Coverage of the project reaches for the usual “energy system of the future” platitudes and “underscores its nationwide significance.” But amid the euphoric language, the press release does the sobering math for you: output could supply up to 500,000 households with electricity for around two hours. Germany has about 41 million households. Two hours of power for 500,000 of them is 1.2% of the country, for a fraction of one evening.

Nevertheless, the upside is real for the operator as energy prices last week demonstrated: a battery storage project could buy power for 0 cents per kWh during the day and sell it for 25 cents at night. At its full 716 MWh capacity, that’s €180,000 in revenue in a single day.

Of course, that arbitrage opportunity only exists because ratepayers and taxpayers subsidized volatile overcapacity for a quarter of a century. Any benefit from negative prices is now pocketed by private companies such as EcoStor, the plant's owner—a classic case of socializing the cost and privatizing the profit. With battery storage exempt from paying grid fees for the next 20 years—a cost that everyone else who draws power from the grid has to pay—the business case for the plant obviously penciled out.

This gold rush is unlikely to last forever, though. THEMA Consulting Group, not exactly anti-renewables, modeled what Germany’s battery boom does to the industry’s returns. At 47 GW—the industry’s central case for 2030—a two-hour battery earns about €50,000 per megawatt a year.

Scaled to Förderstedt’s capacity, that’s €15 million a year against a €250 million investment: a 6% revenue yield before running costs. Push capacity to 150 GW—full parity with the envisioned solar buildout—and revenue falls to €12,000 per megawatt. For Förderstedt, that’s just €3.6 million a year, nowhere near enough to justify the investment.

Eventually, the arbitrage opportunity cannibalizes itself, and the problem with volatile electricity generation remains. Regulators haven't missed this. In the last few weeks, three separate tools for managing the problem surfaced in Germany and the UK. None of them make more electricity. All of them decide who goes without it first. Time to see exactly who that turns out to be.

Start in Great Britain. Along with Germany, it's one of the most fervent pursuers of net zero in Europe, despite its energy potential in the North Sea. If you refuse to dial up the input side of the equation, there's only the output side left to control. In a remarkable push towards interventionism, the British government therefore seeks to control how much electricity people use in their homes:

Heat pump households face winter warmth rationing as the drive to net zero raises increasing fears of blackouts.

By the end of next year, electricity suppliers will be able to remotely turn down heat pump central heating to help Britain’s energy system cope with high demand.

Suppliers are expected to do so on the instructions of the quango responsible for coordinating the grid, which is overseen by Ed Miliband’s Department for Energy Security and Net Zero (DESNZ).

Britain’s electricity supply typically comes under most strain during winter cold snaps. The risk of blackouts is expected to become more extreme as net zero policies shift energy demand from gas to electricity and supply becomes more dependent on less reliable wind and solar generation.

One would assume that this strain on the grid would lead the government to slow down the heat pump rollout, but far from it. The government wants to go from 223,000 heat pumps installed in total to 450,000 installed every year by 2030. Since last year, every heat pump must be capable of being connected to the internet. How else could the government turn off your heat when the wind stops blowing on a cold winter day?

Under the proposal, only heat pump households that agree to join the scheme will be included. In return, they will be offered discount tariffs. However, that’s economically the same as saying: if you don’t adhere, you’ll be punished. Since freezing for net zero is almost certainly vital for the grid’s stability, it’s likely the penalty will be high enough to push the median British household into compliance.

Rationing on an industrial scale is planned on the other side of the Channel. Klaus Müller runs the Federal Network Agency, Germany’s energy regulator. He is a former Green Party politician who is now in charge of deciding, if the power gets tight, who keeps theirs and who doesn’t.

As leaked documents revealed last week, his agency has spent at least two years building a new tool to make that decision. The system is called “security platform electricity”—a central command structure for throttling electricity use during a crisis. If a company doesn’t comply, the agency can have its power physically cut.

Any company using at least 8 GWh of electricity a year—chemicals, metals, paper, food processing—must register with the platform. When a shortage looks close, registered companies report their forecast usage. If it turns serious, they get at least 24 hours’ notice to reduce consumption. The companies ordered to shut down get no compensation, since a production ban isn't expropriation, at least according to the legal opinion the agency holds.

None of this was made public until the leak. Asked by a grid operator why the plans had been kept quiet, the agency answered it wanted to avoid public “unease” over such a sensitive topic.

Reducing consumption only works on companies that already have a connection to throttle. Getting one in the first place is another kind of rationing. In Hamburg, electricity connections are now in short supply: the volume of requests for new connections already exceeds the city’s entire current peak demand. Those affected are mainly data centers, battery storage, and power-to-heat systems for district heating.

The city is now working on a new system to allocate connections above a capacity of 1.5 megavolt-amperes. Bremen and Berlin have similar issues. In Frankfurt, one of Europe’s most important data center hubs, the local grid operator explicitly prioritizes connection requests according to a political wish list: heat pumps and private charging stations come first, then projects relevant to greenhouse gas neutrality.

Economic prosperity doesn’t happen where investors can hardly get a grid connection—and if they can, they risk running into rationing. Reversing course, signaling that this experiment has failed, is always possible. The problem is that you need to admit that you were wrong all along. The unwillingness to do so might explain why talks between OpenAI and the German government last year—only made public in July—went the way they did.

A state-of-the-art OpenAI data center on German soil would have spectacularly pushed the country forward internationally as a location for artificial intelligence. But there was one caveat: OpenAI wanted to pick a location near the French border to directly tap into French nuclear power.

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The negotiations failed, with a senior civil servant claiming that OpenAI made pie-in-the-sky promises and then backed down. Since details didn't become public, we may never find out who is to blame. But there’s a plausible explanation for why the talks collapsed: Berlin didn’t want OpenAI to demonstrate the failure of its energy transition by skipping the German grid.

Instead, the country prefers a policy of rationing—a sign of regression. This crop of leaders seems to have forgotten that Europe relied on wind power for centuries. Then the steam engine lifted us out of that poverty.

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Take Pirelli. A third of the Italian tiremaker belongs to Chinese state group Sinochem. That situation's delicacy is obvious when you consider that Sinochem also owns 52% of Chinese tiremaker Aeolus. Sinochem therefore not only gets dividends. It also has influence over the company via its board seats and gets unique insights that could just as easily end up helping Aeolus, such as the technology behind Pirelli’s connected “Cyber” tires.

Unsurprisingly, the Sinochem stake caused quite a stir. Rome has spent the last few years trying to pry the fingers loose and recently renewed and expanded its “golden power” law to force the Chinese board seats down from eight to three.

Control, insights, and dividends are three ways the Chinese stake pays off. There's a fourth, and it pays China even when Pirelli loses. For months the company has feared its Chinese ownership will lock it out of the U.S. market—a threat serious enough that it's weighing up to $1.2 billion to expand production in Rome, Georgia, and stay in. But if Pirelli is shut out anyway, Beijing still wins: a rival cut off from a vital market is a gift to Sinochem's domestic tiremaker, Aeolus.

Four potential payoffs on four dimensions, Pirelli's success and its ruin both landing in China's column. Recent events across the Atlantic suggest this kind of bet is about to get baked into Chinese stakes across Europe. Time to hop to Washington for the details.

American lawmakers take issue with Mercedes-Benz’s ownership structure. In February 2018, Mercedes-Benz got a new largest shareholder. Li Shufu, the founder of Chinese carmaker Geely, had built a 9.7% stake worth around €7.3 billion at that time. He assembled it through a web of derivatives arranged by Bank of America that were structured to help skirt disclosure requirements.

A Chinese company holding a piece of one of Germany’s automotive crown jewels triggered predictable political concern in Germany. But that was only the beginning. BAIC—Beijing’s state-owned carmaker and Mercedes’s longtime partner in China—bought its way to just under 10% in 2019, a deal that only became public in 2021. Those acquisitions are about to cause Mercedes serious trouble:

Mercedes-Benz faces a possible ban on selling cars in the US after a Senate committee passed a bill that penalises groups with Chinese investment, in another sign of mounting rivalry between the US and China.

Mercedes, a German automaker that is 20 per cent owned by Chinese companies, had lobbied the Senate commerce committee to dilute the Connected Vehicle Security Act, which would also ban the import of battery systems from China’s CATL, the world’s biggest battery maker.

The bill bars automakers from selling connected vehicles — which use hardware and software for communications — in the US if they are more than 15 per cent owned by Chinese groups. It still requires approval by the full Senate before being reconciled with any version passed by the House of Representatives.

Some of the pressure came from Detroit. Ted Cruz criticized the decision, saying General Motors had lobbied for the measure in an effort to push Mercedes out of the US. GM sells the bill as a win for American industry, carmakers and steelmakers alike.

The planned 15% threshold is remarkable given that Volvo is 78% owned by Geely, yet Volvo sells connected cars in America. The Commerce Department already cleared it, despite Chinese ownership. Polestar, a company also owned by Geely, asked for clearance too, but that was refused. Barring a strict ownership stake rule, authorization is today decided on a case-by-case basis, and where that line is to be drawn seems unclear.

Will cutting Chinese board seats and walling them off from the data be sufficient? Who knows. In essence, access to the U.S. market turns on a discretionary ruling in Washington. And of course, justifications can be made up on the fly. The investment pays off for China one way or the other.

If Mercedes is shut out of the U.S., less revenue means less power to fund the next generation of cars. A diminished Mercedes is easier to beat. Chinese carmakers might still not be seen as serious contenders to Mercedes for many buyers in Europe, but given the trajectory of the Chinese auto industry, it’s only a matter of time until that changes in the premium sector.

So what can Europe do? Nothing the market offers. Chinese owners are unlikely to give up their position just to accommodate European firms’ standing in the U.S. Ultimately that leaves one tool: the state reaching in and pulling the owner out.

It’s the next step in an escalation that starts with blocking Chinese buyers, like Germany did when it killed a chipmaker’s sale to a Chinese investor in 2022. Germany also capped Chinese stakes already in place, cutting China’s COSCO from 35% to 24.9% of Hamburg’s port.

