’s natural resource wealth. It is a terrible one for managing a national industrial crisis and defend the country against drone swarms also far inside Western Siberia.

In All the Kremlin’s Men, Mikhail Zygar describes today’s Russian state not as an administration but as a medieval court, rewarding loyalty and proximity to power rather than competence. That system works remarkably well when distributing patronage. It performs rather less impressively when coordinating rail tankers across eleven time zones. My point? Don’t expect the crisis to suddently resolve unless Ukraine stops hitting these refineries.

Imports to the Rescue?

Khodorkovsky (link) is right that imports can cushion Russia’s gasoline deficit. But I argue they cannot solve it.

To close the gap, Russia needs gasoline that clears four hurdles simultaneously. It must be unsanctioned, surplus to the exporter’s own domestic market, available in meaningful volumes and cheap enough to make the trade commercially viable. Clear all four at once and the list of candidates becomes remarkably short, both on land and at sea.

Let’s start at the top of the market and watch the options disappear.

The world’s two largest gasoline exporters, the EU-28 and the United States, are immediately ruled out. Europe remains by far the largest net gasoline exporter globally, while the United States supplies not only Mexico but much of Latin America. Both have imposed comprehensive petroleum-product sanctions on Russia (here & here). That removes the largest part of the global export market at a stroke.

Even if one entertains the fantasy that Brussels lifted sanctions as part of a future peace agreement, the trade still would not work. Russian domestic gasoline prices are simply too low.

That brings us to the second filter, and arguably the more important one. Russia’s domestic gasoline is cheaper than almost anywhere else. Cheaper than China, the only country with genuine spare refining capacity. Cheaper than India, the world’s third-largest gasoline exporter. Cheaper than Turkey, Pakistan, Malaysia and Mexico. Only a handful of Middle Eastern and African petrostates sell gasoline below Russian domestic prices.

No rational exporter voluntarily ships gasoline into a market priced below its own domestic parity.

The Middle East is often presented as the obvious solution. It is not.

Iran, despite being one of Moscow’s closest allies, exports virtually no gasoline. Decades of sanctions and chronic underinvestment have left its refining system unable to produce a meaningful export surplus. Iraq, Kuwait, Qatar and even the UAE are not major gasoline exporters either. Producing export-grade gasoline is considerably more difficult than exporting crude oil, requiring sophisticated secondary refining units that many hydrocarbon-rich countries still lack, even decades after nationalising the assets of the Seven Sisters.

That leaves Saudi Arabia and Oman. From Moscow’s perspective, those are the best-case scenario. Saudi Arabia exports gasoline from the Red Sea, safely outside the Strait of Hormuz, while Oman sits outside the Strait altogether. Their export infrastructure is among the most secure in the world. Unfortunately for the Kremlin, that is where the good news ends. Combined, Saudi Arabia and Oman exported roughly 180kbpd of gasoline during June 2026. That volume would certainly help Russia. It simply is not available. Both countries already supply higher-paying, lower-risk customers across Singapore, the UAE, Egypt, Jordan, South Africa, and elsewhere. Every buyer pays more than Russia can.

With domestic gasoline prices among the lowest anywhere in the world, Russia has effectively priced itself out of the Middle Eastern gasoline market. It cannot outbid Karachi, let alone Singapore. Of course, the Kremlin may chose to subsidise those imports for its consumers at scale. But that is hardly Kremlin-style. The siloviki prefer it the other way around.

Meanwhile, South Korea, Singapore and Taiwan already supply premium markets such as Australia, New Zealand, Indonesia, the Philippines, Malaysia and even California on the US West Coast. Those are mature, low-risk, dollar-denominated trades supported by decades of investment, efficient logistics and reliable counterparties.

Russia cannot compete. Not on price. Not on payment risk. Not on sanctions. Not on logistics. And certainly not with a clean-product tanker fleet it barely possesses.

None of this means Russia cannot import gasoline. It can. Belarus will help, as will the opportunistic cargoes from India or even a cargo from Nigeria’s new refinery Dangote.

But they will likely prove to small to solve the problem. They merely buy time. The underlying deficit remains exactly where it started: inside Russia’s own refining system.

India - A Painkiller, Not a Cure

Now let us turn to India — the most-cited candidate, for good reasons.

India has a vast refining industry, capable of processing around 6mbpd of crude each day (excluding maintenance), with plenty of export capacity. That is what Russia requires. What is not ideal is that India carries a domestic gasoline price around 20% above Russia’s. So prima vista, the arb is closed.

However, India became the largest single buyer of Russian crude starting in 2022 — mostly Urals — besides China with imports well above 2mbpd and closer to 2.7mbpd in June 2026 alone, according to our real time data.

Therefore, the above set-up almost writes itself: a swap — Russian crude for Indian gasoline. It could let one or several Indian refiners buy at a discount to the already-discounted Urals-to-Brent, more than cover the cost of refining and freight, and hand Russia the finished product it can no longer make at home. Prima facie, an elegant fit.

And the trade is apparently already under way, according to this source which cites that Russia seek to import 400,000 metric tonnes of gasoline per month (111,000kbpd) from India - I assume for the time being, not as a one off. That would fit our June data.

That is roughly a third of India's gasoline exports to divert away from existing clients. A stretch — but perhaps a workable compromise. India's refinery complex runs at around 85% utilisation and may be able to push 5% harder to squeeze out an extra 50kbpd for the export trade, while Russia may be able to outbid some barrels from India's existing customers. After all, it too has a bit of leverage.

And let us not underestimate the pull of it: Indians like a good deal, and a subsidised, captive buyer at the other end of a short-ish sea lane is exactly the sort of trade Indian refiners are built to exploit.

However, let us now count the frictions — because this is not a story of one wall, but of many small ones stacked on top of each other. Death by a thousand cuts kind of thing. Who knows, but here are the issues I see coming:

The first cut is the crude leg itself. To force Russia toward the negotiating table, the US tightened sanctions on any trade in Russian crude, and Urals purchases at Indian refiners duly fell. The local champion, Reliance Industries — India’s largest refiner by a distance — stopped buying from Russia altogether in January 2026 (table below), before resuming it through June; most others kept lifting, but at reduced volumes for a brief period of time.

Then, Trump alongside Israel, struck Iran in the spring of 2026 — functionally closing the Strait of Hormuz, sending crude spiking, and giving us a saga I have documented on this platform. The spike changed Washington’s calculus: to keep barrels moving and prices in check, the administration let more Russian oil flow, and handed Indian refiners — expressis verbis — a sanctions waiver to buy the Russian crude that had piled up in floating storage over the preceding months.

Which sets up the live question: does the Trump administration keep waiving? We do not know, and the topic will stay dynamic. The recent signals point to expiry rather than extension — officials, Secretary of State Marco Rubio among them, have stressed that the exemptions were strictly time-limited instruments, meant only to steady global energy markets through the initial Hormuz shock. But Rubio does not call the shots; Trump does, and he is fickle. So I keep an open mind. But crude sanction waivers is the first “cut” meaningful volumes must survive for Russia to fix its gasoline problem.

Now to the cut I think matters most — and it is really two cuts working together: the law and the ton-miles. Take the law first, because it is the one people miss. There is a world of difference between shipping Russian oil and petroleum products out and shipping gasoline in, and it is the whole ballgame.

Sanctioned exports of Russian oil have a legal safe harbour — the G7 price cap. Carry Russian crude or product out below the capped price ($100/bbl for gasoline, diesel and kerosene; moving policy target) and a Greek vessel owner is doing permitted business.

That is how Dynacom, the Onassis group and their peers legally banked close to $4bn over three years hauling Russian oil, as the FT laid out this week. Legal, if not moral — and arguably moral too, in a roundabout way, since the cap was designed to keep Russian barrels flowing so world prices would not spike; the West wanting the oil moved, just not the Kremlin enriched. An uncomfortable trade-off, because nobody should be feeding a war machine. But it is legal, and it is a machine that exists.

Gasoline flowing into Russia has no such machine or, rather, price-cap channel that blesses it — only exposure: Russian ports, Russian counterparties, the EU’s tightening maritime-services net, and the reputational radioactivity that already saw Ukraine brand those same Greek owners “sponsors of war” for the export trade.

So the mainstream, insured, Western-serviced professional fleet — the fleet that does clean-product business every day — has every reason to look at this carefully and make a long-term risk, not a short-term profit judgement.

The tell is in how the cargoes actually move: Russia’s first jet-fuel imports are being laundered from Japan through South Korea “via a chain of intermediary companies,” and the Indian gasoline moves quietly, according to this article. You do not route a legal trade through cut-outs. So that is a first indication of where this is going.

But does that work at scale? Can Russia load enough gasoline it can buy in India each week to bring it back home? I don’t know. What I do know is that there is no established India-Russia gasoline import trade. Creating one means asking tanker owners to dedicate clean-product tonnage to a corridor with limited backhaul optionality.

That raises the freight required to make the trade economically attractive, and I mean substantially. It currently costs $5.34/bbl (about $3.4cent per liter or about 3-4% on current domestic quoted prices) to ship gasoline from Sikka in India to Chiba in Japan. Affordable. But what if that number goes up 10x because of dark-fleet economics and longer routes?

Back to the volume issue. One line of argument says Russia’s own gasoline and diesel export trade is now drying up fast, freeing tonnage for the import run. But that assumes the two are the same trade, legally. I do not think they are — and that difference is the whole point.

People will quickly point out that there is the dark fleet. True that but let’s look at the details more carefully: In February 2026, some 80% of the total value of Russian seaborne CRUDE oil was transported by ‘shadow’ tankers, while tankers owned or insured in countries implementing the price cap accounted for 19%. However, ‘Shadow’ tankers transporting PETROLEUM products such as gasoline handled only some 37% of Russia’s total volume of products. The remaining volume was shipped by tankers subject to the price cap policy.

Russia has now introduced an export ban for diesel too, not just gasoline, which may free up part of its dark fleet capacity used in the product trade. But Russia also continues to export other products such as dirty products. I guess my answer is, we will have to see how this will play out.

The most obvious line of argument is probably truer: among thousands of middlemen in the shipping industry there will always be an idiot keen to make a few dollars, and if that means scrubbing out a dirty dark tanker to load fuel into it, so be it.

Personally, I think size matters most here. 100kbpd — roughly 11,900 tonnes a day, about 360,000 tonnes a month — is about ten MR cargoes a month in pure volume terms. Onto that goes the ton-mile multiplier. Indian gasoline must sail from Gujarat to Novorossiysk on the Black Sea (about 4,200 nautical miles via Suez), or at times to Ust-Luga on the Baltic (some 7,600) — a round-trip cycle of roughly 40 and 65 days respectively, once loading, canal and discharge are counted.

Stretch each cargo over that long a voyage and you no longer need ten ships; you need on the order of 15 held permanently on the Black Sea run, or north of 20 to Ust-Luga — call it something like 6% of the world’s spot-available MR tonnage, just for 100kbpd (see table below). That number is soft, but the direction is not: the distances are punishing, and they multiply every other constraint.

Because now combine the two. The ton-miles say you need a standing fleet; the law says the obvious fleet — the legal, London-insured, Western spot market — will not take the cargo. So you fall back on dark-fleet tonnage and the middlemen, as explained above. A few illegal loadings here and there. No problem.

But 20 MRs day in, day out, for months? I am less sure. Go to my high case in the table below and the requirement climbs to 40-65 tankers — perhaps as much as 38% of the MR spot fleet. That is a stretch. Move it to bigger vessels? Of course — but the same dynamics apply there too, in terms of availability.

Roughly half of Russia’s seaborne oil already moves on the shadow fleet, the G7-serviced fleet carrying most of the rest. Every shadow tanker pressed into carrying gasoline in is a tanker not lifting Russia’s crude out, at least in theory. The two fleets aren’t all interchangeable but you see my point.

Look, it took Russia 18 months to re-shuffle the crude and product trade back in 2022 when the tanker market was loose. Now it isn’t so much. Back then, the interests of the West and Russia were to give it time to adjust were aligned. Now? Not at all.

I do not believe anybody possesses enough knowledge of the dark fleet to answer that question with confidence but let me put it carefully: I’d be surprised if the global (dark) fleet can easily accomodate a 200,000 barrel per day petroleum product trade for months, let alone 300,000 - which is the direction of travel right now. Time will tell.

And another cut: the economics only work because the Russian oil companes pay for it (let’s call it the siloviki crooks). Imported gasoline lands above Russia’s capped domestic pump price, so Moscow is drafting Tax Code amendments to subsidise the importers — the Kremlin paying its own oil companies to bring in fuel it cannot sell at a profit.

Savour the circularity: India buys record volumes of Russian crude, refines it at Jamnagar, Vadinar and elsewhere, and ships a slice of it back to Russia as finished gasoline, which Russia then subsidises on arrival. The self-styled energy superpower, run by hyper greedy siloviki, paying a premium to buy back its own molecules, cracked in Gujarat. That looks risky to me too.

Today, the Financial Times came out with a remarkable report [link]: an unprecedented wave of Ukrainian drone attacks on Russian shipping during July. According to the paper, Ukraine struck more than 110 Russian vessels in just nine days in the Sea of Azov, making it one of the most concentrated maritime attack campaigns ever recorded.

The objective is straightforward. Rather than chasing individual ships, Ukraine is systematically targeting the logistics chain sustaining Russian military operations in occupied southern Ukraine and Crimea. According to Tomas Alexa, senior analyst at maritime security firm Ambrey, even the Iran-Iraq Tanker War of the 1980s saw roughly 450 attacks spread over seven years. Ukraine has now exceeded a quarter of that total in little more than a week.

“I cannot stress enough how unprecedented this is,” Alexa told the Financial Times. “We have never seen anything so concentrated on a global scale.”

Ukraine’s Unmanned Systems Forces announced that a further eleven Russian vessels had been struck overnight, including five tankers, five cargo ships and a tugboat, bringing the reported total to 116 vessels in just nine days.

“The goal of the operation is to systematically disrupt the enemy’s logistics chain,” the force stated. “Disabling tankers, cargo ships and auxiliary vessels complicates the export of oil and petroleum products, limits maritime transport capabilities, and reduces the enemy’s ability to supply fuel to its forces and occupation grouping in temporarily occupied Crimea.”

This matters because it adds yet another friction to any future gasoline import program. Russia would not merely have to find the gasoline, the ships and the subsidies. It would also have to move those cargoes through an increasingly contested maritime environment.

So can India help? Absolutely. The economics mean that it almost certainly will, at the margin. But margins are exactly the point. India can shave the top off Russia’s gasoline deficit. It cannot eliminate it. Stack the constraints together: uncertain sanctions waivers, the legal grey zone surrounding import cargoes, punishing ton-miles, limited clean-product tanker availability, a shadow fleet already working close to capacity, subsidies required to make the economics work, and India’s own domestic market. None of those constraints is fatal on its own. Together they become formidable.

My base case is that Russia can probably sustain imports in the neighbourhood of 50kbpd, perhaps 100kbpd with determined political support and generous subsidies. Three hundred thousand barrels a day, the sort of volume required if Ukraine permanently disables another third of Russia’s gasoline production, looks far more like a strategic sealift than a commercial trade. At that point the question is no longer where the gasoline comes from. It is whether enough ships, terminals, rail capacity and willing counterparties exist to move it every single day for months, perhaps years.

Could that change? Of course. Sanctions evolve, fleets expand and traders invariably find creative ways to make money. But as matters stand today, imports are a painkiller, not a cure. The gasoline can be produced. The ability to deliver it into Russia, economically, reliably and at scale, is the real scarcity.

China To Rescue?

Which brings us to China, now the world’s largest refining system with roughly 17–18mbpd of installed capacity — about three times India’s and marginally larger than that of the United States. Actual refinery runs, however, currently tell a very different story.

At first glance, the set-up resembles India’s: domestic gasoline prices are materially higher than Russia’s, China imports large volumes of discounted Russian crude under its strategic partnership with Moscow, and plenty of idle refining capacity sits ready.

China is also the world’s only major importer of Iranian crude. The Trump administration temporarily relaxed sanctions during the Strait of Hormuz crisis, but withdrew that waiver this week after repeated Chinese breaches of the Memorandum of Understanding.

Unlike India, however, China remains trapped in a prolonged economic slowdown — for reasons I have discussed extensively on this Substack — and domestic fuel demand is exceptionally weak. That weakness forced Beijing into a remarkable balancing act during the Strait of Hormuz crisis. The objective was simple: keep domestic fuel markets fully supplied while avoiding any meaningful drawdown of strategic crude inventories.

The solution was extraordinary. China slashed seaborne crude imports from around 12mbpd to roughly 6mbpd, cut refinery runs from about 15mbpd to 12mbpd, shifted refinery yields towards gasoline at the expense of naphtha, maximised coal-to-gasoil production to offset the lower refinery output — and effectively suspended petroleum product exports, prioritising domestic consumption over export margins.

The consequence: crude inventories barely moved. The adjustment ran instead through petroleum product inventories — which, unhelpfully, cannot be monitored independently by satellite, since they sit largely in closed-roof tanks.

None of this was particularly profitable. Refinery margins were squeezed between government-controlled retail fuel prices and crude purchased at above US$100/bbl for almost four months. Then again, most of the large refiners are state-owned enterprises (SOEs) and profitability was never the priority for the CCP’s SOEs.

With crude prices retreating, China has lifted seaborne crude imports from roughly 6mbpd to around 8mbpd last week. Where this ultimately settles is too early to call. Beyond renewed Saudi volumes following the brief reopening of the Strait of Hormuz — note that the Strait is again functionally closed — much of the incremental crude remains unidentified in Kpler’s tracking system and is most likely discounted Iranian barrels.

Even so, I do not expect China to return to pre-war seaborne crude imports of roughly 12mbpd anytime soon - certainly not in 2026. The country has already likely achieved substantial fuel substitution with a workable equilibrium not to draw too much crude stocks.

Meanwhile, export quotas - a source of future higher runs - remain tightly controlled by Beijing. Yes, Bloomberg reports that authorities have approved around 1.3 million tonnes of product exports for July — roughly 335kbpd at a typical gasoline/diesel/jet split — to at least three refiners, including private processor Zhejiang Petroleum & Chemical and several state-owned names. But I read such articles as a distraction rather than a hint of where this is going. Let me explain.

China isn’t the clean-product exporter Russia needs. Neither gasoline nor diesel nor jet was ever regularly on the export menu — and where it was, the volumes were symbolic. For years, China’s product trade was essentially naphtha, mainly with South Korea’s giant chemical industry, alongside other Asian buyers. Readers who have studied my China episodes on this Substack will recognise the pattern: this is about managing China’s own industrial overcapacity — in chemicals as much as anywhere — not about exporting petroleum products to optimise refinery margins.

Indeed, throughout this decade China has remained a net importer of both clean and dirty petroleum products. All of this suggests the CCP is managing its own energy independence, not the utilisation — and thus economics — of its refining SOEs. As David Baverez’s book argues, the CCP remains in the mindset of a “war economy”, and the only thing that truly matters to it is geopolitical independence.

Moreover, refinery runs are unlikely to return to previous levels unless three conditions are met: the Strait functionally — and sustainably — reopens, export margins turn exceptional, and Beijing allows its refiners to chase them. None of these holds today. For the purpose of oil flows, consider the Strait of Hormuz closed again as of this week — not denying some dark-fleet shuttling, which by definition cannot be measured, only inferred in hindsight.

I have warned repeatedly here, here, here and here, and also in a recent interview (in German), that this administration cannot fix a “deal” with a terrorist regime — and that the Memorandum of Understanding was in truth a Memorandum of Misunderstanding. What do I mean by that?

The MoU is an exercise in constructive ambiguity — the Kissinger playbook of deliberately vague language so that both sides can claim victory. On the one hand, it assigns responsibility for reopening the Strait to Iran. It states that “the Islamic Republic of Iran will make arrangements using its best efforts for the safe passage of commercial vessels” and that Iran, in consultation with regional states, will determine the future administration and maritime services of the Strait. Tehran wanted that language because it provides a commercial escape hatch from sanctions while preserving its claim to control.

On the other hand, the MoU also demands that military obstacles be cleared and commercial traffic resume immediately. In practice, that means merchant vessels use the Omani shipping lane to escape the Persian trap. The consequence: Iran loses its de facto control over the Strait — something the regime appears to have realised over the past 24 hours. That is why it attacked a commercial vessel in the Omani lane: to reassert control. In doing so, it is now in breach of the MoU, prompting the US to retaliate — somewhat symbolically — with overnight strikes against Iranian military assets near the Strait.

But as I have said many times, neither side gives a fig about the MoU. Iran’s regime wants time — time to refinance itself and to preserve leverage through control of the Strait. Trump wants lower oil prices going into the midterms. Once that political objective is achieved, the odds of the shooting starting again are, in my view, materially higher.

Either way, stable crude supply remains a prerequisite for the CCP to raise runs — and that condition remains absent. Brent is back at US$85/bbl, and OVX — oil’s implied volatility — is on the move again, now at 62 against a “stable” reading of 35 or below. The market continues to search for oil’s equilibrium price, and if you read my last Substack on the history of the oil price carefully, you will know it always will. We remain firmly in the Boom-Bust III era.

"But surely China has to help its ally Russia?" Not at all. Beijing has been consistent for years: China's own energy security comes first. Whenever geopolitical uncertainty rises, the CCP becomes more conservative, not less — the priority shifts towards protecting domestic supply, not maximising refinery utilisation or export profits. Time will tell. But from Russia's perspective, China is far from the obvious solution to its crisis.

The Near Abroad Won't Save Russia

Having ruled out most of the seaborne market, let us turn to Russia's immediate neighbourhood: Belarus first, then Kazakhstan. The rest of the former Soviet Union cannot help.

Belarus - the best Address but for How Long?

Belarus is, without question, Moscow’s best remaining option. It is also no more than that.

The country operates two modern refineries, Naftan in Novopolotsk and Mozyr, both ideally positioned to supply western Russia by rail with exactly the gasoline Russia is now short of. Despite what the Bloomberg map above may suggest, both refineries remain operational. Better still for Moscow, Belarusian pump prices sit broadly in line with Russia’s, eliminating the pricing problem that plagues almost every other potential supplier.

Naftan and Mozyr each process roughly 160-180kbpd and together run almost exclusively on Russian Urals delivered through Transneft’s Druzhba pipeline. That gives the Kremlin considerable leverage. There are few more uncomfortable positions in geopolitics than being indispensable to a regime that values power above everything else.

In June 2026 the two refineries produced roughly 117kbpd of gasoline against domestic Belarusian demand of just 24kbpd, theoretically leaving around 90kbpd available for export. Mozyr, in particular, has been pushed well beyond its 2024 operating levels and is effectively running flat out.

Given those numbers, there is little doubt what happened next. The Kremlin almost certainly instructed Lukashenko to divert as much gasoline and, increasingly, jet fuel as possible into Russia. The data suggest he is doing exactly that. According to Pavel Latushka [link], Belarusian gasoline shipments to Russia between 1 and 22 May increased fifty-eight-fold from a year earlier, while jet-fuel exports quadrupled.

The problem is that Kyiv understands those numbers just as well as Moscow. President Zelensky has already warned Lukashenko publicly that continued fuel deliveries make Belarus part of Russia’s military logistics chain. By our numbers, Lukashenko has ignored that warning so far.

That raises an uncomfortable question. How long does Mozyr remain off limits? Unlike Omsk, which lies roughly 2,500 kilometres from Ukraine, Mozyr sits barely sixty kilometres from the Ukrainian border. It is effectively within Ukraine’s backyard. That makes it one of the easiest major refineries in the Russian supply chain to reach, whether by long-range drones or, if matters were ever to escalate dramatically, by other means.

I would therefore be cautious about treating Belarusian gasoline as a permanent solution. It may prove to be the next target instead.

All the Evidence Points to Kyiv
Der Spiegel‘s investigation into the Nord Stream sabotage, English edition, August 2023 (link)

The vessel was almost comically unremarkable. The Andromeda was a Bavaria 50 Cruiser — a production sailing yacht seafarers sneer at as the “Škoda of the seas” — and by 2022 a tired one: dented topsides, a 75-horsepower diesel that rattled like a farm tractor, a broken autopilot, a head that stank. In early September a crew of six — five men and a woman, travelling on forged papers, among them a doctored Romanian passport — chartered her from a small rental outfit in the Warnemünde marina at Rostock. No other sailor on the Baltic gave her a second glance. That was the point.

Over the following weeks the Andromeda wandered the southern Baltic — a stop at Wiek, where the harbourmaster obligingly topped up her fuel tank, a quiet detour south to the Polish resort of Kołobrzeg, and back to Rostock by 23 September, three days before the seabed shook. On the night of 26 September 2022, divers from that unremarkable little yacht went down and blew holes in three of the four steel pipes of Nord Stream 1 and 2. It was the largest act of infrastructure sabotage in modern European history — in the words of Germany’s own federal prosecutors, an attack on “the internal security of the state.” Forensics teams would later find traces of the very explosive used, aboard the boat.

A year on, after investigators from a dozen countries had chased every thread — the yacht, the DNA, the forged passports — Der Spiegel weighed the trail and concluded, flatly, that “all the evidence points to Kyiv.” And here is the tell that matters more than any single clue: nobody wanted to say so. Sweden and Denmark quietly wound up their inquiries without naming a soul; Germany locked its findings away on orders from the Chancellery. Because the answer was radioactive. Had it been Russia, Article 5 of the NATO treaty was in play. Had it been Ukraine, German public support for Kyiv might have collapsed overnight. Silence was the safest option for everyone.

For a year the comfortable assumption had been that reaching a pipeline on the deep Baltic seabed demanded a state’s toolkit — a submarine, naval mines, specialist deep-sea equipment — the sort of thing a country like Ukraine supposedly could not muster. That assumption is precisely why so many casual observers rushed to insist it must have been the Americans, sabotaging the pipeline to sell Europe more of their own LNG.

It was conspiracy rubbish, peddled by armchair commentators who had never served — anyone who had would have known you do not need a submarine to reach seventy-odd metres of water. Any offshore diving professional could have told them the same in a minute: commercial divers work far deeper than that every day, installing and maintaining oil-and-gas equipment. And the motive never held up anyway — America’s LNG is sold by private exporters, not the White House, and Biden would go on to freeze new export approvals altogether.

The truth was cheaper, and entirely of a piece with today’s assault on Russia’s refineries: a handful of divers and a rented yacht. No superpower required. The mission then was the mission now — cut the income to the Russian war machine. Occam's razor.

Kazakhstan - A Distraction

That leaves Kazakhstan.

At first glance, it looks promising. It is a major oil producer, a former Soviet republic and one of Russia’s biggest neighbours. Look more closely and the case quickly falls apart.

The Soviet past does not make Kazakhstan an ally. Since independence, the world’s largest landlocked country has spent more than three decades rebuilding its language, national identity and statehood, fully aware that Russian nationalists, Vladimir Putin among them, have openly questioned whether Kazakhstan should exist as an independent country at all.

Its foreign policy is deliberately “multi-vector”: maintaining commercial ties with Europe, China and Russia alike while becoming strategically dependent on none of them. President Tokayev demonstrated that approach publicly in 2022 when, sitting beside Putin at the St Petersburg Economic Forum, he refused to recognise the so-called Donetsk and Luhansk People’s Republics. Since then, Astana has quietly complied with Western sanctions while carefully avoiding direct confrontation with Moscow. It has played the hand exceptionally well.

Kazakhstan imports no crude oil from Russia. None. It produces and exports its own. The CPC Terminal shipped roughly 1.9mbpd during May 2026, while Kazakhstan’s refineries run entirely on domestic production. The Kremlin therefore holds virtually no leverage over Kazakhstan’s fuel system.

It does retain some influence over crude exports. The CPC pipeline crosses Russian territory before loading at Novorossiysk on the Black Sea. But that leverage cuts both ways.

Moscow would simultaneously antagonise Europe, Turkey and Beijing over export volumes it can ill afford to politicise. In my view, CPC keeps Astana polite. It does not make it obedient.

Nor can Kazakhstan export gasoline in any meaningful quantity. Its four refineries, Pavlodar, Atyrau, Shymkent and Aktau, produce roughly 138kbpd of gasoline against domestic demand of around 115-125kbpd. That leaves little more than the occasional cargo available for export.

Accordingly, Kazakhstan’s Deputy Energy Minister recently dismissed reports that Astana could provide Russia with 50,000 tonnes of gasoline as humanitarian assistance, calling the reports “unfounded” [link].

“We have received no official request from Russia,” he said. “Our priority is supplying Kazakhstan’s domestic market. If surplus volumes exist and there is a commercial opportunity, we will consider it.”

That statement reveals far more than it first appears. Kazakhstan’s principal concern today is not helping Russia. It is stopping Russians from buying Kazakh fuel.

According to local media [link], authorities have established new police checkpoints along almost sixty roads leading into Russia to combat so-called “gasoline tourism”. Border controls have been tightened, while vehicles are now generally limited to a single crossing each day.

That rather sums it up. Russia, the world’s second-largest crude exporter, is increasingly relying on neighbours whose immediate priority is preventing Russians from crossing the border to fill their tanks.

Kazakhstan is not Russia’s solution. It is another reminder of how few solutions remain.

Three Doors, None of Them Good

According to Mikhail Khodorkovsky, the Kremlin has only two “doors” out of the fuel crisis.

The first is the market solution: free gasoline prices and let them rise until demand falls back into line with supply. The second is the administrative solution: coordinate the railways, strategic reserves and oil companies well enough to move fuel across eleven time zones to where it is needed.

The Kremlin has chosen neither. Instead, it has reached for a third option that Khodorkovsky merely hints at: quietly lowering fuel standards and transferring the cost of the crisis onto ordinary Russians - Kremlin style.

Take them in turn.

The market solution is economically straightforward. Let prices find their equilibrium. In a dozen or so regions, gasoline might climb towards US$5 per gallon equivalent, demand would fall, fuel would flow to where it pays best, and within a few months the shortages would largely disappear. Economically, it works. Politically, it is impossible. The Kremlin cannot afford nationwide headlines showing Russians paying European fuel prices while fighting what it insists is a successful war.

Yet, in practice, Russia is already running exactly that experiment, albeit unofficially. The only question is where the market clears. Judging by numerous reports on social media, somewhere around RUB170-250 per litre, roughly US$2-3 and judging by anecdotal evidence posted on social media. That would barely raise an eyebrow in much of Europe. In Russia, it is politically explosive.

Which is why official prices remain anchored far below market-clearing levels. AI-92, the country’s benchmark gasoline grade, sells at an average of just RUB67.72 (US$0.88) per litre at most filling stations. The gap between the official and the market price is exactly where shortages, queues and corruption begin.

The second option is the administrative solution. On paper, it sounds perfectly reasonable. The state simply instructs companies to coordinate rail capacity, release strategic reserves and move fuel from surplus regions to deficit regions. That assumes a government capable of managing a continental logistics network under wartime conditions. If Russia still had such a government, it would not be in this crisis.

The oil industry itself illustrates the point. Khodorkovsky was imprisoned. Vladimir Yevtushenkov was placed under house arrest before losing Bashneft. Lukoil chairman Ravil Maganov died after falling from a hospital window. One by one, capable managers disappeared while their assets were consolidated under Igor Sechin’s Rosneft. A corrupt state can seize an oil company. That does not mean it can run one efficiently.

Catherine Belton reaches goes a step further in Putin’s People. The system built by the siloviki was never designed to administer efficiently. It was designed to extract wealth. Its organising principle resembled the obschak, the common cash pool of organised crime, where loyalty determined access to resources and the distinction between public and private wealth deliberately disappeared. That is the machine now expected to solve Russia’s fuel crisis. It was built to siphon. Not to supply.

Which leaves the third option. Quietly lower fuel quality and let motorists absorb the consequences. It too is field tested, right now. Take Galina from Krasnoyarsk. One morning she stopped at a Gazprom filling station on her way to work and, delighted to find fuel available with hardly any queue, filled thirty litres of AI-92. Eight hundred metres later her engine died.

She was not alone. Roughly twenty-five vehicles reportedly broke down after refuelling at the same station. Some failed before leaving the forecourt. Others managed a few hundred metres. Drivers filmed visibly contaminated fuel flowing from the pumps. Rust, debris and other contaminants clogged injectors and damaged fuel systems. After cleaning, the cars ran normally again. The filling station continued operating. Gazprom had little to say.

Every crisis eventually reveals what a political system was built to do. Russia's was built to extract, not to govern. Faced with a fuel shortage, it does not create more fuel. It raises prices unofficially, rewards corruption, lowers quality standards and asks ordinary Russians to pay the bill.

That is precisely what this system was designed to do. Its response function will not magically change simply because, this time, the problem really matters.

What’s the Trade?

Read more

1. The UAE Left OPEC — Now What?

After fifty-nine years of membership, the UAE walked out of OPEC on 1 May 2026. The decision is about far more than production quotas, recent rifts with Riyadh, or wartime disruption. It reflects structural changes in global energy and in the world economy — and a clear-eyed Emirati view of where the country stands and where it is going.

OPEC was built for oil-dependent states. Abu Dhabi joined in November 1967, four years before the UAE existed as a nation. As a young federation, its economy depended entirely on oil revenue, and OPEC’s framework — collective production management, shared discipline, co-ordinated pricing — offered the expertise, stability and leverage that a small, newly independent country could not generate on its own. But that country no longer exists.

Less than a quarter of UAE GDP is now tied to energy. Aviation, logistics, advanced manufacturing, AI, tourism, and life sciences are its fastest-growing sectors. Just as telling, the Barakah nuclear plant — the Arab world’s first — has been operational since 2020 and now generates clean baseload power across four APR-1400 units totalling 5.4GW of nameplate capacity. For context: Finland has 4.4GW, Switzerland 3.0GW.

Meanwhile ADNOC has built crude capacity to 4.85mbpd and is targeting 5mbpd by 2027 — most of the growth from the Upper Zakum development in partnership with ExxonMobil. Pre-war UAE production sat at roughly 3.5mbpd, the level set by OPEC quota. That is 1.35mbpd of spare capacity sitting idle — on the same order of magnitude as Saudi Arabia’s, and tens of billions of dollars of upstream investment held hostage to a system the country has outgrown.

Leaving OPEC, therefore, is not a commercial calculation. It is a responsibility towards Emirati citizens — to develop the economy beyond oil rather than write down sunk capital deployed for a future the cartel will not allow them to deliver.

The exit was the plan all along. Oil revenue was always a means to an end; the goal was never to be an oil state. It was to build something more enduring — a diversified economy, a knowledge society, a country deep enough and partnered widely enough to thrive in whatever the world becomes next. One can only hope it stays the course, especially in these testing times. Without the UAE as a credible model, which Arab state can the others realistically emulate, for the long-term benefit of all of its people?

The decision may have surprised casual observers and even the Saudis in the moment. But it surprised no long-time oil market insider, and the timing was perfect. Flooding the market — the threat Crown Prince Mohammed bin Salman, whose ambitions and grievances outrun his wisdom, used in March 2020 against OPEC+ member Russia — requires barrels that can leave the Gulf, and right now nobody’s can, Saudi Arabia’s included.