The top rung is the one Britain just reached with British Steel. In 2016, Tata Steel offloaded the loss-making part of its business that made “long products” like transport rails and steel sections for construction. Greybull Capital bought it for one pound and gave it the patriotic name. Insolvency followed in 2019. A year later, the government's receivers sold it to Jingye, a Chinese steelmaker. Earlier this month, Britain moved to nationalize the company:

The government ​said it was bringing British Steel into public ownership in the national interest to ⁠preserve the country’s ability to make steel domestically.

“Today’s decision secures the future of steelmaking in the UK, protects skilled jobs ​and safeguards a vital national capability,” outgoing Prime Minister Keir Starmer said.

The government seized operational control of British Steel from its Chinese owners, Jingye, in April 2025 to prevent the closure of the steelworks in Scunthorpe in northern England and protect 2,700 jobs at the plant, as well as thousands more in the supply chain.

Treating the question of who owns a company as one of national power is a significant reclassification. It means the company can be seized, or fenced off like any other strategic asset. That will undoubtedly lead to significant pushback from China, despite China itself being a major proponent of economic statecraft. A spokesperson for the Chinese embassy already urged the British government to “engage actively with the relevant Chinese company to seek a solution acceptable to both sides.”

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Being ground between superpowers, European capitals may find themselves tempted to reach for interventionist policies like this more often. Tearing up the positions they let China build in the first place is going to get costly. Europe forgot the old poker adage: if you can’t spot the sucker at the table, you’re the sucker. It sat down thinking the game was only about money and never considered whether China might be playing for something else. It’s getting its answer now, one company at a time.

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The Protocol limits attacks strictly to military objectives: objects that by their “nature, location, purpose or use make an effective contribution to military action” and whose destruction offers “a definite military advantage.” The mere claim that Russia fills its war chest with trade therefore rests on shaky ground as a justification for attacks on civilian cargo. International Maritime Organization (IMO) Secretary-General Arsenio Dominguez condemned the strikes against merchant shipping:

Such acts endanger seafarers, threaten the safety of navigation, disrupt global supply chains and undermine the principles upon which international shipping depends. […] Seafarers should never become casualties of conflicts to which they are not a party.

In light of Europe’s support of Ukraine’s personnel, the responsible individuals are unlikely ever to fear prosecution. In essence, international law remains relevant when it bolsters your position, while breaching it isn’t much of a problem when you can safely assume no consequences will follow. What Ukraine spares is bounded not by any legal considerations but by military feasibility, or considerations of another kind.

Unlike the energy infrastructure deep inside Russia that Ukraine has attacked—refineries, pumping stations, fuel depots—Russia’s LNG export terminals stand untouched. The most important of them is Yamal LNG. Located in the Russian Arctic, it accounts for about 60% of Russia’s LNG exports, and with the pipeline routes to Europe largely gone, it has become the cornerstone of Moscow’s gas-export economy.

Given Yamal’s distance from Ukraine’s border, striking it is difficult, and Russia has undoubtedly prepared to fend off attacks. But it is not out of the question that Ukraine could damage Yamal, whether by missiles or by drones traveling via the Baltic states or smuggled into Russia and launched near the target—an approach Ukraine’s Security Service (SBU) appears to be developing into an operational method. Time to ask when we should expect Ukraine to try to hit Yamal, and what a successful strike would do to Europe’s gas market.

Yamal’s significance to Europe’s gas market was once again stressed by the Financial Times this week:

Europe imported more liquefied natural gas from Russia’s leading LNG project than ever before in the first half of 2026, absorbing nearly all of the Siberian facility’s output months before an EU ban on Russian gas imports comes into effect.

EU purchases from Yamal LNG, which Russia’s privately owned Novatek controls, reached a record 9.89mn tonnes in the first six months of the year — 18 per cent more than in the same period last year, according to data from analytics company Kpler.

On an annualized basis and converted into billion cubic meters (bcm), that’s 27 bcm or about 8% of the EU’s entire gas consumption in 2025. Ukraine has made clear it will strike the energy assets that fund Russia's war, yet that ongoing commercial dependency can plausibly explain why it has spared Yamal thus far—all the more since Ukraine itself is entirely reliant on European support to keep fighting. Past strikes on energy infrastructure suggest a pattern for when that restraint might end:

Nord Stream is the first data point. Gas flowed through it into the summer of 2022, and seven months into the war the pipeline still sat untouched. The commerce ended before the pipe did: Gazprom cut flows to zero in early September, citing maintenance and equipment leaks, while Germany had already resolved in March to phase out Russian gas by mid-2024. Weeks after the last gas stopped moving, on September 26, the pipes ruptured on the Baltic seabed. The sabotage created a fact that made reversing that phase-out significantly harder.

The second data point establishes the same logic from the opposite direction. For years Russian gas flowed west across Ukraine through the Urengoy–Pomary–Uzhhorod line under a transit contract, and Ukraine collected the fees while Russia shelled the country the pipe crossed. Neither side touched it. During its 2024 incursion into Kursk, Ukraine even held the ground around the Sudzha metering station, and still the gas flowed and the station stood. The contract shielded it from the army at it. Then the contract expired on January 1, 2025, Ukraine declined to renew, and about twelve weeks later Sudzha was ablaze. Russia blamed Ukraine, Ukraine blamed Russia. The facility survived three years of war and an occupation, but got destroyed three months without a contract.

Two cases, one rule: commerce is the shield. These assets stay safe while the trade runs and are struck once it stops. Applied to Yamal, what follows is this: From 1 January 2027 the EU bans long-term imports of Russian LNG, and Yamal’s European trade ends by law. This, by the pattern and within the weeks to months the earlier cases took, makes a strike consistent with the pattern from that date onward.

The shield need not fall cleanly, though. Some member states will likely want to keep the Russian-LNG business alive, and dangerously low storage into a cold winter would sharpen the incentive. Greece has already blocked the EU’s latest sanctions package to protect such an interest:

[Greek shipping company] Dynagas has transported more than 10mn tonnes of Russian LNG since the start of 2025 on 11 vessels, according to FT calculations using data from Kpler, a data and analytics company. The FT identified 11 Dynagas ships that completed 144 voyages in that time. Its fleet of Arc7 ships has been specifically built to serve Yamal, which sits on Russia’s north coast in the Arctic Circle. Greece argued that Dynagas would not be able to use the vessels elsewhere and would be forced to sell the vessels to non-western actors, according to those briefed on the discussions. The highly specialised ships are among the most complex to build and cost about $300mn.

There is a precedent for what happens to the energy autonomy of member states that obstruct the coalition. Hungary and Slovakia buy Russian oil through the Druzhba pipeline under an EU sanctions exemption, and both blocked aid to Ukraine and the sanctions the rest of the bloc wanted. It did not protect the pipeline. Ukraine struck Druzhba-related oil infrastructure repeatedly through the second half of 2025, halting flows, then struck the Kaleykino pumping station twelve hundred kilometers inside Russia in February 2026. Budapest and Bratislava demanded it stop. Slovakia cut diesel exports and threatened to cut electricity supplies in retaliation. The strikes continued.

So much for the exemption. Hungary and Slovakia had the oil contract, the veto, and the nerve to cut Ukraine's diesel and power in protest. Kyiv hit the pipeline anyway. The Druzhba episode suggests that Ukraine only cares about the room where the weapons are decided: while Paris and Berlin hold the line, a Greek veto is noise, and the plant is fair game the day European contracts expire.

That settles the when. What a strike would cost is the other half of the question. Even if the Russian energy phase-out holds, taking Yamal offline will not shield Europe from the consequences. Europe would be right in the strike's economic blast radius. Yamal cargoes move Europe's TTF benchmark regardless of a ban, because Europe competes for the same global pool they feed. Remove the volume—around 8% of EU demand—and the supply curve shifts. The price the whole market pays rises.

It's the same mechanism that took TTF from below €20/MWh in the years before the war to above €300 at its 2022 peak and close to €60/MWh this week, even though most of the Russian pipeline gas that vanished was sold off-hub. Physical supply sets the level and the contract type doesn't change that. The obvious objection is the coming LNG glut. But it comes late, and the ban's first winter falls ahead of it. Montel cites analysts warning EU prices could double on a cold snap into low storage. Add a Yamal strike to that winter, and doubling becomes the floor.

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The logic of striking Yamal is compelling for Ukraine and for every European politician determined to make Russia a forever-enemy: unlike a ban that can reverse when leadership changes, the destruction of liquefaction trains is hard to undo. A new government in Berlin or Paris that wanted to resume normal relations would face the difficult task of convincing Russia to rebuild for Europe. Those shaping today's events understand the normative power of facts, however loud their professed commitment to the rule of law.

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A decision handed down by the High Court in London this week was likely perceived with the same kind of satisfaction. On July 6, the court ruled on Nord Stream AG v Lloyd’s Insurance Company. Nord Stream AG—the Swiss-registered operator of Nord Stream 1, majority-owned by Gazprom—had sued its insurers for €579 million, after blasts near the Danish island of Bornholm ruptured three of the four lines of the Nord Stream system: both lines of Nord Stream 1 and one line of Nord Stream 2, which was insured separately and is not part of this case.

The insurers—Lloyd’s Insurance Company S.A. and Arch—refused to pay under a war exclusion covering damage “directly or indirectly occasioned by, happening through, or in consequence of war.” The policy also excluded damage done by a government. But the court did not need it. War alone decided the case, and the insurers won. Nord Stream recovers nothing.

At first glance the outcome seems obvious. There was a war, and the pipelines got destroyed. But claimants don’t ordinarily spend a small fortune on a six-week trial, complete with dueling experts on geopolitics and explosives science, if the answer is obvious. Judges don’t ordinarily need 96 pages to explain an obvious answer.

The reasoning that decided the case has the potential to reach far beyond a Gazprom subsidiary’s damage. Like much of what Europe has adopted in response to this war, it can backfire. And the people applauding it are the ones least likely to see it coming. Time to hop to London for the cross-examination.