Nor is there genuine uncertainty about what it means. The UAE exit marks the end of OPEC as we know it — Saudi Arabia now loses one of only two production allies with substantial swing capacity. Yet beyond the blow to Riyadh’s global political reach, it will have surprisingly little practical consequence for oil markets, if any at all.

It is worth stating the inconvenient truth upfront. Despite decades of US presidents picking up the phone to Riyadh for every passing oil anxiety — from Nixon in 1973 to Biden’s fist-bump in 2022 — OPEC has never actually performed the price-stabilising role it claimed to perform. As we will show in detail below, the cartel’s monthly realised volatility under its watch has consistently run two to four times higher than the pre-OPEC Twin Cartel Era’s. The reverence Western capitals paid to the cartel for half a century rested on a function it never delivered. The UAE has now noticed.

As our volatility and quota-decision analysis below will show, OPEC has been a poor buffer of price swings and a dismal steward of oil markets for most of its history. Losing its smartest member changes the optics far more than the mechanics — beyond the 1.5mbpd the UAE will gradually add across 2027-28 once the Strait of Hormuz crisis normalises.

Let me explain.

2. Why Stable Oil Prices Matter

Oil sits at the core of the real economy, particularly in transport, where substitution is slow and scale effects dominate. When prices swing, they don’t just move profits around; they disrupt decision-making everywhere. Producers hesitate on long-cycle investments, airlines defer fleet choices, households rethink vehicles, and logistics firms second-guess fuel strategies. The uncertainty translates into underinvestment, misallocation of capital, weaker employment outcomes, and at the system level it propagates into inflation, financial conditions and policy responses.

Oil moves quickly into headline inflation through fuel and transport, then bleeds into the core via freight costs, food prices, airfares and wage negotiations — as the two 1970s oil crises illustrated and as the March-April 2026 US CPI and PPI prints have re-illustrated for anyone who had forgotten. Central banks are then forced to respond to a supply-driven shock they cannot control, trying to hold inflation near 2% while a critical input price is gyrating.

Stable oil prices dampen these shocks, anchor expectations, and give policymakers cleaner signals. The result is more predictable consumer behaviour, steadier wage setting, and more rational capital allocation. Seen in that light, efforts to smooth oil price volatility — including those by OPEC and earlier regulatory regimes — had a logic beyond simple cartel self-interest. Coordinated supply management could in theory reduce boom-bust cycles, limit fiscal crises in producer economies, and lower the risk of broader geopolitical spillovers.

But the historical record, which the rest of this piece walks through, is that dampening one of the largest sources of macro volatility remains illusive in the 21st century. Among other things, the world simply does not possess the supply-side spare capacity, the institutional discipline, or the political alignment to do so.

3. Historic Oil Price Volatility Regimes

In his book Crude Volatility, Bob McNally did the historical heavy lifting every serious oil analyst now stands on. We borrow his framework of distinct volatility eras and amend it where we disagree — his “Texas Era” becomes our “Twin Cartel Era”, because Texas alone never stabilised the world price; the Seven Sisters did half the work. With modern compute, we have also rebuilt the underlying price series and recalculated each era’s realised volatility from monthly, annual, and — where the data permits — daily returns.

Seven eras across oil’s 167-year industrial life: Boom-Bust I (1859-1881), the Rockefeller Era (1882-1911), Boom-Bust II (1912-1934), the Twin Cartel Era (1935-1970), OPEC Price Setting (1971-1986), OPEC Volume Setting (1987-2003), and Boom-Bust III (2004-present, where we currently sit).

The data delivers a verdict that should make every OPEC apologist uncomfortable. Across 167 years, oil’s calmest stretch by a wide margin was the Twin Cartel Era of 1935-1970, when the Texas Railroad Commission and the Seven Sisters jointly throttled supply — σ monthly of just 10.5%, less than half of any other era. Saudi Light held between US$1.30 and US$1.80 for more than a decade. Those were the days of cheap international oil.

The moment OPEC wrestled the pricing pen away in 1971, monthly volatility nearly quadrupled to 41.1% and annual swings reached 46.5% — the most violent regime since the Pennsylvania speculative collapses of the 1860s and 70s. So much for the cartel’s self-styled role as market stabiliser.

OPEC’s forced pivot from price-setting to volume-setting after the 1986 price war brought relative calm (σ monthly 27.4%, σ annual 21.7%), but only because the cartel surrendered genuine price discovery to ICE Brent futures, launched in 1988. And here is the contrarian finding most analysts miss: across 1990-2003, oil’s annualised realised daily volatility averaged 36.5% — essentially identical to the 36.7% that has prevailed in the Boom-Bust era since 2003. The eye sees a sleepy decade in US$20 oil; the math sees a regime as turbulent as anything that came afterwards. Violent percentage moves on a US$20 base look invisible on a linear chart but compound to the same vol math as much larger dollar moves on a US$100 base.

Our current Boom-Bust III, now in its 22nd year, has delivered σ annual 29.5% and σ daily 36.7% — shale’s productivity revolution, the GFC demand shock, and COVID’s negative-price moment together rank this era as the third most volatile in oil’s history, behind only Boom-Bust I and the OPEC Price Setting decade.

The pattern is unambiguous: tightly held supply arrangements (Rockefeller, Twin Cartel) deliver low volatility; competitive supply shocks and OPEC’s heavy-handed pricing experiments deliver chaos. OPEC’s brand as the world’s swing producer survives more on press releases than on the standard deviation of returns.

Let’s look at these eras now.

4. Boom-Bust I (1859-1881)

Right out of the gate of oil’s commercial discovery, the problem of having too much or too little of it established itself.

From December 1859 to January 1862, oil prices in the United States crashed from US$20 to as low as 10 cents per barrel, forcing many oilmen to close their operations. That is a 99.5% bust in two years, and it was the first of many epic price collapses in oil’s history. With each new field discovered, the market was instantly oversupplied — crude oil production exceeding storage and transportation capacities — and prices collapsed before the next discovery did it again. Unlike soft commodities, oil cannot simply be destroyed or left to spoil; it sits in the ground until someone builds the infrastructure to handle it.

From 1859 to 1875, average monthly volatility ran at 111% (and would have been higher with daily data), according to The Derrick’s Hand-Book of Petroleum published in 1889. The greatest stretch of price chaos the commodity would ever know.

5. The Rockefeller Era (1882-1911)

Drillers tried to cartelise themselves out of the chaos. They failed.

The Oil Creek Association of 1861, the Petroleum Producers’ Association of 1869, the various shutdown movements through the 1870s — all collapsed for the same reason any voluntary supply pact does: the more it works, the bigger the prize for the cheater and the holdout. With thousands of independent operators, low barriers to entry, and a new gusher always around the corner, upstream discipline was a lost cause.

Enter John D. Rockefeller. His insight was that the choke-point was not at the wellhead but downstream and midstream. Refining required real capital and operational skill, unlike wildcatting. Transportation — railroads first, then long-haul pipelines — was a genuine oligopoly, unlike oil resources, which in the United States (unlike most places globally) belonged to whoever owned the land. There were countless such owners.

Rockefeller squeezed both. Through aggressive railroad rebate deals, predatory pricing, secret acquisitions and the 1882 Trust structure devised by his lawyer Samuel Dodd, Standard Oil controlled more than 90% of US refining capacity by 1879 and effectively dominated the pipeline grid through the 1880s to 1911. He never directly set the crude price. He did not have to. By adjusting storage tariffs, refusing to lift excess barrels through his pipelines, and at times curtailing his own refinery runs, he could reach back down the supply chain and force drillers to throttle. When pressure failed, he occasionally just cut a deal — the 1887-88 “Great Shutdown” being the most successful voluntary supply cut of the era.

The results speak for themselves. Average annual price volatility collapsed from 78% in Boom-Bust I to 23% under Rockefeller — the first sustained period of price stability the industry had ever known. And it was not just stability for stability’s sake: kerosene retail prices fell from roughly 45 cents per gallon in 1863 to about 6 cents by the mid-1890s. Stable and disinflationary, which is largely why the public tolerated the monopoly as long as it did.

On 15 May 1911, Standard Oil was found guilty of violating the Sherman Antitrust Act and was forced to break up within six months. Rockefeller retired but retained his original share ownership in every one of the new spin-offs — anti-trust did not mean expropriation. The asset-light architecture of the breakup made him wealthier still: the combined value of the resulting Standard Oil descendants rose fivefold over the next decade.

6. Boom-Bust II (1912-1934)

The 1911 dissolution didn’t just remove the stabiliser — it coincided with a complete rewiring of the demand side. Gasoline overtook kerosene as the most prized refined product in 1910, the Model-T was three years old, and oil’s strategic role for navies and armies was about to be cemented by the First World War.

On the supply side, the discovery treadmill never stopped: Spindletop (1901), Glenn Pool (1905), Cushing (1912), Healdton (1913), the Los Angeles basin in the 1920s, and finally East Texas in 1930. Bigger industry, same pathology. The price pattern repeated almost mechanically as it had in Boom Bust I. WWI demand sent mid-continent crude from US$1.30 in March 1915 to US$6.10 in March 1920 — a 452% jump that would not be exceeded for fifty years. Then California’s new fields came on, supply overwhelmed everything, and prices nosedived from US$6.10 at the start of 1921 to US$2.25 six months later. The full boom-bust cycle, compressed into a single business cycle.

Stabilisation efforts ran on two tracks. Domestically, state officials tried to step in where Rockefeller’s trust no longer could: the Oklahoma Corporation Commission issued the first “proration” orders on the Healdton and Cushing fields in May 1914, Texas followed in 1919 with a Texas Railroad Commission given limited authority over physical waste — but the early quotas were toothless.

Internationally, in August 1928, Walter Teagle of Standard Oil of New Jersey, Sir John Cadman of Anglo-Persian, and Sir Henri Deterding of Royal Dutch Shell met for two weeks of scotch, grouse-shooting and negotiation at Deterding’s Achnacarry Castle in Scotland, and signed an “As-Is” Agreement freezing global market shares at 1928 levels. The Red Line Agreement that July had already carved up the former Ottoman oil territories among the same group plus partners. Both were private treaties between the majors. Both held — for a while.

Average price volatility came in around 26% — much better than the 78% of Boom-Bust I, but only because the industry was now bigger, more interconnected, and faster at moving barrels. The structural problem was unchanged: massive new finds, sticky demand, the rule of capture, and no domestic entity with the authority or scale to choke flow.

Stability would have to wait for the Texas Railroad Commission to discover what it was really capable of — which happened sooner than anyone expected when, on 3 October 1930, a 70-year-old wildcatter named Columbus “Dad” Joiner brought in his Daisy Bradford No. 3 well in Rusk County and triggered the East Texas field, the largest oil discovery in American history to that point. It would produce more than 5.4 billion barrels between 1931 and 1980.

7. The Twin Cartel Era (1935-1970)

The problem of price volatility never really went away — to this day — except for one 35-year stretch when oil traded essentially range-bound between US$2 and US$5 a barrel, with annual volatility as low as 10% between 1935 and 1971. McNally calls this the “Texas Era,” which is half-right. From a global perspective it is better described as the Twin Cartel Era: US stability administered by the Texas Railroad Commission (TRC), international stability administered by the Seven Sisters, with Eisenhower’s import quotas welding the two systems together. Each cartel needed the other to work.

The TRC version began with the crisis Dad Joiner had just delivered. The “Black Giant” (the East Texas Field) was a 220-square-mile contiguous reservoir that within nine months was producing one million barrels per day from thousands of wildcat wells, and East Texas crude duly crashed from US$1.00 to US$0.10 a barrel by July 1931. Between 1926 and 1936, wildcatters discovered 4 of the 10 largest conventional oil fields in the United States. That required drastic measures. Texas delivered them.

On 17 August 1931, Governor Ross Sterling declared martial law and ordered 1,200 men of the Texas National Guard’s 56th Cavalry Brigade into the field to physically shut wells in. They stayed there until the courts forced them out, by which point Austin had figured out how to do it with regulators instead of soldiers. The 1935 Connally Hot Oil Act criminalised interstate transport of oil produced over quota, the Interstate Oil Compact extended the model across the major oil states, and from then on the TRC ran a monthly “allowable” system: forecast demand, set quotas, swing US output to fit. It worked for 35 years.

Internationally, the Seven Sisters did the same job through different means. Achnacarry and the Red Line had already laid the framework in 1928 — frozen market shares, jointly-owned concessions, “self-denying” clauses preventing independent development. The Seven Sisters — namely Anglo-Persian Oil Company (BP), Royal Dutch Shell, Esso (Exxon), Mobil, Chevron, Gulf, and Texaco — between them controlled around 85% of global reserves outside the US, USSR and Mexico, and they didn’t need quotas because they owned the wells outright. Their concessions across the Persian Gulf, Indonesia and Venezuela meant they could decide how much each host country produced, post a price benchmarked to US Gulf crude, and call it a market.

Their political reach was on display in 1953, when the CIA and MI6 jointly engineered the coup against Iran’s Prime Minister Mossadegh to reverse his nationalisation of Anglo-Persian Oil Company (BP) and force the British monopoly open into a consortium that included the Americans.

The result was the calmest oil market in history. Annualised volatility collapsed to 10.5% between 1935 and 1971 — roughly 8x quieter than the boom-bust eras either side of it. Between 1948 and 1970, US crude prices held a US$3-5 band. Monthly Arab Light, quoted in the World Bank’s Pink Sheet between January 1960 and December 1971, hovered between US$1.21 and US$1.74 — less than half its American equivalent. For a brief period in history, oil had become a utility — for the benefit of the post-war development of Western economies.

Why two prices? In 1959, President Dwight D. Eisenhower established the Mandatory Oil Import Quota Program to restrict the volume of foreign petroleum entering the United States at 12.2% of US demand. The primary goal was to safeguard national energy security by preventing dependence on vulnerable foreign supplies, while also protecting the domestic oil industry from cheaper global competition — competition the Seven Sisters had been discovering at an unprecedented pace.

It is almost impossible to grasp the market power the Seven Sisters held in their prime. A staff report by the Federal Trade Commission on “The International Petroleum Cartel” in August 1952 explained the scale. They controlled substantially all production and reserves outside the United States and the USSR — what I call the Free World Reserves. By 1944, with the world’s first publicly disclosed country-by-country reserve figures laid before Senator Truman’s committee, the seven companies already controlled 59.3% of Free World reserves while pumping just 17.4% of Free World output. By 1955 their share of reserves was 78.5%, ex United States.

Perhaps the most interesting observation is what I call the spread between their reserve-to-production (R/P) ratio internationally versus that observed for the United States: it peaked at 68.2x versus 12.1x in 1955. The measure is a way of illustrating the Seven Sisters’ spare production capacity mainly in the Middle East, what I like to call “latent spare capacity”. The Sisters could have easily tripled their output within a relatively short timespan with modest capital. But why repeat the mistakes made during Boom-Bust I with every new giant field discovery in the Middle East and with a set rule of global market share in place?

In the four decades they sat astride the global oil concession, the Seven Sisters added roughly 351 billion barrels to their reserve base — a thirty-one-fold expansion against the US industry’s three-fold — while quietly absorbing the largest sequence of giant-field discoveries in human history: Kirkuk (1927), Burgan (1938), Dammam (1938, the discovery well that pointed to Ghawar), Ghawar itself confirmed in 1948, Rumaila (1953), Safaniya (1951). Five of the ten largest oil fields ever found were brought into the Sisters’ concession portfolio in a span of twenty years, and almost everything that still matters to global supply in 2026 — Ghawar, Burgan, Safaniya, Kirkuk, Rumaila — was on their books before the first OPEC quota was ever set.

As McNally documents from the 1928 Achnacarry minutes, the Sisters’ own internal estimate was that “world shut-in production amounts to 60% of the production actually going into consumption.” This was the deliberate management of an oil glut: an era when annual demand growth ran below the pace of new discovery, and where the cartels’ job — both the TRC in Texas and the Sisters abroad — was not to find more oil but to keep what had been found from drowning the price.

The system did exactly what it was designed to do, and the Western consumer was the beneficiary: 35 years of cheap and stable oil underwrote the post-war industrial miracle. But the wealth transfer that followed its collapse deserves to be named plainly. The nationalisations of 1972 (Iraq), 1975 (Kuwait), 1976 (Venezuela), and 1980 (Saudi Aramco) expropriated concession assets that had been developed under contracts running 60 years or longer, financed and de-risked entirely by the majors, with host-government royalties already restructured to a 50/50 profit split since 1948.

By any standard of contract law these were illegal seizures and forced sellouts, and in any other decade Washington or Westminster would have responded as they had in Mexico in 1938 or Iran in 1953. But the host governments were spectacularly lucky in their timing. Britain had been politically broken by Suez in 1956 and economically broken by sterling’s 1967 devaluation; the United States was distracted by Vietnam, the August 1971 closing of the gold window, and a domestic political crisis that would end in Watergate. The pricing baton did not so much pass as get dropped — and the producing countries picked it up.

Three things guaranteed price stability during the Twin Cartel era: (a) annual demand growth was smaller than new discoveries, so there was always a glut to manage; (b) the TRC monopolised US supply while the Sisters cartelised the rest, with Eisenhower’s 1959 Mandatory Oil Import Quotas welding the two systems together; and (c) the duo together held enough global spare capacity to absorb any shock without breaking the price stability.

Three things guaranteed price stability during the Twin-Cartel era: (a) annual demand growth was smaller than new discoveries, so there was always a glut to manage; (b) the TRC monopolised US supply while the Sisters cartelised the rest, with Eisenhower’s 1959 Mandatory Oil Import Quotas welding the two systems together by walling off the domestic market from international competition; and (c) the Cartel duo together held enough global spare capacity to absorb ANY kind of shock without breaking the price stability.

Read more

What’s the News?

As I was preparing the next episodes on crude oil and what lies ahead, President Trump, as so often, interrupted the process with a rapid stream of high-intensity posts on the negotiations with Iran.

According to the latest headlines, the Strait is “fully open”, mines are being removed, and Iran has agreed never to close it again. Markets reacted immediately. Oil and product prices dropped sharply on the announcement.

And yet, scratch the surface and the picture becomes far less clear. The reopening is conditional, traffic is still routed and controlled, and a U.S. naval blockade on Iran remains in place.

In other words, we are not looking at clarity. We are looking at the fog of peace.

Let’s break it down

First, the reopening of the Strait of Hormuz is part of a two-week ceasefire agreed on 8 April 2026. It is contingent on the cessation of hostilities in Lebanon and subject to “technical limitations”, which in practice means a controlled and limited flow of vessels, as outlined in Episode 1. Link to agreement.

Second, even under generous assumptions, the exit rate remains constrained. If we assume up to 10 vessels per day, it would take roughly three months to clear the backlog of some 800–900 vessels of all sizes currently trapped in the Persian Gulf, ranging from crude tankers to LNG, LPG, product carriers, dry bulk and containers.

So far, I cannot observe a meaningful increase in transit activity that would challenge this assumption. The high-frequency data from Kpler, which captures vessel movements across all ship types, supports that view as of the time of writing.

Read more

Crude Quality Matters

There is no such thing as “oil”.

Instead, the world produces hundreds of different crude grades, almost as many as there are oil fields, although some fields yield very similar qualities.

The chart above illustrates this. Think of it as a periodic table of crude. The one below is interactive and works well on a desktop (not so much on a mobile phone), so take a moment to hover over or tap the individual bubbles. Each represents a crude grade, positioned by API gravity on the x-axis and sulphur content on the y-axis. The size of the bubble reflects production volume.

What matters is not just how much oil exists, but what kind of oil it is.

The chart shows 152 crude grades. In reality, there are closer to 700 grades produced across roughly 6,400 extraction areas and more than 2 million active wells. These 152 alone account for roughly 56mbpd of the 85mbpd produced globally each day and are sufficient to make the point.

To begin, focus on the Medium-Sour quadrant, highlighted in orange. You will quickly notice that most of these barrels originate from the Middle East. This is not a coincidence. It is the backbone of the global refining system.

Take Arab Light as an example. It sits squarely in that cluster, with around 1.96% sulphur and an API gravity of 33.3. Production is roughly 4.6mbpd. It is one of the most important barrels in the world.

P.S. Please use the interactive chart on a desktop. It does not scale well on mobile.

So what does this mean? Roughly 75–85% of Middle Eastern crude exports are shipped to Asia in any given year, as shown in the table below. Refinery systems across Asia have been optimised over decades to run on that specific crude diet.

Refineries are not flexible machines. They can be adjusted at the margin, but they cannot be reconfigured quickly to process entirely different crude qualities while maintaining the same product yields.

And this is the key point the chart above illustrates in simple terms. The missing barrels are not just volumes. They are specific grades, predominantly medium-sour crude, produced at scale in the Middle East.

Those barrels cannot be replaced in the quantities required. Not by the United States, not by Latin America, not by anyone.

Read more

Guidance & Thoughts Upfront

Over the coming episodes, I will try to explain, to the best of my ability, different aspects of this Hormuz crisis, share a significant amount of data, most of it hard to obtain and rather expensive, and assess the implications for the global economy. The aim is to stay grounded in probabilities and avoid bias, as markets do not care about our narratives.

As this will take time and there is a lot to cover, each episode will include updated oil balances, as introduced in the Executive Summary. This should allow you to observe the dynamics in real time and act accordingly.

I begin with the Strait of Hormuz itself. For global oil and gas balances, normalising transits through the Strait has no alternative. Without it, a recession arrives in 2026, not 2027. That is unavoidable, as outlined in the Executive Summary. Avoid commentators who describe the situation as “manageable” or “replaceable”.

It is not, at least not in the medium term. U.S. exports cannot solve the problem. They may increase slightly, for instance as SPR barrels are sold due to domestic crude quality mismatches. But fundamentally, U.S. exports do not create new supply. They merely redistribute existing barrels.

Likewise, U.S. shale, often described as a fast-cycle response to price, will remain marginal. The constraint is not time, but geology. The remaining Tier 1 inventory is limited, and the industry no longer has the locations to scale meaningfully where it matters. Think 1-2mbpd. That is highly unlikely. But at least higher prices will further delay the decay of U.S. output. At least I suspect so.

Nor can domestic re-routing solve the problem in the Middle East itself. Beyond the East-West pipeline in Saudi Arabia and limited flows via Fujairah in the UAE, alternatives are constrained, vulnerable and take years to be in place. That is not a near-term response.

And yet, unless the Strait is reopened quickly, closing it will prove a long-term strategic mistake for the regime, should it survive. Why? Because shutting it for more than a few weeks inevitably triggers behavioural change. The pain inflicted by this economic weapon of mass destruction is simply too severe.

That, in turn, accelerates long-term workarounds that marginalise Iran’s influence. New pipeline infrastructure will be developed, and upstream investment will be redirected, at scale.

The 1970s oil crisis offers a clear precedent. It triggered the development of the North Sea basin in the U.K. and Norway, where major discoveries in 1969–1970 led to production ramping from the mid-1970s onwards, ultimately adding millions of barrels per day to global supply.

Venezuela could become part of that adjustment. In 2026, it exports roughly 0.9–1.1mbpd, far below historical levels, and meaningful expansion requires years of investment and infrastructure repair. The world needs to replace up to 14mbpd. This is not the solution, but it is a start.

Venezuela’s relevance lies in crude quality. Its reserves are dominated by heavy and extra-heavy sour crude from the Orinoco Belt, the type of barrel currently missing from the Middle East, although extracting and upgrading it remains capital-intensive and time-consuming .

This Venezuela does not possess “spare capacity” in the IEA sense (higher production in 30 days for 90 days), but it is one of the few scalable sources of the right barrel with potential well above the 2mbpd it exported in 2014. Think 5mbpd and beyond.

And yes, of course, the local situation requires years of investment, some with quick yields, others much longer, depending on the field and infrastructure. None of this happens without rule of law. Without it, capital will not return. I discussed this in detail a few weeks ago. So this too requires this administration to finish the job.

Anyway, in the coming episodes, I will cover a range of topics, from crude quality and barrel counting to unintended consequences for Russian exports, the role of LPG in India, the importance of sulphuric acid and other chemicals, and the impact on LNG and even gold. It will be quite a journey.

Today, we begin with what I call the Persian Trap.

Negotiation Failed, Now What?

Almost a full day of negotiations ended with a terse press conference and no deal. Talks between the United States and Iran began on Saturday afternoon and continued through the night, almost 21 hours in total.

The sun had risen in Islamabad by the time Vice President J.D. Vance emerged to brief reporters: “We have not reached an agreement. We’ve made very clear what our red lines are and they have chosen not to accept our terms.” The press conference lasted less than three minutes.

If the Administration believed that, after 21 hours of negotiations, this regime would give up uranium enrichment, as Vance implied, it misread both the moment and the Iranian power structure, in particular the IRGC.

On a lighter note, they did not spend much time studying the past 80 years of conflict and the rather poor track record of reaching lasting agreements, let alone durable peace.

Below is an extract on the Korean War and how it ended, which I published on this Substack. Not many read it. Nor my other pieces on war and peace. Perhaps now is as good a time as any to prepare mentally for what lies ahead?

The Death of Peace Treaties and Why Wars Often End Without Justice

The armistice signed on July 27, 1953, between the United Nations Command and North Korea reaffirmed the 38th parallel as the border between North and South Korea and created the four-kilometer-wide “Demilitarized Zone” (DMZ). The Military Demarcation Line bisects the “Bridge of No Return,” used for prisoner exchanges until 1968, when the crew of the USS Pueblo crossed it into South Korea.

The Korean War lasted just over three years, from June 1950 to July 1953. While fought on a divided peninsula, it was in fact the first hot war of the Cold War—a violent proxy confrontation between the democratic-capitalist West, led by the U.S., and the communist East, led by the Soviet Union. South Korea was supported militarily by U.S. and UN forces; North Korea by China, which sent hundreds of thousands of troops, and by the USSR, which supplied matériel, strategy, and legitimacy.

Because the war was a proxy clash between two worldviews, there was never a foundation for trust, let alone a peace process. Yet negotiations began relatively early, just over a year into the conflict. Formal talks opened in Kaesong in July 1951 and later moved to Panmunjom. Despite stalemate on the battlefield, they dragged on for more than two years, paralysed by disputes over prisoners of war and the demarcation line.

It took more than 700 meetings and nearly two years to negotiate the agreement—almost as long as the war itself. The signing of the armistice took just 12 minutes, conducted in silence at two separate tables so the delegations did not face one another.

The armistice contained operational provisions, notably prisoner exchanges: Operation Little Switch and Operation Big Switch staged the return of sick, wounded, and eventually all remaining POWs. But beyond this, the agreement was strikingly shallow. After 700 days of talks, the sides had failed to address any core political questions: no peace treaty, no normalisation, no territorial settlement.

Many North Korean and Chinese prisoners refused repatriation, fearing persecution or worse at home. Their resistance became a major stumbling block and symbolised the deeper ideological divide. We see similar dynamics today in Ukraine, where defections and shifting loyalties complicate any prospect of peace.

The Korean settlement was a minimalist framework—closer to a UN resolution than a true bilateral accord. It reflected the smallest possible denominator: not a shared vision, but mutual exhaustion. Violence stopped, but the war never truly ended. To this day, there has been no Korean equivalent of the Tokyo Trials—no reckoning, no justice, no closure for victims. Remember this when you hear calls for a “just peace” in Ukraine.

Since 1953, the armistice has been violated more than 100,000 times. Even during global détente—such as the 1975 Helsinki Conference—tensions on the peninsula deepened. The frozen conflict became a “continuous nightmare”: artillery duels, assassinations, espionage, hijackings, and later, nuclear and missile tests. What was achieved in 1953 was not peace, but stalemate.

And that is why the Korean Armistice matters today: it offers a cautionary lesson to avoid false expectations as the world debates a “just peace” in Ukraine.

From the Iranian side, officials indicated that progress had been made on several points. Two or three outstanding issues, including the handling of the Strait of Hormuz, prevented a breakthrough, according to Foreign Ministry spokesperson Esmail Baqaei. After 40 days of war, mistrust remains deeply entrenched. “Naturally, no one could expect us to reach an agreement after a single meeting. We will continue working to bring Iranian and American positions closer together.”

Baqaei added that the talks took place amid “mistrust and suspicion”, while state media blamed American “excessive demands” for the lack of progress. Both delegations have now returned home without setting a date for further negotiations.

The talks ended in Islamabad on Sunday morning. The path forward remains unclear. Pakistan’s Foreign Minister, Ishaq Dar, urged both sides to adhere to the ceasefire. Iranian officials signalled no urgency to resume discussions. Until the United States presents what Tehran considers a “reasonable agreement”, there will be no change regarding the Strait of Hormuz.

A breakthrough was always unlikely

Reaching an agreement on such a complex and multi-layered dossier over a single weekend was never realistic. The more relevant question was whether a framework for continued negotiations could be established. That would have required both sides to recognise the altered realities after six weeks of war and move away from maximalist positions.

For Iran, this centres on uranium enrichment, a red line for Trump. During the last round of talks in Geneva, Iran was reportedly prepared to make meaningful concessions. Its enrichment facilities in Fordo, Natanz and Isfahan are believed to have suffered significant damage, although it remains unclear how quickly operations could be restored.

The last nuclear agreement between the United States and Iran took two years to negotiate. The more likely outcome now is an interim arrangement that addresses part of the dispute and buys time. Iran would need to relinquish control over the Strait of Hormuz and potentially limit its near-weapons-grade uranium. The United States would need to offer economic relief, for instance by unfreezing Iranian oil revenues held abroad under sanctions.

The dilemma is as much about sequencing as substance. Iran views uranium as leverage, to be traded for a comprehensive agreement, not a temporary one. The United States prefers to resolve the issue early, rather than allow it to remain in Iranian hands during a prolonged negotiation.

Each side expects the other to concede. The Iranians believe they hold the upper hand, having endured six weeks of bombing by far stronger opponents while inflicting significant damage on the global economy. Time, in their view, is an ally. To them, Trump appears increasingly eager to end the war before elevated energy prices weigh on the Republican Party ahead of the midterm elections.

The United States sees it differently. While the war has fallen short of several objectives, it has weakened Iran’s leadership, its armed forces and its economy. A further escalation would likely be more painful, particularly if the United States and Israel intensify attacks on infrastructure and economic targets.

My own view is that the U.S. focus on the nuclear file risks granting Iran excessive leverage. Based on my research, the regime lacks both the financial and industrial capacity, as well as the political time, to rebuild its nuclear programme meaningfully before internal pressures mount. This raises the question whether the nuclear issue is primarily a negotiating tactic: insist on it now, only to accept a more ambiguous compromise later in exchange for reopening the Strait.

Meanwhile, Iran expert Robert Malley highlighted what we outlined in the Executive Summary: time favours Iran, at least in its own perception. The closure of the Strait generates increasing marginal returns for Tehran, while additional strikes deliver diminishing marginal returns for the United States.

The Persian Trap

Another sticking point is the Strait of Hormuz, and what I call the Persian Trap, the Persian Gulf is easy to enter, but not necessarily to leave.

Iran has pledged to keep the waterway open during the ceasefire. In practice, only a handful of ships have been able to transit the Strait. According to U.S. officials, one reason is that Iran itself may no longer be able to locate all the mines it has deployed.

Iranian officials have indirectly acknowledged these constraints. Foreign Minister Abbas Araqchi noted that any reopening would take place “taking into account technical constraints”. That may reflect genuine operational limits, or simply a mechanism to control flows and extract rents.

Following the U.S. and Israeli strikes on 28 February, Iran asserted de facto control over the Strait. As part of the ceasefire, it signalled to mediators that crossings would be limited to roughly a dozen vessels per day, subject to tolls. President Trump, by contrast, has insisted on a full reopening.

In reality, shipowners from Greece, China, India and Pakistan are now negotiating individual crossings with the Islamic Revolutionary Guard Corps. Toll payments reportedly reach up to US$2m for VLCCs. Iranian vessels are exempt.

What we can observe is the routing. Approved vessels are directed north of the standard shipping lane, navigating a narrow corridor between Qeshm and Larak, hugging the Iranian coastline before exiting into the Gulf of Oman.

Pre-war, roughly 130 vessels transited the Strait daily. Since the conflict, flows have collapsed. Between 13 March and 9 April, only 122 crossings were recorded in total, across all cargo types. In other words, one month of traffic now equals a single pre-war day.

The majority of these movements are bulk carriers and tankers carrying petroleum products, primarily linked to Iranian exports into markets such as China and India.

Technically, the northern route is viable, but only just. The Strait’s depth ranges from 30–90 metres, while the northern corridor offers roughly 25–30 metres. That is sufficient for some fully laden VLCCs with drafts approaching 20–30 metres, but it leaves little margin for error. The route works, but it does not scale.

And scaling is the issue. The northern route cannot replicate the throughput of the standard channel. Even under a ceasefire, expect a structural bottleneck across all vessel classes. Crude tankers will not receive priority.

From a purely technical standpoint, I would expect 5–10 vessels per day to exit the Strait during a ceasefire, assuming it holds. The constraint is not only physical, but operational. For vessel operators, this is an execution nightmare.

The backlog already sits at 800–900 vessels. At 10 per day, clearing it would take 80–90 days, assuming no further disruptions. That is a heroic assumption. Entries are effectively zero, excluding Iran’s dark fleet. Without inbound flow, the system cannot normalise.

The core point is simple: until the trapped fleet exits safely, no rational operator will accept entry risk. You cannot price this level of schedule uncertainty. The opportunity cost alone is prohibitive.

The implication is that this crisis extends well into July and likely beyond, potentially bleeding into 2027, regardless of any temporary SPR releases. Tehran will not relinquish the Hormuz lever easily. It is an economic deterrent, cheaper and, in this context, more effective than a conventional weapon.

Example from a Financial Times article:

Jakob Larsen, chief safety and security officer at Bimco, advised members to “await further guidance from the relevant authorities”, warning that transit currently involves “heightened risk”.

The toll regime introduces an additional constraint. Payments may violate U.S. sanctions. As Lars Jensen of Vespucci Maritime noted, shipowners face a binary choice: keep vessels stranded in the Gulf or pay Iran and risk breaching sanctions.

Shipbrokers said insurance also remained a big challenge. “The situation remains clear as mud . . . the main stumbling block for most parties remains a lack of clarity around insurance,” one told the FT.

Anchan, the chief executive of Safesea, said underwriters were requiring shipping companies to provide proof of approval from the IRGC before providing insurance but “no one has a clue where to get this approval from”.

David Smith, head of marine at insurance broker McGill and Partners, said there had been “a huge volume of requests for quotes since the ceasefire”. But he noted that the strait was still “classified as a very high-risk area” by the insurance market’s Joint War Committee, whose designations influence the premiums set by underwriters.

Cargo insurance rates quoted for shipping through the strait have fallen from about 7.5 per cent of the insured value of goods last week to roughly 3.75 per cent on Wednesday, according to one large broker.

Signal Versus Noise

I still expect more vessel transits to be registered in the coming days, perhaps weeks, even in the absence of a deal. That, however, is not what matters. After all, exits from the Strait resemble the kind of escape one would expect after being trapped for six weeks.