Presumably every property policy in the world contains a war exclusion, and the reason—far from being a punitive measure—is math. Insurance works by pooling losses that strike randomly and are uncorrelated. That model breaks down in a war environment: entire regions get destroyed at once, and losses can exceed the capital of the insurance industry itself. War has been carved out of standard cover for centuries.

The critical question has always been where war’s causation ends, and English case law has delineated the boundaries generously. In 1916, the court considered the death of an army officer struck by a train while inspecting sentries along a railway line in wartime England. No enemy was within hundreds of miles. But the blackout was a wartime measure, the darkness killed him, and the loss was held to be a consequence of hostilities.

In 1922, warehouses full of tobacco burned in Smyrna (modern-day Izmir, Turkey) after the Greek occupation of the city. It couldn’t be established who lit the fires, but that didn’t matter, because the ill-feeling created by the invasion was cause enough. The principle that emerged is that it suffices if war is a contributing factor you can specifically point to. It doesn’t have to be the main one.

But simply pointing to “war” with no threshold whatsoever gets you into vague territory quickly. Bornholm sits in the Baltic Sea, about 1,200 kilometers from the nearest fighting in Ukraine. No shell has landed anywhere near it. If you asked people whether a war exclusion should apply to damage this remote from any war zone, most would assume distance counts for something, that at some point a pipeline is too far away for a war on someone else’s border to claim it as a casualty.

There’s a second reason suggesting distance from the exclusion clause. The pipelines weren’t in active use for gas flows when they were sabotaged. Nothing was flowing that a saboteur could stop, and Gazprom wasn’t making a cent off them either way. An idle pipeline, sitting outside any war zone, doing nothing for anyone’s war effort, is a remarkable thing to call a casualty of war. But that’s something for insurance law academics to dwell on.

The court didn't have to answer where the threshold sits, because it never reached the question. It asked a different one: assuming each of four candidates it considered—Russia, the United States, Ukraine, or a Ukrainian substate actor—had carried out the attack, would the war have been a significant cause of its actions?

For Ukraine, sabotage would have served the war effort against Russia. For Russia, pressure on Germany over its support for Kyiv. For the Americans—a country not formally at war, however obvious its fingerprints—the court found the motive would still have traced back to the war, since the attack would have been aimed at influencing its course. The link to the war travels through intention, and intention can originate anywhere and land anywhere. Thinking like that doesn't stay contained.

This is a first-instance ruling, not yet tested on appeal. Still, if proximity or functional relevance to the fighting isn’t what matters, this reasoning will hardly stop at the Baltic seabed. Last week I argued that this war has the potential to seep into other countries through extraterritorial operations: bombings on European soil. Does any sabotage anywhere in Europe, so long as a plausible Russian or Ukrainian angle exists, now carry the same exposure? Russia might strike to pressure Europe into cutting aid. Ukraine might strike to keep the pressure running the other way. Neither has to be proven. The mere possibility might be enough to sink the claim.

But insurance is not just protection. It’s a precondition for capital. No bank finances a piece of infrastructure without a lender’s requirement that the asset be insured against destruction risks, and if that insurance has a hole in it, the hole becomes the lender’s problem too. Projects that can’t be insured against a risk that’s now demonstrably real can still get built, but only with a government picking up the tail. An expanding war exclusion, in other words, shifts the cost of infrastructure security from private capital onto taxpayers.

At the trial, both sides’ market experts agreed on this: as of 2019, energy insurers had confined war-risk cover to floating assets, excluding fixed installations like pipelines and cables. A tanker can sail away from danger and buy war cover for the voyage. A pipeline bolted to the seabed for decades cannot move, so the market did not build a war policy to buy in the first place.

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But even that tanker's advantage is eroding. Six days before the ruling, Ukraine's Deputy Prime Minister Oleksiy Kuleba wrote a letter to the International Maritime Organization (IMO). In it he justifies Ukraine's strikes on tankers trading with Russian-occupied ports, after Moscow accused Kyiv of "terrorism" for hitting them. His argument: vessels exporting oil from those ports "sustain a sector of the economy" and fund the war, so they can't be regarded as ordinary commercial operations.

Shadow fleet vessels aren’t insured in London. But there’s little reason this logic stays confined to occupied ports. The same argument can apply to any cargo a war can plausibly connect to. Greek shipowners made nearly $4 billion carrying Russian oil over the past three years under the G7 price cap, much to the chagrin of Ukraine. Commerce stops being commerce once a war can explain attacks on it. That’s the same idea the London court reached six days later, from the opposite direction.

Applauding all this as a fair rebuke of Russia will come at a cost—in financing, project cancellations, and government balance sheets absorbing risk private capital won't—as European governments acquiesce to the war's sprawl. The bill for that rebuke lands on the West either way.

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The prediction turned out to be clearly wrong while the trends described were correct. Russia did intensify its attacks on Ukrainian energy infrastructure during the winter, though the disruptions have not been severe enough to destabilize the country. The incumbent Ukrainian president remains highly alert to potential rivals. And the demographic drain has Kyiv fighting at both ends: "busification"—systematic, often violent, street-level conscription operations—is documented enough to have its own Wikipedia entry. Meanwhile, the European Commission has suggested withdrawing protection status for military-age Ukrainian men abroad, a plan Kyiv welcomed.

Ukraine’s resilience runs on European money: €90 billion planned for 2026 and 2027, out of €215.2 billion in total. In recent months, this support has emboldened Ukraine to intensify its attacks deep inside Russia, an effort Kyiv frames as pressure on Putin to agree to end the war. Oil refinery capacity has been disrupted enough to force Russia to ban the export of jet fuel until November, and Putin says he is considering a ban on diesel exports to address shortages at home. Depending on what analyst you listen to, Russia’s potential responses run from caving to holding steady to treating the poking as grounds for escalation.

But no matter how Russia responds in the weeks ahead, the element my November analysis missed points to the same outcome regardless: no peace treaty. What the model lacked was a feedback term. The point at which adaptations to a war grow heavy enough to become constituencies for it. If we account for that term, the war becomes something European leaders are almost irrevocably invested in. Time to ponder how these adaptations might shape the continent in the years to come.

Start with the largest adaptation underway. Volkswagen’s decision to cut 100,000 jobs in Germany lists high energy prices among its structural cost pressures, alongside weak demand, labor costs, and competition. This places the EU’s refusal of cheap Russian energy inside the cost structure of the largest job cut in automotive industry history:

Closing the plants at Hanover, Zwickau, Emden and Audi’s ​Neckarsulm site would put more than 45,000 jobs at risk, according to the people. That would add to the 50,000 cuts that are currently planned.

In absolute terms, laying off 100,000 people and ​axing four assembly plants would be the largest restructuring in automotive industry history.

It would be comparable to major shake-ups by GM leading up to and during its ⁠2009 bankruptcy and in the early 1990s when it cut as many as 74,000 jobs over four years and shut or idled 21 plants.

The impact extends past Volkswagen’s payroll. The automotive ecosystem consists of hundreds of smaller suppliers that form the backbone of the German and broader European economy. But the displaced capacity already has a destination. As Euronews wrote mid-May:

Volkswagen is also exploring possible opportunities linked to defence production. CEO Oliver Blume has said the company plans to decide later this year whether military transport vehicles could be produced at Volkswagen’s plant in Osnabrück. At the same time, Blume stressed that Volkswagen would not manufacture weapons or tanks.

Meanwhile, defence companies are increasingly turning toward the struggling automotive sector. Rheinmetall said it is examining whether some of its current automotive supplier sites in Neuss and Berlin could be converted for defence production.

The company is also reportedly considering taking over entire factories from carmakers facing economic pressure. Among the sites being discussed is Volkswagen’s Osnabrück plant, whose long-term future remains uncertain.

That thinking extends past Wolfsburg. As Mercedes-Benz CEO Ola Källenius told the Wall Street Journal: “I think it is absolutely clear that Europe needs to increase its defense profile. Should we be able to play a positive role in that, we would be willing to do so.” The demand Källenius is offering to serve is already contracted. The carmakers are converting toward order books stretching past the end of the decade:

Rheinmetall's backlog stands at €73 billion against 2026 revenue guidance of about €14 billion. That’s five years of production sold before it is built. Leonardo's book exceeds €46 billion. Thales carries €41.6 billion in defense orders, 3.4 years of sales. According to my math, across Europe's largest weapons makers, the signed total reaches roughly €270 billion, before counting the supplier layer. The peace risk is stated exemplified by sell-side analysts at Bernstein Research, who warn that “a sustainable ceasefire in Ukraine would remove the primary catalyst for the defense sector.”

Not everyone benefits from defense spending that consumes capital without forming any, so why does no counterforce form? The Logic of Collective Action explains why small, organized special-interest groups consistently defeat large, unorganized majorities in policy-making. When a policy’s benefits concentrate on a few actors, the lobbying is worth the expense; the costs spread across millions who each lose too little to justify organizing against them. Those who do feel the pain simply leave. Chemical giant BASF inaugurated its world-scale Verbund site in China in March, the company’s third-largest after Ludwigshafen, Germany, and Antwerp, Belgium. Sector-wide investments in Europe’s chemical capacity decreased 86% between 2024 and 2025, according to a Roland Berger study.

Suppose Putin wanted a peace treaty tomorrow. One that, as peace treaties usually do, assumes the return of normal relations: trade resumes and the enemy reverts to being a neighbor. The Commission’s €800 billion rearmament decade was justified because “Russia will remain a fundamental threat to Europe’s security for the foreseeable future.” The decision to let energy-intensive industry wither was accepted on the premise that cheap Russian energy would never return anyway. A normalization treaty would be incompatible with everything committed.

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Barring further escalation, this leaves the configuration that lets the commitments stand: a frozen conflict where the enemy remains an enemy and the spending remains justified. The front hardens into a line of demarcation, and the war persists at the intensity that requires no one to decide anything.

The frozen state is not quiet, though. Fifteen years after the Korean armistice, in 1968, a North Korean commando team reached Seoul to kill the president. And conflicts that don’t end tend to seep into other countries. In the 1970s, the Middle East’s conflict arrived on European soil: the Munich Olympics, the airport attacks, the letter-bomb campaigns, and the reciprocal assassinations fought out in Rome, Paris, and Oslo. Extrajudicial and extraterritorial operations of this kind are already part of this war’s repertoire. Early this week, a Ukrainian woman allegedly bombed a countryman in Monaco who did business with Russia.

That leaves elections as the remaining candidate for breaking the equilibrium. Will the bitterly opposed parties on the fringes bring about a normalization of relations? The record suggests any course correction will be made as hard as possible: Romania annulled a presidential election over alleged Russian interference, France’s courts removed Le Pen from the 2027 ballot, and Germany’s state interior ministers are preparing to change procedural rules before the likely winner can take office.

One only needs to consider the record in leadership turnover since February 2022: four (soon five) British prime ministers, six French ones, and a German chancellor removed early. Through every handover, the aid kept escalating and the rearmament plans intensified. A policy that holds through that much turnover tends to be located in the structure, not the governing personnel. If the analysis is right, there’s no pretty way out of this. Given the number of people dying and a European economy accelerating toward the abyss, the piece I would most like to write six months from now is the one dissecting why I was wrong twice.

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Politicians in France’s neighbor Germany predictably used the lowered nuclear output as proof that nuclear power is “the wrong path,” while conveniently ignoring that a 12% nuclear output reduction is modest compared to the near-total drop in wind generation caused by this week’s almost breezeless days.

Curtailed output also pushes electricity prices higher, and those prices are a recurring theme in French politics. Both the left and right fringes have repeatedly argued that French customers are getting fleeced by Europe’s electricity pricing mechanism, demanding that France exit the European Union’s single energy market. Ahead of the French elections next year, these calls have been renewed this week.

As is the case in almost all industrialized economies, the European energy market runs on a system some people consider unfair: the merit order. In this system, generators submit bids to the electricity exchange. The last power plant that needs to be mobilized to balance supply and demand determines the price that all the resources called upon will receive.

The charge is that the marginal price overpays producers who submitted lower bids due to their lower operating costs. The “fair” solution, some say, is to pay each producer only its own bid. But since market participants tend to do what’s in their best interest, generators would stop bidding their real costs and start bidding their guess at the clearing price. The merit order would lose what makes it work: a price that reveals the true cost of each megawatt.

That marginal spot price serves a critical function: it informs operators and investors of what interconnection, cables, and generation capacity to build. Thus far, no one has come up with a fairer system that won’t destroy these price signals. Attempts at top-down control have only added a considerable layer of complexity, producing a price disconnected from the system’s physical constraints.

But France does not need to exit the single energy market or end merit order to reap the benefits from its low-cost generation. The market forces critics want to override are already moving the country into a position favourable relative to its neighbors. And unlike this week’s heatwave, that position won’t reverse when the weather does. Time to take a closer look.

France is Europe’s largest electricity exporter. In 2025 the French grid pushed a net 92.3 terawatt-hours (TWh) across its borders, more than what Belgium consumes in a year. That volume sells at a different price per unit. France’s system operator RTE puts the 2025 export price at €59 per megawatt-hour (MWh), just slightly below the French spot price. But that price balloons in the countries the electricity flows into.

Across the border, those electrons were worth €101.5 per MWh. In other words, French plants generate the most strategically valuable product on the continent—firm, dispatchable power—and capture barely half of what it’s worth the moment it reaches its neighbors. This raises the question of whether there is a more profitable use for these electrons. There is, and the difference is worth an order of magnitude.

Take again the number France earns today: €59 per MWh. Now route that same MWh into a data center sitting on French soil instead of exporting it. Industry estimates put traditional data centers at about $4.20 in annual revenue per watt of capacity. Spread across a year's run-hours and converted to the same unit, that's roughly €400 per MWh for conventional compute.

AI runs far higher. The same benchmark puts AI facilities at $12.50 per watt, while a separate, bottom-up breakdown of AI data center unit economics lands at roughly $15 million in annual infrastructure revenue per megawatt of capacity. Together they put AI compute between €1,300 and €1,800 per MWh. The exact figures move with utilization, build type, and a volatile market for AI compute, but the size of the gap is not in question: the electron is worth seven to thirty times more as compute than as exported power.

France does not capture the full value, of course. The compute margin accrues to the data center operator, often American hyperscalers. However, the country banks the slice it can tax: corporate income booked domestically, property and local levies, construction and operating wages. The inevitable result: An electron consumed at home anchors a high-value activity that pays French tax, while the same electron exported produces a meager commodity invoice.

The buyers are already here. French data centers drew about 10 TWh in 2024. France’s Agency for Ecological Transition (ADEME) trend path puts them near 37 TWh by 2035. That increment alone—27 TWh of new demand—is larger than the entire net export France sent Germany and Belgium in 2025.

Of course, all this rests on the assumption that AI will become profitable at some point. French politicians also have to execute correctly on the gift of this infrastructure that’s been handed down by a generation of politicians that—looking back—has proven to be of superior competence. The political will for that kind of independence may exist: France reportedly called the US-led “Pax Silica” initiative an attempt to colonize Europe. But since Brussels can’t make enough advanced chips at the cutting edge to go it alone, joined the pact anyway.

From the perspective of generators, having a data center as a customer is beneficial. In contrast to neighboring countries with fluctuating demand, a data center runs flat, around the clock, near full capacity, indifferent to season and spot price, and it signs long contracts to do so. As a result, the firm electron goes to this customer first, ahead of the leftover the export market takes.

For the countries losing out, viewing the loss on the annual average understates the problem. Because the shortfall shows up in the cold, dark, windless winter hours, when their own demand peaks and renewables vanish. What fills the gap when the French import thins is whatever sits next in the stack.

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For Germany, which has retired its nuclear and is phasing out its coal, that means gas. The hours it can least afford the exposure are the hours it now leans hardest on the one dispatchable source it has left. And because power clears at the margin, a few GW of missing French import don’t just cost the volume they represent. They reset the price for every MWh in that hour, up to whatever the gas plant bid. The unwritten assumption behind the renewable build-out—that firm power next door would always be there—no longer holds.

This week’s stress test is caused by heat, and it passes when the weather breaks. A must-run data center claiming France’s firm capacity does the same thing, year-round, and it doesn’t break.

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Transitioning away from fossil fuels is no longer just a climate strategy, it is a security strategy. Domestic renewable energy is, by definition, immune to geopolitical disruption. Wind blowing over the North Sea cannot be sanctioned. Electrolysers producing green hydrogen are not subject to Strait of Hormuz closures.

According to the EU’s REPowerEU plan, the bloc aims to massively ramp up its hydrogen production and imports. By 2050, renewable hydrogen is meant to cover around 10% of the EU’s energy needs. In 2022, all hydrogen—overwhelmingly produced from natural gas—covered less than 2%. Renewable hydrogen is supposed to displace gas in power generation and as a feedstock and heat source in industrial processes. As the Commission puts it: “Hydrogen stands as a key component in the EU’s strategy to the energy transition, net-zero, and sustainable development.”

However, neither domestic nor international green hydrogen production has seen an uptick to any meaningful extent that could cover Europe’s needs, despite member states having spent about €20 billion in subsidies in recent years. Normally, you’d assume that when a technology repeatedly fails to deliver, common sense eventually dictates that funding stops.

But last week’s Draft Scenarios for the Ten-Year Network Development Plans (TYNDP) by ENTSO-E and ENTSOG—the European associations representing national electricity and gas transmission operators—confirm not just the unwavering political commitment to the hydrogen goal. According to this paper, hydrogen should displace gas by 1,600 TWh/year by 2050.

Reaching even half that target through domestic electrolysis is functionally impossible. Generously assuming 80% electrolyzer efficiency, it would require roughly 1,000 TWh of electricity: almost exactly as much as all of Europe’s wind and solar generation combined in 2024, using Statistical Review of World Energy figures.

It took about 25 years to build Europe’s current wind and solar fleet. Replicating that entire buildout once more in the years remaining, and dedicating every bit of the new capacity solely to hydrogen, is exactly as visionary as the Net Zero Industrial Complex™ likes to present itself.

While some of that volume may eventually be covered by nuclear-powered hydrogen production, the bulk would have to be bought on a market that can’t deliver such volumes. Time to check what it takes to make them appear on paper.

In a normal market, when two products do roughly the same job, customers buy the cheaper one. That's the simplest explanation for why hydrogen remains a niche industrial input rather than an energy-transition cornerstone. Most of what the report counts toward that 1,600 TWh is this kind of interchangeable use—gas turbines, boilers, and trucks that can in principle switch fuels—yet the price difference between gas and green hydrogen borders on the absurd.

HYDRIX, the EEX’s weekly market-price benchmark for green hydrogen delivered to German consumers, currently puts that price at €256/MWh. Far from falling as the market matures, it has risen from €238/MWh in the earliest data EEX’s tool shows (June 2025), holding flat near current levels since roughly March 2026.

Cost estimates from the Institute of Energy Economics at the University of Cologne assume the opposite trajectory: domestic German production at roughly €240/MWh today, falling to €200/MWh by 2030, with pipeline imports from North Africa cheaper at €150-170/MWh. Shipped ammonia imports run €250-300/MWh due to conversion and transport losses.

LNG, meanwhile, has traded on the Dutch TTF benchmark between roughly €30 and €50/MWh over the past year. Even hydrogen's cheapest pathway costs three to four times more than gas.

Given this insurmountable price difference, none of the gas substitution happens through ordinary supply and demand. So how does the ENTSO-E report get from that gap to 1,600 TWh of hydrogen anyway?

ENTSO-E's methodology answers that question. Half of all import capacity gets secured through long-term contracts—the kind of take-or-pay structure used in LNG deals, where a buyer commits to a fixed volume regardless of price. The report does not state what these contracts actually cost or how the price will be determined. Instead, the model ranks supply sources cheapest-first to decide what gets used. Then it assigns these contracted volumes a modelled cost of zero, guaranteeing they're used before anything else.