For the purpose of re-establishing the regular supplies of oil flows, what exits the Persian Trap during this ceasefire is largely irrelevant for long-term oil and gas balances, or for products such as LPG and fertiliser. It is, in effect, one-off noise.

Yes, if the above calculations hold, and assuming the ceasefire is extended, roughly 80 million barrels of trapped crude and products could reach their intended destinations. But that remains a one-time release.

Read more

Executive Summary

Freedom of Navigation At Stake

Iran did not need to sink a single tanker to shut down a fifth of the world’s oil and gas supply. A handful of missile and drone strikes was enough to deter the global commercial shipping industry from transiting the Strait of Hormuz.

Within two days, the vital energy chokepoint was functionally closed for exports. Only Iranian oil and gas continues to move through the Strait, with the odd exception that proves the rule and carries no relevance for the functioning of the world economy.

The most honest gauge of the current balance of power in this conflict is the chart below: monthly transits of oil and petroleum products through the Strait of Hormuz. Iran’s regime, not the United States, is in control of this war, as the only objective that matters now is regaining control of the Strait.

If that fails for a prolonged period, everybody outside Tehran loses. Everybody, including the United States and China. Every other 3D chess, game theory narrative, usually advanced by generalists with little understanding of oil, is not worth the paper it is written on.

Tehran’s strategy is one of economic attrition, built on the assumption that the United States cannot tolerate a prolonged war and elevated oil prices indefinitely and will eventually back down. If and when it does, Iran’s Revolutionary Guards will control Hormuz. Oil will flow again, but only on Tehran’s terms and at the right price.

This is a replicable playbook in an age of cheap but effective weapons proliferation. Interrupting freedom of maritime navigation is astonishingly simple. The reason is behavioural. The adversary is not a navy, it is a commercial vessel owner and an unarmed crew. Deterrence is as simple as stopping a car on the street with a gun in your hand. Often, an explicit threat is enough. Remember Captain Phillips? A true story.

Nor are such attempts rare in post-war history. There have been thousands of naval interventions by the United States, Britain and France, and increasingly by India and China, in response to disruptions, from the 1980s tanker wars in Hormuz to piracy off Somalia and in the Strait of Malacca. Maritime trade has always required policing.

If word spreads that this policing breaks down systematically, global commerce will suffer immeasurably, and with it the petrodollar system.

There are some 200 straits globally, with at least two dozen highly relevant for global commerce. Because they often overlap with territorial waters under the 12 nautical mile rule, they fall under the U.N. Convention on the Law of the Sea (UNCLOS) transit passage regime, which guarantees continuous, uninterrupted freedom of navigation for commercial and military ships and aircraft. The question is, who guarantees what?

Iran’s attempts to charge tolls, restrict passage, or impose conditions are violations of this framework. The Houthis applied a similar blackmail playbook, with fewer means, in the Bab el-Mandeb, which was functionally closed between 2019 and 2021. None of this required sea mines or heavy lifting. A credible threat, perhaps a drone strike, is sufficient.

Back then, a U.S.-Saudi coalition restored order. U.N. conventions are only as strong as the power that enforces them, which is why Pax Americana enabled freeriding, with significant net benefits accruing to the United States and its reserve currency, while Britain and France carried a large share of the burden without the exorbitant privilege of the global reserve currency.

Regardless, what if no one feels responsible in the current situation? Iran is a state actor behaving like a terrorist organisation, a different calibre altogether than the Houthi militias. It is all rather problematic in an age of “butter”, not “guns”, and misguided strongman leadership.

If that insight takes hold, why would Turkey not begin charging additional fees for “security services” at the Bosporus, beyond the limited service fees already in place, a point correctly highlighted by Andrey Sizov, a Black Sea agri-commodity expert? It is vastly more capable than Iran.

China is an order of magnitude more capable than Iran and Turkey combined, and could deploy a far more sophisticated version of the same economic leverage in the Taiwan Strait, with severe short-term consequences for global semiconductor supply chains and corresponding retaliation, perhaps in the Strait of Malacca, Gibraltar or the Panama Canal.

It serves no one’s long-term interest. Yet history has periods in which old lessons must be re-learned before reason prevails. As Henry Kissinger noted in one of his final interviews with the Financial Times on 20 July 2018:

“Trump may be one of those figures in history who appears from time to time to mark the end of an era and to force it to give up its old pretences. It doesn’t necessarily mean that he knows this, or that he is considering any great alternative. It could just be an accident.”

The Fog of War Collides with the Midterms

Meanwhile, Trump’s increasingly erratic and aggressive reactions suggest his administration was not prepared for this. He certainly did not prepare his voter base for a war of attrition to regain control of Hormuz, the true weapon of mass destruction in the wrong hands. That leaves this, in the eyes of his electorate, as a war of choice. But is it? Regaining control of Hormuz does not look optional.

The problem is perception. United States voters, and others, are not yet ready to see this clearly. A few weeks of higher oil prices and three cancelled flights in Timbuktu will not suffice. A prolonged recession would.

Iran’s regime has not acted irrationally in the past, but it does not follow standard cost-benefit logic. Its decisions are shaped by ideology and regime survival under stress. Historically, it has behaved risk-averse in gains and risk-seeking in losses, particularly during the Iran-Iraq war. Under pressure, concessions are framed as losses, not gains. That makes escalation more likely as stress increases. Trump’s approach, and his reliance on deadlines, is therefore counterproductive.

Trump appeared to be aiming for an evolutionary version of Operation Midnight Hammer in Iran and Absolute Resolve in Venezuela, a compressed playbook of surgical air strikes, special operations and real-time intelligence integration. A campaign to prevent a nuclear Iran, reassert control over Middle Eastern oil flows and engineer regime change, with a Nobel Peace Prize as the epilogue. Peace through strength. The fog of war denied him that sequence.

Earlier military success reinforced a false sense of control. Operation Absolute Resolve, months in planning and executed in hours, likely shaped expectations of repeatability. That misread carried into Iran.

The administration failed to explain the stakes of this war, and its necessity, to the electorate. On the contrary, Trump campaigned on avoiding Middle Eastern entanglements. For his base, and for a majority of Americans, this remains a war of choice.

How is the war going? If one were to ask the President whether he would start this war again with the knowledge he has today, the answer would undoubtedly be no, in a classified setting. In public, this war remains a roaring success. Despite undisputed battlefield success, including air dominance, the honest assessment is that the President lost control of this war weeks ago.

Trump is left with two bad choices. (A) He can walk away and leave unfinished business, with immeasurable risk to American soft power and the petrodollar system. Or (B) he can attempt to finish the job while fighting a political war at home, which makes a military resolution increasingly unattainable the longer the conflict drags on, as the fog of war collides with the midterms.

The regime in Iran understands this. In its own calculus, time has become an ally. And in this conflict, perception dictates reality.

Some argue this conflict has no military solution. I am less certain of that, but I am certain an air campaign alone will not suffice. As historian Stephen Kotkin notes, regimes can fail at almost everything as long as they retain a monopoly on violence against its own people.

This regime appears to have fine-tuned, and at the same time decentralised and automated, its response functions when faced with internal uprisings or external attacks, brutally so. But who is going to take the Kalashnikovs out of their hands? It is not the F-35 pilot from Israel or the United States.

At the same time, regimes have a habit of looking invincible the day before they collapse. These apparent contradictions often coexist, as seen in the fall of the Berlin Wall and the subsequent breakdown of the Soviet Union.

Overlay this with the current negotiation dynamic. Deadlines, threats and tactical escalation are now part of the playbook. By the time this is read, positions will have shifted again, whether through escalation, delay or partial retreat.

What matters is the pattern. TACO and short-term escalation are not mutually exclusive. They tend to occur together, as both sides seek to improve their bargaining position before stepping back. Iran understands this well.

Likewise, the President may still get lucky on the battlefield, but from where I sit the most likely outcome is that the United States and Israel win the battles, yet lose the war and the peace that follows, at least in the near term and until the regime eventually collapses. That leaves a highly uncertain set-up for the global economy in 2026 and likely into 2027.

Who Controls the Barrels?

My Base Case is TACO this month, followed by a series of bilateral “arrangements” between Iran and producing countries such as Iraq, Kuwait and Bahrain. India and other emerging Asian economies are likely to pursue similar deals. That will not be sufficient to avoid a global recession, and several of these dynamics will overlap.

I do not expect Saudi Arabia or the UAE to negotiate. They think in generations, not in midterms. Their barrels return fully, either through a clean reopening, via physical bypass pipelines or under coalition force. There is no middle ground.

Likewise, China, Japan, South Korea and Europe are unlikely to enter bilateral agreements with institutional weight, as doing so would set a dangerous legal precedent for global maritime commerce.

The tables below illustrate crude oil import flows by origin and help frame regional exposure. Japan sources roughly 90%+ of its refinery intake from the Middle East, South Korea and Taiwan are similarly exposed, while China sits closer to 50%. These are material dependencies, but they are only one part of the equation.

Inventories, strategic reserves, crude quality and refinery configurations matter just as much, if not more, in determining how this shock propagates. Take China. It holds the world’s largest crude oil and product inventories. That provides time, not immunity.

The CCP can afford to watch its geopolitical rival, the United States, absorb not just the economic strain, but also the geopolitical damage to its soft power and, ultimately, to the petrodollar system, for an extended period at current run rates before it needs to react. As Napoleon once put it, do not interrupt your enemy when he is making a mistake. And it will not.

An important caveat here. The stakes for the global economy are so high that a pronounced recession could alter this calculus and force “creative” solutions, such as a Two-Tier Transit System with an Oman and Iran lane in the Strait of Hormuz. But without the United States interrupting Iranian barrel flows as well, I see no reason why Tehran would concede to such an arrangement. Nor is it clear what that would imply for transit frequency. Let us call this the “Face Saving Case”.

The Upside Case assumes a negotiated settlement between the United States and Iran, restoring most transits within 3–24 months, the time required to repair war damage and bring shut-in fields back. The track record for such agreements is poor, particularly with regimes in the Middle East, Russia or North Korea.

The Downside Case extends the disruption to the Bab el-Mandeb, adding a second chokepoint and a further layer of escalation. More short-term pain may be required to avoid longer-term damage. Such an escalation would frontload the economic impact by several months, removing an additional 2–3mbpd from the market (some barrels will continue exiting at the Suez Canal).

Both TACO and the Downside Case may ultimately require a coalition of the willing, boots on the ground and naval escorts to restore flows to perhaps 75%. Alternatively, new pipeline infrastructure could restore capacity over a 3–5 year horizon. The most likely outcome is a combination of these paths, as no single solution satisfies all parties.

What matters is timing. Even if the regime proves more fragile than it appears, that does not resolve the current disruption. The sequencing runs the other way. First, the hot phase of the conflict ends. Only then do internal dynamics begin to matter.

No one takes to the streets to be hit by “friendly fire”. From there, several outcomes are possible, including a more democratic one. But for oil markets and global trade, that sits firmly in the second order.

Barrel Counting: Houston, We Have a Problem

Given my domain in commodities, and energy in particular, I have more confidence in what this means for barrel counting. And I have nothing but bad news. The damage to the physical oil market has already been done for prices to return to pre-war levels in 2026, while the risk of significant economic downside increases by the day.

The oil market, and with it the global economy, cannot function with 10–15% less energy supply, from oil to gas to fertiliser to helium. Physical commodities must balance. We cannot consume what we do not supply on any given day.

That sounds trivial, but the implication is not. Global supply chains, in energy and beyond, were never designed to absorb a shock of this magnitude. We do not hold strategic reserves for everything, everywhere, for 3–5 months while policymakers search for solutions. Meanwhile, so-called OPEC spare capacity of 4–6mbpd is trapped within the conflict zone too.

That leaves one mechanism to restore balance: demand destruction. Prices must rise until consumption falls by 10–15%. Every country will feel this, directly or indirectly, and the adjustment is already underway.

My table above shows the scale of the disruption in a 102mbpd global liquids market, pre-war. If the Base Case extends into July, the world effectively draws down crude inventories by 30%. For context, a 1–3% change in inventories is sufficient to move prices materially.

And inventories are the least of the problem. Over the same period, petroleum products begin to run short in unexpected places. Jet fuel, diesel and naphtha shortages in Asia become ground zero of the crisis.

Japan illustrates the constraint and as mentioned above. It imports 92% of its refinery intake from the Middle East. These heavy-sour barrels are not easily replaced, and substitution materially alters product yields. Replace Arab Medium with WTI Midland and diesel output falls sharply, potentially by 30%, given refinery configurations. Crude quality matters in this crisis. I will explain why in a future episode in detail.

The situation is not much easier for South Korea, Singapore, China or Australia. Australia, in particular, has shut domestic refining capacity and now imports 90% of its 1.1mbpd product demand from regional hubs. The vulnerability is obvious.

Pro-tip: avoid Asia as a travel destination while the Strait remains functionally closed.

But this is not just an Asian problem. Europe, Africa and the Americas will feel it, if only through higher prices at the pump. The disruption transmits through supply chains. Today’s naphtha shortage in Japan becomes tomorrow’s feedstock constraint in Germany.

So when European or Asian policymakers argue that this is not “their” war, the instinct is understandable. But I am afraid the supply chain won’t care who started it. It will only reflect who pays for it.

Covid-Type Demand Destruction

The required level of demand destruction to rebalance the oil market can be measured, and it implies a prolonged and difficult global recession. Think of it this way: to remove 10–15mbpd of demand, slightly less with temporary SPR releases, we require sustained periods of US$200+ oil.

When I say oil, I mean the entire barrel, gasoline, diesel, jet fuel, naphtha, marine fuels and more. In reality, we are already there for key products. Diesel and jet fuel prices are trading well above US$200 per barrel in many regions. The invisible hand is already at work.

Demand does not adjust in a straight line, nor evenly across regions or products. Product prices determine elasticity. Destruction takes time, not only because consumers react with a lag, but because price signals transmit from products back to crude with delay.

In the scenario below, Lakshmi Sreekumar at Capital One, one of the most rigorous oil analysts in the field, models demand response to sustained price levels over a 90-day period. Her work draws on five decades of demand elasticity studies.

Once the scale and timing of demand destruction are understood, the broader economic consequences follow. This is not a marginal adjustment. It is a global shock. If realised, it would rank among the most economically stressful periods in modern history, arguably more insidious than Covid.

During Covid, central banks operated in a deflationary environment. They could supply liquidity aggressively without immediate inflation constraints, even if they ultimately overdid it on the fiscal side. This time is different.

This scenario places us squarely in a stagflationary environment in the near term, followed by a sharp recession as demand destruction restores balance. Central banks are constrained. Cutting rates into inflation is not viable, and balance sheet expansion carries credibility risks. Markets will anticipate the downturn well in advance.

Lakshmi’s framework highlights key convexity thresholds at US$150, US$200 and US$250 per barrel. At each level, different parts of the global economy begin to shut down. The burden is not evenly distributed. While oil intensity has declined in developed economies, it remains high across emerging markets, where the adjustment will be more severe.

Think of it as Covid without policy mandates. Instead of governments forcing people to stay home, the market does. Daily life simply becomes unaffordable in pockets of the global economy.

Misalignment of Incentives

In summary, this situation is too complex, with too many actors, constraints and conflicting incentives, to resolve cleanly through negotiation alone. Meanwhile, the oil system still has to balance physically and cannot wait for diplomacy and reason to play out.

The core issue is misalignment at the top. The key actor, the United States, is under political pressure to end the war quickly. That leaves the door open for a partial outcome, TACO without a full reopening of the Strait. The two are not the same. A ceasefire does not guarantee restored transits. Disruptions can persist for months, possibly years, and until bypasses are fully established.

As I am writing this, the latest development underscores the point. President Trump has agreed to suspend bombing for two weeks, conditional on Iran agreeing to the “complete, immediate and safe opening” of the Strait. This is not resolution. It is negotiation through escalation.

Deadlines, threats and tactical retreats follow the same pattern. Escalate to gain leverage, step back to test the response, then reset expectations. TACO and short-term escalation are not contradictions. They are part of the same process.

Crucially, a temporary ceasefire does not equate to a reopening of the Strait. The suspension of force is conditional, fragile and reversible. Markets trade flows, not press releases.

Nor are bilateral solutions straightforward. As outlined earlier, Saudi Arabia and the UAE will not negotiate with Iran under coercion. On the demand side, OECD countries and China have no incentive to legitimise any restriction on freedom of navigation. At least I cannot see how the EU Commission will sign a toll service arrangement with this Iranian regime. But I keep an open mind, I promise.

Some countries, including Japan, South Korea and parts of Southern Europe, may be forced to muddle through via an Oman lane. But that solution is operationally uncertain and slow to establish. Parts of EM Asia may well cut “deals” with Iran, but that will not rebalance the global market and would set a dangerous precedent few can afford.

Even regime change, often cited as a release valve, does not solve the near-term problem. It is highly unlikely to occur on a timeline that restores flows within weeks, even if it happens in 2026.

A global recession is therefore the most likely mechanism through which a durable solution emerges, whether through restored flows in Hormuz or a broader geopolitical reset. Before that, alignment among participants remains unlikely.

Closing Thoughts

This Substack will lay out the case in detail across multiple episodes, with a data-driven approach that prioritises precision over narrative comfort.

The executive summary remains free. Subsequent coverage will return behind the paywall. The next instalments will go deeper, at times technical, covering critical aspects of the oil market such as crude quality and why it matters in this context.

As an independent investor based in Switzerland, I have the freedom to call it as I see it. Oil sits firmly within my circle of competence, and I feel obliged to prepare those willing to listen for what lies ahead. And warn people of foolish statements like the below.

There seems to be a persistent narrative that losing 5–6% of global oil supply is manageable. Firstly, it will be much more. Second, it isn’t for many people around the world. It is a category error to say otherwise.

Oil is not priced on total supply. It is priced at the margin.

The world does not price oil at 100mbpd supply versus 94mbpd. It prices the last barrel that clears the market. Remove that barrel, and you are not “6% short”. You are short the barrel that sets the price.

Think of it as musical chairs. One hundred people, one hundred chairs. Everything works. Remove five chairs. The price of the remaining chairs does not rise by 5%. It goes vertical, because five people get nothing.

That is how energy markets behave. They are tight systems with very limited buffers.

This is why comparisons to prior “surplus” narratives miss the point. Yes, the market may have been heading for a 1-3mbpd surplus in 2026. That surplus no longer exists. More importantly, what matters is not the average balance, but the available flexibility at the margin and crude quality feeds around the global refinery system, among many other things.

Spare capacity is limited, geographically constrained and, in this case, trapped within the conflict zone. What looks like a 5–6% disruption on paper can represent a far larger share of the system’s usable flexibility. That is when prices move non-linearly, as already evident in distillates, with a broad move above US$200 for diesel and jet fuel globally, not just in isolated pockets.

Demand does not adjust smoothly either. It is stepwise. Airlines do not fly 70% of a route. Consumers do not partially commute. Industrial plants do not run at arbitrary utilisation rates. They run, until they stop. Listen to the fisherman in France from two days ago.

This is why prices must rise sharply to force actual demand destruction. And why that adjustment is both abrupt and economically painful. Commodity markets are not set by averages. They are set by the barrel that does not exist.

Anyway, this will become an extensive coverage because this is an unusually complex crisis. It deserves more than headlines and hot takes. I hope you all agree. Stay safe out there.

Warm regards,
Alexander Stahel

Subscribe now

Europe’s Post-Gazprom Era: Cheaper Gas, Uneven Access

The European natural gas market is structurally in a bear market. That is unequivocally good news for European consumers. Yet it remains vulnerable on a country-by-country basis for reasons we will lay out in this Substack.

In other words, the Title Transfer Facility (TTF) should remain around current levels of roughly US$11/MMBtu, or about €33/MWh, and likely below that well into 2030. But that only holds if European utilities avoid the complacency we witnessed in Q3 2025, when time spreads were mistaken for certainty, and weather forecasts were treated as guarantees rather than probabilities.

That country-level vulnerability explains the abrupt shift in speculative positioning in January 2026. Within days, the market flipped from net-short 92TWh to net-long 124TWh, as illustrated below.

Colder-than-expected January weather suddenly made Europe’s otherwise manageable storage levels look precarious for March 2026.

At the end of October, in my Substack titled “The Calm Before the Thaw: Europe’s Natural Gas Market Finds Its Balance”, I argued that an 81% storage level across Europe was sufficient to keep TTF contained, given weak Chinese and Japanese LNG demand.

That call proved directionally correct. But today I want to refine it — from a country-by-country perspective and in light of the awkward distortions now visible in parts of the European gas market.

Before we dissect those vulnerabilities, we must first revisit our gas model and examine how fundamentals have shifted since our 31 October 2025 forecast.

Fundamentals First

Back in October, we forecast a European exit storage level of 20.9% by the end of March. Based on the latest weather data as of yesterday — with November, December and January now fully incorporated and limited moving parts left for February — our model now suggests an exit level of 16.8%.

For our purposes, Europe comprises 28 geographic nations: all 27 EU members excluding Malta and Cyprus, plus the UK, Switzerland and Norway. This is the relevant demand–supply perimeter for the formation of the Dutch Title Transfer Facility hub price, better known as TTF.

Bifurcated Storage Levels

An exit level of 16.8% would mark the lowest in a decade. Ordinarily, that would justify higher prices, not the softer tone we observe today.

More importantly, 16.8% would be by far the lowest exit level in what we call the Post-Gazprom era, as the second chart illustrates. Whether the final number prints at 17%, 18% or even 21%, it will still represent a new record low for this regime. That much is already clear.

And the situation is worse than the European average suggests.

Italy, Europe’s second-largest storage holder at 18.8bcm, sits in a comfortable position at 51.8%-filled (green line). Germany (yellow line) and the Netherlands (blue line), by contrast, are materially below the European average (orange line), at 24.8% and 17.0% respectively.

In other words, Italy’s healthy position flatters the continental average. North-West Europe looks stronger on paper than it is in practice.

Germany holds the largest storage capacity in Europe at 23.3bcm. The Netherlands ranks third with 13.4bcm. What happens in these two countries alone will largely determine Europe’s supply security next winter.

TTF Doesn’t Seem to Care

And yet, TTF barely moves.

It is down 21% from its brief January spike, when prices jumped from US$9/MMBtu to US$14 on a colder-than-normal forecast and heavily short speculative positioning. Once shorts covered, the spike followed.

With February now turning milder, TTF 1M forward futures hover again around US$11/MMBtu, only marginally above its Asian sibling, the Japan–Korea Marker (JKM).

Once April 2026 closes the books on winter, TTF will likely have traded within a US$9–11 band for most of the season, January aside. That is a far cry from the volatility seen post-summer 2023, let alone during the immediate Gazprom crisis of 2022.

Timespreads Matter Most

Daily price behaviour becomes far more instructive when looking at the futures curve and time spreads.

In theory, summer contracts should trade below winter contracts. That positive spread allows utilities to buy gas cheaply in summer, inject into storage, and sell higher in winter — covering storage fees, logistics and financing costs.

For summer 2026, however, the January 2027 minus July 2026 spread offers a mere US$0.53/MMBtu. That is better than the negative spreads seen during summer 2025, but far below the US$2/MMBtu that prevailed through much of winter 2023/24 and that the market likely requires to function normally.

Is US$0.53 enough to refill storage to the cavern top this summer? Not where regulators have failed to fix the structural distortion.

Let me explain.

Outdated EU Storage Regulation

In 2023, following the Gazprom crisis, the European Commission mandated minimum storage levels. That decision was understandable in the immediate aftermath of Russia’s deliberate decision not to refill its European storage sites in 2021 ahead of the invasion of Ukraine.

At the time, I pointed out rather clearly that Gazprom’s European storage levels were collapsing. Few listened. Gazprom claimed it was not in breach of contractual obligations. The rest, as they say, is history.

The new Gas Storage Rules (2023–2027) required storage to reach 90% by 1 November. In June 2025, that target was lowered to 80%.

Such intervention was arguably justified in crisis mode. But over time, rigid monthly targets distorted price signals to the point where storing gas became uneconomic.

The regime effectively created a forced bid for summer molecules: market participants must hit a calendar target, regardless of curve economics.

The June 2025 reform acknowledged the distortion and introduced flexibility: the target could be met any time between 1 October and 1 December, with up to 10% deviation allowed under “unfavourable market conditions,” meaning negative spreads.

It did not go far enough.

During winters 2022/23 and 2023/24, Europe was bailed out by mild weather. Many convinced themselves that structural risk had vanished. Winter 2024/25 and again 2025/26 proved otherwise. In summer 2025, European storage averaged 33% depleted. By October, levels recovered only to 82%, well below the previous 90% target.

The curve explained why. Buying high in summer and selling lower in winter locked in day-one losses of roughly US$1/MMBtu — at times equivalent to €3.5–7/MWh. That is not a functioning merchant signal.

Too Little Too Late?

The June 2025 reform improved flexibility, but not incentives.

The Netherlands entered winter 2025/26 at 73%-filled on 7 November — roughly 3bcm below capacity. Germany entered at 76%, around 6bcm below capacity. That is 10bcm missing from two countries alone before winter even began.

Austria was at 85%. Hungary at 73%. Meanwhile Italy entered at 94%, France at 93%, the Czech Republic at 93% and Poland at 100%.

Same EU regulation. Different outcomes. Why? Local incentives.

Italy did not rely on the futures curve to solve the problem. It’s regulator introduced a policy-backed premium mechanism, explicitly recognising that the spread was insufficient. Estimates discussed levies around €2.19/MWh to compensate injection economics — effectively a policy-implied minimum storage premium.

France operates under a more infrastructure-like regulatory framework. CRE has publicly stated that its storage regime functioned effectively in 2024 and early 2025, though without explicitly detailing the compensation mechanics.

Germany and the Netherlands, by contrast, operate predominantly merchant storage systems. Gasunie publicly acknowledged that summer–winter spreads were too thin, making it more attractive for market participants to resell molecules rather than store them. Similar comments emerged from Germany during summer 2025.

We estimate merchant storage requires €2–3/MWh spreads to clear. One year ago, the curve did not offer that. It did not offer it through most of summer either. October storage levels in Germany and the Netherlands confirmed the result.

Yes, today’s curve (orange line) has improved. But incentives likely remain insufficient for Germany and the Netherlands to refill above 80% — levels these countries arguably require in the Post-Gazprom regime to navigate winter safely.

Two Sundays ago, when February weather forecasts turned colder for North-West Europe, our model immediately exposed the gap. Under that scenario, at least one of Germany, the Netherlands, Belgium or Slovakia would have approached critical storage depletion by March, depending on LNG arrivals.

That is absurd. Europe requires 90%+ storage entering winter. Period.

Unless German and Dutch regulators introduce an Italian-style incentive mechanism soon, expect refill levels to disappoint again by October. Either regulators compensate the curve distortion they helped create — effectively paying an insurance premium for consumers — or they scrap rigid storage targets altogether and allow the curve to clear naturally.

One way or another, the distortion must go.

LNG Glut Reflected in the Curve

The futures curve now signals roughly €10/MWh lower prices by 2029 — equivalent to about US$3.16/MMBtu. Why?

As outlined in October, the single biggest comfort factor for future European gas balances is the sheer availability of LNG export capacity coming online. None of that existed in 2022 at the height of the crisis. The picture only improves into 2027 and 2028. For TTF purposes, LNG balances are already edging into glut territory.

Three forces drive this:
(a) LNG Surplus — a classic commodity capex boom–bust cycle triggered by the Gazprom shock;
(b) The Chinese Switch — structurally lower LNG imports as pipeline volumes and domestic production rise;
(c) Lower Japanese Demand — nuclear restarts reducing LNG burn.

Let me take them in reverse order.

Japan’s Nuclear Renaissance

Japan’s new prime minister, Sanae Takaichi, has signalled accelerated nuclear restarts to combat inflation and reduce costly fuel imports.

Will she deliver?

Well, last week her coalition achieved a landslide snap-election victory, securing around 310 seats, a two-thirds supermajority. That political capital should translate into faster nuclear reactivation.

Japan currently derives roughly 8% of electricity from nuclear power. It was 33% in 2000, before Fukushima struck in 2011. If nuclear generation rises even to 15%, with a longer-term policy target of 20% by 2040, that implies roughly 100TWh of additional nuclear output.

The latest proof came last Monday when Tokyo Electric Power Co restarted Reactor No. 6, the nation’s largest unit. With 1.35GW capacity and a 90% capacity factor, it delivers roughly 10TWh per annum.

That alone displaces about 1bcm per year of gas. In fact, each 100TWh of nuclear generation theoretically reduces LNG demand by roughly 9bcm per annum, against Japan’s 65bcm import market.

We will see how quickly restarts materialise and how utilities substitute fuels. But at US$11/MMBtu and with persistent volatility, LNG — not coal — is the obvious target for displacement.

Japan’s stated objective is clear: reduce imported fuel costs in a country carrying 200% debt-to-GDP and now facing inflation after decades of deflation. Japanese LNG imports peaked in 2021. The direction of travel is lower.

The irony? These policy shifts were triggered by Putin’s decision to weaponise gas supplies to Europe in 2021 and 2022 which caused also Asian prices to spike, the key reason for Japan to restart nuclear.

Meanwhile, the 150bcm removed from Europe did not disappear; some of it is now redirected at lower prices to China. That hurts Gazprom immensely and indirectly, as you will see in a moment, also puts pressure on global LNG prices, which hurts Novatek. So much for 3D chess. Russian roulette is closer to the mark.

The Big Chinese Switch

The larger story for LNG is China.

Energy security has been a strategic priority since Xi Jinping took office. In 2014–2015, Xi championed an “energy production revolution,” explicitly pushing domestic oil and gas output to reduce geopolitical dependency.

The results are measurable. According to official data we collect locally, Chinese domestic gas production reached 261bcm in 2025, up from 136bcm in 2016. Output has doubled in less than a decade. That is structural.

Pipeline imports are the next lever — and they are cheaper than LNG.

In 2025, China imported pipeline gas from Russia, Turkmenistan and Myanmar, with technical capacity around 120bcm and actual imports likely around 82.5bcm, pending December data.

That capacity will expand materially. Commercial agreements are now in place for up to 106bcm of imports from Gazprom alone.

The Central Asia–China pipeline, anchored by Turkmenistan, carries 55bcm per annum of technical capacity. The Power of Siberia (PoS) pipeline from Russia has 61bcm of technical capacity. Myanmar contributes another 5.2bcm.

Until 2024, however, China had commercial agreements in place for only 38bcm of the 61bcm technical capacity from Gazprom’s Power of Siberia. In other words, physical pipe capacity exceeded contracted volumes. The infrastructure was ahead of the commercial reality.

That changed in 2025. China signed additional commercial agreements for what is now referred to as the Far Eastern Corridor, effectively an extension of Power of Siberia tapping the Sakhalin fields, adding another 12bcm of contracted capacity. More importantly, Beijing and Moscow appear to have agreed the commercial contours for Power of Siberia 2 (PoS2), a new 55bcm pipeline targeting a 2030 start.

If PoS2 proceeds as planned, commercially agreed Russian pipeline volumes alone rise to 106bcm per annum.

Now step back and look at the physical picture.

Add the 55bcm Central Asia corridor, 61bcm Power of Siberia, 12bcm Far Eastern Corridor and 55bcm Power of Siberia 2, plus the 5.2bcm Myanmar line, and China’s total technical pipeline import capacity could reach roughly 183bcm per annum post-2030.

Put that against apparent demand of 426bcm in 2025, which was essentially flat year-over-year. Even without heroic demand growth, pipeline gas alone could theoretically cover close to half of China’s total gas consumption within a few years. And pipeline gas, as we know, sits structurally lower in the cost stack than LNG which should alter the structural shape of the Asian LNG balance.

Either way, it is not difficult to see where this is heading.

China, recessionary as it is — and I encourage you to revisit my China series if there is any doubt — is unlikely to generate the sort of explosive apparent demand growth that underpinned LNG optimism over the past decade. Demand may grow slowly in the coming years. It may not grow at all.

Meanwhile, domestic production continues to rise at a remarkable pace and pipeline imports are expanding structurally, in many cases at double-digit rates. Both sources sit lower in the cost stack than LNG and will therefore push the more expensive molecule out of the merit order whenever possible.

Over time, that mechanism leaves LNG as the balancing supply rather than the growth driver in the Chinese market.

LNG Surplus

Finally, to the decisive factor: the wave of new LNG export capacity that is about to hit global markets.

Capacity timelines always move. The latest example comes from Qatar, where state-owned QatarEnergy has pushed the start of part of its multibillion-dollar LNG expansion towards the end of the year. That is not unusual. Mega-projects shift. But the direction is unmistakable. Qatar plans to expand from roughly 83 million tonnes today to around 145 million tonnes by 2035. That is not incremental. That is structural.

The real acceleration, however, is coming from North America. Between 2024 and 2029 alone, the region is on track to add roughly 120–140bcm per annum of new LNG export capacity. Put differently, North America is set to more than double its LNG export footprint within five years.

For perspective, 140bcm is roughly what all of Europe, as defined by our perimeter, imported in 2022 and again in 2023. Imports fell to 114bcm in 2024 before rebounding to 146bcm in 2025. In other words, North America alone is adding the equivalent of an entire European LNG consumption market within half a decade.

Unlike Qatar, much of this US supply comes with destination flexibility. That matters. Cargoes can move to whoever pays the highest netback, irrespective of geography. Portfolio players can arbitrage between Europe and Asia without contractual constraints. Qatar, by contrast, requires its counterparty to lift the cargo, limiting re-routing flexibility. It is one reason Japanese utilities have been reluctant to extend long-term Qatari contracts post-2021.

Cheniere, by far America’s largest LNG exporter with an enterprise value around US$75bn, estimated during its Q3 2025 earnings call that global LNG export capacity will increase by roughly 180 million tonnes — around 252bcm — between now and 2030, with additions peaking in 2028. Consultant forecasts embedded in that presentation show spot LNG prices around US$6/MMBtu by 2028. At those levels, liquefaction margins will compress materially, even for the lowest-cost operators.

The IEA, not an agency I treat as gospel, nevertheless estimates roughly 325bcm of new LNG export capacity between 2025 and 2030. That implies a 50% increase on today’s global capacity base of around 620bcm.

Pause on that number.

A 50% expansion in capacity within five years is not a marginal adjustment. It is the largest build-out in LNG history, based on projects that have already reached FID and are under construction. This is what commodity boom-bust capex cycles look like when high prices attract capital at scale. Textbook right here, or rather MBA book.

Who absorbs that volume? At current demand trajectories in Japan and China, certainly not Asia at the same pace as before. Europe can take part of it, but not all of it, especially in a structurally softer demand environment.

Commodities price at the margin. A surplus of even 5% is enough to tilt the market decisively. LNG is no different.

Between 2021 and 2023, LNG generated extraordinary profits, particularly for portfolio players such as Shell and Trafigura. Capital followed those returns, as it always does. Now the supply arrives. And once it does, it tends to stay.

Yes, projects can slip. Construction delays happen. New FIDs may be postponed. Some approved projects may never proceed. But the direction of travel is clear. These are multi-year infrastructure commitments underwritten by majors and long-term LNG players. They are not easily reversed.

The curve reflects this reality already. TTF trades around US$11/MMBtu today and slopes toward roughly US$7/MMBtu by mid-2030.