The not-so-unwelcome side effect is that this system is insulated from price signals because the contracts pay out the same whether the bet on hydrogen turns out right or wrong. The cost to tax- and ratepayers will likely be folded into grid fees and EU budget allocations spread across dozens of programs that obscure the true cost of the shift.

In any other market, a bad bet surfaces and gets corrected: prices adjust and capital moves elsewhere. But there's no “elsewhere” in hydrogen—every pathway is expensive, which is why only contracts immune to price make building capacity rational in the first place. No producer sinks capital into electrolysers and export terminals otherwise, because everything else about this trade argues against it.

Infrastructure is the clearest example: what gas has that hydrogen doesn’t is decades of pipelines, storage caverns, and power plants built and paid for. Hydrogen's equivalent network barely exists, because the underlying resource gives producers no reason to build it.

Despite occasional crisis-driven shortages, which are more distribution than production problems, the world has all the natural gas it needs: as of 2021, there were an estimated 7,299 trillion cubic feet (Tcf) of total world proved reserves compared to annual consumption below 145 Tcf in recent years. Given this abundance, there is no economic incentive to even attempt a hydrogen switch on any timeline that matters.

China will inevitably come up as the counterargument: no country pushes harder on hydrogen. Yet even there, hydrogen is just one mosaic piece in an energy-security portfolio that runs heavily on coal. On an energy-equivalent basis, China’s coal-to-liquids (CTL) capacity—11 million tonnes of synthetic fuel in 2023—outweighs its green hydrogen sector—220,000 tonnes per year—roughly 16 times over.

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China’s build-outs reveal what the country actually bets on with capital. Europe’s auditors have reached the same conclusion on paper. As Germany’s Federal Court of Auditors put it in late 2025:

Expectations that green hydrogen would become price-competitive have not been fulfilled so far. Rather, hydrogen will remain expensive going forward as well. Permanent government subsidies are therefore foreseeable as a result.

The EU’s Court of Auditors said much the same a year earlier, in 2024, finding the Commission’s hydrogen targets unrealistic and “driven by political will rather than being based on robust analyses.” Two independent institutions, the same verdict, and the subsidies keep flowing anyway.

Ursula von der Leyen stressed the role of hydrogen once again at the recent EU–South Korea summit in Brussels, shortly before the grid operators’ report went public. Committing increasingly scarce capital to a bet insulated from ever being proven wrong is a vulnerability in itself. The biggest risk to Europe’s energy security may not sit at the Strait of Hormuz but 5,000km away.

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While crazier conspiracy theories have turned out to be correct, the idea that no one will take the other side of a suppression trade would be quite the outlier in the world of commodity trading. Vitol, Trafigura, and Glencore would be printing free money: buy cheap paper, take physical delivery, sell into the real market. With an arbitrage opportunity this enormous, the gap would close.

The deeper problem with the claim that $100 oil is not the "correct" price is that this thinking is backwards: those commenters are so certain about the eventual outcome—massive physical shortage, prices far higher—that they work from that end result and conclude any current price that does not reflect it must be fraudulent. The certainty about the future state is being used to invalidate the current market price. Occam’s razor tells us the simplest explanation tends to be correct, and put it plainly back in April:

Effectively, the markets are pricing a binary outcome: a long war and the potential for catastrophic damage to priceless assets, or a sudden peace and the rush of supply it would bring. If one scenario implies $150 oil and the other $50, is a rough price of $90 all that far off?

However, it is one thing to ask which price is right today. The more persistent question is whether anyone pricing physical supply has ground truth to work from. As Oil & Gas 360° wrote this week:

More vessels are leaving the region after passing the Strait of Hormuz in a dark mode with transponders switched off, and those entering the Persian Gulf to load cargoes are increasingly doing the same.

The dark-mode tactics, once the feature of Iran-linked vessels aiming to skirt sanctions, are now the norm for the majority of commercial traffic at the Strait of Hormuz.

The threat to tankers attempting to pass the Strait of Hormuz has created a new shipping reality. Dark-mode activity, with transponders switched off, is no longer for Iran-linked vessels only. It has spread to commercial shipping of non-sanctioned barrels and other goods that typically move through the chokepoint, data from Vortexa showed last week. Dark transits through the Strait of Hormuz have accounted for 57% of all transits recorded over the period, peaking at 65.2% in May.

A visibility floor as low as 35% at its May peak raises the question of who knows what is moving and who does not. Regardless of whether this conflict ends in the peace deal currently on the table or remains latent for years, that question is permanently reshaping price discovery in oil markets. Time to take a closer look.

Under the International Convention for the Safety of Life at Sea, every cargo vessel above 300 gross tons on an international voyage is required to broadcast continuously on the Automatic Identification System (AIS). This is a VHF radio protocol that transmits position, heading, speed, destination and draught: the vessel’s depth in the water, which acts as a real-time proxy for how much it is carrying. Since that figure is self-reported, it is frequently unreliable. The system was originally designed for collision avoidance but became, in the absence of anything better, the primary data source for global oil market intelligence: the feed behind flow estimates.

One partial substitute for AIS is synthetic aperture radar (SAR) via satellite. SAR confirms a hull is present at the time of the orbital pass, but none of the details AIS would provide. What it can establish is how many vessels are operating without AIS. The gap from pre-conflict norms is substantial. Windward—a maritime intelligence firm whose satellite collections include radar and optical imagery alongside AIS analytics—surveyed the broader Hormuz area on 5 May and identified 167 commercial vessels, 146 were operating dark. A separate SAR collection the following day focused on the northern corridor: 97 vessels, three were transmitting AIS.

Since oil price discovery is such a big business, analysts use all the mosaics they can get in the absence of more reliable data. One method to track oil flows is satellite imagery of oil storage. Large tanks are fitted with floating metal roofs that ride on the liquid surface, rising as tanks fill and falling as oil is drawn. The shadow the roof casts against the inner tank wall reveals fill levels. Tracking those readings at Gulf origin terminals and destination storage facilities allows analysts to recover some of what dark transits remove.

But that method is only an imperfect substitute. Matt Smith, Kpler’s Director of Research, noted in a recent interview that the product inventory draws that would confirm dark cargoes arriving in Asian terminals are “in opaque areas and we just cannot see that right now.” More fundamentally, the Gulf storage cross-check tells you what happened in the past while transit data is a real-time signal. Oil price formation runs on the real-time clock, and a backward-looking confidence check is of limited help.

Not everyone is flying blind, though. In March 2026, Iran began requiring vessels to seek permission before transiting the Strait. In May it formalised the arrangement: the Persian Gulf Strait Authority (PGSA), administered by the IRGC Navy, went live with a domain name, an official email address, and a transit-permit regime.

Before a vessel receives authorisation, it must submit what the PGSA calls a Vessel Information Declaration: over 40 questions covering ownership, insurance provisions, crew manifests, cargo details, past port calls, and intended routing. A permit is issued only after the PGSA accepts the submission and a fee of up to $2 million, paid in yuan or Bitcoin, is settled.

The PGSA’s cargo manifests give Iran comprehensive intelligence on flows before vessels move. In price formation, who knows first prices first. The logic is that of payment for order flow: see the order before the market does, price accordingly. With the Strait of Hormuz representing 20-25% of global maritime oil trade, Iran will want to keep a system in place that preserves that informational advantage even if it dispenses with the toll fee. And as the US is increasingly insulated from Middle Eastern supply, the PGSA’s informational architecture may not even register as a concession worth demanding.

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Foreign Minister Abbas Araqchi has already insisted that the administration of the Strait of Hormuz “will not return to the pre-war era.” Such arrangements tend to have remarkable durability. As points out, Denmark controlled the Øresund Strait from 1429 to 1857. Even after Denmark lost the eastern shore to Sweden in 1658, the toll system stayed in place for another 199 years.

The payment infrastructure for non-dollar energy settlement is scaling rapidly alongside the conflict. CIPS, China’s dollar-alternative interbank settlement network, processed an average of $134 billion per day in March 2026, a 50% surge from February that coincided exactly with the conflict’s onset. While this is not direct proof of PGSA-linked flows, it indicates that capital will find ways to monetise an informational advantage of this scale, inside or outside Western settlement systems.

The “correct” price of oil will remain elusive. Dated Brent and Dubai assessments are constructed from visible, Western-compliant transactions. PGSA-corridor flows—yuan-settled, excluded from assessment windows—contribute nothing to those assessments. What the benchmarks record is increasingly the price of what stays visible: a shrinking fraction of the market, self-selected for Western compliance. Traders pricing oil from those benchmarks are working from a signal with a growing blind spot.

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Against that backdrop, a recent proposal by Federal Network Agency (Bundesnetzagentur) president Klaus Müller deserves more attention than it has received. The agency is preparing a new pricing framework for industrial consumers: capacity charges, surcharges for exceeding contracted capacity, and flexibility incentives. In his own words:

We enable commercial and industrial consumers more flexibility in electricity consumption. There are great opportunities to respond more strongly to low electricity prices. Large consumers and the power system benefit equally.

Müller’s mandated task is to keep the grid reliable. But he is also a Green Party member, and as such his allegiance is to follow the net zero dogma without deviation. Bringing both imperatives into alignment is what his call to give “commercial and industrial consumers more flexibility in electricity consumption” aims at. Beneath the flowery language, an unrelenting constraint is hiding. Electricity production and consumption must match in real time, or the grid fails. If production follows the weather, consumption must follow it too. Hum during the breeze, go quiet during the cold doldrums. Production a function of meteorology.

Germany’s energy-intensive production is already in decline. As the Federal Statistical Office reports, production in energy-intensive industrial sectors fell 15.2% on a seasonally and calendar-adjusted basis from February 2022 to March 2026. Asking factories to shoulder some of the highest energy costs in the industrialized world is one thing. Telling them to only keep the machines running when the weather permits is the next escalation step that guarantees another wave of departures. Müller’s pilot runs through 2026, final rules land early 2027.

Germany is only the leading edge of a European energy policy that has made the same bet at continental scale. The EU’s Renewable Energy Directive sets a legally binding target of 42.5% renewable energy in the total energy mix by 2030. A target which does not bend for rising prices or industrial exit.

Instead of solving Europe’s self-inflicted competitive problems, Brussels is now drafting a move to export the consequences onto others. The plan is to discipline the country that benefited most from Europe’s self-inflicted energy disorder: China. The EU is looking to unleash a trade fight over the two economies’ growing trade imbalance. One instrument has been given remarkably little scrutiny, even though it stands in direct and obvious contradiction to the EU’s sacred energy transition. Time to take a closer look.

The proposal is called the “overcapacity instrument,” which the EU’s College of Commissioners discussed on May 29th. The term “overcapacity” has no formal definition in this context. The Commission’s working standard: China accounts for 30% of global production but only 13% of consumption. That gap alone is sufficient grounds for restriction. No predatory pricing, no dumping, no market manipulation required.

A March 2026 European Parliament study titled “Industrial Overcapacities with a Focus on China” backs this framing, flagging “high levels of investment in production despite low levels of domestic consumption” as inherently problematic. By that definition, every competitive exporting economy in history has been guilty. The Chinese commerce ministry hit back accordingly:

If we label trade surpluses as “overcapacity,” then should EU’s exports of automobiles, pharmaceuticals, wine and cosmetics also be labeled as “overcapacity”?

The “overcapacity instrument” would allow the bloc to restrict Chinese access to EU markets in sectors where China’s production significantly exceeds demand. Few specific details have been officially disclosed since the proposal remains closely guarded.

The instrument’s current primary targets reportedly are chemicals, machinery, and plug-in hybrid cars. But the Commission’s own threshold — 30% of global production against 13% of consumption — does not stop there. Applied consistently, it catches two sectors that sit at the physical foundation of the EU’s energy transition: solar panels and batteries. China produces approximately 80% of global solar modules against domestic absorption of roughly 35%. Batteries have a similar production to absorption ratio. Both clear the threshold by a wide margin.

For solar, Brussels has already tried something similar. Between 2013 and 2018, the EU imposed anti-dumping tariffs on Chinese solar panels. The outcome was a failure: no significant European manufacturing capacity was built. Instead, a long string of insolvencies culminated in the flagship of German solar manufacturing, SolarWorld, going bust during that time and the dependency deepened. In 2023, 98% of solar panels installed across the EU came from China.

What the “overcapacity instrument” will achieve is that the energy transition becomes even more expensive. The EU wants to reach 600 GW of solar PV capacity by 2030 from 406 GW in 2025. As Chinese panels are about 2.5 times cheaper than European ones, restricting Chinese supply either requires taxpayers to cover penal import duties through higher renewable subsidies or developers to absorb the cost delta, who will then find ways to pass it on to ratepayers regardless.

One result can already be ruled out: European polysilicon and wafer manufacturing will not scale to the required roughly 50 GW per year within this decade. Current manufacturing capacity is at approximately 5 GW, according to Bruegel. There is no subsidy large enough to conjure that capacity into existence. Similar math can be run for batteries.

The likely outcome: Brussels will carve solar and batteries out of the instrument’s scope. Both are some of the biggest overcapacity sectors by the Commission’s own threshold, and both are untouchable for energy transition reasons. That exemption exposes inconsistency and reveals the instrument for what it is: selective industrial protection disguised as a principled trade standard.

But like the EU’s Anti-Coercion Instrument before it, the application of the “overcapacity instrument” will be so slow and predictable that China can read the direction of travel months in advance and respond accordingly. While Brussels holds talks to decide what to exempt from the instrument’s scope, China restricts rare earth exports as it did in November 2025.

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The entire effort is a self-defeating attempt to compensate for Europe’s own uncompetitiveness by penalizing the trade partner that outcompeted it. China is obviously not an innocent bystander. Europe is dismantling its industrial base and bleeding its taxpayers to hit climate targets that its second-largest trading partner (and the world’s largest coal burner) treats as aspirational. Even the Financial Times had to concede this week:

At present, China is not on track to meet its goal of carbon neutrality by 2060 in large part because of its rise in coal use to meet its demands, despite world-beating efforts to electrify energy and transport.

There is a direct correlation between energy abundance — using every source available — and the industrial capacity to pursue ambitious goals. China burns coal at scale and leads the world in electrifying energy and transport. The EU fails to see that this correlation explains its trade deficit with China. A bloc whose biggest economy has shed 15.2% of energy-intensive output and is now being told to schedule production around the weather forecast will not become competitive regardless of how many trade war instruments Brussels reaches for. When all you have left is trying to trip the runner ahead, you’ve already lost the race.

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Grant the premise behind the green movement: reducing CO₂ emissions is the overriding industrial policy objective. If the premise holds, the rational response is to deploy every available decarbonisation tool with greater urgency, not less. Carbon capture and storage (CCS) is one of those tools. It’s the only tool, in fact, for capturing the unavoidable chemical emissions from cement calcination, which cannot be eliminated by electrification. A policy apparatus serious about its own premise would have accelerated that infrastructure.

Instead, a de facto ban was imposed. In 2012, the Carbon Dioxide Storage Act was passed, allowing CCS only for trial and demonstration projects, with a total storage limit of 1.3 million tonnes. The law gave federal states the right to prohibit CCS entirely on their territory, and most states did so. The green argument: CCS is not “real” decarbonisation since it still allows the creation of CO₂. At best, it’s a fossil fuel lobby delay tactic. Ideological purity only knows the true way or no way.

For thirteen years, German industry could not pursue CCS regardless of economics or engineering readiness. This changed in November 2025 when the new Carbon Dioxide Storage and Transport Act (KSpTG) came into force. It’s the first statute in German legal history to permit commercial CCS at all.

Earlier this month, the EU Commission approved a German subsidy scheme to kickstart commercial CCS. Will this mark a turning point in industrial decarbonisation, or is it merely the decarbonisation narrative buying itself one last reprieve? Time to take a closer look.

CCS is a three-step logistics business. First, the factory separates CO₂ from its exhaust, essentially filtering the carbon dioxide out of the smokestack stream. Second, the CO₂ is compressed into a dense fluid so it can be moved efficiently, the same way natural gas is compressed for pipeline transport. Third, it travels by pipe or tanker to a disposal site and is pumped deep underground into porous rock formations capped by impermeable stone, where geological pressure traps it.

The cost of CCS stacks therefore in three layers too: capture, transport, and storage. Capture runs €13–22 per tonne for concentrated industrial streams (ethanol production and natural gas processing) where the CO₂ arrives pre-separated. Cement costs north of €50 per tonne, because the emissions come out of the chemistry itself, not the combustion. Aluminium smelters are estimated to run up to €300 per tonne. Transport adds a number that varies widely since a coastal connection is a different problem than a continental pipeline. Storage adds €1–20 per tonne. The EU Joint Research Centre puts the all-in range at €13–103 per tonne across industrial applications in a 2023 paper.

CCS could, in theory, be an attractive way to avoid the cost pressure caused by the European Emissions Trading Scheme (ETS), which puts a price on CO₂ emissions. At about €80 per tonne today, the ETS pushes towards CCS for the cheapest capture processes but leaves sinter plants and aluminium smelters, for example, well out of reach. Denmark and the Netherlands already run national subsidy schemes to bridge that gap, and Germany has followed suit. It has introduced a €5 billion Carbon Contracts for Difference scheme that the Federal Ministry for Economic Affairs and Energy describes as follows:

Carbon Contracts for Difference [CCfD] are modelled on private-sector hedging contracts, i.e. risk hedging instruments: They offer companies financial planning security with regard to certain price developments (for example, for energy carriers such as hydrogen) and thus hedge against risks that currently still stand in the way of investment in climate-friendly production processes.

ETS serves as the reference market. As such, the contract guarantees the difference between the agreed strike price and the price of a CO₂ certificate, measured against emission reductions relative to a conventional reference technology. If the strike price is above the current CO₂ price level, the state subsidises the project.

While the details of what emission reductions trigger funding grow increasingly complex, treating €5 billion as a direct per-tonne CCS subsidy reveals the scale mismatch. The scheme runs 15 years: €333 million per year. At an average abatement cost gap of €58 per tonne (the midpoint of the EU Joint Research Centre’s €13–103 per tonne range), the fund can subsidise 5.7 million tonnes per year of captured emissions. Against Germany’s 105-million-tonne industrial CO₂ flow, that is a measly 5% coverage.

The priority mismatch is striking too. Germany spent €18 billion on renewable electricity subsidies in 2025 alone. The CCfD allocates €333 million per year. The ratio is 54:1. A single year of renewable subsidies equals 54 years of CCS support at current rates. Nevertheless, EU Climate Commissioner Teresa Ribera proclaims:

This scheme will help deliver substantial emissions reductions in key sectors, using public support in a targeted and proportionate way. It shows how we can move forward on decarbonisation while preserving a level playing field and ensuring that competition continues to work for Europe’s long-term prosperity.

This is laughable not just because the funding is too thin to compete against countries without a carbon tax. The required infrastructure does not exist.

The cement industry association (VDZ) estimates that Germany will have to build a 4,800 km (2,980 miles) CO₂ pipeline network at a cost of approximately €14 billion to decarbonise its cement, lime, and waste incineration industries. One section is scheduled to open in 2029. Its length: 28 km (17.4 miles). Only 4,772 km left to go.

Another problem is storage. Onshore storage is not allowed at the federal level, but the states can allow onshore storage of CO₂ within their territories through an opt-in provision. There can be little doubt that green NGOs will fight any such plans through to the highest courts, leading to year-long delays at best.