That is the good news for Europe’s medium-term gas balance. Now let me turn to what complicates that otherwise beautiful story.

Structural Vulnerability

We are now firmly in what I call the Post-Gazprom regime of European natural gas.

That regime forced European customers and utilities to adapt to the loss of roughly 140bcm of Russian pipeline supply. On a pre-crisis market of 450–460bcm, that represents a 30% supply shock. Few energy systems absorb such a shock in peacetime without structural consequences.

Europe rebalanced those 140–145bcm losses within roughly two years. LNG imports increased by around 50bcm relative to 2019, while consumption fell by roughly 80bcm versus the same reference year. The market adjusted. The numbers prove it.

But the defining structural change since 2017 is neither lower demand nor higher LNG imports. It is the collapse in non-storage coverage.

Let me explain.

Before the Gazprom rupture, Europe entered winter with a system that largely balanced itself in real time. Pipeline imports and domestic production together covered a substantial share of winter consumption. Storage and LNG played important roles, but they acted primarily as smoothing mechanisms.

That world no longer exists. The chart below shows what I call the Non-Storage Coverage Ratio, defined simply as pipeline imports plus domestic production divided by consumption. In the pre-2019 period, this ratio oscillated between roughly 0.6 and 1.0 during winter months.

Winter 2016/17 illustrates this clearly (red square on the left).

In plain English, Europe could largely meet winter demand by adjusting between modest incremental LNG imports and storage withdrawals. Utilities had optionality. They could optimise based on price and availability.

Storage was used heavily — as designed — but it functioned as insurance rather than survival. Pipeline gas and domestic production provided ample daily flow during peak winter consumption and, crucially, excess capacity in summer to refill storage comfortably. In summer 2016, the Non-Storage Coverage Ratio peaked at 1.97 on 7 August. That was a system with headroom.

Post-Gazprom, the ratio has shifted structurally lower.

Winter coverage now frequently falls toward 0.35 and no longer approaches 1.0 between December and February, when Europe is coldest. In practical terms, that means half or more of winter consumption must now be met by a combination of storage withdrawals and LNG imports.

Both must function. If either fails, the system tightens abruptly by February or March. That is what I mean by a straightjacket.

Visually, compare the right-hand winter square during 2024/25 with the left-hand square from 2016/17. The difference is not marginal. Even during summer months, the ratio now struggles to exceed 1.5. That is the new operating regime.

This shift is mechanical, not cyclical. It reflects the loss of roughly 140bcm of Russian pipeline gas combined with steadily declining domestic production in the Netherlands and the UK. Nothing has replaced that continuous flow-through supply. Nor do many policymakers appear to appreciate how materially that matters for industrial security in Europe.

LNG Is Not (Yet) a Full Substitute for Pipeline Gas

This distinction is often glossed over.

Pipeline gas and LNG are not interchangeable inputs within the European system. Pipeline gas is continuous, predictable and largely insulated from short-term global price swings. Its infrastructure was purpose-built over decades to match Europe’s consumption patterns and industrial geography.

LNG, by contrast, is episodic, price-clearing and globally contested. Its infrastructure — particularly in North-West Europe, Poland and the Baltic States — remains largely improvised, built at crisis speed rather than as part of a long-term design. That difference matters.

It is precisely for that reason that I exclude LNG from the non-storage coverage metric.

The second chart makes the point clearly. Europe’s LNG sensitivity — defined as LNG imports divided by consumption — has surged since 2021. What was once a marginal balancing component has become a dominant swing factor, frequently exceeding 70% during summer months.

Europe now depends on LNG not merely as a supplement, but as the primary mechanism to refill its storage.

Pre-2019, winter reliance on LNG was minimal. During winter 2017, LNG sensitivity was as low as 4%. In other words, only 4% of winter consumption depended on LNG. That is negligible.

Moreover, much of that LNG flowed into Iberia due to geographic isolation and limited pipeline interconnection with the rest of Europe. Spanish and Portuguese households certainly require gas, but their winter heating needs are structurally lower than in North-West and Central Europe. A cold winter in Poland or Lithuania is not remotely comparable.

Europe now operates under a dual winter dependency:

• structurally higher reliance on storage withdrawals, and

• structurally higher exposure to global LNG availability and pricing.

Storage is no longer merely a buffer. It has become the load-bearing pillar of the system.

The Post-Gazprom Reality

This is the core vulnerability of Europe’s gas market in the post-Gazprom era.

Mild winters are manageable. Recent seasons have shown that. But the margin for error has narrowed significantly compared with a decade ago. Cold weather does not need to be extreme to matter. It merely needs to coincide with tighter LNG balances elsewhere.

Europe effectively traded pipeline security for LNG optionality and storage dependence after the Kremlin chose to weaponise gas flows. That trade works in a world of LNG oversupply and subdued Asian demand — the environment we are entering. It becomes fragile the moment either assumption is challenged.

Curtailed - Not Reduced - Consumption

Natural gas in Europe is primarily used for heating — both households and industrial sites — and for power generation. It is therefore highly seasonal.

During winter months, more than 60% of total consumption derives from households. In summer, that share collapses toward zero. More importantly, peak winter consumption can exceed real-time supply by up to 100%, which is precisely why storage exists. Europe must withdraw gas in winter to balance the system.

A smaller but still important share of gas is used as industrial feedstock, for example in ammonia fertiliser production via the Haber–Bosch process. That component can be measured with reasonable precision, although reporting across all 28 countries is not entirely consistent.

Have Households Reduced Consumption post Gazprom?

This brings us to the first behavioural question.

Have European households permanently reduced gas consumption following the loss of Russian supply, as frequently claimed by policymakers? Have green policies in North-West Europe structurally altered private heating behaviour?

The short answer is: not meaningfully.

Household gas consumption is overwhelmingly driven by temperature. When temperatures fall, consumption rises — and it rises non-linearly. That relationship remains robust across virtually all European countries, with the partial exception of Scandinavia, where electricity plays a larger role in heating.

Consumption appeared subdued between winters 2022/23 and 2024/25. But those were mild winters, as the below charts illustrate for the examples of Germany and Poland. This season, however, marked a return to normal winter conditions in North-West Europe and below-normal cold in parts of Eastern Europe (see Poland below). That makes it the appropriate moment to test whether structural behavioural change has occurred.

Running the analysis across all 28 countries, only Germany shows signs of a potential shift. German household consumption appears to plateau once temperatures fall below roughly 2.5°C. January 2026 provides the first meaningful data point supporting that observation. It is too early to call this permanent, but the pattern is noticeable.

For all other countries, however, no structural change is visible.

Below we illustrate the correlation between monthly temperature and gas consumption since January 2019 for a representative group: Germany, the United Kingdom, France, the Netherlands, Belgium, Italy, Spain, Poland, the Czech Republic, Hungary, Romania and Lithuania. January 2026 consumption is highlighted in red, representing the first genuinely cold winter month in the Post-Gazprom era.

These countries account for roughly 88% of European household gas consumption. There is no cherry-picking here.

The conclusion is straightforward. With the possible exception of Germany — and perhaps marginally the Netherlands — household consumption patterns remain temperature-driven. The loss of roughly 140bcm per annum of Gazprom pipeline gas has not materially altered heating behaviour.

Poland and Lithuania illustrate this most clearly. Colder temperatures translate into sharply higher gas consumption. The relationship remains intact.

A Note on Russian Gas Flows

Hungary and Slovakia continue to receive Russian pipeline gas via TurkStream. That must not be confused with Blue Stream or the Trans Adriatic Pipeline. In addition, Russian LNG cargoes still arrive in Spain and France. Russian gas imports remain unsanctioned in the EU, unlike oil and coal.

Serbia, though outside our perimeter and not part of TTF price formation, has recently sought to diversify away from Gazprom after failing to secure a new long-term contract last November. That development is politically notable, though not directly relevant for European hub pricing.

Back to natural gas.

Natural Gas Demand for Power Generation

Where we do observe meaningful change is in power generation.

Utilities have reduced natural gas burn for electricity, but primarily during summer months, when wind and solar displace gas-fired turbines in the merit order.

That is the key distinction. The displacement is seasonal.

As the chart below for the 22 largest European markets illustrates, during Dunkelflauten — periods of low wind and solar output — Europe consumes more natural gas for power generation, not less. Dispatchable power must come from somewhere. Gas turbines remain the marginal stabiliser of the grid.

This dynamic is particularly visible in Germany, where nuclear output has fallen to zero. But it also applies to the United Kingdom, the Netherlands, Italy, Spain — where solar capacity has expanded rapidly — Belgium and even France.

As I have argued repeatedly, Europe requires dispatchable power to keep the lights on. Gas provides that flexibility. Wind and solar do not.

Natural Gas Demand for Industrial Use

Industrial consumption tells a different story.

Gas use to heat factories and plants appears to have declined permanently, at least for now. Whether this reflects genuine efficiency gains, structural behavioural change or simply lower utilisation and outright closures is difficult to disentangle.

European industry — from chemicals to automotive manufacturing — was already struggling before the full impact of the Gazprom rupture in summer 2022. Since then, the sector has not meaningfully recovered.

The numbers reflect that reality.

Uneven Adjustment

In summary, the roughly 70bcm reduction in European gas consumption — from about 450bcm per annum in the Gazprom era to roughly 380bcm in the Post-Gazprom regime — has been highly uneven.

Household consumption for heating has barely changed, with the notable exception of Germany during extreme cold episodes. That may reflect structural adjustments in Germany’s long-term contracts, which include substantial retail and public-sector demand — schools, municipal buildings and mixed-use properties — potentially driving some peak suppression.

Several countries — notably the UK, Spain, Italy, the Netherlands and Belgium — have reduced gas burn in power generation during summer by expanding wind and solar capacity.

Germany, Poland and Ireland, however, have increased gas-fired generation. In Germany’s case, the reason is straightforward: the removal of nuclear capacity has reduced dispatchable supply. The remaining countries show little structural change in power-sector gas demand.

All countries have reduced industrial gas use. The open question is at what economic cost. I do not yet have a definitive answer. I am not entirely sure I will like it when I do.

Flows Required Eastward

The Post-Gazprom regime has not only reduced volumes. It has reversed direction.

Before 2022, gas molecules entered Europe from multiple directions, with a substantial share flowing east to west.

Russian gas via Nord Stream entered Germany, feeding local consumption and transiting onward into the Czech Republic and France. The Yamal pipeline via Belarus supplied Poland and Germany. The Brotherhood pipeline — yes, that was its name — transited Ukraine into Slovakia and Hungary, serving local markets and moving further west through Austria into Italy. Finally, TurkStream delivered Russian gas into Greece, Bulgaria and Serbia, as well as parts of the Balkans.

With the exception of TurkStream, these corridors have effectively ceased to function.

The system has had to reconfigure itself accordingly. Pipeline flows that once ran east to west now need to run west to east.

Norway, producing roughly 100bcm per annum and by far Europe’s largest remaining domestic supplier, now sends gas primarily into Germany, the Netherlands, Belgium and France. From there, molecules must transit further east — into Austria, the Czech Republic and Slovakia — to replace lost Russian volumes. Additional Norwegian gas now flows through Denmark via the Baltic Pipe into Poland.

This is not a minor adjustment in routing. It is a structural reversal of flow patterns that were built over decades.

Unsurprisingly, such reconfiguration has generated friction. ACER, the European regulator, measures this in congestion revenues. These peaked at more than €3.7bn in 2022 before declining to around €140m more recently. That reduction is encouraging.

But falling congestion revenues do not mean the system is fully adapted. Infrastructure built over 70 years does not reconfigure itself seamlessly within three.

Vulnerabilities remain.

One area where this is most visible is LNG import capacity in Germany, Poland and the Baltic states. The easiest way to illustrate this is to revisit the Coverage Ratio — this time applied to German balances.

Germany was the country most exposed to the Kremlin’s attempt to weaponise gas supplies. That vulnerability was amplified by policy choices stretching back years.

Angela Merkel’s doctrine of Wandel durch Handel — change through trade — sought to integrate Russia into the liberal economic order. In practice, it increased dependence on a single supplier. When the rupture came in 2022, the “Wandel” indeed arrived, though not in the intended sense.

I state this without irony. Germany’s resilience matters enormously for Europe. But shutting down roughly 150TWh of nuclear dispatchable capacity while deepening reliance on Russian gas was a profound strategic error. There is no softer way to phrase it.

Back to natural gas.

The German Causa

The German balance sheet illustrates the structural shift more clearly than any other country. We run these balances for all 28 countries, but Germany is the extreme case.

Germany is the central hub of the continental gas system. Without it, landlocked countries such as Austria, the Czech Republic, Slovakia and, to a degree, even Switzerland would struggle to secure sufficient supply.

In 2020, Germany received roughly 80bcm of Russian gas via Nord Stream and Yamal. Within two years, those flows vanished.

Germany responded by reducing baseline consumption from roughly 90bcm to 70bcm by 2025, a 22% contraction. That alone is extraordinary.

After that demand adjustment, around 60bcm still needed to be rebalanced.

By 2025, Norwegian inflows had increased from roughly 30bcm to 60bcm. Of that, about 40bcm arrived directly via pipelines landing at Emden and Dornum, which together have 54bcm technical capacity. A further 20bcm was effectively redirected via transit flows through the Netherlands and Belgium.

Around 10bcm came from newly built LNG terminals.

The remaining gap was closed by reducing export deliveries to France, Italy — transited via Switzerland — and the Czech Republic, including onward transit to Slovakia and Hungary.

But the system has not simply rebalanced internally. Germany now supplies more gas eastward to Austria and modest volumes to Poland, instead of receiving large east-to-west flows from Russia via Poland. It no longer supplies certain Belgian pockets either.

The question, then, is not whether Germany survived the rupture. It did. The question is at what cost — and with what structural fragility. A 22% forced reduction in consumption is rarely benign. Germany’s industrial slowdown did not occur in a vacuum.

The Coverage Problem

The deeper issue lies in Germany’s summer refill capacity.

Before 2022, Germany’s Coverage Ratio — pipeline imports plus domestic production divided by consumption — hovered around 1.0x in summer. In other words, baseline supply was broadly sufficient to cover demand and allow net injections into storage.

Today, that ratio is closer to 0.8x. Had consumption remained at 90bcm, it would be nearer 0.7x.

That difference matters.

Lower structural coverage means reduced net injection capacity during summer, even after adding roughly 10bcm of LNG imports.

In practical terms, Germany must now work harder to refill storage than it did pre-2022.

The State of German LNG

Germany likely requires at least 20bcm of LNG imports per annum to replenish deeply depleted storage. Thirty would provide far greater security, not only for Germany but also for its landlocked neighbours. Can it deliver?

Well, German LNG import capacity remains a moving target.

There are currently five terminals in various states of operation or development. Lubmin — located at the former Nord Stream landfall and therefore ideally positioned within the pipeline grid — was effectively abandoned after a short operational period and consolidated at Mukran under Deutsche Regas.

Mukran, the biggest terminal on paper, has a technically “approved” capacity of 13.5bcm per annum. However, it operated at only 17.6% utilisation in 2025. That is well below what was politically promised. Why?

The Mukran LNG import terminal originally planned two floating storage and regasification units (FSRUs) to achieve its approved annual capacity of about 13.5bcm as outlined above. But only one vessel (Neptune) with a capacity of 5bcm per annum is currently in operation, which operator Deutsche ReGas isn’t keen to explain explicitly on its Website.

A second FSRU, the Energos Power (174,000 m³), was previously deployed but its charter contract was terminated in early 2025. Deutsche ReGas ended the Energos Power FSRU agreement with the German Federal Ministry for Economic Affairs and Climate Protection, citing pricing distortions and competitive disadvantages introduced by state-backed LNG terminals, which were offering capacities at below cost-covering fees approved by the regulator.

Stade, the state-backed 6bcm FSRU project, remains delayed and is unlikely to enter operation before Q2 2026. Wilhelmshaven and Brunsbüttel are functioning but require materially higher utilisation to provide meaningful refill support.

Based on current trajectories, Germany may import no more than roughly 14.8bcm of LNG in 2026. That is for the full year. For the summer period between 1 April to 31 October, the number is likely 8.2bcm, according to our calculations. Is that sufficient to refill 23bcm of storage capacity by October?

Unlikely and as the table below illustrates. More concretely, we assume Germany can inject 15bcm into its storages during the summer months. Were it to exit the winter at our assumed 3.2bcm at the end of March, that brings it to 18.2bcm by the end of October - 78.5%-filled.

In the Post-Gazprom regime, Germany achieved strong net injections only in 2023, when storage stood at 70.5% as of 31 March. In both 2024 and 2025, net injection performance was weaker.

Our current forecast suggests German storage could fall to roughly 13.7% by 31 March. Refilling from that base to 90% is materially more demanding than in prior years. Those are simply the numbers.

Given those numbers, the German regulator would be wise to ensure that inadequate time spreads do not become the binding constraint on refill economics.

The Technical Question

To be clear, we are not arguing that Germany cannot technically refill storage to 23bcm by end-October.

We have stress-tested this question from a capacity and congestion perspective and conclude that Germany, in theory, should be able to inject enough gas between 1 April and 31 October to refill its storages.

However, technically possible does not equal commercially realised or practically feasible, and as illustrated for the Murkan regas terminal capacity of only 5bcm, not the approved 13.5bcm per annum.

What is required is sufficient upstream flows, adequate LNG utilisation, and functional west-to-east transit throughout the system, not “approved capacities”. When measured this way, we get to 15bcm of net-injection forecast between 1 April and 31 October 2026. And Germany does not have it where we sit.

Please note that the above table assumes 8.2bcm of LNG imports during April to October at German regasification terminals. For the same period in 2025, they imported 6.3bcm. We thus assume 30% year-over-year growth. That may prove to be too optimistic still.

Furthermore, we assume seamless imports from Norway, which is not a given either if any of the big fields like the Troll field has to undertake unplanned maintenance work. We also assume 2.6bcm pipeline imports from France, which has not been the case in 2025 and will require the latter to import more LNG on behave of Germany, the logic of which we cannot judge commercially.

Which brings us to the real question. Can Europe refill storage in every corner of the continent by October 2026 and enter winter 2026/27 prepared for a below-normal cold season? That is the only question that matters.

The European Natural Gas Puzzle

The proper way to analyse the European summer balance is to begin with what we know with reasonable certainty, then progressively fill in the gaps from the known to the uncertain at country level until the full picture emerges.

The highest “known known” is Norwegian supply. Between now and 31 October, we expect roughly 72bcm of Norwegian gas to enter the European system. We know the technical pipeline capacities and we broadly understand the distribution pattern among clients: Germany typically receives 35–39% per month, the UK 13–24%, Belgium 3–15%, France 12–15%, Poland via Denmark 6–9% and the Netherlands 4–10%. Monthly nominations fluctuate, but this provides a solid starting grid.

Our model forecasts country-level consumption for households, power and industry with reasonable precision. That determines which countries without storage must receive flows from countries with storage. Germany, for example, must supply roughly 1bcm to Switzerland between February and April under our base case. Similar balancing flows occur throughout the system.

We also know regasification capacities, North African pipeline inflows, Azeri volumes and domestic production profiles.

From there, the puzzle can be assembled.

Spain and Portugal are effectively self-contained systems. LNG is the balancing item, storage less so. Greece operates similarly. Italy is comparatively easy to ring-fence given stable North African and Azeri pipeline inflows combined with ample LNG capacity. Romania remains largely self-sufficient due to domestic production.

The UK is near self-sufficient thanks to domestic output, steady Norwegian inflows and significant LNG capacity of up to 3.1bcm per month. It uses minimal seasonal storage. The Nordics are small in gas terms. The Baltics are systemically minor.

Once these higher-certainty components are locked in, we can iterate country-by-country flows and derive the LNG volumes required to maximise storage levels by 31 October across the major hubs.

The result is sobering.

Under current assumptions, four of the seven biggest EU storage-capacity countries remain materially below the 80% October target: Germany, the Netherlands, Austria and the Czech Republic.

Yes, Belgium and the UK show similar profiles, but their storage volumes are too small to function as true seasonal buffers. They operate more like short-term balancing tanks, as we have them at regas terminals. Systemically, however, they are secondary for natural gas supply-security during winters.

Importantly, our projections assume elevated — though manageable — LNG imports throughout summer. France and Belgium, in particular, would need to operate near regas capacity for prolonged periods. That has not yet been tested in a sustained, routine fashion.

Beyond Germany’s vulnerability, allow me some more observations.

Take the Netherlands.

Why accept a structural gamble on weather and LNG terminal availability? Why shut down Groningen entirely rather than maintain limited production as strategic insurance? Why reduce nuclear output rather than reduce gas-fired generation if decarbonisation is the objective?

Dutch policy appears internally inconsistent. It is a bet on wind, a bet on LNG availability and a bet on mild winters — all in a highly industrialised economy that depends on energy reliability. Energy security is not a domain for optimism bias.

The UK illustrates a different version of fragility.

It is Europe’s third-largest gas consumer at roughly 55.4bcm in 2025, behind only Germany and Italy. Households rely heavily on gas for heating and cooking. The power grid relies heavily on gas when offshore wind output falls — which it does regularly.

Domestic production has fallen from 36.2bcm to 29bcm in 2025 and may drop below 26bcm in 2026. The Energy Profits Levy, introduced post-Gazprom, has materially dampened new upstream investment. Production decline was already structural. The levy accelerated it.

Meanwhile, the UK possesses just 0.9bcm of storage. For a 56bcm market, that is symbolic. A one-week unplanned outage at Norway’s Troll field during winter would be enough to create acute stress. The margin for error is thin, while the Continent does not seem capable anymore to help under any circumstances.

Under our forecast, the UK must import roughly 2.9bcm of LNG in February alone to remain balanced. That is dependency instead of redundancy.

France presents a different problem.

It entered winter at roughly 90%-filled storage, then drew down during a relatively mild November instead of maximising LNG imports and preserving storage optionality. That choice now forces elevated LNG requirements later in the season.

Our projections require roughly 1.8bcm of LNG in February and around 3.0bcm and 2.9bcm in March and April, respectively. The 2022 crisis peak monthly import was 3.6bcm. France must operate close to that level again, while avoiding unnecessary exports to Spain. This could have been mitigated with more conservative refill behaviour.

It also, in our assumption, must import about 0.4bcm more LNG monthly to export gas to Germany. A novum the commercial feasibility of which we cannot judge.

France looks as if it either requires greater LNG regas capacity, larger storage buffers, or a more disciplined injection strategy. The current configuration leaves limited room for error in a below-normal January or February.

System Fragility

The broader conclusion is uncomfortable.

The European system now operates with thinner margins than a decade ago. A combination of events — an unplanned outage at a major Norwegian field, temporary LNG terminal disruption in the UK, France, Belgium or the Netherlands, or a sustained below-normal cold spell — would place the system under acute strain by March.

Under such circumstances, curtailments would likely occur at industrial level first. For now, the February outlook suggests moderate conditions in North-West Europe. The weather remains cooperative.

But reliance on cooperative weather is not a strategy. The real question is whether Europe is comfortable running a structurally tighter system indefinitely — and whether the next winter will be equally forgiving.

Executive Summary

That, ladies and gentlemen, is the current state of the European natural gas market.

Europe will have access to ample and increasingly cheap LNG on the global spot market. The glut is real. But especially in North-West Europe — the Netherlands, Belgium and Germany — as well as in Poland and Greece, usable import capacity must increase materially if these countries are to benefit fully from it.

Approved capacity is not the same as operational capacity. Technical nameplate is not the same as actual throughput.

Insufficient Coverage Ratios — local production plus pipeline flows relative to consumption — combined with limited usable LNG capacity mean that not every country will automatically refill storage by October at attractive prices. Not until storage rules are rationalised and supply-side bottlenecks, both in gas and electricity, are addressed.

The overarching issue is not the absence of Russian pipeline gas. That source was always geopolitically unreliable. The real issue is poorly conceived top-down policy that reduced domestic production without delivering credible replacement capacity in the name of energy security or affordability.

European households still consume roughly as much gas as they did before the Gazprom rupture. Industrial demand, however, has fallen — partly by design, partly because parts of European industry were priced out of global competition. The de-industrialisation debate is no longer theoretical.

European policymakers would do well to acknowledge these realities and recalibrate. Lower utility bills require supply expansion across all energy forms, with the market determining the efficient mix. Artificial scarcity is not climate policy. It is cost inflation.

From where I sit, the unilateral pursuit of aggressive fossil fuel exit targets under the Green Deal is neither affordable nor strategically coherent in the current geopolitical environment — especially as Europe is simultaneously expected to increase defence spending and maintain extensive social commitments.

Europe cannot re-arm, decarbonise at maximum speed and preserve its existing welfare architecture without trade-offs. Something will give.

The global economy has shifted. What David Baverez calls the transition from a peace economy to a war economy is not rhetorical flourish. The former was built on demand growth, cost optimisation and global cooperation. The latter is shaped by supply constraints, geopolitical leverage and strategic autonomy.

Energy sits at the centre of that transition. For investors, this shift has consequences, not least for commodity producers and real asset exposure, which we analyse regularly on this Substack.

Bringing it back to gas.

In the Post-Gazprom regime, Europe must enter winter with storage levels comfortably above 90% to avoid renewed March stress. Frankly, 95% would provide a far healthier buffer given the structurally lower Coverage Ratio.

That objective would likely be achieved more efficiently by allowing timespreads to function properly rather than through rigid storage mandates.

Beyond that, Europe should consider establishing a true strategic gas reserve of roughly 37–40bcm — around 10% of annual consumption — analogous to the US Strategic Petroleum Reserve. Such a buffer could be drawn during system stress and replenished when conditions normalise.

That may be the most rational lesson from this winter.

Warm regards,
Alexander Stahel


PS: Press the heart if this analysis added value.
PPS: And tell me if you’ve seen a better deep dive on European natural gas. I’ll wait.

The Cannibal’s Dilemma

Let us approach mining using First Principles.

Mining is an extractive industry that consumes itself year-by-year. To wit: every tonne of ore mined is one less tonne in the ground. Every ounce poured shrinks the reserve base. Whether the commodity is gold, silver, copper, nickel, iron ore or oil, the principle is the same. Production is depletion and depletion is destiny, unless the company doing the extracting can continuously replace what it extracts.

In practice, however, most miners are chronically bad in the replacing game. Not just in absolute terms, but in the only terms that matter to shareholders: per share.

That is why I keep coming back to Reserves per Share (as first presented here), in the table below measured as ounces of reserves per 1,000 shares. It collapses all the usual excuses into a single number: geology, M&A discipline, capital allocation, and dilution.

Solving for Reserves per Share yields a brutal insight: as a group, senior gold miners went from 97.03oz per 1,000 shares in 2010 to 38.26oz per 1,000 shares in 2024. That’s a long-term, structural transfer of value away from existing owners.

Put differently, mining is an awkward place to hunt for moats.

Most industries are structured in such a way that an exceptional entrepreneur can build a business where time becomes an ally. They leverage their unique strengths to establish a strategic advantage, which can manifest in novel ways.

Consumer brands, like Coca-Cola or WD-40, embed habit and distribution. Buffett calls this “share of mind”. Luxury houses, like Hermès, embed scarcity and pricing power. Media and software platforms, like Alphabet, grow revenues while marginal costs remain stable, which is the Network Effect in action.

Great financial franchises, like Berkshire Hathaway or Svenska Handelsbanken, compound because they reinvest into systems, relationships, and underwriting cultures that scale. In Berkshire’s case, the growing insurance float became the cheap capital Buffett could redeploy at attractive returns.

Even in industrials, the best operators build moats through installed infrastructures, service revenues, technical know-how, and procurement scale. Think Siemens Energy and its gas turbine business.

Buffett has a clean way of putting it: the best businesses make time their friend. Bruce Greenwald explains the machinery behind this beautifully in Competition Demystified. The essential point is: When a moat exists, compounding becomes natural because the business gets stronger as it grows.

In mining, that kind of compounding is rare.

True, miners can enjoy a supply-side advantage; they own a specific resource. Yet, that advantage comes with a string of sunset clauses, e.g. reserves are finite, licences have durations. The tough truth is that even the best ore body is a wasting asset in a legal wrapper. This is why land optionality matters so much; it is the closest thing the mining sector has to extending the time horizon of a good asset. And it’s why many “high quality” miners still struggle to become true long-duration compounders.

Worse, resource companies are price takers, i.e. they do not set the price of gold, copper, or oil. (Pro tip: When someone in a Patagonia vest utters the comfortable (but false) macro line that ‘commodities protect you from inflation’, it’s best to ask which part of the chain has pricing power. The cleanest inflation hedge is a company with durable pricing power, not “real assets” in the abstract. Commodity producers often have the opposite. Input costs can rise while realised prices fall. Commodity cycles do not care about macro theses. Remember that please when you read the next stupid line like it.

Worse still is above-ground risk, that inchoate discomfort that masquerades as political interference, windfall taxes, permitting delays, social licence, or good old corruption. That’s when you build the perfect mine with one set of rules and then watch it all slip away as the rules change because of reasons. Investors learned that that hard way, in Panama, with First Quantum’s Cobre Mine in September 2023. They were reminded again across West Africa, including Burkina Faso’s more assertive stance in 2025.

And Western jurisdictions are not immune. The UK’s 2022 windfall tax episode in oil and gas was a blunt reminder that “rule of law” does not mean “rule stability”. In the United States, the slow-motion theatre of permitting and NIMBY politics (Not In My Back Yard) has become its own form of de facto expropriation. No wonder generalist investors keep their distance.

So, if lasting moats are scarce in mining, then where are they and when do they manifest?

Spoiler Alter: Usually not from geology alone, even when the geology is spectacular. Lundin Gold’s Fruta del Norte is as close to what consider a geological unicorn. K92 has extremely rare growth qualities. Island Gold is a very special asset with grades steadily increasing as the mine goes deeper. Yet, the depletion clock still ticks percussive effect on all of them, and above-ground risk still applies in each case, particularly in Ecuador and Papua New Guinea.

However, when a mining company builds something approaching a moat, it comes from the firm’s winning culture, operational excellence, disciplined capital allocation — all of which repeated over decades. You see it in all of the best operators, without exception. That’s why I have previously emphasised what culture does for names like Alamos Gold, Agnico Eagle, and historically for Endeavour Mining.

Which brings us to G Mining Ventures (GMV).

Read more

Let me give you a quick take on the events unfolding in Venezuela. Given oil is part of my circle of competence, as most of you know well, I will keep this short, sharp, and open (no paywall) for all to read. If you enjoy my take, please re-post it.

Dictator Nicolás Maduro, the bus-driver-turned-dictator, is responsible for the deaths of tens of thousands, the exile of 8 million, and the oppression of 34 million people. All of that was primarily enabled by oil riches, corruption, and the “warmth of collectivism”. Yes, the resource curse is real and alive.

Today, the U.S. administration announced his capture in a special military operation. Maduro and his wife were reportedly flown out of Caracas and are now in U.S. custody at an undisclosed location, with the stated intent to prosecute him in New York on narco-terrorism and drug-trafficking charges. AP News+1

So what is next? We do not know. But if Trump decides to reclaim expropriated U.S. oil assets in Venezuela, perhaps even to govern the country temporarily until institutions are re-established, I am all for it. You should be too, if you dare to think it through to the end.

Not only have Venezuelan elites proven incapable of overcoming the resource curse for decades, such a policy would be a blessing for humanity and for freedom. How so? Well, Venezuela is not just another marginal OPEC producer and as one may assume when studying my below OPEC output table over time.

Rather, Venezuela possesses the largest oil reserves globally, with the same conventional qualities as Saudi Arabia does. In other words, it has the potential to influence global oil prices much in the same way as Saudi Arabia does. And as a general rule of thumb, lower oil prices (which is what Trump wants) are a blessing for peace and prosperity.

Before drilling further into geology and barrels, let’s be honest about first principles. In my humble opinion, and I am Swiss, not an American voter, Trump is right when he says U.S. oil assets should be returned to their rightful American ownership. That is clearly his viewpoint. So yes, this intervention is also about oil, not just drugs, and that is exactly where I stand.

As a resource investor, I am sick and tired of watching Western assets get seized by dictators and regimes around the world without just compensation, while Western leaders either look away or hide behind process and polite statements. Let’s not reward corrupt leaders, not now and not ever. Let’s enforce the rule of law wherever Western companies are affected. And even if you disagree with me here (which is totally fine), consider it a blessing as a resource investor as Trump may just have lowered global above-ground risks in emerging markets for all commodities, at least for a while.

Anyway, Venezuela holds the largest oil reserves in the world, much of which once belonged to Western companies who discovered these reserves and developed some of them, thereby paying their just taxes to the country who hosted them.

The Orinoco Belt alone represents the largest oil accumulation on the planet, with an estimated mean of roughly 513 billion barrels of technically recoverable heavy oil. As for reserves, meaning the portion that is economically proven to be recoverable, Venezuela sits on roughly 20% of all known reserves globally, while its oil output on a total market of roughly 85 million barrels per day (not mix it with total liquids output of some 103 million barrels per day) is about 1%. That’s what socialism and corruption do, lades and gentlemen. Under Maduro, people literally died on the street from hunger, for years. Keep that in mind when the next person pitches us the “warmth of collectivism”.

Note: keep in mind that OPEC oil reserves have an incentive to be overstated as it dicates their production quote which is why, for example, every serious geologist will tell you that, as one example, Kuwait’s heavy oil reserves are overstated. But that is unlikely the case for Venezuela’s heavy oil resource, if you study the USGS report carefully. And even if medicore viscosity halves the ultimate recovery in the Orinoco belt, other resource will mostly likely be found elsewhere, including offshore Venezuela (think Guyana). So the pize is big one way or another and allows for substantial production growth over time.

If the American oil industry and the global oil services industry are allowed to lift that prize, Venezuela will outproduce Saudi Arabia in the next decade. Mark it. I told you now. These fields are so conventional, so prolific, that once the sophistication of today’s oil industry gets unleashed on these reserves, the upside cannot be overstated. American entrepreneurship managed to squeeze 9.8 million barrels per day out of tight hard rock called shale. This is like a swimming pool the size of Texas full of oil to be lifted, piped, and transported. The last frontier of oil riches.

Oil production growth would be a blessing for Venezuela across the board: huge tax income, highly paid jobs, and a surge of associated services, from oil services to construction, from leisure and hotels to restaurants, the whole ecosystem. Think Texas, but much bigger. The left will spin it as colonialism. But as Texas and Norway illustrate, it is called capitalism, and it works with institutions, but never with corrupt elites in emerging markets without functioning institutions. Fact. Quote me, anytime, anywhere.

Under the right conditions, Venezuela’s oil output can scale fast, and even “smaller” growth numbers matter in a commodity market where prices are set at the margin.

Start at roughly 900kbpd today. Fix property rights and the rules of the game, and 1.5mbpd within 18 months is a realistic first milestone. That would be led by the majors with the most knowledge, the deepest balance sheets, and the biggest unresolved claims, Chevron, ConocoPhillips, Exxon, and potentially Shell and ENI. All burned in the past. All sitting on substantial open invoices they will want to recover. ConocoPhillips alone reportedly has an incentive to collect more than US$10bn it is still owed. But let’s be clear, ex Chevron, it is highly unlikely the majors will lean in until there is political stability, clarity on who actually runs the country, and a rock-solid legal framework that cannot be reversed on a whim.

Clear the bottlenecks in pipelines, power, upgrading, and ports, and getting back to 3.5mbpd becomes achievable. Here is where big numbers can be deceptive. Assume it takes US$60bn to get pipes, power, and export infrastructure back into proper shape. That sounds huge until you remember that in 2010, the U.S. shale industry collectively spent more than that on wells alone. Capital exists. Capacity exists. What determines speed is the legal framework. Without it, nothing much changes.

And if the rules get rewritten after Trump, or if Venezuela simply morphs from one corrupt mess into the next, then output gets stuck in the 1.5–3.0mbpd range, at best. That is the downside case. But if the rule of law actually holds, an upside case of 10mbpd over the next decade is not fantasy. It is simply what happens when world-class resources are finally developed by a world-class industry.

And here is the key point: it does not need the upside case to structurally lower prices at the pump, globally. If Venezuela simply becomes a consistent 5mbpd producer, think Canada today, and can hold that level for decades, it would at the very least offset future losses from the U.S. shale industry as its fields mature and decline. In a market where the marginal barrel sets the price, that is enormous.

In fact, you do not even need to wait for 5mbpd. The mere trajectory, Venezuela moving from 0.9mbpd to 1.5mbpd next year, is enough to hurt Brent, because the market is already swimming in supply for 2026 and 2027. Yes, physical commodities price in the present and do not discount the future. But in oil, where paper barrels trade in multiples of the physical market, expectations move prices long before the barrels arrive. Trump’s explicit, determined language can set up paper shorts and push the curve lower well ahead of any meaningful Venezuelan supply hitting the water. Think Q4 2018, when he effectively helped drive Brent from US$90 to US$55 on next to nothing other than an Iran waiver and a change in tone.

Either way, lower-for-longer oil prices would be a blessing for humanity.

Again, and given many of you will find it hard to see how Venezuela could grow its oil output meaningfully and once property rights and the rule of law are re-established, let me offer another perspective.

America pulled off something that, at the time, looked equally absurd. U.S. shale oil output grew from 1.8mbpd in 2010 to 9.8mbpd by the end of 2025. In other words, American entrepreneurship built an entire Saudi Arabia’s worth of oil production out of rock. If you include Alaska and the Gulf of Mexico, the U.S. now produces roughly 13.8mbpd in total, which is a different universe from what most people thought was possible 15 years ago.

So what? Here is the point: shale is brutally hard compared with conventional onshore oil. It is not sitting in a friendly underground “tank” of limestone or sandstone where it naturally wants to flow. Shale is trapped in tight source rock, with miserably low porosity and permeability, meaning the oil basically does not want to move. You do not “drill a well” and let it produce. You assault the rock with horizontal drilling, multi-stage fracturing, enormous volumes of equipment, people, water, sand, steel, and capital, just to release small packets of oil at a time. Think hundreds of thousands of barrels per well, not the millions and tens of millions conventional reservoirs can deliver and for years, not a few months like shale and then you have to drill the next hole (which the industry calls the Drilling Frenzy).

That is why the shale revolution is one of the great industrial feats of our time. It was not just a story of geology. It was a story of incentives, property rights, technology, logistics, and capital markets all aligning at once.

Now compare that with Venezuela, and specifically the Orinoco. Whatever you think about heavy oil, and yes, it comes with upgrading and processing challenges, from a pure “can we get the molecules out of the ground” perspective, Orinoco heavies are light years easier to get out of the ground when compared to shale.

A quick look at the slide above gives you a numerical perspective. Shale permeability sits in the 0.001 to 0.1 millidarcy range. The heavy oil reservoirs in Venezuela’s Orinoco Belt typically range from 1,000 to north of 13,000 millidarcies. That is not a rounding error. That is several orders of magnitude. Same story with porosity. Permian shale, the best shale on the planet, typically runs 4–8%. Orinoco heavy oil sands are more like 20–38%. So ask yourself a simple question. Which resource would you rather drill and produce, if politics is kept out of the way? And which one do you think produces lower full-cycle breakevens?

Yes, the U.S. had three massive tailwinds that made shale scale fast. First, property rights. In places like Texas, the landowner typically owns the minerals under their land, which creates a direct incentive to develop it. Second, the oil services ecosystem. Texas has an enormous, decentralised oil services industry that can mobilise quickly and compete aggressively. Third, financing. The U.S. has the deepest debt and equity markets in the world, which allowed shale to be funded at scale, even when it looked crazy to outsiders. Add those together and you get speed.

But here is the punchline: even with all those tailwinds, shale was still a technical nightmare compared with conventional onshore resources in the Orinoco Belt. If American capitalism can manufacture a Saudi Arabia out of tight rock in 15 years, then once Venezuela has functioning property rights and basic rule of law, the global oil and gas industry will rush in and treat the Orinoco for what it is, the last great frontier of oil riches. Because it actually is.

Now, does Trump accept the political risk of nation-building in this case? The answer is yes. That is, in fact, his stated goal, and he says it as plainly as a President ever does. Listen to him yourself.

Trump’s administration will not leave quickly. They want the oil assets back, they want to rebuild the industry, and they want to get paid for past expropriation and losses. That is the strategy, in black and white.

My point? Be very bearish oil prices. Trump’s message is huge. In fact, it’s a game changer for the oil industry where I sit. And yes, nothing will change overnight. But it will change, every day a little more. You have been warned.

Besides, I do not see the risk for this administration in the way the usual critics will frame it. This is not fighting a war in Afghanistan against a hostile insurgency. It is not trying to transplant institutions into Iran or Afghanistan under an Islamic political order with built-in hostility towards Western values.

This is Venezuela. It is culturally Western, overwhelmingly Christian, and it used to be a beacon of success before the socialists around Hugo Chávez and Nicolás Maduro destroyed it systematically. This is fixable.

Now let’s zoom out. This is not just a Venezuela story. It is a global oil price story, and therefore a geopolitical story. Venezuela has the potential to deliver structurally lower oil prices, or at least prices as low as today, for a long time to come (ceteris paribus). If that happens, it will cut the financial oxygen feeding the war in Ukraine and squeeze the Kremlin’s mobsters, substantially weakening the CCP in the process.

And before all of that, the mullahs could be gone too, reinforcing the chain reaction, because they also sit on massive untouched oil reserves waiting to be lifted by the invisible hand of the rule of law.

All of this will break the cheque books of terrorist sponsors in Qatar and elsewhere. And that, ladies, is a blessing for peace and humanity.

You will not hear any of this from the progressive-left “do-gooder” Marxist cult in the coming weeks. But the fact is that lower oil prices are one of the biggest creators of peace and prosperity. Few ever get that.

Instead, the left will raise every objection, however absurd, until they inevitably find themselves siding with murderers and dictators. Such are the rules of the legacy media game today, sadly. They are strictly partisan.

Of course, the Venezuela episode is far from over, and the final outcome is not written in stone yet. But Trump may well deserve the Nobel Prize if luck, ongoing courage, and good decision-making remain on his side. For now, he is on track where I sit.

Therefore, let us give credit where credit is due. We shall praise and criticise each action on its merits, never by partisan colour. Well done, Donald Trump and team.

And please, do not dare criticise this surgical, highly successful military operation for even one second. Salute it. I do.

Warm regards
Alexander

PS: For good order sake, here is the full press conference of the operation yesterday night and for our archives.

High quality asset with a clear pathway to first gold

Eskay Creek is a sizeable, high grade open pit project, grading roughly 3.5g/t gold equivalent. The mine plan targets around 450kozpa gold equivalent production in years 1 to 5 and roughly 320kozpa over a 12 year mine life. With AISC below US$900 per ounce in the feasibility study, Eskay sits in the rare category of high margin projects in a tier one jurisdiction.

What makes this story particularly interesting is that it is not a typical greenfield discovery that still needs to invent its infrastructure. Eskay is a brownfield re start with significant legacy assets, including road access, camp infrastructure, and most importantly an existing permitted tailings facility. This materially reduces both capex intensity and permitting loop risk, and it helps explain why management believes first gold in H2 2027 is achievable.

At today’s price, Skeena trades at a material discount to NPV, roughly 0.55 times, despite the project now having a clear catalyst pathway. Over the next 12 months, we expect further de risking to drive a re rating through three primary levers. First, final permitting milestones, including formal consent under the Tahltan framework, which until recently was the dominant political risk but isn’t anymore. Second, continued de-risking of capex and execution, including engineering progress and early works. Third, the potential buyback of the Orion gold stream, which would increase unencumbered leverage to gold and silver prices and improve equity quality.

In short, the project has moved from being a permitting and governance question to becoming an execution and valuation question, and that is where the market typically begins to pay most attention, and not just institutional investors, also the competition.

Eskay Creek, A Mine the Gold Price Left Behind

One of the cheapest and least risky ways to find a new gold mine is not to explore for gold, but to revisit old gold mines that were placed into care and maintenance because the gold price at the time no longer justified continued production. The industry refers to this as brownfield exploration, as opposed to greenfield exploration.

The advantage of this approach is simple. Historical mines come with data. Technical reports, drill logs, production records, and cut off grades already exist. In theory, if one takes a systematic view across closed gold mines and revisits the cut off grades that defined resources decades ago, it becomes possible to identify ounces that were uneconomic then but profitable at today’s gold prices. There is no magic involved. It is mostly arithmetic, discipline, and patience.

This is precisely what Walter Coles did in 2018. His background as a credit analyst at UBS in New York, perhaps, allowed him to see the forest for the trees at a time when gold prices were still relatively uninspiring. Somebody had to do the work, take a view, raise capital, and act. Walter did. Today, he owns roughly 4% of Skeena Resources, which seems well earned.

Walter identified Eskay Creek as a target within the so called Golden Triangle of northwestern British Columbia. The Golden Triangle is one of Canada’s most prolific mineral belts, host to both historic and current world class deposits. Seabridge’s KSM sits within the region. Brucejack, now owned by Newmont, is located there as well, along with its famously challenging high grade geology, which I have mentioned more than once by now.

Eskay Creek’s history stretches back to 1932, when prospector Tom Mackay first recognised the area’s unusual geological potential. Lacking modern exploration tools, Mackay relied on surface sampling and was unable to locate the core of the ore body.

It took more than fifty years for Eskay Creek’s true potential to be revealed. In 1988, a new exploration syndicate returned to the site under the guidance of legendary Canadian geologist Ron Netolitzky. Consolidated Stikine Resources, together with Murray Pezim’s Calpine Resources, initiated an aggressive drilling campaign. After 108 drill holes, it was hole 109 that changed everything, intersecting 27.2g/t Au and 30.2g/t Ag over 208m.

Following permitting, Eskay Creek entered production as an underground mine in 1994. Over the following 14 years, Eskay Creek produced roughly 3.3Moz of gold and 160Moz of silver at average grades of 45g/t Au and 2,224g/t Ag. It became the highest grade gold mine in the world and, by volume, the fifth largest silver producer globally.

In 2008, in the midst of the Great Financial Crisis, Eskay Creek ceased production and was placed on care and maintenance. Gold prices at the time were roughly US$872/oz. In simple terms, an underground cut off grade of 15g/t Au was no longer sufficient for Barrick Gold to justify continued mining. Despite its exceptional grades, Eskay Creek operated as a diesel and propane powered underground mine, which made it a high cost operation by the standards of the time.

After sitting dormant for several years, Walter Coles, through Skeena, secured an option to acquire Eskay Creek from Barrick Gold in 2017. In 2020, Skeena exercised that option and became the sole owner of the asset. In 2019, Walter also acquired the nearby Snip mine from Barrick, located west of Eskay Creek, for zero consideration plus assumed environmental obligations of roughly US$3m. Snip is another brownfield asset, formerly a high grade underground gold mine, and comes with extensive historical drilling and production data.

Below is a short clip of Walter Coles explaining how he approached the Eskay Creek opportunity, in conversation with Rick Rule in June 2024.

Before turning to the specific permitting framework at Eskay Creek, it is helpful to step back and clarify the geological risk differences between open pit and underground mining. That distinction explains not only why Eskay Creek looks the way it does today, but also why I deliberately structured the order of company discussions in this Substack the way I did.

We now turn to geology.

Read more

Mining veteran Sean Roosen’s message for the industry: “Shut up and drill”

Gentle Reminder

Before diving into Osisko Development, a brief note. The easiest way to extract value from this Substack is to revisit my earlier pieces on underground gold miners, namely Alamos Gold, Lundin Gold and K92 Mining.

They outline some technical foundations and investment principles that matter most in this sector. I won’t repeat those lessons here and in future posts. Instead, I build on them. A quick refresher will help frame the analysis that follows and make the nuances of this post far easier to absorb.

Mining Developers and the Lassonde Curve

Before assessing Osisko Development, it is worth revisiting a framework that has guided my thinking for years: the Lassonde Curve, named after Franco-Nevada co-founder Pierre Lassonde.

The Curve is not a law of nature, but it is one of the most useful mental models for understanding how value is created and destroyed during the mining life cycle. It maps the major inflection points in a project’s journey and helps investors distinguish between geological uncertainty, permitting and funding risk, construction risk, operating risk and above-ground jurisdictional risk. Over time, it has helped me identify where genuine alpha in this sector tends to emerge.

The Curve follows a simple narrative arc. It begins with the concept phase, when a company acquires ground, conducts early mapping and sampling, and tries to raise capital on a geological idea. If the rocks respond, the project enters the discovery phase, where drilling defines the scale and quality of the mineralisation. This is often the moment of maximum excitement and maximum volatility, because the market is forced to update its priors in real time.

If a discovery holds together, the project moves into the feasibility phase, where engineers, metallurgists and financiers replace the geologists. Here, PEAs, PFSs and FSs translate drillholes into mine designs, capital budgets, operating cost estimates and economic models. The romance of discovery gives way to spreadsheets, trade-offs and discipline. A strong feasibility study can re-rate a project; a weak one can collapse it.

From there, the Curve descends into the development phase, the part of the cycle that destroys the most value. This is where permitting, funding, inflation, labour shortages and cost overruns collide with reality. Only once construction is complete does a project reach the start-up phase, where the mine produces its first metal and the market finally learns whether the geology, engineering and cost assumptions were accurate. By then, the risks are fewer, but so are the potential returns.

The Lassonde Curve does not tell you whether a specific project will succeed. It is not a substitute for technical and common sense due diligence. But it does remind us that the market consistently misprices risk as a project moves from imagination to execution, and that the sharpest opportunities, and the most painful losses, tend to cluster around the transition points. Understanding where a company sits on that curve is often half the investment decision.

And here is how Sean Roosen positions the company on the Lassonde curve. He basically pitches a re-rating, i.e. construction start to producing gold miner (development stage), along the lines of G Mining Ventures and Artemis Gold, two of the best gold companies in the sector (I will discuss both these companies in December). Is this realistic?

Ticking All the Development Boxes?

At first glance, Osisko Development appears to tick every box required to catch the next upward leg on the Lassonde Curve.

The company controls roughly 4.5Moz of resources at Cariboo in British Columbia, with a risked NAV at spot of about C$3.4bn. On a fully diluted share count of 377 million, assuming the 19.1 million warrants do not meet their strike, this implies a value of C$10.25 per share, or roughly 108% upside from its close on 30 November 2025.

The headline story seems attractive. Cariboo, the company’s flagship, is now fully permitted at the provincial level and fully financed as of Q3 2025. Construction should begin in 2026, with first gold at the end of 2027 and a ramp-up to 4,900tpd some time in H2 2028. The entire effort is led by Sean Roosen, one of mining’s few modern-day legends. For a gold developer in a Tier-1 jurisdiction, this combination of scale, permits, financing and elite leadership is rare.

Viewed against the broader development universe, Cariboo stands out. Rupert’s Ikkari is high quality but remains years from first gold and still sits in the permitting maze. Skeena’s Eskay Creek is not yet permitted but already sports a US$2.2bn valuation. Perpetua, heading toward a federal Record of Decision, is valued at US$2.5bn. Probe Gold’s Novador has just been taken out by Fresnillo. Snowline faces a long and uncertain permitting risk and infrastructure cost road in the Yukon. Coffee, now owned by Fuerte Metals, has major execution questions ahead. Seabridge and Novagold each require US$8bn+ and remain too large for the usual financing channels for now (think dilution). West African names like Montage Gold or Robex–Predictive are interesting but carry jurisdictional baggage and share overhang risk, if you studied it closely.

Note: we will discuss all the relevant names above over the coming weeks.

On that landscape, Cariboo can look irresistible. A permitted, financed, construction-ready Canadian gold project with multi-million-ounce scale and a household-name operator at the helm. For many portfolios, it feels like the project you “have” to own.

And Sean Roosen sells this vision masterfully. In one interview he even jokes that you can order pizza and McDonald’s from the mine site, proximity that most developers could only dream of. He is an outstanding communicator and, more importantly, an outstanding miner. None of that is in doubt.

But now we must turn to what really matters and what will drive the success or failure of this project far more than permits, infrastructure or charisma. This is where the narrative stops being all blue sky. The central issue, again, is geology.

Before walking through it in detail, listen carefully to Roosen himself. At Minute 7:15–7:45 of the interview, he says:

“And we know it’s there, but we didn’t do enough detailed drilling to define it. And we’ve averaged about 1.2 million ounces of overall resource for every kilometre that we’ve drilled over the 4.4 kilometres. So the next plan is, so we’ve got the main 2.2 million ounces. 2 million ounces is there, the measure indicate and inferred. That’s in and around. That is the next plan. The ‘at depth target’ is just to keep extending these vein corridors. At depth it is this orogenic system. Very, very predictable, very knowable.”

This is where the story becomes more complex—and where the technical realities matter much more than the marketing sheen.

Read more

Winter is Coming

High time for an update on my beloved natural gas sector.

What should have caught your attention is the relatively muted price action in TTF and JKM as Europe enters the winter with storage levels around 82%. To be precise, Europe begins the heating season with 86.5 billion cubic meters (bcm) of natural gas held across 19 countries that provide storage for 28 European nations — our relevant perimeter for TTF price formation, including the UK, Switzerland and Norway, but excluding Ukraine and Turkey.

That is a low level in the post-Gazprom era. In fact, it’s the lowest since the post-Covid winter of 2021/22, when Gazprom, already preparing for its illegal invasion of Ukraine, stopped filling its European storages in Germany and Austria. That same winter, Europe entered with just 78.7bcm in storage. By 2022, Gazprom — at the Kremlin’s order — had shut off nearly all pipeline supplies to Europe (flows through TurkStream remain but are marginal). The aim was to fracture Europe’s political, military and financial support for Ukraine. The result was the most violent price spike in TTF history, which dragged Asian markets higher alongside it.

Since then, Europe has filled the 180bcm void left by Russia with higher LNG imports and lower consumption. What it has not done is replace those lost pipeline volumes — neither through Azerbaijan or North Africa nor through a revival in domestic output. In fact, production has kept falling since 2018, thanks largely to “green” policies in the Netherlands and the UK. Both now produce substantially less natural gas than they did seven years ago. Think of Groningen, once a top-ten global field, shut down because of tremors so minor they’d make every Japanese smile.

Europe, in short, now depends on LNG from across the world to keep its households warm through winter. Were Europe to import the same 68bcm of LNG between October and March as last season, and given today’s relatively mild weather forecasts, storages would fall below 10% — an emergency threshold. Pipeline systems must maintain a minimum pressure to function; below roughly 5%, the system risks mechanical failure.

And yet, speculative positioning in TTF — the benchmark European gas contract — has been steadily unwinding. From a February 2025 peak of 292TWh in speculative longs, the market fell to 202TWh around this time last year, when storages were completely full. Now, with storages at only 82%, net speculative longs have collapsed to 46TWh and could turn neutral by November. Who knows.

The Calm Before the Winter Storm?

So why is the market so calm?

Some may argue, intuitively, that Europe is sliding into a technical recession and that industrial demand for gas and power will be weak this winter. But the recession is likely already here nor is it particularly relevant. What drives European gas consumption are households, not industry or power generation. And some 237 million European households — including those in the UK, Switzerland and Norway — will inevitably turn up the heating as temperatures fall.

The correlation is stunningly clear, as we’ve shown time and again. From Edinburgh to Rome, from Amsterdam to Bucharest, consumption rises as temperatures drop below 20 °C, and it accelerates exponentially once we fall below 10 °C. Green transition rhetoric aside, the numbers speak for themselves, month after month since 2019. For those of us who care about data, it’s deeply satisfying.

Because of these correlations, we can now forecast European gas demand with remarkable precision. The method is straightforward: country-by-country consumption models built on four independent European weather forecasts, weighted by their certainty. To this, we add industrial demand (adjusted for economic indicators) and power-sector gas use (adjusted for spark spreads and other electricity metrics). The more we refine it, the more accurate and responsive the model becomes — perhaps even a step towards automated trading execution one day.

We’ll see.

Read more

Why is K92 A Special Situation?

K92 is a scrappy operator’s masterclass.

Under John Lewins, a narrow-vein, undercapitalised asset that most misunderstood—Barrick included—has been turned into a high-margin growth engine through incremental geological intuition, focused exploration, careful engineering and disciplined reinvestment. Restarted in 2016 and declared commercial in 2018, it is no longer a promising teenager; it is a tier-one athlete hitting its stride.

What sets it apart is not a slide deck but a production profile and a cost base. K92 is moving into the 400,000 oz Au-equivalent class, with one of the lowest unit costs in our universe—thanks to a superior cost structure (grid power, access, paste backfill, mechanisation, geometry, labour costs, etc.) and copper and silver by-product credits that the market has barely priced.

This is also an execution story, not a promotion: grades and continuity in a “spaghetti soup” of veins—but really golden curtains, as I explain below—access opened and mechanised; and, crucially, the best near-mine resource endowment in our universe, much of it still to be declared as resource over the coming years by one of the largest exploration teams in gold mining. Huge.

All of that comes without financial leverage and with low operational gearing, courtesy of the superior cost structure. Just as important, the current growth leg carries minimal, if any development risk: the key expansion building blocks such as the new processing plant, paste plant and underground development access are already in place. Very special.

The kicker? John Lewins has executed this brownfield revival with the least equity dilution per ounce we know of. K92 may yet prove the most successful mining growth story—across commodities—with the lowest dilution per ounce produced from start to finish. A tier-one athlete on a value multiple, hiding in plain sight.

How Kainantu Found its Pulse Again

When K92 Mining bought the abandoned Kainantu mine from Barrick in 2014, the consideration was intentionally light up front and heavy on success: US$2m cash, a contingent US$60/oz on the first 1Moz produced, and a 2% NSR in Barrick’s favour. It was a classic “pay as you prove it” deal.

The original operation started construction in 2004 and came into production in 2006. Barrick acquired the mine in December 2007 from Highlands Pacific. Under Highlands, output was 27koz in 2006 and 32koz in 2007; under Barrick it managed a mere 10koz in 2008—69koz in total—before the mine was placed on care and maintenance in early 2009. Barrick’s rationale was straightforward: narrow-vein geometry and high operating costs made the mine uneconomic at prevailing gold prices.

Reading Barrick’s 2007 announcement with hindsight and the point is obvious: the acquisition was never really about the struggling mine; it was about the 2,900 km² land position.

By 2015, when John Lewins and team took over, Kainantu wasn’t a turnaround so much as a rescue—albeit one with roughly US$100m of sunk development to access Irumafimpa and Kora and a small processing plant. After seven years of care and maintenance, the tunnels were flooded, the plant was idle, and the highlands jungle had begun to reclaim the site. Not an easy brownfield set-up.

Before the details, look at the site yourself: three Google Earth history screenshots (September 2015, July 2022 and August 2025) tell the story of a mine being brought back to life.

What looked like failure to a major with a 30,000-foot portfolio view in 2009 was opportunity to a team that understood how to treat a small, high-grade system. A firmer gold backdrop helped: gold averaged US$1,160 in 2015, US$1,393 in 2019, then broke out to US$1,770 in 2020.

Crucially, the government renewed Mining Lease ML150 and no state equity was imposed. Kainantu carries no 10% free-carried interest at the mine or company level. Papua New Guinea participates via royalties and taxes, not share ownership: a 2% royalty (NSR/FOB basis), the 0.5% MRA levy on mine revenue, and 30% income tax, alongside landowner agreements.

Important Risk Assessment:

The statutory right for the State to take an equity stake can apply to new mining leases in Papua New Guinea, but K92’s current ML150 carries no such provision. Politically, alignment still comes from operating performance, stable relationships and benefits flowing to landowners—not from a carried interest. But a possible development of Blue Lake within the Exploration Licence 470 (EL 470) may change that conversation. Also, to our knowledge there is no Standstill Agreement in place to legally protect (in practice everything can change) the current status quo, similar to Fruta del Norte, for example.

Geological Comparison

Before drilling into Kainantu’s operation, it helps to anchor the deposit against the underground case studies we have already covered—Island Gold, Young-Davidson and Fruta del Norte—using the same simple comparison table to keep the contrasts sharp.

Kainantu is a high-grade, narrow-vein epithermal system with pronounced variability in thickness both between and within the principal lodes, yet with consistently very good continuity along strike and down dip. In round numbers, working widths sit in the narrow-to-moderate camp, with true thickness commonly in the 1–15 meters range and resource grades in the mid-to-high single digits for gold.

That geometry puts Kainantu near to the Island Gold deposit, not bulk-tonnage underground archetypes: not as high-grading as the best Island Gold panels, but generally thicker and with comparable continuity—exactly the sort of profile that matters for stope design, dilution control and mine scheduling.

Set against Young-Davidson, the differences are first principles. Young-Davidson lives on volume rather than grade: orebody thickness on the order of 80–120 meters enables bulk mining at low single-digit grades, a strategy that optimises unit costs through scale but depends on sheer tonnes moved.

Kainantu extracts value through selectivity. Mining widths are measured in metres, not tens of metres; production leans on long-hole stoping and cut-and-fill to preserve head grade and contain dilution; development is targeted to chase discrete, steeply dipping lodes rather than to sweep a broad, homogeneous panel. It is a different cost and risk equation.

Fruta del Norte, by contrast, is the unicorn that combines thickness with high grade and excellent continuity. A deposit capable of 100–150 meter mining widths while still carrying resource grades around 7g/t for gold is rare, and it compresses both operating and capital intensity per ounce. Kainantu cannot claim that blend of bulk width and high grade; what it does have is a disciplined narrow-vein architecture that delivers continuity over kilometres of strike, allowing value to compound by repeating well-understood stoping patterns at scale.

The Golden Curtains of Kainantu

When geologists speak of a narrow-vein system, most of us non-geologists instinctively picture our own human blood vessels — thin, branching, fragile. At least that’s what happens in what Daniel Kahneman calls System 1 in his brilliant book Thinking, Fast and Slow: when certain words are spoken, intuition takes over.

But in this case, intuition deceives us. That mental picture is a misleading one as it doesn’t do this geological system any justice. The “narrow veins” of the Kainantu Mine — the Kora and Judd systems — are not fine threads of gold, but rather steep, towering curtains of quartz, sulphides, and metal running deep through the mountain.

Technically, the term narrow-vein system is of course correct. But “narrow” refers only to thickness — typically one to fifteen metres wide. Imagine a bird, or avatar with laser vision, flying over the Kainantu mountainous region able to look through solid rock. From his vantage point high above, he would see two glowing lines buried in stone — perhaps like spaghetti laid out beneath the surface.

These “spaghetti” (lines in red above) would be astonishingly long — literally kilometres in what geologists call strike length (strike, by the way, has nothing to do with labour disputes or lightning bolts here, more with a poorly developed English vocabulary). Our laser-eyed avatar would see these narrow veins stretching for two to three kilometres, their thickness expanding and contracting from one to fifteen metres as they undulate through the rock. Huge dimentions.

But the real beauty of Kainantu would only reveal itself to our avatar if he could slice the mountain open into its cross section like a cake, right along the lines of those veins. Inside, he would find mineralized curtains of gold, copper, silver, and quartz hanging down for hundreds of metres — what geologists call their vertical extent (or down dip). Johan Wolfgang Goethe wouldn’t approve of such simple words, but it is what it is.

So don’t imagine tangled spaghetti in stone. Imagine instead long, folded golden curtains, descending vertically through the crust — continuous lodes where mineral-rich fluids once surged upward, cooled, and crystallized. In some places, these curtains swell — forming dilatant zones, where the rock cracked a little wider and trapped more quartz, sulphides, and gold. Those are the rich pockets — the geological knots of fortune, with a mix of gold and copper clitter.

Kora and Judd run side by side, like twin arteries of an ancient geological heart, shaped by the same tectonic rhythm and fed by the same molten pulse. Nor is it a two-vein curtain of Kora and Judd. The 2024 technical report sets out at least nine other golden curtain siblings: Judd (including Judd South), Kora (including Kora South), Karempe, Irumafimpa (Barrick’s original production target), Mesoan, Mati, Bona Creek, Maniape and Arakompa. That is the visible family; the geophysics hints at more.

This breadth flows from John Lewins’s pragmatic approach to exploration. When he and his team reopened the mine from Barrick in 2017, they did not declare reserves. They kept disclosure at resources, fully aware that spending scarce capital to engineer reserves in a narrow-vein system—before underground access and close-spaced drilling—would waste time and money to appease generalists who would not grasp the geometry anyway.

Instead, they restarted with limited but well-aligned capital and a clear aim: let production fund exploration. Cash flow has since underwritten the drill-out of multiple targets, with Arakompa the current standout—growing rapidly and not yet even a declared resource. The company will bring in two more surface diamond rigs to arrive in late Q4 2025, supporting a significant ramp-up in its exploration. That is land optionality at work: acquire a district, open the cash register and let geology compound. It is, within the rules, the clean way for you to front-run Wall Street too.

The menu is already a small but excellent meal—and it gets better. The technical report points to the likely price of this spaghetti soup, and it is large. A helicopter-borne electromagnetic survey, flown in November 2021 by Expert Geophysics Limited, mapped the property at depth and outlined it in a technical report. The programme delivered a far greater depth range than was technologically possible before. Think of it as geology’s analogue to improved seismic tech in oil and gas: higher fidelity, deeper penetration, better targeting. In short, a sharper, bigger image where a smaller, blurred one once stood.

Data were collected along east–west lines nominally spaced at 200 metres, with north–south tie lines at 2,000 metres. The conductivity maps light up the known lodes and, more importantly, illuminate many more noodles plus a few likely bolognese pots. The grey “interpreted structures” (below in grey) are new spaghetti strands yet to be drilled and potentially converted into resources, and there are loads of them. The yellow-circled zones mark porphyry targets—the sauce. We will return to those.

The 2024 report says it plainly. The airborne deep-penetrating geophysics over the entire property shows strong correlation between known deposits and conductive bodies. A swathe of high Apparent Conductivity extends from Kora and Judd into EL470 for several kilometres, and a longitudinal section shows the same highly conductive corridor north and south of the Kora mining centre.

The conclusion is unambiguous: there is extensive untested strike potential to the Kora–Kora South and Judd–Judd South vein systems beyond the A1 porphyry to the south-east for several kilometres. The programme also identifies new vein and porphyry targets on K92’s licences and highlights known mineralised porphyries, including A1, Blue Lake, Tankaunan and Timpa.

Now let that settle and glance at the reserve and resource table for Judd and Kora alone. Gold resources and reserves for those two veins total 6.38 Moz. Add silver and copper and the package equates to 8.8Moz AuEq, supporting a 27-year life at 240,000oz per annum, which the company is set to deliver from 2026. These veins are not bounded; both remain open at depth and are likely to lengthen as development advances and provides ever cheaper underground drill platforms. That is how narrow-vein systems behave when the lodes are continuous and the structure is coherent.

Now layer in the rest of the vein systems already mapped—and the additional structures now outlined by geophysics—and the size of the prize comes into view. The district potential is very large. A 20Moz gold endowment or more is within reasonable geological expectation.

Have I misplaced my marbles? Hardly. The number is defendable. A 20Moz district endowment sits well within reasonable geological expectation—strictly as an exploration target, not a resource—and the distinction matters. Here is the sanity check, built only from what we can see and measure today.

Time will decide what the drill bit delivers, but the investment point is balance. Geologists are paid to be conservative; their craft is humility before geology, because Mother Nature punishes hubris without appeal. At the other pole sit the Silicon Valley promoters—Elon, Cathie and friends—who can conjure trillion-dollar valuations from a sketch and a slide on “TAM expansion”. Hand them land optionality and they would price Kainantu at 100 Moz booked by tomorrow morning. Neither instinct serves capital well. Too conservative and you rack up silent opportunity cost; too promotional and you incinerate cash.

In my humble opinion, our job as resource investors is to sit between those extremes: recognise that land optionality has real, compounding value when the geology is predisposed; insist on disciplined capital allocation and let production pay for proof; refuse to badge exploration upside as reserves or resources until the drill core says so; but allocate capital where land optionality is waiting to happen. Then let time be your friend and invest for the long term. Find a few of those and take a holiday.

This series began with Alamos Gold for a reason, and K92’s spaghetti soup earns its place on the table precisely because it rewards patience without requiring faith. And no, three elephants in a row — those being Alamos, Lundin Gold and now K92 — does not mean they’re as common as mice — you won’t find them on every corner. What you do get in this Substack is the benefit of my pre-selection. If this work proves useful, I’d be grateful if you shared it with a few like-minded investors; it helps justify the time it takes to do it properly.

Share

Read more

“Early on I learned that it takes as much time and effort to do a small project as a large one.” Adolf Lundin

Girlfriend, Not a Marriage

I first met Ron Hochstein at a classic speed-dating session—Berenberg, Zurich, 2018—when they pitched me Lundin Gold. I knew the Lundin dynasty from the oil patch. Lundin Petroleum rode Johan Sverdrup and was the best value for money on the Norwegian Continental Shelf besides Aker BP, by a country mile. But I wasn’t into gold miners; gold trades off real rates and I wasn’t exactly bullish on the metal.

Still, it was a Lundin outfit, so I burned 45 minutes crossing town—almost as big a waste of time as broker speed-dating. My mindset: maybe a girlfriend, not a marriage. Once the dog-and-pony show ended, I asked two things: how do you work with Lukas Lundin (mining side; Ian Lundin ran the oil side), and if you had a silver bullet, which competitor would you take out?

Ron was mid-construction and looked appropriately stressed. His answers: “two to three times a day,” and “Pretium.” Yes, you read that right. Lukas Lundin—who ran many operations, including Lundin Mining, Bluestone Resources (a gold development that was left for dead later), Filo & Josemaria (both copper explorations in Argentina which took off big later; no, they didn’t own NGEX back then)—called Ron multiple times a day for construction updates.

Anyway, Ron delivered on time and on budget. Or rather, the Gignac family did—with their mine-construction firm, G Mining Services. Today I know they’re the best construction team on the planet—mining hall-of-fame material. Back then, I had no clue. Remember the name; we’ll come back to them in this series.