That leaves offshore storage. The German Federal Institute for Geosciences (BGR) estimates storage capacity in the German Exclusive Economic Zone (EEZ) of the North Sea at approximately 0.9 to 5.5 billion tonnes of CO₂. But simulations show that only up to 10 million tonnes of CO₂ per year can be injected in the examined “Area A”, the geologically less challenging zone within that EEZ. That is approximately 10% of Germany’s industrial CO₂ flows.

One way around storage is utilization. Heidelberg Zement is building a plant in Lengfurt, Germany that will capture CO₂ and liquefy it for the industrial gas market via a joint venture with Linde. But the European liquid CO₂ market absorbs just 3.5 million tonnes annually. Germany’s share is perhaps one million tonnes across all applications, while the country’s cement calcination alone emits about 20 million tonnes. The entire industrial CO₂ market is dwarfed by the calcination problem alone.

In short: The funding is insufficient, the infrastructure does not exist, and thirteen years of developing solutions have been lost. The counterfactual writes itself. Statista puts German wind and solar subsidies between 2000 and 2024 at almost €229 billion, when the country could’ve just stuck with nuclear. One can only imagine what even a fraction of that sum would have bought in CCS infrastructure.

Industry forced to decarbonise under these conditions has only one workaround: displacement — moving production to jurisdictions without carbon costs, or shuttering capacity entirely. But displacement is not decarbonisation. Turkey will supply the cement, China the glass and steel.

None of that stops the Federal Ministry for Economic Affairs from clinging to its unmoored fantasies. In one sentence it shows how thoroughly it has lost contact with reality:

As soon as transformative production can be carried out more cheaply than conventional production, the payment relationship established by the CCfD is reversed: Additional revenues of the subsidized companies then flow back to the state.

Cement production that requires CCS can never be cheaper than cement production without it, because the conventional process vents CO₂ to the atmosphere at zero cost. Nor can steel, chemicals, or glass decarbonise via CCS at lower cost than venting. If the low-carbon route were cheaper, companies would adopt it without subsidies. They would race ahead of competitors.

The ministry’s reversal clause assumes a world where the state must force companies to save money. That world only exists when carbon prices are high enough to push industry out of the bloc anyway. With ideological purity supreme, this outcome is exactly the point.

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With this Action Plan, we are investing in a stronger European fertiliser industry, supporting European farmers and accelerating innovation in sustainable, home-grown solutions. The ongoing fossil fuel crisis shows that climate leadership and economic resilience are interlinked. This is why Europe is building a future based on sustainability, affordability and industrial strength.

Applying a flat 1% markup to carbon border tax default values for fertilizers (compared to as much as 30% on other goods) while keeping tariffs on Russian and Belarusian fertilizer imports in place is one of the measures that demonstrate short-term activism under the illusion of problem-solving. On the physical side, the Commission once again demonstrates remarkable ignorance.

Start with one of the plan’s core elements: manure. Farmers will be allowed to apply it beyond ordinary caps. For millennia, farmers used manure to grow crops, and there is good reason why this practice was largely replaced by industrialised methods. As Vaclav Smil describes in his book How The World Really Works, there is no path to feeding the world by going back to organic nitrogen, the most important input in modern farming. Synthetic fertilizers like urea are at least an order of magnitude more nitrogen-dense than recyclable wastes.

Smil estimates that to supply the same amount of nitrogen to growing crops, a farmer would have to apply anywhere between 10 and 40 times as much manure by mass, and in reality even more, as significant shares of nitrogenous compounds are lost through volatilization. And regardless of the effort that might be put into recycling, the total mass of recyclable materials is too small to provide the nitrogen required by today’s harvests.

Another idea the Commission keeps pursuing, and that has proven just as futile so far: green fertilizers. A lot of capital has been committed to such projects with limited success. A few weeks ago, however, the Financial Times reported on one company it claims “challenges industry’s reliance on natural gas.” The CEO has read the room: not a “green story,” he says, but “actually a food security story.”

Notably, the company has already secured a long-term offtake contract with Yara—one of the world’s largest fertilizer producers—for 100% of its output, so this is not a struggling startup pitching slides to Brussels. Time to take a closer look at whether this project’s approach could make any meaningful dent in the fossil fuel dependency the Commission is so desperate to eliminate.

The project is a $665 million fertilizer plant in Villeta, Paraguay, developed by UK-listed Atome, using non-fossil energy. As chemists and regular BSJ readers will know, most nitrogen fertilizer begins with ammonia, and ammonia begins with natural gas. Conventionally, the gas is used to produce hydrogen, which is then combined with atmospheric nitrogen to synthesize ammonia. In so-called “green ammonia” production, electrolyzers use electricity to split water into hydrogen and oxygen before the hydrogen is reacted with nitrogen from the air to produce ammonia.

The constraint is the electricity source. Electrolyzers degrade under variable loads like intermittent wind and solar. Reservoir-based hydropower is dispatchable, stable, and weather-independent, making it by far the most suitable renewable source that can economically feed green ammonia production.

This is why Atome picked Paraguay. The country is home to the 14GW Itaipu dam which stands as the world’s second largest hydroelectric dam, providing Paraguay with over 90% of its energy needs. Atome has secured power at an impressively low price of $30/MWh under a long-term agreement.

The amount of fertilizer the plant will generate is modest on a global scale. Atome expects to produce 260,000 tonnes of Calcium Ammonium Nitrate per year, all of it purchased by Yara under a 10-year offtake contract. Yara’s own Fertilizer Industry Handbook puts total annual nitrogen fertilizer production at 109 million tonnes. Atome’s Villeta plant delivers less than 1% of that. Yet the project’s backers argue it could serve as a template for similar developments. Can it?

The world generated 4,453 TWh of hydroelectricity in 2024, according to the Statistical Review of World Energy. That figure includes run-of-river plants, which are often weather-dependent and unsuitable for the steady loads electrolyzers require. A reasonable estimate on the higher end of typical ranges sets reservoir-based hydro at 70% of that total, or about 3,117 TWh. Assume generously that 10–15% is uncommitted enough from existing grid obligations to be candidates for green ammonia production. Call it 390 TWh.

At current electrolyzer efficiency, every addressable hydro watt on earth covers roughly 32% of global nitrogen fertilizer production. (The math: 390 TWh produces ~7.8 Mt of hydrogen at 50 kWh/kg, which Haber-Bosch converts to 35 Mt of nitrogen equivalent, against current global production of 109 Mt.). That is the maximalist case: every suitable reservoir, no competing grid demand, no permitting delays. Covering one third of global nitrogen production would be an impressive feat. But it would also require hardware that doesn’t exist.

Global installed electrolyzer capacity reached 2 GW in 2024, according to the IEA. Atome’s Villeta plant requires 145 MW, roughly 7% of that entire global base, for a single project. Replacing just the nitrogen fertilizer that moves through the Strait of Hormuz—around 30% of global exports, roughly 7 million tonnes of nitrogen equivalent annually —requires approximately 100 plants the size of Atome’s Villeta facility. (The math: Hormuz exports 9 Mt of urea at 46% nitrogen content and 3.5 Mt of ammonia at 82% nitrogen content, totalling ~7 Mt of nitrogen equivalent. Atome’s plant produces 260,000 tonnes of Calcium Ammonium Nitrate at 27% nitrogen content, or ~70,200 tonnes of nitrogen per year. 7,000,000 ÷ 70,200 = ~100 plants.)

One hundred of those plants would require 14.5 GW of electrolyzer capacity or seven times current global installed capacity. A major reason the buildout cannot easily be accelerated is iridium: this metal, a byproduct of platinum mining, is an essential electrolyzer catalyst. Its annual global production is measured in single-digit tonnes, and there’s no readily scalable substitute available today. Competing for essentially all available electrolyzer capacity would run into financing constraints too. But the deeper problem is geography.

Atome works because it produces for a regional market and doesn’t need to ship far. The project’s viability in Paraguay—surplus hydro at $30/MWh, short supply chain, Yara as a creditworthy offtake partner—depends on that proximity. That is hardly a “challenge to the industry’s reliance on natural gas,” as the Financial Times titles. It is a demonstration of why that reliance will not end.

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Yet there can be little doubt that companies across the world will pitch for EU subsidies in the name of “green food security.” And Brussels bureaucrats dazzled by the prospect of fossil-fuel-free fertilizer supply, who believe scaling impossibilities can be smothered under a torrent of taxpayer cash, will be receptive. Extra-territorial projects not excluded and each one a rounding error on the supply gap. What can close that gap?

European gas-based ammonia producers are the accidental beneficiaries of the current supply crunch. Unlike 2022, when gas-benchmark TTF spiked as Russian gas was cut off and European plants shuttered, the Hormuz closure is symmetric. Every major import-dependent region loses supply simultaneously, and no obvious cheap-production alternative exists to absorb the shortfall.

At current TTF prices just below €50/MWh, European ammonia producers spend about €500 per tonne on gas, which constitutes 70–80% of total operating expenses. With ammonia currently trading at a record $885 (€761) per tonne CFR Northwest Europe, the spread is wide. Ironically, Brussels spent years legislating the economic obsolescence of gas-based nitrogen, but the Hormuz shock priced it back in.

The crisis has not yet reached the field, but the autumn 2026 and spring 2027 planting seasons are a different matter. By then, none of the Commission’s measures will have produced a single additional tonne of nitrogen. The only mechanism that currently increases supply is high prices. The ceiling is there, though.

The Hormuz shock that pushes ammonia prices to record levels is also tightening LNG supply. If TTF follows, the gas cost that makes European production viable today kills profitability tomorrow. The producers Brussels cannot afford to lose are running on a spread that the next leg of the same crisis could close. These producers are actually the “home-grown solutions” the Commission calls for.

Climate leadership and economic resilience are interlinked, says von der Leyen. She is correct: the more aggressively you pursue one, the more you undermine the other.

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Clearinghouses also compete. Euroclear and Clearstream have divided European settlement between Brussels and Luxembourg for decades. Now Hong Kong’s HKMA is building CMU OmniClear, a direct challenger for Asian settlement business. Expanding the eligible collateral universe is how you win that competition. More asset classes mean more clients. More clients mean more flow. The obvious new frontier is renminbi-denominated (RMB) assets.