The Lundin Gold stock, meanwhile, gyrated in 2018 like a pole dancer on an oil-slicked stage. Not much of a Lassonde Curve to admire. Only in June 2019 did it finally move—from C$5.10 to C$8. Partly because it was nearing commercial production (declared in February 2020), but also because gold did a 20% shuffle from US$1,250 to US$1,500.

Miners were hated across the board—precious, base, anything metallic. Why go asset-heavy when you could own Google’s asset-light recipe? When my “girlfriend” finally perked up, I happily passed her to the next suitor at C$8. Early 2020, the stock overshot gold as commercial production was announced for a few weeks, then cratered back to C$5 during Covid when Q2 2020 production went dark.

From there Ron delivered—or overdelivered—quarter after quarter, and yet the stock merely tracked gold for roughly 10 straight quarters, just with more whiplash. So no, you’re not gonna win a market-neutral set-up as a hedgy in metals. By July 2022 it was back under C$8, broadly in line with the metal. So much for the “leveraged play” in a quality name; it traded more like a guaranteed put on a slippery earnings print. That 2018 meeting taught me more about gold mining than I realized—less romance, more cash flow; keep the relationship casual until the geology proves it wants a ring.

And for the record, I owned Pretium too. That was the real stomach acid. Why, you ask? Try my last post on Alamos. The answer’s there—assuming you can read. Hint: geology. No, Pretium’s problem wasn’t grade; it was nuggety, discontinuous geology—bonanza pockets stitched through blank rock, the textbook nugget effect. Wall Street hated it. Bottom line: nature and quarterly reporting are rarely a match made in heaven.

Fun fact:

Lundin Petroleum, born in 2001, discovered Johan Sverdrup. Yes, Statoil showed up later, but Lundin made the first strike in 2010 on Avaldsnes with well 16/2-6—later recognized as part of Johan Sverdrup.

Why does that matter? Because Johan Sverdrup is, by far, the largest conventional offshore field in the North Sea today (Ekofisk/Statfjord were bigger in their days): 2.7 billion barrels of recoverable reserves and a plateau capacity up to 755,000bpd—roughly a third of Norway’s current oil production. Let that sink in. And yes, just like the best deposits, Johan Sverdrup only got bigger as the drill bit did the talking.

After the merge with AkerBP in June 2022, their Working Interest in the field is 31.57%. Nemesia, the primary investment vehicle of the family, holds 14.38% of AkerBP as per Bloomberg at the time of this writing, worth US$2.2 billion.

Better Lucky AND Brilliant: The Fiscal Turn That Made Fruta del Norte

Lukas Lundin bought Fruta del Norte (FDN) from Kinross in December 2014 for US$240m—US$150m in cash and US$90m in Fortress common shares (today’s Lundin Gold).

At the time it was one of the largest, highest-grade undeveloped gold projects on the planet: 36 mining concessions over 64,300 hectares in southeast Ecuador, 80 km east of Loja. In Kinross’s book, FDN carried 7.2Moz M&I and 2.5Moz inferred. To prove up the system, Aurelian—the original discoverer—and later Kinross drilled at least 141,000 exploration metres from 2006 to 2012 in proper jungle conditions. In today’s drilling-cost terms, that’s roughly US$50m before technical work.

Kinross walked in 2013 after failing to agree key fiscal and legal terms with Ecuador, including a punitive windfall-profit construct of 70%. The government also wouldn’t grant the stability Kinross wanted. Mining is long term. Hence, good mine operators want a legally binding standstill agreement that is enforceable under international arbitration. Consequently, Kinross took a US$720m write-off (mostly non-cash), including US$20m in severance and closure, and treated FDN as discontinued. Despite sabre-rattling over the licence timeline, Kinross ultimately sold to the Lundin group.

For perspective, in 2014 Kinross produced 2.7Moz GEO (gold equivalent) and carried 34.4Moz reserves, 23Moz M&I and 4Moz inferred, with a US$3.2bn market cap. In other words, the market valued all of Kinross’s resource at US$52/oz with gold at US$1,266/oz. Kinross sold FDN for US$25/oz of resource. Today, markets value 15Moz of FDN resources at north of US$1,000/oz—forty times that. Not bad.

Did Kinross blow it? Not ex-ante. In 2013–2014, Ecuador’s regime under Rafael Correa (notably the 70% WPT) made FDN uneconomic for a major at US$1,300/oz. The mine was in the middle of nowhere and required power lines, roads and plenty of upfront capital. The US$240m exit was rational. One could even argue it was a good price, likely replacing most of Kinross’ cash cost. Who knows.

What we do know is that Latin America had the usual above-ground noise around that time. On 6 February 2016, The Economist was tallying social-licence conflicts across the region. Chile’s Supreme Court suspended Pascua-Lama; Colombia’s courts blocked Mandé Norte. Latin America has the metals endowment across the periodic table, but politics were (and are) a contact sport. And that is why Ecuador remained a mining minow. It had a mere 60 mines operating in 2015 and registered 7 conflicts in the piece. That is 12%—“Lodes of conflict,” as the title of the graph correctly reads.

Only after Lenín Moreno took office in 2017 did Ecuador finally grow up on mining policy—the 2018 reform killed the 70% Windfall-Profits Tax (WPT) for mining and made the regime investable. But when Lukas bought in December 2014, the “reforms” (Decree 475 and a grab bag of incentives) were lipstick on a pig; the 70% WPT still hung over the model. For a portfolio major, FDN screened poorly. And Quito wasn’t offering squatters’ rights: work it or risk the licence. You can’t have your cake and eat it too. Lukas was a risk taker in the Lundin family sense. Adolf is quoted to have said, “no risk no glory”. It lived on in his most capable sons.

By 2016, Lundin announced the adult thing—paper first, rocks second. Call it proper risk management. The Exploitation Agreement locked the project’s fiscal rules and clarified how the WPT would work: it would apply only when the metal price exceeded a stipulated contract “base price,” and only after FDN had recouped its cumulative investment (the Government even floated “payback + four years” during the legislative clean-up). In plain English: the 70% take hit just the price-above-base slice, not every dollar of profit, and not until the mine had paid itself back. The contract also included a US$65m advance royalty—unusual for most mining jurisdictions, but part of the bargain to get bankable certainty for a worldclass deposit.

The Investment Protection Agreement signed later in 2016 layered legal and tax stability on top: a fixed 22% income-tax rate for FDN, ISD remittance-tax relief on debt service, and most-favoured-investor style protections. But none of that repealed the WPT. It just made the playing field knowable while the politics caught up. The actual repeal of the mining WPT arrived in 2018 under Moreno’s Ley de Fomento Productivo. That’s when the windfall tax finally left the stack. That was the game changer. And that was lucky.

Today, Lundin Gold still pays plenty of taxes. If you own the stock, study the fiscal take as closely as grade and capex—it defines intrinsic value. Ecuador mandates a 15% profit share on pre-tax profits in mining: 3% to employees, 12% to the State. It shows up as 3% in operating costs and the 12% in the tax line.

On headcount, Lundin doesn’t list employees in the AR, but 2023 sustainability materials note 1,907 employees (local press pegs 2024 in the same ballpark). That’s a lot of paycheques tied to one mine—a real, tangible resilience mechanism in a country-risk discussion. Our calculation suggests FDN will pay out US$334,000 per employee, assuming a US$4,000 price deck, ceteris paribus.

FDN’s operator, Aurelian Ecuador, pays a fixed 22% corporate income-tax rate (CIT) for the life of the mine under the IPA, even though Ecuador’s headline rate rose to 25% in 2018. So that is good news. It shows some fiscal stability. It’s the little things that matter in judging country risk. Also, Profit Shares are deductable for the purpose of CIT. Sensible.

FDN obtained relief on debt service in the so-called Impuesto a la Salida de Divisas (ISD)—Ecuador’s tax on the exit of foreign currency. Dividends can qualify for ISD exemptions subject to the usual conditions, which we assume too. As social influencer and presidential candidate Gloria Álvarez in Guatemala explains: Latin America knows 50 shades of socialism. Finally, under the Canada–Ecuador treaty, dividends to Lundin Gold carry 5% withholding (treaty conditions apply); without treaty relief, Ecuador’s domestic rule is 10%.

In our intrinsic value work we thus model the stack as 15% profit share + 22% income tax + 5% dividend WHT, with profit share deductible before CIT and dividends paid after tax, the effective take lands below 42%. Not great, but certainly more competitive than many African regimes that layer equity carries up to 15% on top of royalty and income taxes.

In all, Lukas had timing and spine. Better lucky than brave, sure—but they were both. You couldn’t guarantee the political turn in 2017–2018; you could position for it. He sure did. But let’s be frank: the FS 2016—before the turn—suggested US$669m upfront capital to put the mine to work. The gold price in 2016 and 2017 averaged more or less US$1,250.

If we were to apply that price deck in our model with a 70% WPT, FDN would have had a hard time returning its invested capital—we mean ever. Even with the capital-recovery protection agreed in 2016, it still would have struggled to pay dividends later at a US$1,250 gold deck. Water under the bridge.

The IPA, combined with the 2018 repeal of the mining WPT under Moreno, made greenlighting FDN a no-brainer. Without both, Lukas might have walked—just as Jack Lundin (one of the two active superstar sons now running the mining side of the Lundin empire) did with Bluestone Resources in Guatemala in 2022. Adam is the other. Harry and William—also Lukas’s sons—are active on the energy side of the group. We’ll leave other family details aside; this story is about FDN.

The lesson: if you invest long-duration in LatAm resources, you study politics, social issues and taxes like an operator and do not rely on management slide shows. The amplitude of change dwarfs North America, Australia, and Europe—despite the fashionable takes that “our” above-ground risk is just as bad.

Among us girls: it isn’t—except, of course, in the UK, with its so-called Energy Profits Levy (EPL), the local windfall tax that’s been kneecapping the North Sea’s best operators since the post-Russia gas shock in 2022–2023.

Fruta del Norte — The Geological Unicorn

Those of you who’ve followed me on X know the drill: resource investing starts with the deposit (in metals) or the reservoir (in oil and gas). A gift of nature can offset a lot of above-ground pain and price volatility. It’s the insurance policy for corporate survival—especially when it takes real technical skill to lift and sits out of easy reach of bureaucrats and “rebels.” Think offshore Nigeria in oil terms. Same playbook.

So let’s look at what Fruta del Norte actually is. Before the jargon, apply common sense. The ideal underground gold deposit looks like this.

Continuity. The ore body sits at moderate depth and runs laterally—a panel, not a pinprick; a football, not a fishing line. You drive in, not down a thousand-meter shaft. Minimal waste development. A short, straight road to ore. The grade shell barely pinches over mineable distances. Lower risk, lower cost, fewer surprises when it’s time to hit the quarter for Wall Street.

Width and depth. You want a thick, consistent block—again, football not spaghetti. Not stringy lenses disappearing at depth, not broken shoots you can’t find when you need them. Call it 100–150 meters true thickness, at serious grade, near enough to surface that physics and diesel are on your side.

Rock competence. You want competent host rock that doesn’t fall apart, so you can run big stopes without diluting grade. In the plant, you want metallurgy that cooperates—gold that separates cleanly enough to deliver high recoveries, without throwing the periodic table at it. Doré over alchemy; if you must make concentrate, fine, but don’t make it the only route to pay dirt.

That’s the dream. Continuity, simple geometry, competent rock. Simple!

Now, let’s park the daydream and look at this ore body.

Fruta del Norte is an epithermal vein-breccia hosted in sediments. Now, I have no idea what that really means - geologically speaking. But in my resource table below you’ll notice three things that pop immediately if you’ve looked at enough mines. None of it takes a geology degree to comprehend, just commen sense and basic math.

First, grade: M&I averages in the 7g/t neighborhood with reserves around 7.8g/t—serious rock even in underground land. Second, scale: the ore zone is 100–150 meters thick, runs roughly 1,700 meters along strike, and sits around 700 meters below surface. Very special. Third, continuity: it’s a single, laterally continuous panel. That’s “rare earth” material.

The geometry makes the mining plan sing. A true thickness of 100–150 meters means big, mechanized stopes—exceptional at these grades. Access is by side portal and decline; you’re not hoisting from a kilometer down. It’s “drive to the face, mine, turn, drive home”—far simpler than the contortions at Island Gold or Young-Davidson.

Don’t get me wrong: Alamos turned both into industrial beauties. My point is that Fruta del Norte asks for less tech and fewer brain cells to deliver. It’s the kind of asset Buffett wants—a wide moat that even an idiot can run, because one day an idiot may will.

On the plant side, the company reports dilution around 8% and 88% gold recovery. That’s fine—room to optimize, but already very profitable rock. Metallurgy isn’t trivial here; FDN produces a mix of doré and concentrate, and the team keeps nudging recoveries upward. If they crack another couple of points consistently, so much the better—but let’s not get greedy now when geology is doing this much heavy lifting.

Fruta del Norte is the rarest thing in mining: size and obedience. Continuity, thickness, access, grade—four aces in one hand—translating straight into low costs and long duration. She’s a Latino beauty, but without the usual high-maintenance supermodel drama. Look at her. It’s screaming “buy.” Meanwhile 99% of Wall Street can’t read a long-section. A geological unicorn, hiding in plain sight.

If Escondida is the type example for open-pit copper, FDN is the underground gold analogue—an ore body that just gets the big things right. Per kilometer of strike, it’s one of the densest gold endowments per kilometer on the planet. A block of money lying flat at 700 meters, waiting to be mined for the next 20 years—methodically, predictably, without endless technical headaches. The proverbial gift of nature.

Which is why Lukas Lundin didn’t need a séance in December 2014. He’d looked at hundreds of deposits across metals. When a world-class geometry shows up at a price with a pathway to bankable contracts, you take the risk. Pros do.

And you don’t need to cosplay as a geologist to see it. Spend a few hours with technical reports, stare at the long-section, compare vein systems and thickness columns across peers, and let common sense do the work. Mining has so many comps it’s practically a stock picker’s playground. The edge isn’t in sounding smart; it’s in seeing the obvious—continuity, geometry, competence—and then waiting while the cash flow tells the story. Looking at geology and knowing who the real operators are is the legal version of front-running Wall Street.

Land Optionality: Let the Drilling Begin

Does the Latina supermodel have geological upside? I don’t know. Nor can we know. It’s a known unknown, in the words of former Secretary of Defense Donald Rumsfeld. But there are a couple of things we can say.

Let’s start with the country. Ecuador—LatAm drama like the rest of the EM pack—did its best to stay poor by shutting the mining cadastre in 2018 over “irregularities in the concession system,” whatever that meant. Code for corruption, in all likelihood. It reopened in June 2025, finally launching new concessions after seven years to attract projects and curb illegal operations. Dahh.

Between 2018 and 2025, Ecuador didn’t outlaw drill rigs at FDN, but it starved exploration with policy, permitting gridlock, and uncertainty. Closing the cadastre froze fresh ground and slowed anything beyond the mine’s immediate footprint. Add the 2020 COVID stoppage and, later, court fights over new environmental-consultation rules (Decree 754 was provisionally suspended in 2023), and you had a national case of hurry up and wait.

The rational choice for Lukas Lundin and Ron Hochstein was to build the mine first, chase ounces later, which is exactly why the resource history reads like a flatline with barely a pulse: tiny additions, depletion marching on, and not much movement until the drills came back in earnest in 2022/23, with real replacement finally in 2024. In fact, Lundin Gold didn’t even bother to report annual reserve reports for 5 years straight.

Once the mine was running and access improved, Lundin rolled out its largest district drill push since 2007—first near-mine, then regional. By 2021–2022 they were back on pads around the Suárez Basin, a 38km² pull-apart that hosts FDN and—crucially—looks big enough to host siblings. The run of news that followed (near-mine hits in 2022–2023, then a full district program) reads like a company taking the restrictor plate off. See for yourself.

Can the company deliver on this 2025 ambition? Absolutely. Lundin is running 16–17 rigs in 2025, which is massive. At that fleet size, you need only 16–18 meters per rig per day to hit 108,000 meters—well within normal productivity, especially with a mixed fleet (surface + underground). The implied 8 meters per crew per day (two crews per rig) is conservative for diamond coring, leaving buffer for weather, maintenance, or pad moves. Ron and team will deliver—unlike the many junior lifestyle outfits without funding. Hunt elephants, not mice. It pays over time.

It gets better. Listening to Lundin Gold’s Investor Day 2024, studying their approach, and thinking about the industrial probability I get good karma in a probabilistic ballgame. They have a team of 20 geoscientists underpinned by a successful operating model. And much of it is new. VP Exploration Andrey Oliveira joined in March 2022. Since then, he’s hired 18 new geologists (ten women from communities around FDN).

Under his leadership, the company is focusing on near-mine exploration within a system that is open south, west, east, and at depth, plus a regional program—what I’d call a real exploration culture run by people who’ve actually seen this epithermal style before. Best of all, Andrey seems to embrace AI and big-data tools. Tech should let exploration make quantum-leap gains when applied with discipline.

Do I know what that will ultimately yield? No. Known unknown. But here’s a known known: Andrey’s team will likely turn over every single rock on 63,000 hectares of highly prospective epithermal ground—meter by meter, systematically, with no budget constraint and a tech stack unprecedented in Ecuador’s exploration history. That’s real horsepower. Name me a junior that can match it and fund it without equity dilution. There isn’t one.

Here, you get real exploration by pros—in proven geology, with a unicorn already on site, an operating mine ready to absorb any discovery (speed matters), and a rock-solid social contract on top. Keep that in mind when you’re pitched junior stories with nothing but glossy slides, a Lassonde-curve cameo, and “100x” typos. That’s not investing; that’s roulette—most of it noise dressed up as geology.

Here, the drilling is already paying off. Bonza Sur, one kilometer south of the FDN portal, started as a humble soil anomaly and is now a new gold deposit. The mineral envelope starts at surface, runs more than 1.8km along strike, is about 100 metres wide, and extends to at least 500 metres depth in drilling. That’s not a scout blip; that’s scale with geometry.

Lundin Gold is guiding to a maiden resource in H2-2025 and had one rigs chewing on it in Q2 2025. 11 surface rigs were drilling, with four of them at Trancaloma (east to FDN), one at Sandia (north east to FDN), one below FDN depth, one at FDN East, one at Bonza Sur, and three testing new sectors. Whatever they find inside the above white-dotted perimeter converts, by design, to high-margin cash flow—no fresh permits, no new mine build, no strings attached. Call it 1:1 conversion when its slot comes up in the mine schedule. Sexy.

Meanwhile, the regional map remains gigantic. Lukas acquired 64,300 hectares—roughly half the size of the Canton of Zürich with its 1.6 million inhabitants. It’s huge. There’s hardly a soul on it, and the land package has never been systematically explored. So yes, you can be cautiously optimistic that where one supermodel hid, a few mini-models may be waiting their turn. A dream come true for dreamers.

When FDN’s VP Exploration Andrey Oliveira says “epithermal systems are never alone,” he isn’t speaking figuratively. The geological corridor already hosts other mines and projects—Mirador (copper), Warintza (copper), and several prospects. The best mental model might be this: the Carlin Trend began with one orebody in 1961; today it’s a 90-million-ounce hydrothermal city. Pierre Lassonde understood the power of that optionality when he scraped together US$2 million to buy the royalty—every dollar he had.

Epithermal systems come in clusters, and if the geology stays preserved—as it has under the sedimentary cap at FDN for 150 million years—each new vein corridor can extend mine life by decades. I don’t need to and couldn’t lecture you for one minute on the petrology; I just need the history: that’s what nature did. What we’re watching in southern Ecuador could be the early chapters of a modern Carlin-style evolution, written in epithermal script rather than carbonate. With budget, brains, and tech, Andrey’s team is likely to find more gold, copper, silver, and friends. But let’s not outrun the drill bit—or mother nature.

Have we valued any exploration upside yet? No. I’m not going to model fences and micro-structures off a handful of holes, and unless results cluster, regional targets won’t become economic. Our model, however, uses ALL 9.4Moz of resources and risks none—chance of success set to 100% for the in-resource case.

Sell-side analysts typically value reserves in full, then apply a risk factor to measured and indicated, and often assign zero to inferred. They have their reasons, but most are intellectually flimsy and mainly designed to avoid embarrassment when the market is watching. Intrinsic value in resources has to be situational. But resources come in countless configurations: sometimes the extra ounces aren’t worth the paper their block model is printed on; sometimes they’re worth every ounce on paper; most often it’s somewhere in between.

Unfortunately, many sell-siders are juniors fresh out of university—overwhelmed for the first couple of years—and they operate inside a culture that rewards herd behavior over independent thinking. Keep that in mind when you read their price targets (which I haven’t done in years). They struggle to think outside the box on gold and, in a rising tape, basically set targets to match the market. Groupthink at its finest. It’s a total waste of time.

Anyway, my value approach is not timid, as you will learn further down. Nor should it be—with a Latina supermodel. But it’s a shade more conservative than what I did at Alamos’s Island Gold, where we have a no-brainer growth track over five years and on-the-record guidance from John McCluskey. Here, we wait. The unicorn orebody makes the inferred feel borderline a no-brainer (hence the 9.4Moz in the model), but we’ll let the assays, not the adjectives, carry the rest of the day.

The range of outcomes is wide: Fruta del Norte could carry 9+ million ounces for years—if not decades—via steady year-by-year replacement; or the resources could peak in the next few years. What the drilling already suggests is that average grades aren’t improving the way they did at Island Gold—but tonnage (ore volume) may grow. Time will tell.

One last remark on exploration: you read our Alamos piece. You know what to look for on resource upside: continuity that scales, geometry that mines, competence that recovers, metre by metre.

That’s the essence of land optionality. FDN has the address. Now let the drill bit write the invitations. At the very least, near-mine results should keep replacing reserves for years to come, as 2024 already showed. Now let’s watch out when the first maiden resource for Bonza Sur is decleared.

Meanwhile, FDN isn’t just a geological unicorn, it’s an operational case study too.

Read more

“It’s the optionality value of the land, the value of the operator spending money on our land, and the optionality to higher gold prices. And that is worth so much money… it’s what’s given us the Goldstrike billion-dollar royalty, the Detour billion-dollar royalty, the Tasiast royalty, and so on.”

Pierre Lassonde, Founder Franco Nevada

Guiding Principle

Last month I promised a series of gold-miner drill-downs. This is the first, and it will set the tone for the rest. My aim is simple and unfashionable: help you look under the roof of resource companies the way we have done for more than 10 years. This is not trading. It is fundamental work anchored in an industrial view of how mines actually make money, tied to a Discounted Cash Flow that treats the business as if you owned 100% of it. Gold will remain volatile, yet the metal sits in a structural bull I intend to lay out in detail this year. For now, we begin where it matters: the miners.

I’ll start with Alamos Gold because it lets us teach the discipline of underground mining through a live, compounding case: Island District, Young-Davidson, Mulatos pivoting underground, and Lynn Lake moving from permit to construction. You will learn how geology, method, power, people, and capital combine in the only way that counts—cash flow. You will also see why words like “resource,” “reserve,” “cutoff,” “AISC,” and “optionality” are not jargon; they are the grammar of value.

Thereafter and as a preview, this series will continue with Lundin Gold, then K92 Mining and Osisko Development. Each of these underground operations or soon-to-be operations sit at a different point in the life cycle, in a different jurisdiction, with different ore bodies and methods—long-hole stoping versus bulk tonnage, shaft versus ramp, grid power versus diesel.

Those choices explain costs, margins, replacement ratios, and the pace of discovery. They also let us talk plainly about capital structure: royalties, streams, prepay gold loans, and why taxes—royalties, VAT, withholding, windfalls—are not a footnote but a central driver of intrinsic value. Country risk will be treated the same way: not sentiment, but contracts, cash costs, power tariffs, permits, and social license.

Later in the series we’ll move to open-pit gold miners and heap-leach operators, because understanding how oxide flowsheets print cash at scale is as important as knowing how a shaft mine compounds.

If you stay with me through this arc, you won’t need to chase tickers or narratives. You’ll have the tools to read a technical report, translate it into cash, and decide whether time is your friend or your enemy.

That, in the end, is the point of this Substack. Let’s begin…

Alamos Gold and the Value of Land Optionality

Pierre Lassonde bought Franco-Nevada’s first royalty in 1986 on the Goldstrike mine in Nevada’s Carlin Trend for US$2m. At the time it was a small heap-leach run by Western States Mining.

Soon after, American Barrick (now Barrick) bought Goldstrike and drilled deep. The result was a 50Moz system that powered Barrick—and turned Franco-Nevada’s tiny cheque into a franchise.

That is land optionality: let a capable operator spend money on your ground, let geology and time do their work, and let higher gold prices widen the funnel.

John McCluskey at Alamos has done the same in his own way. Few outside the industry realize he’s a living legend—active, disciplined, and still compounding.

If you want a clean, liquid way to be long gold with operating leverage, Alamos Gold is, in my view, the best beta in the space that still trades easily.

Why is Alamos special? It starts—and ends—with people.

Read more

Ration Cards in the “Petrostate”

Gasoline in Russia is being rationed from Kaliningrad to Vladivostok.

The state that styles itself an energy superpower can’t keep its own drivers on the road. In region after region, stations are limiting buyers to 10–20 liters per visit—if they have gasoline at all; elsewhere only diesel remains—which 98% of Russian passenger cars do not use. Russians move on gasoline.

Even pro-government outlets acknowledge ad-hoc curbs: Lukoil stations in Moscow banned fills into canisters and suspended certain fuel cards around Nizhny Novgorod to tamp down panic buying. This isn’t rumor; it’s on the record.

On some days, Russia’s refining capacity has fallen by nearly a fifth, with exports from key ports sharply curtailed. Crimea’s local newspaper reported that about half of Crimea’s gas stations have already run dry. But the situation seems also severe in the Far East and the Volga Federal District, where supply lines stretch thin and shortages bite hardest.

OMT Consult’s latest analysis measures the closing of petrol stations nationwide and suggests that only within the month of September 2.6% of all gas stations have closed down — a reduction by 360 petrol stations. They show that independent gas stations are overproportionally effected, with a uneven effect by region.

Prices tell a similar story, even though retail fuel is heavily managed and never a pure market signal. The exchange tape is. On the country’s main wholesale venue, the St. Petersburg International Mercantile Exchange (SPIMEX), AI-92 settled up 1.9% to 73,144 rubles per tonne—about US$0.66 per liter, US$2.50 per gallon, or US$105 per barrel at ₽82/US$. Those are hard prints—before retail taxes.

Volumes are the clincher. As Kremlin-friendly Kommersant noted in its 17 September 2025 market wrap, gasoline turnover fell to a two-year low: AI-92 sales dropped 21.7% d/d to 15,600 tonnes, AI-95 slipped 15.5% to 12,060 tonnes, and total gasoline sales slid 19.1% to 27,700 tonnes. Peak seasonal demand colliding with unplanned outages drains inventories fast—and the tape showed exactly that.

The capacity side is worse. In a 18 August 2025 Telegram post, Seala (Сиала) — a Russian energy-market analytics firm that compiles real-time stats on crude and product flows, refinery operations, and LNG — estimated that 226,000 tonnes/day of crude-refining capacity and 12,000 tonnes/day of condensate processing were offline nationwide at that time.

More recent reads are starker. Citing Seala’s plant-by-plant analytics, RBC Pro—the paywalled professional edition of the RBC business outlet—reported that by 28 September roughly 38% of Russia’s primary (CDU) refining capacity—about 338,000 t/day—was idle, while capacity suitable for producing gasoline and diesel fell 6% in August and a further 18% in September. On 1 October 2025, OilKapital repeated the same Seala-based figures: roughly 38% of primary units were down, i.e., this was not routine maintenance.

On 2 October, Seala (Сиала) clarified on Telegram that the “38%” figure reflected peak September downtime; by early October some units were returning from accident-related shutdowns. Their breakdown attributes 70% of September losses to drone strikes, with the balance to scheduled work. They also note that temporary restarts of older primary units skew yields toward fuel oil, leaving the gasoline balance much tighter than diesel.

Important caveat: the above October improvements are Seala’s forecast trajectory, not a statement that normal operations have broadly resumed.

My view? That trajectory is optimistic. Ukraine’s long-range drone campaign shows no sign of abating. On 4 October 2025, Ukraine’s General Staff listed fresh strikes, including Kirishinefteorgsintez near St. Petersburg. And Russian repair cycles are anything but straightforward under sanctions: parts, catalysts, control systems, and specialist contractors are all constrained. We unpack that later in this piece.

One more note on method. I pride myself on independent, data-heavy work and try to stay clear of propaganda—on both sides. Here, the exchange prints and Seala’s capacity math line up with what TV, Telegram, and even X are showing on the ground.

The fuel crunch in Russia is real—and it’s national, not local.

Minister Novak reacted as usual, with an extention of the diesel and gasoline export ban for producers — hardly surprising.

How Russians Move

If you want to grasp the drama of today’s shortages, start with a simple truth: Russian households run on gasoline.

The country counts roughly 55 million registered vehicles, of which ~46 million are passenger cars. Only a sliver of those cars are diesel. New-car data underline the point: diesel’s share of new passenger registrations has collapsed to about 1%; in the installed fleet it’s only a few percent. If you’re driving in Russia, you’re almost certainly burning gasoline.

My table below does the heavy lifting, but here’s the headline: 0.801 mbpd of gasoline fuels private mobility, while 0.608 mbpd of diesel is consumed mostly by commerce, bus fleets, agriculture, and the military. Gasoline moves people; diesel moves the economy. That single split explains almost everything that follows.

Now put that fleet into its geography. Outside Moscow and St Petersburg, public transport thins out fast. Intercity rail is engineered around freight first, passengers second; timetables are sparse, routings indirect.

Yes, there are seven metro systems, namely in Moscow, St Petersburg, Kazan, Nizhny Novgorod, Novosibirsk, Samara and Yekaterinburg. Yes, there are a handful of higher-speed corridors, notably Moscow–St Petersburg with branches toward Nizhny. But once you leave the big hubs, daily life is road-bound.

People often wave around “Russia has 85,000 km of railway” (and pundits love to confuse Moscow’s ornate metro stations with nationwide service) as if that settles the question. It doesn’t. Network density, frequency, and passenger capacity per person are what matter for everyday resilience—on those metrics, Russia lags far behind rail-first countries.

Measured as track per land area, Switzerland has about 129km per 1,000 km² (Germany 108; UK 131; France 43). The U.S. and Russia sit near the bottom—single digits per 1,000 km²— because their distances are continental and populations are spread out. Sparse track can still haul a lot of coal and containers. But it does not automatically move people.

A cleaner like-for-like is passenger-kilometres per capita and offered capacity:

• Switzerland (SBB) in 2024: 20.5bn passenger-km and 75.1bn seat-km offered. With 9 million people that’s 2,280 rail passenger-km per person and 8,340 seat-km of capacity per person. Rail is designed to be the default. The average Swiss takes 54 rail trips per year—and most ride the train twice a day for work.

• Russia (RZD) in 2023: 136.3bn passenger-km (103bn long-distance; 33bn suburban). With 146 million people that’s 930 passenger-km per person — about 40% of Swiss usage. RZD does not publish comparable national seat-km, but given longer trains serving lower density, offered capacity per capita is well below Swiss levels. And none of that speaks to what happens after you step off the train in a far-flung oblast without trams, frequent buses, or reliable taxis. Believe me. I have been in the pampa many times. Not pretty.

That’s the structural backdrop to the shortages. Western Europe, Japan, South Korea—even China now—are built to move people by rail: short headways, dense stops, seamless hand-offs to metros and trams, and very high seat-km per capita. When petrol hiccups happen, life mostly continues; you take the next train.

Russia isn’t built like that. Distances are vast, settlement patterns thin, and outside a few cores the practical default is the road—for work, shopping, medical visits, and seeing family across an oblast. If gasoline is scarce, there isn’t a dense, high-capacity rail fallback to absorb everyday trips. In that sense - but only in this one - it is similar to the United States.

That’s why the current crunch cuts so close to the bone. Russians do not use gasoline for home heat or power—that’s district heat and natural gas. They use gasoline for mobility: getting to work, stocking shops and pharmacies, moving children and the elderly, keeping ordinary life ticking over.

So when you see ration limits of 10–20 litres per visit, wholesale exchange volumes hitting two-year lows, and capacity analytics showing a large share of CDUs down, translate that into lived reality: in a road-locked country whose households overwhelmingly drive gasoline cars, fuel shortages matter - immensely. And winter is arriving too, don’t forget.

In Soviet and post-Soviet writing, public transport is rarely a refuge; it’s a trial. Venedikt Erofeev’s Moscow to the End of the Line unfolds entirely on a suburban elektrichka that lurches, stalls, and seethes with overpacked carriages, hawkers, and drunks—a rolling purgatory where time and timetables dissolve.

The through-line is clear: outside a few privileged corridors, rail and trolleybus were something you endured, not a flexible backup that can absorb a sudden shift from cars to carriages. That’s why gasoline shortages translate into queues, cancellations, and fewer trips—not a standstill, but a grinding drag on everyday life. Let me say it bluntly: everyone tries to avoid public transport, if they can.

Let us now move to the supply side and drill down on some inconveniences.

Supply: Big Picture First

At Burggraben we track global crude and liquids balances closely. Even with wartime opacity, Russia’s oil system is still measurable.

Russia produces roughly 10–11 mbpd of crude. About half leaves the country—moving either by sea or through Transneft’s pipeline grid (whose site is now geo-blocked for most Western IPs). The remainder, around 5.5 mbpd, is run through domestic refineries.

On destinations, the pattern is clear: India absorbs about 1.4–1.8 mbpd of Russian crude; China takes roughly 2.2–2.4 mbpd—about 1.7 mbpd seaborne, with the balance via pipelines feeding the ESPO/China network. Hold those anchors; they frame everything that follows and they’re harder (and more expensive) to find than you’d think.

The Great Consolidation of Russia’s Oil Empire

To our knowledge, Russia operates 24 active and relevant refineries.

Official counts sometimes reach 38, depending on how multi-site complexes are categorized. However, many smaller independents became irrelevant after Igor Sechin’s Rosneft consolidation crusade began in 2004—a campaign that transformed Russia’s oil sector from a patchwork of competing firms into a single, hierarchical system run by the security elite—the siloviki.

Catherine Belton chronicles this in Putin’s People: the siloviki turned oil and gas wealth into an instrument of political control. The destruction of Yukos, following Mikhail Khodorkovsky’s confrontation with Putin in February 2003, was the turning point: a fake auction of assets, legal theater for political expropriation.

The Bashneft raid in 2014 replicated the playbook: Sistema’s jewel seized, Vladimir Yevtushenkov confined, and in 2016 Bashneft formally folded into Rosneft. Markets noticed; trust never recovered.

By the late 2010s, consolidation was all but complete. Gazprom Neft retained limited operational autonomy. Novatek sits inside the President’s inner circle; its co-owner Gennady Timchenko is a regime pillar.

Lukoil remained the last bastion of genuine professionalism under Ravil Maganov: transparent, disciplined, commercially minded. In 2022, days after Lukoil’s board called for peace, Maganov fell from a hospital window and died. Officially, an accident. Unofficially, the end of corporate autonomy in the Russian oil and gas sector. As the great Garry Kasparov once wrote on X: “every country has its own mafia, but in Putin’s Russia, the mafia has its own country.”

By the time the siloviki finished re-wiring ownership, most of Russia’s refining sat inside state or state-aligned groups (with Rosneft roughly 40%). Retail prices were essentially administered—via excises, the ‘tax manoeuvre,’ the 2019 damper, and ad-hoc export curbs. The net effect wasn’t just higher prices over time; it was a system optimized for central control and export netbacks, not resilience. When a few big refineries go down, there are fewer independent suppliers, thinner inventories, and the shortage shows up at the pump fast.

The 24 That Matter

On that happy note, let’s focus on the 24 industrial-scale refineries that actually determine Russia’s gasoline and diesel supply.

Between 2016 and 2021—when corporates still reported with some rigor—the system produced roughly 900,000 barrels per day of gasoline and about 1.5 million barrels per day of diesel.

Those company tables are unusually useful because they split output into domestic sales and exports. That lets us check our demand math from the consumer side: around 800kbpd of gasoline burn at home, and roughly 750kbpd of diesel—leaving a diesel surplus on the order of 700–800kbpd for export.

The pattern is consistent year after year (excluding the COVID trough of 2020). Russia is roughly balanced on gasoline—able to cover passenger-car demand in normal times—but structurally long diesel. In practical terms, gasoline is the weak link; diesel carries the safety margin and will only become a bottleneck long after gasoline shortages break the system.

We can cross-check this with external flow trackers. Kpler’s seaborne data for 2021 show gasoline exports of 89kbpd versus 86kbpd in the company reports—almost a perfect match. On diesel, Kpler shows 695kbpd versus 773kbpd reported domestically; the gap is what you’d expect once you account for pipeline and rail movements to neighbors plus export timing differences.

Close enough to be statistically reassuring—and strong confirmation that the 24 refineries, not the long tail of “teapots,” are the ones that matter for national fuel balance. That’s the backdrop for everything that follows: a concentrated system, balanced on gasoline in good times, now being stress-tested by strikes on its conversion units.

And once again: Everything above is arithmetic, not attitude: company refinery ledgers cross-checked against independent flow telemetry and our internal balances—data that outlives the news cycle.

Structurally Short Gasoline

There is more.

The imbalance isn’t just about outages; it’s baked into how Russia refines crude. On average, Russian plants are less technologically complex than their Western peers. Their Nelson Complexity Index (NCI) sits mostly in the 5–9 range; the U.S. system averages 9–11.

That number isn’t a vanity score. It tells you how much conversion muscle a refinery has—how far it can push heavy molecules “up” the value chain. Lower NCI means fewer and smaller high-conversion and upgrading units—fluid catalytic crackers (FCCs), hydrocrackers, reformers, cokers—and therefore less flexibility to tilt the yield toward light, high-value fuels like gasoline when the market screams for it. Configuration and capital intensity lock in those limits; you can’t just turn a valve and make more octane.

The Lukoil table (likely the best in Russia) makes this visible plant by plant. A mid-complexity refinery with limited FCC or hydrocracker capacity simply doesn’t have the hardware to swing its slate. If a hydrotreater goes down, even temporarily, gasoline production isn’t just lower; the quality of the blendstock (sulfur, aromatics, octane) becomes a bottleneck. And every bit of this gets harder when catalysts, sensors, compressors, and DCS components live under sanctions.

Then comes the feedstock - I usually like to call it the refinery diet. Most of the domestic system runs on Urals, a medium-to-heavy, sour grade (about 31–32° API, 1.3–1.4% sulfur). U.S. refiners, by contrast, process a lighter, sweeter diet—WTI 39–40° API plus very light shale streams blended with heavier Canadian barrels.

The chemistry is merciless: heavier in, heavier out. Urals yields more middle and heavy fractions—diesel, fuel oil, vacuum gas oil—while lighter crudes naturally produce more naphtha (the raw material for gasoline) and kerosene.

That’s why the yield tables look so different. In the United States, a barrel of crude reliably throws off 47% gasoline thanks to lighter feed and a conversion-rich system designed to maximize the octane pool. In Russia, the gasoline yield is closer to the low 20s because both the molecules and the machines lean toward diesel and residuals.

For decades, none of that was a problem. The Soviet and post-Soviet economies were diesel-heavy—freight, agriculture, construction, the military. Middle distillates were the sweat spot. Now overlay war-time attrition and that slate becomes a liability.

When Ukrainian drones hit conversion or treating units—FCC risers, hydrocrackers, naphtha hydrotreaters, reformers—the problem isn’t only physical; it’s chemical. You can sometimes limp along by running older primary units (CDUs/VDUs) to keep crude moving, but that pushes yields toward fuel oil and vacuum gas oil, not motor gasoline.

There’s also a quieter bottleneck insiders keep flagging: clean gasoline depends on hydrotreating — and hydrotreating depends on hydrogen. Russia’s Euro-5 sulfur cap (10 ppm) makes those units non-negotiable. When a hydrotreating/reforming train is down, or when catalysts and sanctioned parts are slow to arrive, crude can still flow through the CDUs — but the gasoline pool tightens anyway.

Of course, public reports don’t spell out “hydrogen shortages,” yet the pattern fits: sanctioned parts crippling a key gasoline unit at NORSI; repeated strikes on Ust-Luga cutting light blending components; and Seala/RBC Pro tallies showing sharp losses in capacity suitable for making gasoline and diesel. In refinery math, that’s how you run out of gasoline long before you run out of crude.

And that difference matters—immensely—when a handful of key conversion units go dark.

A laundry-room way to think about clean gasoline

Think of a refinery like a giant laundry.

• The crude distillation unit (CDU) is the washer that sorts and spins out the big loads (light, middle, heavy “fabrics”).

• The conversion units (cat crackers, hydrocrackers, reformers) are like heavy-duty cycles and stain removers that break down the tough stuff into smaller, more useful items.

• The hydrotreaters are the detergent stage that actually gets things clean—they strip out sulfur and other impurities so the “shirts” (naphtha streams) are wearable as on-spec gasoline.

Now the quiet constraint: detergent = hydrogen. Hydrotreaters only work if there’s enough hydrogen flowing through the plant. If a hydrogen unit or a hydrotreating train is down (or starved of catalyst/spares), you can still run the washer (the CDU) and keep turning the drum—but what comes out isn’t clean enough to wear. In fuel terms: crude keeps arriving, but the gasoline pool tightens because you can’t desulfurize and finish enough blendstock to spec.

That’s why outages or sanction-snagged repairs in those “detergent” stages show up as gasoline shortages long before you “run out of oil.” The shirts are there; they’re just not clean enough to put on the rack.

Feedstock Geography: The Asian Lifeline

There’s a geographic logic to Russia’s refining problem that sits on top of the chemistry.

West of the Urals, the system runs on Urals blend—a medium, sulfurous crude that feeds most domestic refineries and the Baltic/Black Sea export grid. East of the Urals, the stream is ESPO (Eastern Siberia–Pacific Ocean), a lighter, cleaner barrel. ESPO’s specs (roughly 34–35° API, 0.5% S) make it naturally friendlier to gasoline/jet and light distillates than Urals (31–32° API, 1.3–1.4% S), which leans toward middle and heavy fractions. The molecules already predispose the product slate before a single valve turns.

But ESPO’s importance isn’t just chemical—it’s topology and politics. ESPO flows east through the dedicated ESPO pipeline to Kozmino (near Nakhodka), where it is loaded straight onto Pacific tankers. A smaller Pacific outlet, De-Kastri, ships light crude from Sakhalin projects (often blended and marketed separately), but for our purpose the point is the same: the Pacific system is plumbed to move light barrels out to Asia.

In 2023, those Pacific outlets together averaged on the order of 1.0 mbpd of crude exports, the overwhelming majority landing in China (with periodic parcels to Japan and South Korea when sanctions, insurance, and pricing aligned).

Set that against the western grid. Primorsk, Ust-Luga, St. Petersburg on the Baltic, Murmansk in the far north, and Novorossiysk on the Black Sea used to ship >2 mbpd of Urals into the EU and UK (note that mostly exports from Novorossiysk include exports from Kazakhstan too which are deducted below).

Post-sanctions, those flows collapsed and were re-routed mainly to India and Turkey—but only with longer voyages, higher freight, and a persistent discount to Brent to clear the barrels. The Russian west kept its heavy slate and its older refineries; the east kept its premium stream and direct Asian demand.

Two Russian Oil Economies

In effect, Russia now runs two oil economies—two crude diets with two distinct stacks of pipelines, refineries, and tanker routes.

West of the Urals sits the domestic-and-western system built around Urals: heavier, more sulfurous, and largely processed in older plants whose gasoline yields are highly vulnerable when conversion units go down—whether from strikes or maintenance.

To the east, the export system is built around ESPO, a lighter, cleaner blend that moves to Asia and typically clears at near-market prices.

Russian Oil Infrastructure

Pipeline physics make the split real.

Deliveries via the ESPO corridor to mainland China began in 2011. From the Russian grid, crude feeds a 942-kilometer China branch operated by CNPC and then into the northeastern pipeline network. Capacity started at 15 million tonnes per year (300kbpd), was later lifted to 20 million tonnes, and in 2018 China built a parallel line for another 15 million tonnes. Together, the two lines can move roughly 35 million tonnes per year—on the order of 700kbpd—directly into the Chinese system.

On the refining side, CNPC’s Daqing Petrochemical has been upgraded to process around 3.5 million tonnes per year of Russian crude. Daqing slots into an established northern fleet—Dalian, Liaoyang, Jilin, Jinzhou, Jinxi, Harbin, WEPEC—that runs ESPO blended with domestic grades. The ESPO share typically ranges from 15% to 50%. That isn’t trivia; it’s a reminder that a refinery’s “crude diet” is a capital choice: units, catalysts, and control schemes are tuned to a specific envelope of crudes, and the return on that tuning is earned back over years, not months.

That engineering reality sits on top of a commercial one. Moscow cannot simply redirect meaningful ESPO volumes to domestic refineries to chase higher gasoline output from lighter crude (higher API, lower density).

The barrels are plumbed east—to Kozmino on the Pacific and directly into China—under long-dated supply arrangements that took years to negotiate. Russia and mainland China signed a long-term supply contract in 2012 for roughly 15 million tonnes per year over twenty years, and similar commitments underpin the broader ESPO stream. Rerouting would fight both pipeline topology and the economics of plants already optimized for ESPO. Most of all, it would antagonize your most important buyer—the last partner the Kremlin can afford to alienate.

The practical implication is straightforward. If domestic gasoline shortages persist, the path of least resistance is not to starve the premium ESPO stream, but to import finished gasoline from China or other friendly refiners—if logistics permit.

Kremlin Math

There is more.

At $64 Brent as of this writing, ESPO has become the Kremlin’s financial lifeline for an illegal and self-destructing war. Nikolai Patrushev, the architect of that war, is unlikely to care about the arithmetic. But the arithmetic cares about him (and certainly about his son Dimitry), so let’s spell it out.

Sanctions and logistics frictions force Moscow to sell Urals at steep discounts to India and Turkey. In 2024, Bloomberg still quoted the Urals–Brent differential at roughly minus $12/b (see chart) — textbook monopsony: a few dominant buyers squeezing a captive supplier. The discount isn’t ideology; it’s just that Indian refiners like cheap.

Start with the Urals barrel. At Brent $64.5, less a $12 discount, you clear $52.5 FOB. Now walk down a realistic cost stack. Lifting runs $8–20/b depending on field and water cut; transport & marketing add $4–5/b; sustaining capex is at least $6/b but likely closer to $15 if you want tomorrow’s barrels to arrive; export duty contributes a couple of dollars on top of that. You’re quickly in the $25–35/b neighborhood before the Mineral Extraction Tax (MET).

Then the Kremlin raises the MET coefficients to keep the budget funded, and once you layer in export duties, war-risk freight, and insurance premia for the gray fleet, there isn’t much left to finance future barrels. As the Lukoil series showed up to 2023 (they stopped breaking it out in 2024), net profits on many Urals barrels collapse into the low-teens — and lower still on the tail of “hard-to-recover” barrels.

ESPO, by contrast, still clears near Brent in Asia — often at very narrow discounts or the occasional small premium. Call it $64.5 FOB at Kozmino against a broadly similar operating stack (with some east-side fiscal quirks). That leaves a pre-MET margin in the mid-30s per barrel. In other words: the premium eastern barrel pays for the war without immediately starving every upstream project that touches it as you can clearly see in my first table above.

The key takeaway is not that Gazprom Neft or Lukoil forgot how to run oilfields; it’s that the fiscal dial has been twisted to prioritize near-term budget cash over field economics.

The government could not afford to keep Urals-side MET gentle, so it didn’t. That props up the budget today, but it starves the upstream: less internal cash flow means lower reserve replacement, delayed maintenance, and a slower cadence of workovers and infill wells. It is the oil-patch version of eating your seed corn — the pipeline looks full now because you’re emptying the bins meant for next season.

None of this detonates tomorrow. It does, however, set the slope of the next few years. The more the state leans on MET and export levies to backfill the budget, the more Urals-weighted producers defer capex and cannibalize decline-mitigation work (e.g. reserve and production replacement). And Urals are the majority barrels Russia still produces. ESPO keeps the lights on; Urals determines whether the lights dim.

That’s the uncomfortable arithmetic behind the headlines: budget stability today bought with production instability tomorrow. Arithmetic masquerading as strategy — the kind that keeps pipelines full now by emptying fields later.

Which brings us to the status quo of the Russian oil fields.

The Slow Demise of Russian Oil Fields

Read more

Freeport’s Grasberg Copper Gold Mine: More than “Force Majeure”…!

Freeport has declared force majeure at Grasberg — and with good reason.

This will shake both copper and gold balances. Let me explain why.

Grasberg: a Giant

Grasberg is one of the largest mines on earth, producing roughly 1.7 billion pounds of copper (≈2% of global supply) and 1.6 million ounces of gold annually (≈1.5% of global supply).

Think of it as a vast underground city: 28,000 employees, 250 kilometers of tunnels across dozens of levels. Each year, another 35–40 kilometers are added — about the length of Switzerland’s Gotthard Base Tunnel, the world’s longest rail tunnel.

At its heart lies the Grasberg Block Cave (GBC), accounting for about 70% of reserves and output. Other sections include Big Gossan and Deep MLZ.

Ore bodies in Grasberg Block Cave Mine. There are five existing blocks in the Grasberg Block Cave Mine, i.e., Grasberg Block Cave, Kucing Liar, Big Gossan, DOZ, DMLZ. Each block is accessed through a spur towards the Portal at Ridge Camp.

Disaster Struck

On September 8, disaster struck: roughly 800,000 tons of wet material suddenly rushed in, flooding multiple underground levels. The mud hit GBC directly — the very core of Grasberg’s production.

A catastrophic failure. How was this even possible?

Here is a clip. The stuff of nightmares

Block Caving: Rare and Risky

Block caving itself may become central to the story. Out of more than 12,000 active mines worldwide, only about 20–25 have ever used block caving. Today, fewer than ten are active. That’s <0.1% of all mines.

It is an exceptionally rare method, reserved for very large, low-grade underground ore bodies, which themselves are scarce. Most mines use open-pit, stoping, or cut-and-fill.

The economic appeal of block caving is obvious — very low cost per ton. But the geotechnical risks are immense. Once caving starts, the process is essentially an engineered collapse of the mountain. What could possibly go wrong?

The Climate Dimension

Grasberg doesn’t just face block caving risk — it faces it in one of the wettest places on earth.

The mine site and access road receive around 12 meters of rainfall per year, with rain on about 330 days annually. Papua often records monthly peaks above 2 meters. And remember: Grasberg is high in the mountains.

Compare this to El Teniente in Chile, the world’s largest underground copper mine, also a block cave. Its “normal” rainfall? About half a meter annually. Same method, completely different hydrological setting. And Chile is not tropical humid — infiltration and groundwater pressure risks are fundamentally lower.

Wet muck is a known risk even in Chile’s dry climate. In Papua’s rainfall regime, the risk should be an order of magnitude higher.

Wet Muck: The Nightmare Failure Mode

When water infiltrates a block cave, broken rock can turn into a dense slurry — wet muck — that suddenly rushes into tunnels. It is one of the most feared failure modes underground. And it appears to be what happened at Grasberg.

Yet what are analysts saying? Everyone parrots “force majeure” and “back by 2027.” Why is wet muck risk missing from the conversation?

Read more

In natural resources, companies can only move in two directions: they either grow, or they decline as reserves are depleted. Standing still is not an option. Both paths can create wealth — or destroy it — for shareholders.

A disciplined management team can, in theory, extract the last ounce of a great gold, copper, nickel, or oil deposit efficiently and return capital to shareholders without needing to risk reinventing itself. The Lundins have done this successfully, over and over again.

Yet in practice, very few succeed like them. A resource company without a long-term vision is often like a sinking ship: it struggles to attract and retain talent, trades at a discount to NAV, and destroys capital as the asset is undermanaged, underfunded, or both. The slightest hiccup can push costs above breakeven and put the entire asset at risk.

Meanwhile, growth has an even worse track record. From ExxonMobil to Chesapeake in oil & gas, from Glencore to Rio Tinto in base metals, from Barrick to Newmont in gold — history shows a consistent pattern: resource companies are, on average, poor stewards of capital, mediocre operators of assets, and chronic under-estimators of geological and geopolitical risk. The result: declining earnings per share, dwindling reserves per share, and dismal returns on invested capital.

The key problem starts at the beginning of the replacement process: discoveries. Finding a meaningful gold discovery resembles finding the proverbial needle in a haystack. Not only are new discoveries scarce, but they are shrinking in scale. Industry databases show that the average “major” discovery of the past decade (>2 Moz) contains about 3.5 million ounces, down from 5.5 million ounces in the 2010s.

But even this overstates reality, since only deposits above 2 Moz are counted. In practice, most new deposits being advanced today are in the 1–2 Moz range — far too small to replace the 5–10 Moz depletion profiles of the majors and often too small to be durable commercial successes. No discovery from the past 10 years has cracked the list of the world’s 30 largest, underscoring just how rare Tier-1 gold finds have become.

And size matters. A 5 Moz gold deposit can sustain 200–300 koz of annual production over 15+ years, making it bankable, scalable, and attractive to majors. By contrast, a 2 Moz deposit typically supports <100 koz/year over a short mine life. Fixed costs dominate, debt is harder to raise, and the economics are fragile to any hiccup in commodity prices. That is why smaller deposits often end up stranded.

It gets more brutal. One of the great truths in resources is that big deposits often get bigger, while small deposits usually disappoint. History shows that Tier-1 discoveries like Grasberg and Yanacocha grew multiples of their original size as brownfield drilling continued, whereas most 1–2 Moz deposits fail to reach production or underperform if they do.

Rubicon Minerals’ Phoenix project in Ontario is a cautionary tale: once promoted as a 3 Moz high-grade discovery, it consumed ~US$770m of capital, then collapsed when production fell short of forecasts. Industry studies confirm the pattern: fewer than 10% of small discoveries become lasting mines, and those that do rarely replace what majors need. As investors, we must be wary of “promising” small deposits — the odds are stacked against them.

So why bother with natural resources at all? Because cyclical industries, when understood properly, can be the most rewarding of all. A quality asset bought early — or a stake alongside a talented, disciplined steward — can easily return tenfold within a few years.

The evidence of stewardship and long-term value creation is clear: the Lundin family (multi-cycle builders across mining and energy), the Sawiris family office (patient capital behind Endeavour and G Mining), Pierre Lassonde (royalty pioneer at Franco-Nevada), Robert Friedland (copper visionary at Ivanhoe), Rob McEwen (who revolutionized exploration by crowdsourcing Goldcorp’s Red Lake data, unlocking world-class discoveries), Bill Beament (who led Northern Star to a decade of outperformance), Andrew Forrest (who turned Fortescue into an iron-ore giant), Kjell Inge Røkke (who shaped Aker BP into a disciplined oil & gas platform), and Amir Adnani (who built UEC into the leading U.S. uranium producer). Collectively, they prove a simple truth: in resources, leadership and stewardship often matter more than the rock itself.

But not every story ends like the Lundins or Lassonde. For every world-class steward, there are dozens of companies built on hype and hope. Spotting the difference is where investors must be rigorous.

Take Hurricane Energy. In 2017, it was one of the UK’s most hyped oil stories — a “fractured basement” discovery touted as holding 460 million barrels. Backed by reputable investors and praised widely, the narrative was irresistible. We commissioned RS Energy Group in Toronto to study the resource. Ross Runciman, a senior geologist there, returned a 100-page report. His conclusion, boiled down: the deposit was a fluke. That US$50,000 report protected our capital. Within two years, production collapsed and the company failed. The lesson: in resource investing, one must understand the resource itself — and oneself, independently — because reports and teams often don’t, or worse, mislead.

And while going the extra mile takes discipline and hard work, much of this is not rocket science and doesn’t require big capital outlays with independent specialists. It comes down to common-sense curiosity: asking the right questions, checking assumptions, and refusing to take glossy presentations at face value. Anyone willing to be patient and diligent can build the tools to succeed. My goal with this series is to share what we look for — and help you build your own independent framework to spot value and avoid costly mistakes.

In the coming months, I will lay out the DNA of great, mediocre, and poor resource companies: what defines them, why they create enduring value (or don’t), and how to spot them early. We will start with gold miners. Gold, I believe, is in a super-cycle. I prefer to begin where you can convert insight into results immediately, while I remain cautious on the cycle for copper and energy commodities.

But why bother at all if even mediocre miners could benefit from a gold upcycle? Because there is no rule that says they must. So far, poor quality has not benefited, while quality gold companies have performed extremely well over the past 12 months. By the end of this series, I hope you will see clearly why quality almost always outperforms — and feel equipped to separate signal (5%) from noise (95%) for decades to come.

One important rule we must establish upfront to avoid misunderstandings: I will not tell you what to own. Instead, I will explain what makes a mining company high-quality and how we value it. Prices move; strategies change; above- and below-ground risks strike. I cannot update my views monthly. Ultimately, you are the steward of your own capital. My aim is to provide a framework you can apply independently.

For annual subscribers, I’m happy to provide short feedback on gold names you’re considering — as input to, not a substitute for, your own due diligence.

Finally, a word on approach. At Burggraben, we are investors, not traders. That is not a dismissal of trading; it reflects my background in private equity and operations, and the long-run statistics: patient investing, with time as your ally, tends to outperform attempts to time markets. Our promise is to focus on structural insights — at the company and sector level — and to go the extra mile so you can make higher-conviction decisions.

So: in the months ahead, expect deep dives into individual gold miners (likely around ten, across seniors, intermediates, and juniors). In parallel, we’ll address copper, uranium, oil & gas, and the European gas market (TTF) as winter approaches. We’ll also update our work on China and offer context on geopolitical shifts such as the war in Ukraine — because what Russia does still matters for commodities.

Warm regards,
Alexander Stahel

PS: Which Senior gold miner would you like me to discuss first and why for the above excel list? Please send us a message.

Lesson 9: Peace is a Process

From Bolero to Dayton: Sarajevo’s Rise, Fall, and the Illusion of Peace

In February 1984, the world turned its eyes to Sarajevo—in admiration. Then part of socialist Yugoslavia, the city hosted the Winter Olympic Games under the stewardship of the late Spiljak Presidency. For two radiant weeks, Sarajevo became a rare symbol of openness during the Cold War. Even Western sponsors like Coca-Cola, Kodak, and Miller Brewing poured money into the biggest sporting event ever staged in a communist country outside the Eastern Bloc — a novum.

The Games modernized Sarajevo’s infrastructure, brought in more than $100 million in spending, and ignited a lasting love of sport. One unforgettable moment came when British ice dancers Jayne Torvill and Christopher Dean performed their legendary Bolero, earning twelve perfect sixes and captivating the world. Sarajevo—nestled among snowy mountains—had never seemed more radiant. For a moment, it was a city of coexistence: where Bosniaks, Croats, and Serbs, Muslims, Catholics, and Orthodox Christians lived side by side, and where East and West mingled with elegance and grace.

But sadly, Sarajevo did not survive the decade.

The Collapse of Yugoslavia, the Road to War and the Dayton Agreement

In the early 1990s, as communist regimes crumbled across Eastern Europe, the multiethnic Yugoslav federation began to unravel. Originally created after World War I from the remnants of the Austro-Hungarian Empire as the Kingdom of Serbs, Croats and Slovenes—and later rebranded Yugoslavia—the state had long struggled with internal divisions. Although the formation of Yugoslavia in 1918 was framed as a union of South Slavic peoples, there was no popular referendum in 1919 to approve this historic merger. Slovenians and Croats, emerging from the collapse of the Austro-Hungarian Empire, sought self-determination and initially supported the idea of unification—but under expectations of equality and federalism. Instead, they were absorbed into a centralized monarchy dominated by the Serbian royal house, without direct input from the people.

What followed was not a consensual union but a top-down political construct shaped by elite negotiation and geopolitical urgency. This lack of democratic legitimacy sowed disillusionment early. Some now argue there was never a genuine foundation for a unified “Slavic” state—only an uneasy balance, held together first by monarchical centralism, then by Tito’s charisma and Cold War geopolitics.

Marshal Josip Broz Tito, who led Yugoslavia after World War II, forged a communist federation from this fragile foundation. Through a mix of authoritarianism, decentralization, and strategic neutrality between East and West, Tito held the union together for over four decades. But with his death in 1980 and the collapse of communism a decade later, long-suppressed nationalist forces re-emerged with a vengeance.

When Bosnia and Herzegovina declared independence in 1992—following similar moves by Slovenia and Croatia—the Yugoslav People’s Army and Serb nationalist forces, backed by Belgrade, responded with force. Their goal: to carve out a “Greater Serbia” through territorial conquest and ethnic cleansing.

Bosnia descended into war. The capital, Sarajevo, was surrounded by Bosnian Serb forces in a siege that lasted nearly four years. What followed was one of Europe’s darkest chapters since 1945: ethnic cleansing campaigns, concentration camps, and the systematic destruction of towns and communities—often under the command of indicted war criminals like Radovan Karadžić and Ratko Mladić. More than 100,000 people were killed, the vast majority Bosniak Muslims. In July 1995, over 8,000 men and boys were executed at Srebrenica, the worst genocide in Europe since the Holocaust.

The war ended not with reconciliation but exhaustion—and foreign intervention. After weeks of NATO airstrikes against Serbia under U.S. leadership, the warring leaders were flown to Dayton, Ohio, where they were locked inside an American air base for three tense weeks. Out of this came the Dayton Peace Accords, signed in November 1995.

A Peace of Entities

Dayton stopped the killing (which was phantastic), but sadly it froze Bosnia into a constitutional straitjacket. The country was cleaved into two “entities”: the Federation of Bosnia and Herzegovina, where Bosniaks (around half the population) and Croats (about 15%) dominate, and Republika Srpska, home to most of the country’s Serbs (roughly 31%). Each entity was granted sweeping autonomy. There is no hard border, yet lives are lived apart. Schools teach different histories, children grow up in parallel worlds, and mixed marriages—once common in Sarajevo—have all but vanished.

The state structure is a monument to over-engineering. Bosnia’s 3.3 million people live under a labyrinth of governance: two entities, ten cantons, fifteen parliaments, six presidents, three governments with 160 ministers, 760 deputies, and a three-member state presidency that rotates every eight months. It is government designed to prevent domination—but also to prevent progress.

The Protectorate Within

To enforce this peace, the international community created the post of the High Representative, appointed by the UN Security Council and backed by the so-called “Bonn Powers”: the ability to impose and annul laws, to appoint and sack officials, even to rewrite constitutions. Since 1995, every High Representative has come from an EU country, with American deputies at their side. For three decades, they have ruled like viceroys, stepping in whenever Bosnia’s fragile system teetered.

On paper, this was meant to ensure stability. In practice, it entrenched dependency and corruption. The presence of an all-powerful international arbiter allowed local elites to avoid responsibility, to exploit veto powers, and to paralyze reform. Bosnia became less a democracy than a managed protectorate, where the final word rested not with citizens, but with foreign supervisors. The Dayton Accords promised peace with justice; what they delivered was peace without ownership.

The Strongman of Republika Srpska

Few have exploited this arrangement better than Milorad Dodik. Once praised by Madeleine Albright as a “breath of fresh air,” he is now Bosnia’s most notorious nationalist and likely the sprider of a corrupt empire web. “I am a Serb… Bosnia is only my place of employment,” he declared the day after his inauguration as head of state. Dodik has built his career by railing against the very system that sustains him—mocking Bosnia as illegitimate, flirting with secession, and courting Moscow.

He welcomes Kremlin-linked biker gangs to Banja Luka, endorses Russia’s annexation of Crimea, and promises that Republika Srpska (RS) is a “state-in-waiting.” When scandals or fiscal crises threaten him, he escalates secessionist rhetoric to rally his base. Sanctioned by Washington, tolerated by Brussels, he thrives on the dysfunction Dayton created. By institutionalizing ethnicity, the Accords rewarded politicians who divide rather than unite.

In many ways, Dodik’s story is a familiar one in Eastern Europe, that of a politician changing his stripes when the moment suits, and courting Russia as an ally (think Victor Orban or Robert Fico). But here in Bosnia, the stakes are higher, not just for the people who live here, but for the legacy of a significant American foreign-policy achievement, too. By taking aim at the Bosnian state, Dodik is, in effect, targeting the Dayton Accords, one of the signature peace deals of the 20th century.

Why does he do it? Simple. Deception. It’s always deception from corruption. As Michaela Ulbrichtová writes in her article titled “Milorad Dodik’s metamorphosis and the hijacking of the Dayton peace agreement”:

But what is the real logic behind Milorad Dodik’s current political strategy? Is he again seeking to divert attention from his corruption scandals and simultaneously gain additional political credit from media publicity, or has his political game gained more threatening contours in light of global geo-political changes and his close ties with the Russian Federation?

His political dominance is built on systemic looting: state institutions captured by loyalists, public contracts awarded to cronies, and media and civil society muzzled through legislative intimidation. Transparency International’s Corruption Perceptions Index paints a bleak picture: Bosnia scored 33/100, ranking 114th out of 180 countries—the worst in the Western Balkans and second-worst in Europe after only Ukraine and Russia. In an indictment of Dayton's design, these abnormalities have thrived under the cover of institutional paralysis and international cautiousness.

The latest? In April 2025, Bosnia’s State Court and Prosecutor’s Office sought international arrest warrants for Dodik and RS assembly speaker Nenad Stevandić, accusing them of subverting constitutional order. They had declared daytime police and judicial authorities null within RS—an egregious legal defiance. Interpol ultimately rejected the request, deeming it politically motivated.

By June–July 2025, Dodik was convicted in absentia and sentenced to one year in prison and a six-year ban from political office. His courtroom absence was emblematic; he rejected the verdict outright, labeling it politically engineered. He continues to defy the ruling with legislative maneuvers that bolster RS autonomy and deepen the constitutional crisis.

This conflict has triggered what analysts now call Bosnia’s gravest political crisis since Dayton, exposing the fragility of its institutional architecture—and the ease with which a single figure can weaponize it

Clearly, His Excellency Christian Schmidt lacks either the courage or the mandate to end Dodik’s corruption theatre. For all his sweeping powers under the Bonn framework, he acts more like a cautious administrator than a determined guardian of peace. Instead of decisive action, we get stern communiqués and vague warnings to Brussels—that Bosnia is once again “at risk of breaking up.”

The risk isn’t theoretical. It’s already unfolding. And Schmidt, despite his authority, seems to believe that appeasement is still a viable strategy. But appeasement never works with strongmen. It emboldens them.

In trying to avoid destabilization, the High Representative preserves the very dysfunction that makes collapse more likely. And in doing so, he confirms what many in Bosnia already feel: that the international community no longer has the will—or perhaps the interest—to confront the very forces unraveling the peace it once imposed.

Protest Without Change

Ordinary Bosnians see through the illusion and corruption. They have taken to the streets again and again, only to be met with inertia.

In 2014, as many as 40,000 people protested across 20 cities, torching government buildings in outrage over poverty and failed privatizations. Between 2018 and 2019, Banja Luka saw weekly rallies under the slogan “Justice for David,” after a young man’s suspicious death exposed state complicity. In 2023, more than 10,000 marched against gender-based violence after a femicide was broadcast live on social media. And in 2025, students in Sarajevo flooded the streets, blocking roads and demanding accountability for corruption and disaster mismanagement.

Each protest began with a spark but revealed a deeper truth: Bosnia’s peace is shallow. The war is over, but the system that replaced it works for corrupt elites, not citizens.

A Laboratory of Illusions

Anthropologist Larisa Kurtović calls Bosnia a “political laboratory”—a place where Western liberal powers tested peacebuilding models, declared victory, and moved on. For a brief moment after Dayton, Bosnia was the showcase of liberal internationalism. But as global attention shifted—first to Iraq, then to the financial crisis, then the Arab Spring—Bosnia slipped into the margins. What remained was a hollow peace: stable enough to endure, fragile enough to stagnate.

What makes Kurtović’s critique especially urgent is her challenge to the geopolitical imagination itself. She urges us to move beyond the illusion that peace can be engineered through ready-made models or universal norms. Lasting peace, she implies, cannot be imposed from above—it must emerge from context, memory, and lived experience. But the international community, eager to claim success, never invested in that kind of transformation. Instead, Bosnia became a testing ground for “new forms of technocratic reason”—tools that often deepened existing fractures rather than healed them.

Kurtović’s essay is not just about Bosnia—it is a warning. It asks what happens when peace becomes a product, exported from distant capitals and tested on societies shattered by war. In a world still addicted to quick geopolitical fixes, her words are clear: peace without justice is no peace at all. And forgetting the unfinished past only guarantees its return.

Three decades later, Bosnia remains frozen in the scaffolding of Dayton. It is held together not by trust or reconciliation, but by annexes, vetoes, and international oversight. Its people live parallel lives. Its leaders exploit division. A peace designed to prevent domination has bred paralysis. A system meant to encourage equality entrenches separation. And an international protector meant to guarantee justice now preserves dysfunction, afraid to dismantle the house it was sent to rebuild.

The Orphan of Dayton

Bosnia today is less a country than an orphan of the Dayton order—a post-war teenager never allowed to grow up. Held in a constitutional straitjacket for nearly three decades, the state remains unreformable and paralyzed—yet paradoxically, reform is its only hope if it’s ever to join the European Union.

The very structure meant to guarantee peace has instead become a perfect playground for nationalist strongmen and systemic corruption. Leaders like Milorad Dodik have no genuine interest in European integration—they thrive on division. Public life operates like a patronage racket: loyalty to the ruling parties is traded for jobs, permits, and favors. Citizens, not ideology, are the real losers in this market of influence.

Meanwhile, the High Representative hovers like a distant guardian angel—equipped with sweeping Bonn Powers, yet increasingly reluctant to use them. His role is to ensure stability, but not to challenge the roots of dysfunction. He preserves the scaffolding of Dayton, but never clears the space to build something new. In practice, Bosnia is trapped—not collapsing, but unable to grow. In chess terms, it is not in checkmate, but in pat—a stalemate in which no one wins and no one can move.

The paradox is partly bureaucratic: to shake the system would risk the very mandate the international community still clings to. Why dismantle the rules of the game, when the game justifies the referee’s existence? What this leaves behind is a suffocating climate—not one lacking talent or energy, but the conditions to use them. Entrepreneurship is choked by a political class that acts like a mafia: blocking permits, hijacking contracts, and strangling competition. Prosperity would empower people—and that, more than anything, would endanger the elite’s grip on power.

The Dayton Accords promised peace with justice. What they delivered is peace without ownership. And thirty years later, Bosnia lives in managed silence, waiting not just for stability, but for permission to grow up.

From the Stagnation of Dayton to the Promise of European Accession

Bosnia’s political paralysis today is no accident but the direct consequence of the Dayton Accords—a bureaucratic monster designed to freeze peace but inadvertently freezing progress, reform, and national cohesion as well. While Dayton may have prevented outright collapse, it created a system rigged to reward division and empower corrupt strongmen like Milorad Dodik. The very architecture intended to guarantee stability has calcified Bosnia’s political dysfunction, trapping its people in a state of managed silence and suffocating stagnation.

Yet amidst this bleak landscape, a new hope flickers on the horizon: European Union integration. Bosnia’s path towards EU accession offers not just a procedural process, but the potential to finally break free from the deadlock of Dayton’s failure and the entrenchment of corruption. The Stabilisation and Association Agreement (SAA) signed in 2008 and fully in effect by 2015 marked the first concrete step towards closer ties with Europe. The granting of candidate status in December 2022 and recent recommendations by the European Commission to open accession negotiations signal a cautious but growing momentum for reform and alignment with EU norms.

However, the road ahead remains fraught with political obstacles—most notably from Republika Srpska’s leadership, which continues to weaponize ethnic division and reject the very institutions meant to guide Bosnia towards the European future. The entity’s recent legislative moves to annul decisions linked to the High Representative and halt EU-related processes reflect a defiant resistance to integration, fueled by nationalist rhetoric and secessionist threats from Dodik. Why doesn’t his Excellency just take him out?

The EU’s response has been unequivocal: the sovereignty, unity, and constitutional order of Bosnia and Herzegovina must be respected, and political actors must recommit to the difficult reforms necessary to advance the country’s accession path. European integration offers a chance not only to modernize Bosnia’s institutions but to replace Dayton’s brittle peace with a more durable social contract—one built on rule of law, democratic accountability, and economic opportunity.

Whether Bosnia can seize this opportunity depends on overcoming the deeply entrenched political culture that Dayton helped create—a culture that rewards division, protects corruption, and fears the consequences of genuine change. The question remains: can Bosnia leverage the EU accession process to finally break its cycle of dysfunction and reclaim its future?

European Union — A Peace-Building Supranational Project

In the aftermath of World War II, Europe’s leaders embarked on an ambitious and visionary project: to build lasting peace by transcending centuries of conflict through cooperation and integration. The European Union (EU) was born from this ideal, evolving from economic cooperation into a political and security union designed to bind nations so closely that war would become unthinkable.

The project’s origins trace back to the landmark Schuman Declaration of 1950. French Foreign Minister Robert Schuman famously proposed pooling the coal and steel industries of France and Germany—historical sources of conflict—into a shared community that would make war “not merely unthinkable, but materially impossible.” This European Coal and Steel Community, established in 1951 by six founding countries, laid the foundations of the supranational institutions that would evolve into today’s EU.

Peace is enshrined as a core value in the EU’s legal and political framework. Article 21(2)(c) of the Treaty on European Union commits the bloc to “preserve peace, prevent conflicts and strengthen international security,” reflecting its deep-rooted identity as a peace project.

The Common Foreign and Security Policy (CFSP), formalized in 1993 with the Maastricht Treaty and reinforced by the 2009 Lisbon Treaty, enshrines the EU’s foundational commitment to peace. It advances democracy, human rights, the rule of law, and the peaceful resolution of conflicts as pillars of European cooperation.

A famous quote that describes the European Union as a peace project comes from Chancellor Helmut Kohl. On December 15, 1991, at the CDU party congress in Dresden, he said:

„Die deutsche Einheit, die europäische Einigung waren immer unsere Visionen. Jetzt realisieren wir die europäische Einigung, weil es dem Frieden, weil es der Freiheit, weil es der Zukunft dient.“

(“German unity, European unification have always been our visions. Now we are realizing European unification—because it serves peace, because it serves freedom, because it serves the future.”)

Without the EU’s gravitational pull and its conditionality mechanisms, it is difficult to imagine many Eastern European countries—certainly Romania and Bulgaria—achieving the political and institutional reforms needed for stability, prosperity, and democratic consolidation, however fragile those gains may still appear. The European project did not merely offer a vision of peace; it created the structure and incentives necessary to begin building it.

I have personally witnessed this in practice—having dealt with significant civil court proceedings in Romania, I can attest that, despite its imperfections, the system works. That would have been unthinkable without the reforms driven by EU accession. No, it does not extinguish corruption—but it does contain it, and it allows for steady economic and institutional progress. That alone — and for all its flaws — makes the EU model not just a peacekeeping force, but a mechanism for transformation.

The EU’s response to shifting global realities has also involved expanding its security ambitions. The Common Security and Defence Policy (CSDP) seeks to foster a European strategic culture and collective defence capacity. The Russian invasion of Ukraine in 2022 accelerated this trajectory, culminating in initiatives like the EU Strategic Compass, which aims to deepen cooperation and resilience by 2030.

Beyond military capacity, the EU actively engages in peacekeeping and conflict prevention globally. The European Peace Facility (EPF), launched in 2021, exemplifies this ambition by funding missions that stabilize fragile regions, help prevent conflict, and promote peace worldwide. Currently, thousands of EU personnel serve on peacekeeping missions across continents, projecting the Union’s commitment to security beyond its borders.

The EU, therefore, stands today not only as a unique economic union but as a peace project grounded in supranational governance, multilateral cooperation, and a shared commitment to stability. This legacy of turning conflict into cooperation is particularly relevant to Bosnia and Herzegovina, a country still shackled by Dayton’s fragile peace.

For Bosnia, EU integration offers more than economic gains—it is an invitation to join a system built to overcome ethnic divisions through the rule of law, democratic governance, and shared values. Designed to limit the power of strongmen, the European model provides a promising framework to tackle entrenched corruption, institutional paralysis, and nationalist politics that have long hindered Bosnia’s progress. I have seen it first hand. It works.

As EU leaders like former High Representative Christian Schmidt have argued, European integration offers Bosnia “the best—and perhaps the only—path towards sustainable peace and prosperity.” Yet this path demands more than symbolic gestures. It requires real reforms, political courage, and the willingness to break free from the constraints of Dayton’s outdated framework.

Remove the bad actor in Bosnia, Your Excellency. The time for appeasement is over. Let’s fix it and remove a future source of conflict now.

Cyprus: The Island That Froze

Cyprus is the Mediterranean’s unfinished proxy war—a divided island propped up by a permanent UN buffer zone and an uneasy peace that’s endured for over fifty years without resolving the root conflict. It stands, like Bosnia, as both a monument to international diplomacy and a warning about the paralysis of “frozen peace.”

Colonial Legacies and Political Fault Lines

Global attention first focused on Cyprus in 1955, when Greece-aligned Cypriots—roughly 80% of the population—launched an uprising against British colonial rule, demanding enosis (union with Greece). The minority Turkish Cypriot community supported taksim (partition between Greece and Turkey), stoking ethnic tensions.

To avoid civil war, Britain, Greece, and Turkey brokered a compromise: a newly independent Cyprus. But there was no referendum. On 19 February 1959, the inconvenient Zurich-London agreements were signed—by Makarios and Fazil Küçük—behind closed doors and without consulting the people — a huge mistake once more.

The constitution that followed established a precarious bi-communal republic: a Greek Cypriot president and Turkish Cypriot vice president, each armed with veto power; proportional representation; separatist municipalities. Yet, before long, fault lines cracked. Violence erupted in 1963, and the UN deployed its peacekeeping force (UNFICYP)—one of its oldest missions—to stem the bloodshed.

It looked like a mini-Dayton avant la lettre.

1974: Coup, Invasion, and Partition

Tensions escalated into rupture in July 1974. A Greek-backed coup in Nicosia aimed to subsume Cyprus into Greece. In response, Turkey invaded—claiming its right as a guarantor power under the 1960 treaties. Turkish troops swiftly occupied the northern third, displacing 160,000 Greek Cypriots and prompting a reverse exodus of 50,000 Turkish Cypriots.

Once bustling Famagusta became a ghost town. By August, the island was sharply divided. In 1983, the Turkish-occupied north declared itself the Turkish Republic of Northern Cyprus (TRNC)—a state recognized only by Ankara and condemned by the UN Security Council. To this day, no other country acknowledges it.

Unfortunately, little progress was made throughout the rest of the 1980s, or during the 1990s – largely due to the intransigence of the late Turkish Cypriot leader, Rauf Denktash.

A Peace That Stabilizes Without Healing

The Green Line, stretching 180 kilometers across Cyprus and through Nicosia—the last divided capital in Europe—came to symbolize the frozen conflict. UN peacekeepers patrol it to this day, enforcing a peace that prevents war but deepens separation.

Like Bosnia, Cyprus has been the subject of endless rounds of international mediation—each raising hopes, only to fall short.

The turning point came in the early 2000s, when the Republic of Cyprus was set to join the European Union. Ankara, recognizing that an EU-member Nicosia would gain the power to veto Turkey’s own accession, backed a renewed UN effort to resolve the division. The result was the Annan Plan—a comprehensive proposal for reunification.

But the gamble failed. Greek Cypriot leader Tassos Papadopoulos urged rejection, believing that imminent EU membership would strengthen their negotiating position and yield a better deal later. In the April 2004 referendum, two-thirds of Turkish Cypriots voted in favour, but three-quarters of Greek Cypriots voted against. One week later, on 1 May 2004, a divided Cyprus entered the European Union.

In the years that followed the failed Annan Plan, multiple attempts were made to revive negotiations between the two sides. Yet for a host of political, strategic, and psychological reasons, none gained traction. A renewed sense of hope emerged in 2013, when the Greek Cypriots elected Nicos Anastasiades—a leader who had openly campaigned in favour of the Annan Plan. Two years later, the Turkish Cypriots followed suit by electing Mustafa Akıncı, a moderate and vocal advocate of reunification.

With Anastasiades and Akıncı at the helm, the UN-facilitated talks finally began to show real momentum. Broad consensus was reached across key areas: governance, territory, and property rights. By December 2016, the process advanced to a new stage, with the UN announcing a high-level international conference to tackle the most intractable issue—security guarantees.

The first round convened in Geneva in January 2017, but collapsed on the opening day. A second attempt followed in Crans-Montana six months later, where negotiators endured ten days of intensive dialogue. Yet despite initial optimism, no breakthrough emerged. The UN Secretary-General formally closed the Conference on Cyprus, and once again, the island slipped back into deadlock.

In the aftermath, scholar Van Coufoudakis offered a sober reflection on the impasse:

Hiding behind the rhetoric that only a comprehensive settlement will resolve these issues will only encourage the continuation of Turkey’s illegal conduct. The Cyprus problem was and remains one of illegal invasion, continued occupation, and documented violations of human rights and not an inter-communal problem to be resolved by a new constitution based on the affirmation of the violations that took place in and since 1974 in Cyprus. The UN has conveniently forgotten the consequences of the League of Nations rationalizations over Ethiopia in 1935 and Chamberlain’s folly in Munich in 1938. Accommodating aggressors only wets their appetite.

The Present Paradox

Today, the Republic of Cyprus stands as a functioning EU member state—wealthy, stable, and internationally recognized—while the self-declared Turkish Republic of Northern Cyprus (TRNC) survives largely on Turkish subsidies and political patronage.

Meanwhile, the once-militarized buffer zone has become a tourist attraction: in Nicosia, cafés and shops now hug the edges of checkpoints; tourists wander across for the day, passports stamped on one side but unrecognized on the other. Yet beneath this surface normalcy, the political division remains absolute.

The deeper fracture is psychological. Two generations have now grown up in separation, with no living memory of coexistence. While efforts at reconciliation persist—bi-communal initiatives, civil society dialogues, and cross-line projects—they unfold within a structure that has long ossified.

Like Bosnia, Cyprus is caught in a peace that prevents war but also thwarts true resolution. A conflict paused, not solved.

Four Strategic Paths Forward

1. Continue the UN-Facilitated Federal Talks
Despite decades of negotiation, support for reunification via a bizonal, bicommunal federation is waning. Recent polling suggests that many Greek Cypriots are wary—fearing institutional paralysis, disproportionate power-sharing, and a return to political deadlock.

2. Turkish Cypriot Statehood Ambitions
Formal recognition of the TRNC remains improbable. Few states are willing to endorse unilateral secession, especially when it contradicts UN resolutions and EU law. Recognition would trigger diplomatic backlash and likely economic sanctions from the European Union—a dead end in the current geopolitical climate.

3. Annexation by Turkey
Absorbing Northern Cyprus into the Turkish state would be a dramatic escalation—and a geopolitical earthquake. Though such a move may appeal to some hardliners in Ankara, it would prompt universal condemnation, kill off any remaining prospect of EU accession, and erect a permanent, militarized boundary at the EU’s southeastern frontier. For both Turkish and Greek Cypriots, annexation would mark the end of autonomy—and the beginning of something far more volatile.

4. A Flexible, Incremental Approach
Amid stalemate, a growing number of voices advocate a pragmatic alternative: a slow, deliberate process of mutual gestures. Turkish Cypriots could return select territory or properties; in exchange, they might gain limited access to international platforms, participation in cultural and sporting events, or an agreement on energy revenue sharing. These steps need not imply recognition of the TRNC but could serve as confidence-building measures toward either eventual reunification—or at the very least, a dignified coexistence.

Peace as a Process: Cyprus in 2025

Cyprus remains divided, but the peace process has not stalled—it has shifted into quieter, incremental steps of trust and cooperation.

In early 2025, the UN appointed María Angela Holguín as its new envoy to rebuild confidence through symbolic, low-stakes measures. A high-level summit in Geneva is planned, alongside proposals like new Green Line crossings, joint infrastructure projects, demining, and cemetery restorations—small but meaningful steps toward reconciliation.

On the ground, an EU- and UN-backed initiative is restoring 30 abandoned cemeteries, turning sites of grief into shared remembrance. Trust is being rebuilt one grave at a time. Green Line trade reached €16 million in 2023, with 7.1 million crossings. EU-funded programs support civil society and infrastructure, slowly reshaping coexistence without forcing premature political solutions.

Politics, however, remain deadlocked. Turkish Cypriot leader Ersin Tatar pushes for a two-state solution, while Greek Cypriots reject partition and Turkish military presence. Property disputes and deep-seated grievances continue to fuel tension.

Cyprus today illustrates the essay’s core message: peace is not a fixed moment but an ongoing movement—sometimes slow, sometimes stalled, but never fully abandoned. The real question is whether the will to pursue it endures.

A Mirror to Bosnia

The parallels are unmistakable. Like Bosnia, Cyprus lives under a power-sharing architecture drafted abroad. Like Bosnia, it relies on international oversight: peacekeepers in Cyprus, a High Representative in Sarajevo. And like Bosnia, it shows how a frozen peace—designed to stop war—can also stop transformation.

Both cases reveal a deeper European dilemma: one half of Cyprus is a full EU member; the other, a legal and diplomatic vacuum. Bosnia is promised EU membership, but structurally paralyzed. The continent finds itself managing peace, not building it.

Cyprus teaches us something crucial: the longer a provisional settlement lasts, the more permanent it can become. What began as a "temporary" partition in 1974 has now persisted for fifty years. For Bosnia, the warning is clear—today’s stopgap risks becoming tomorrow’s status quo.

Northern Ireland: From Walls of Division to the Good Friday Agreement

I now turn to my third and final example—one that, remarkably, ends in hope.

The story of Northern Ireland is not merely one of religious or political strife. It is, more powerfully, the story of a peace that was not declared but constructed—patiently, painfully, piece by piece.

For three decades, from the late 1960s through the late 1990s, Northern Ireland endured what became known as the Troubles: an era of bombings and assassinations, of riots, hunger strikes, and funerals that blurred one into the next. At its worst, Belfast was a city physically and emotionally scarred—divided by concrete walls and barbed wire, with neighborhoods split along sectarian lines: Catholic versus Protestant, nationalist versus unionist.

And yet, by 1998, the unthinkable had occurred. A peace agreement—the Good Friday Agreement—was signed. Not a ceasefire in name only, but a genuine and lasting framework for coexistence. In a world littered with failed negotiations and broken truces, Northern Ireland became one of the rare places where a peace process not only held but slowly transformed a society once trapped in the cycle of retaliation.

The Sources of Division

The roots of Northern Ireland’s conflict run deep—centuries deep. They trace back to the 17th-century Plantation of Ulster, when Protestant settlers from England and Scotland were granted land seized from the native Catholic Irish. This colonization didn’t just redraw the map—it planted a lasting demographic and religious divide that would shape Ulster’s politics for generations.

When Ireland gained independence from Britain in 1921, that historic divide solidified into partition. Six counties in the north—where Protestants held a majority—remained part of the United Kingdom. The south became the Irish Free State, later the Republic of Ireland. For Northern Protestants, partition safeguarded their British identity. For Northern Catholics, it marked a betrayal: they were left isolated in a state that did not represent them, cut off from the Irish nation they felt was rightfully theirs.

Northern Ireland became a Protestant-dominated polity. For decades, unionist governments at Stormont—the Northern Irish parliament—presided over a system of institutional discrimination. Housing, employment, and voting districts were all tilted to maintain Protestant power. Catholics were systematically marginalized—treated as second-class citizens in their own land.

Battle of the Bogside and Bloody Sunday

Many historians mark the true beginning of the Troubles with the events of August 1969, when a loyalist parade in Derry triggered days of violence that spiraled far beyond the city itself.

Across Northern Ireland, loyalist groups regularly staged parades to commemorate Protestant military victories dating back to the 17th century. In Derry, the local branch—the Apprentice Boys—planned one such parade for 12 August 1969, a patriotic display set to march directly past the Bogside, a predominantly Catholic and nationalist neighborhood.

For residents of the Bogside, the parade was not just provocative—it was incendiary. Fearing violence, they barricaded streets and stockpiled Molotov cocktails. As anticipated, tensions erupted. Clashes broke out between the Bogsiders, the Apprentice Boys, and the Royal Ulster Constabulary (RUC). The police response only inflamed the situation.

What followed became known as the Battle of the Bogside—three days of fierce rioting in Derry. But the worst devastation happened in Belfast, where loyalist mobs, assisted by the B-Specials (a reserve police force), attacked Catholic neighborhoods and burned more than 1,500 homes.

By 14 August, the Northern Ireland government had lost control. The overwhelmed prime minister appealed to the British government for help. British troops were deployed to restore order—marking the beginning of a military presence in Northern Ireland that would last nearly four decades.

Initially, Catholic nationalists welcomed the soldiers as potential protectors. But that changed quickly. The British Army soon introduced internment without trial, rounding up and imprisoning hundreds of suspected IRA members—many without sufficient evidence or due process. It radicalized entire communities overnight.

By the early 1970s, the violence had calcified into what many regarded as open war. The Irish Republican Army (IRA) relaunched its campaign to force British withdrawal and reunify Ireland. Loyalist paramilitaries like the Ulster Defence Association responded with their own terror campaigns, often targeting Catholic civilians. The British state, for its part, responded with force and surveillance, further fueling resentment.

Then came one of the darkest days of the conflict. On 30 January 1972, Catholic civil rights activists in Derry staged a peaceful march to protest internment. The British Army was deployed to contain the demonstration. What happened next shocked the world: troops opened fire, first with rubber bullets, then with live rounds. Thirteen unarmed protestors were killed on the spot. A fourteenth died later from his wounds. The massacre would come to be known as Bloody Sunday.

In the years that followed, Northern Ireland descended further into bloodshed. Car bombings, shootings, and sectarian attacks became tragically routine. Paramilitary groups on both sides—such as the Provisional IRA and the Ulster Volunteer Force—claimed hundreds of civilian lives, pushing communities even further apart.

Belfast and the Walls

Belfast became the crucible of Northern Ireland’s division. Entire neighborhoods were carved up along sectarian lines. As violence escalated, British authorities began constructing so-called peace walls—towering barriers of concrete, steel, barbed wire, and watchtowers—designed to physically separate Catholic and Protestant communities. By the 1980s, more than 100 such walls crisscrossed the city, turning Belfast into a patchwork of fortified enclaves.

An old friend of mine served as a British Army officer in Northern Ireland in the late 1980s and early 1990s. I remember him telling me how constrained the soldiers were by the rules of engagement: they could only return fire if they were shot at first. It sounds reasonable in theory, but in practice, it created a high-stakes, high-pressure environment. Every action—no matter how defensive—was subject to intense legal scrutiny. Even justified responses could result in formal investigations, or worse, prosecution. It was a kind of warfare unlike most others: fought not just on the streets, but in courts and inquiries long after the bullets had stopped flying.

Like the siege lines of Sarajevo or the buffer zone in Nicosia, Belfast’s walls became physical embodiments of political failure: visible, towering reminders that a society had split and could no longer find its way back together.

Thatcher and the Hard Years

The election of Margaret Thatcher in 1979 marked a sharp hardening of British policy toward Northern Ireland. To Thatcher, the IRA were not insurgents or political actors—they were simply criminals. “Crime is crime is crime; it is not political,” she declared.

In 1981, republican prisoners launched a hunger strike demanding recognition as political detainees. The strike electrified nationalist communities. Bobby Sands, a 27-year-old IRA member, was elected to the British Parliament while starving in prison. He and nine other strikers would die before the protest ended.

Thatcher’s unyielding stance deepened the conflict—but it also shifted its trajectory. For many republicans, the hunger strikes were proof that sacrifice could deliver political legitimacy. Sinn Féin, the IRA’s political wing, began seriously contesting elections, inaugurating what became known as the “ballot box and the Armalite” strategy: using both the vote and the gun to push for Irish unification.

It was a grim duality—violence and democracy running in parallel—but it signaled the start of a long, uneven transition from armed struggle to political negotiation.

Diplomacy and Shifting Ground

Even during the darkest years, seeds of diplomacy were quietly planted. In 1985, Margaret Thatcher and Irish Prime Minister Garret FitzGerald signed the Anglo-Irish Agreement. For the first time, the British government formally acknowledged the Republic of Ireland’s consultative role in Northern Ireland’s affairs.

Unionists were furious, viewing it as a betrayal by London. Nationalists, meanwhile, saw it as long-overdue recognition. Though modest in scope, the agreement opened vital channels of communication between Britain and Ireland—connections that would later prove essential.

In the 1990s, the diplomatic ground shifted more decisively. John Major, Thatcher’s successor, deepened cooperation with Irish Taoiseach Albert Reynolds. At the same time, across the Atlantic, newly elected U.S. President Bill Clinton broke with long-standing policy by granting Sinn Féin leader Gerry Adams a visa in 1994.

The move infuriated London but sent a clear message: the United States was now willing to engage all sides—including republicans—in the pursuit of peace. Adams, once denounced as the public face of terrorism, was suddenly recast as a potential political partner.

Toward Peace

By the mid-1990s, exhaustion hung in the air. The violence, once fueled by passion and ideology, had lost its momentum. The IRA declared a ceasefire in 1994—broken and renewed again by 1997. Loyalist paramilitaries followed suit. Sinn Féin began emphasizing its political role, while unionist leaders like David Trimble came to accept a hard truth: if the bloodshed was to end, a deal was inevitable.

U.S. Senator George Mitchell, appointed by President Clinton, became the mediator—a calm, trusted presence amid deep mistrust. The European Union, working more quietly, invested heavily in cross-community projects that laid the groundwork for reconciliation. The stage was set for a grand bargain.nto cross-community projects. The stage was set for a grand bargain.

The Good Friday Agreement

On April 10, 1998, after marathon negotiations in Belfast, the Good Friday Agreement was signed. It was a triumph of careful language and painstaking balance. Among its key provisions:

• A new Northern Ireland Assembly, based on power-sharing between unionists and nationalists. Neither community could govern without the other.

• Cross-border institutions to foster cooperation between Northern Ireland and the Republic of Ireland.

• The British and Irish governments became joint guarantors of the agreement.

• The “consent principle” was enshrined: Northern Ireland would remain part of the UK unless a majority chose otherwise.

• Paramilitary groups committed to disarmament, and British military presence was scaled back.

• Human rights and equality protections were formally embedded in law.

The deal was put to a vote. In referendums held north and south of the border, it was overwhelmingly endorsed: 71% in Northern Ireland, 94% in the Republic of Ireland. For once, peace had democratic legitimacy. It was not imposed—it was chosen.

After the Peace

The Good Friday Agreement transformed Northern Ireland. Belfast blossomed into a city of cafés, startups, and cultural revival. Tourists came to see the murals that once marked territories and enmities. The walls remained—but now more as monuments than front lines.

Still, peace has been fragile. The Northern Ireland Assembly has collapsed multiple times amid political deadlock. The legacy of trauma, mistrust, and sectarian division lingers. Brexit, too, threatened to unravel core compromises. But the Northern Ireland Protocol—a key part of the UK–EU withdrawal agreement—preserved the open border with the Republic. By keeping Northern Ireland in the EU single market for goods (unlike the rest of the UK), the Protocol upheld one of the central pillars of the peace process: the freedom to move seamlessly across the island.

It is this of creativity and adjustument that is certainly missing in Bosnia and Cyprus today.

The Lesson: Peace from Both the Top Down and the Ground Up

The Northern Ireland peace process stands as a powerful example of how deep transformation happens—not just through high-level agreements, but through sustained grassroots action.

Yes, political leadership was indispensable. Thatcher’s hardline stance inadvertently propelled Sinn Féin into politics; Gerry Adams, once sidelined, became a vital negotiator. David Trimble risked political ruin to push for compromise. Bill Clinton opened diplomatic doors, and George Mitchell’s steady mediation provided the scaffolding for agreement.

But just as crucial was what happened on the ground—in community halls, classrooms, and across neighborhood lines. From PEACE I to PEACE IV to PEACEPLUS, the EU backed over 15,000 reconciliation projects in just five years—spanning dialogue, school exchanges, and shared public spaces. Since the Good Friday Agreement, €2 billion has flowed into peacebuilding. Let me say it again: peacebuilding—not house building.

One Northern Irish civil servant, Quentin Crisp—author of The Naked Civil Servant—once quipped: “When I told the people there that I was an atheist, a woman in the audience stood up and said, ‘Yes, but is it the God of the Catholics or the God of the Protestants in whom you don’t believe?’” Let that sink in.

Let’s Get a Sense of Perspective

Peace in Northern Ireland wasn’t a single event; it was the invisible, relentless labor of thousands over decades. We can measure it.

Since the mid-1990s, EU-funded PEACE programmes supported over 22,500 local projects across Northern Ireland and the Irish border counties. One program alone—PEACE II—engaged nearly 870,000 participants. At the time, Northern Ireland’s population was only about 1.6 million. That’s more than half the country, touched by one initiative.

Let’s do the math. Assume conservatively that each of the 22,500 projects had just two core staff working two years each, at 1,000 hours per year (roughly 4 hours/day for 250 days). That’s 90 million hours of on-the-ground effort (22,500 × 2 × 1,000 × 2).

Add the civil service. With about 25,000 staff over the years, if just 10% of their workload touched peace delivery—grants, reports, coordination with Dublin, London, Brussels, Washington—that adds another 80 million hours (25,000 × 2,000 working hours × 10% × 16 years).

Now factor in civil society. Northern Ireland has one of the most active volunteer sectors in Europe. Surveys in the 2000s recorded tens of millions of hours volunteered annually. Even if just 5% was focused on reconciliation or community healing, over three decades that adds over 300 million hours of effort.

Altogether, that’s easily half a billion hours invested in peace—not counting the conversations, compromises, or quiet moments that never made it into reports.

And that’s the lesson: Peace in Northern Ireland wasn’t simply signed. It was worked into being—again and again—in town councils, church basements, classrooms, and government offices. That’s what “peace is a process” really means: Not a headline. A generational labor. Measured not in words, but in hours.

For Each Hour of Violence—Thousands of Peace Work

If you try to weigh the time it took to stop the killing against the time invested to keep it stopped, Northern Ireland’s balance sheet is lopsided in the best possible way.

Between 1969 and 1998, police recorded 36,923 shootings and 16,209 bombings—roughly 53,000 violent incidents in total. Even if we convert that crudely and conservatively into “hours of fighting” (treating each bomb or shooting as one hour of active violence, though most lasted only minutes), we’re looking at ~53,000 hours of conflict activity.

Now set that against the scale of peace: an estimated 500 million hours of peacebuilding, from civil servants, educators, volunteers, local activists, EU administrators, and community workers over the last three decades.

On that math, the exchange rate of history looks something like this:
For every single hour of recorded violence, Northern Ireland has invested between 1,700 and 3,400 hours of peace work.

And if you lean just slightly closer to reality—acknowledging that many violent incidents lasted less than an hour, or that most peace projects were longer and involved more people—the ratio climbs easily into the many-thousands-to-one.

The point isn’t false precision. It’s scale. The Troubles produced tens of thousands of violent spikes. But peace required millions of discrete actions: Writing grant bids. Booking rooms. Drafting legislation. Mediating neighborhood disputes. Running school exchanges. Auditing funds. Training facilitators. Revising curricula. Listening—again and again.

When translated into time, the truth is simple and sobering: Peace has taken thousands of hours for every single hour of violence—and it still does.

Secret Peacemakers

Peace needs more than top-down diplomacy and millions of hours of work. It needs bottom-up leadership—the kind that can’t be scripted or summoned by official decree.

In 1976, after three children were killed by a runaway car driven by an IRA member shot by British troops, two women stepped into the void. Betty Williams and Mairead Corrigan did something unthinkable at the height of the Troubles: they marched. Side by side with mothers, neighbors, and strangers—Catholic and Protestant alike—they walked into Belfast’s no man’s land, carrying a simple, defiant message: enough.

Barbed wire was pulled down. Silence gave way to conversation. Neighbors shook hands. Streets were reclaimed—not by force, but by will. Their movement, The Peace People, rallied tens of thousands. They didn’t care who held the gun—they wanted the killing to stop. For this, Williams and Corrigan received the Nobel Peace Prize in 1977. The movement would later lose momentum, but not its meaning: it proved that in the darkest hour, ordinary people can lead—and sometimes, they lead louder than governments or guns.

Another such figure was Father Alec Reid, a Redemptorist priest from Belfast who worked behind the scenes for more than 20 years to make the impossible thinkable. He quietly opened channels of dialogue between Sinn Féin’s Gerry Adams and SDLP leader John Hume—laying the human and political groundwork for what would later become the Good Friday Agreement. Reid’s principles—justice, consent, mutual respect—echoed years later in the terms of that peace. And the photo of him administering last rites to two murdered British soldiers in 1988 became one of the defining images of human dignity in the face of brutality.

Hume himself, though a political leader, embodied patience and moral clarity. For decades, he championed non-violence, European-style integration, and constitutional politics, even as he faced criticism for engaging with Sinn Féin. He shared the 1998 Nobel Peace Prize with David Trimble, the unionist leader who also risked everything to strike a deal.

But the deeper architecture of peace was built beyond politics. Thousands of teachers, clergy, youth workers, and community organizers laid the foundation for trust. Initiatives like the Corrymeela Community created safe spaces for dialogue. Women’s coalitions and cross-community groups sustained relationships long before political institutions could formalize them. These “ordinary giants” didn’t make headlines—but they made peace possible. They held the line when official talks stalled, and built the human infrastructure that held Northern Ireland together.

When Violence Becomes Profit

Peace may require half a billion hours of labor, but war—when entrenched in identity and conflict—demands almost no investment yet yields immense returns for a few.

Consider Hamas: multiple credible reports estimate that leaders like Ismail Haniyeh and Mousa Abu Marzouk are billionaires, each with fortunes ranging from $3 to $4 billion, amassed through misused aid, smuggling networks, and investments abroad. Meanwhile, ordinary Gazans—many displaced and impoverished—bear the brunt of conflict.

The situation is worsened when humanitarian institutions become compromised. According to IMPACT-se, over 10% of UNRWA principals and senior educators in Gaza are affiliated with Hamas or Islamic Jihad. These schools sometimes teach extremist narratives, glorifying martyrdom and erasing Israel from maps. The infiltration is not anecdotal—it is operational, using aid networks and educational platforms to perpetuate violence.

In this model, pain becomes capital, and war becomes a means of enrichment—through money, ideology, and power. In such settings, peace treaties can ring hollow unless they dismantle the systems profiting from conflict. Bosnia comes to mind too.

At the end of the day, it’s easy to play the victim, point fingers, or fall into simplistic blame. But it takes genuine courage, hard work, and a grounded moral framework to build a different path. Peace demands not just agreements, but the dismantling of structures that translate suffering into profit.

Conclusion: Peace Is a Process

Once treaties are signed, the real work of peace begins.

Peace isn’t declared; it’s cultivated. It must become a shared mentality—built brick by brick, person by person, community by community. Without broad civic engagement and visible symbols of trust—and without leaders brave enough to walk the political tightrope—peace remains fragile. Northern Ireland shows that lasting reconciliation requires both the wisdom of negotiators and the will of the people. It also demands a clean break from corruption and conflicted interests.

Peace is not a singular event, but a layered process—from negotiating tables to street corners, from foreign diplomacy to grassroots projects. Strong leadership can open the door to compromise, but it is citizens—through schools, youth programs, and quiet acts of cross-community courage—who lay the foundation for something that endures.

For Bosnia and Herzegovina, Cyprus, Kosovo, Moldova, and for Europe as a whole, peace will never be “done.” It must be tended—politically, socially, and psychologically. It must be renewed by each generation, not merely remembered by the last. Northern Ireland proves what’s possible. But it only happened through a peace mentality—powered by collective virtues, not just political signatures.

As Quentin Crisp once said: “If at first you don’t succeed, failure may be your style.” But peace, at its best, rewrites the script.

With warm regards,
Alexander Stahel

Appendix: Turkey — The Candidacy That Froze in Time

Turkey’s EU accession, once a beacon of hope, is now stalled indefinitely. Since applying in 1987 and gaining candidate status in 1999, the process promised to bridge East and West—but that bridge was never completed.

Key obstacles persist: Turkey’s refusal to recognize EU member Cyprus and its democratic backsliding under Erdoğan, marked by crackdowns on dissent and erosion of the rule of law. The EU has made clear these issues are non-negotiable.

No new negotiation chapters have opened since 2016. Accession talks are effectively dead, replaced by “recalibrated partnerships” focusing on limited cooperation. Erdoğan’s pivot eastward and threats to sever ties with the EU underscore the growing divide. Though opposition leaders pledge renewal, the structural gap remains wide.

Turkey’s stalled candidacy reminds us that EU membership demands shared values and reforms—not just strategic importance. Without these, the process grinds to a halt. Sometimes, one can’t help but miss the secular vision of Atatürk.