That frontier may have been part of the backdrop to Donald Trump and Xi Jinping’s meeting last Thursday. The summit’s joint statement—constructive relations, strategic stability, three years and beyond—cooled any de-dollarization narrative. But diplomatic temperature and structural architecture are different things, and they move on different timescales.

While the two presidents met, BRICS foreign ministers were convening in New Delhi. A recurring item on the BRICS agenda: a digital payments framework linking member currencies, settling cross-border transactions locally. As the South China Morning Post frames it: intra-currency payments as “immunity” against Western clout.

Against that backdrop, a piece from this week’s Financial Times reads like a marketing pitch. Euroclear wants Beijing’s business as it plans to accept Chinese bonds as collateral. CMU OmniClear is circling the same opportunity from Hong Kong. That self-reinforcing machine works best if you keep expanding the eligible collateral universe. The pool of Chinese domestic government bonds is the largest untapped opportunity on the board.

Euroclear’s CEO Valérie Urbain described the move as contributing to RMB internationalisation and expanding client services. The timing, ahead of a US-China summit and a BRICS meeting, is worth noting. So is what the Financial Times didn’t ask. Time to examine what it means for Brussels to become the Western anchor for RMB collateral infrastructure.

When Iranian strikes began hitting Middle Eastern energy infrastructure earlier this year, global bond markets sold off. While Western sovereign debt wobbled, Chinese government bonds held. The 10-year yield settling to a low of 1.75% as, while US Treasury yields moved to 4.59%

One explanation points to China’s diversified energy structure: domestic coal, pipeline gas, strategic reserves softening the blow despite China being one of the world’s major oil importers. That kind of insulation is what makes Chinese bonds attractive as collateral in a volatile rate environment and it explains why a Brussels-based clearinghouse might find €5 trillion worth of Chinese domestic government bonds worth the regulatory complexity.

But what makes this more than a routine business expansion is who is likely pushing for it. China’s State Administration of Foreign Exchange (SAFE)—the arm of the People’s Bank of China that manages the country’s $3 trillion in foreign reserves—owns 7.25% of Euroclear. The position surfaced in late 2019 when Euroclear, weighing a possible IPO, was compelled to disclose its ownership structure. The stake is held not by Beijing directly but through Kuri Atyak Investments Limited: a vehicle registered in the British Virgin Islands, with board representation at Euroclear. When the position was built remains undisclosed.

What is known: by the time Russian assets were frozen at Euroclear in 2022, China was already sitting at the table. The institution now being asked to accept Chinese bonds as collateral is partly owned by the Chinese state body with the most direct interest in seeing that happen. But China’s interest goes beyond demand for its bonds. Embedding them inside Western settlement infrastructure reduces exposure to financial sanctions.

Here’s how Western sanctions generally work: any institution that wants to maintain access to US correspondent banking must comply with US sanctions, regardless of where it is domiciled. The legal obligation falls on financial intermediaries, making dollar access the lever that pulls the rest of the world into compliance.

RMB collateral transactions sit largely outside that chokepoint. Chinese bonds posted as margin through Euroclear’s Collateral Highway are RMB-denominated assets moving through a euro-zone settlement infrastructure. To the extent the transaction chain avoids dollar clearing, US secondary sanctions lose their operational grip and that chain can be deliberately structured to minimise dollar exposure. While this doesn’t eliminate sanctions risk entirely, it raises the cost of enforcement significantly.

The protection against sanctions runs deeper still. Because the entanglement of these bonds—posting margin, securing repo, sitting inside European bank collateral buffers—means that removing them becomes a question of financial stability. The SAFE stake provides the equity anchor, collateral eligibility provides the entrenchment. China’s strategy to create a lock-in is, if successful, comparable to its rare earths and pharmaceutical dependency strategy. Both were recognized late and are proving expensive to reverse.

Far from being on the “right” side of the de-dollarization narrative, Europe is being squeezed from both sides. At the physical layer, dollar dependency is here to stay. The majority of the EU’s energy imports, which were at € 337 billion in 2025, is settled in dollars. And that dependency is only deepening. As Slovak Prime Minister Robert Fico put it this week:

The US plans to buy out the entire oil and gas transportation system to Europe. The Russians will supply gas and oil to the Americans at standard prices, and the Americans will sell them to us at a high American markup. Are we really that stupid now?

According to Russian state media TASS, Nord Stream itself is now on the table: Washington seeking to acquire the pipeline infrastructure that once delivered cheap Russian gas directly to Germany. Foreign Minister Lavrov alleges what was laid out on these pages back in March: the US wants to buy out European-owned pipeline stakes at a fraction of original investment value, then control both flow and price.

The strategic miscalculation is almost comically self-defeating: Europe’s hawks have spent four years arguing that appeasing Russia over Ukraine sets a precedent for China over Taiwan. That military coercion must be answered, regardless of price, or the signal to Beijing is fatal. Europe has used this argument, among others, to justify sanctions, energy costs, and rearmament spending simultaneously.

The Euroclear architecture makes that argument significantly harder to execute. If a Taiwan scenario forces the sanctions response European think tanks claim it must make, the institution at the center of that response is partly owned by Beijing, with Chinese bonds running as load-bearing collateral through European banking infrastructure.

But the Beijing summit this week may have rendered that question academic. When the two largest economies on earth meet to negotiate strategic stability for the next three years and beyond, the shape of the world gets decided, Taiwan included. As always, Europe was not in the room. The conversation that determines whether a Taiwan scenario ever materializes, and on whose terms, is happening between Washington and Beijing. Brussels will learn the outcome when everyone else does.

In the meantime, Washington is selling the energy. Beijing is inside the financial plumbing. The Euroclear announcement is one more data point in an order Europe neither designed nor controls.

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Benzene-derived drugs keep Europe’s ageing population alive at a scale that is easy to underestimate. Statins taken daily by tens of millions of cardiovascular patients, many targeted cancer therapies, and the most commonly prescribed antidepressants frequently incorporate it as a core structural element. These benzene‑centered scaffolds characterize some of the highest‑volume, highest‑dependency drug classes in European healthcare.

Benzene does not occur in nature at industrial scale but is derived from crude oil. Unsurprisingly, the Hormuz disruption is already moving through the benzene supply chain. The most visible early signal comes from India, the cornerstone of global generic drug supply.

The prices of certain key raw materials have risen by more than 60%, according to data reported by The Economic Times, and industry bodies are warning governments of emerging shortages in antibiotics, antidiabetics, and cardiovascular medicines. Many companies still have months of inventory. But that buffer is the only thing standing between the current disruption and visible consequences.

Europe suffers from the same feedstock dependency. Crude oil enters a refinery and gets broken down into fractions, among them naphtha. That naphtha feeds petrochemical crackers, which produce benzene as a co-product. Roughly 70% of Europe’s benzene supply comes from domestic sources running this chain. The full impact of the Hormuz disruption will only be visible in the coming months. After the strait closed, tankers still in transit kept arriving for weeks, masking the disruption like air trapped in a pipe. Now that air has reached the end. Europe is drawing on strategic reserves of crude and oil products, with no reliable picture of how much remains.

What is clear is that refineries cannot simply run lean in response: below roughly 60% throughput, operations become technically unstable and economically unviable. The plant shuts entirely rather than dimming: no linear decline but a step function below the threshold. When Hormuz settles, the infrastructure to restore European benzene supply may not be what it was. Time to take a closer look at what this means for Europe’s pharmaceutical security of supply.

The Hormuz disruption has started to hit refiners around the time JP Morgan’s shipping analysis marked as the day the last pre-closure tankers from the Persian Gulf reached European ports. European refining margins turned negative on April 6: minus $6.45 per barrel for the benchmark hydroskimming configuration, according to IEA data cited by Reuters. Sparta Commodities estimates that European runs could fall by as much as 500,000 barrels per day as refineries cut throughput to avoid running at a loss. However, the input shock is only half the story.

European refineries were under pressure before the first Hormuz tanker was threatened. The EU’s climate legislation—the Emissions Trading System, Fit for 55—has been systematically eroding the economics of European refining for years. Staying competitive against Gulf and Asian producers carrying none of the carbon cost burden makes the economics worse still. The result was a refinery industry running on shrinking margins before crude prices spiked.

The problem for non-combustion uses of oil is that refineries have no off switch for individual products. Process a barrel of crude and you get everything at once: jet fuel, diesel, naphtha, bitumen, and the aromatic fractions that feed the chemical and pharmaceutical industries. The ratios are determined not by procurement decisions but by physics. A refinery is a column: heat crude from the bottom, different molecules rise and condense at different temperatures, each fraction emerging at its own level. That’s why a refinery works only if the economics for all outputs make sense. Naphtha—the refinery fraction required for benzene output—dims with everything else.

The effective combustion engine ban from 2035 poisoned long-term investment decisions too. No board approves a decade-long capital commitment when politics have scheduled your product for elimination. The attempt to render European refining unprofitable has proven successful: Shell shut down crude processing at its Wesseling refinery in Germany in March 2025. BP cut roughly a third of capacity at Gelsenkirchen. Petroineos converted Grangemouth—the only refinery in Scotland—into a fuel import terminal. Eni shuttered Livorno. ExxonMobil closed Slagen in Norway. Nearly 400,000 barrels per day of European refining capacity disappeared in 2025 alone. Each closure was reported as an energy story. The benzene column was on hardly anyone’s radar.

The IEA estimates that up to 1.5 million barrels per day could follow by 2030. According to the most recent Statistical Review of World Energy, Europe’s total refining capacity stood at 15 million barrels per day in 2024, making this a 10% cut. That doesn’t sound too dramatic. But this estimate was made before Hormuz hit.

Until recently the picture looked very different. In September 2025, European benzene was in oversupply, prices had fallen 27% from the prior year, and the market consensus was that only cracker capacity closures would drive recovery. Since Hormuz, prices have climbed. The market is getting the recovery it called for, just not the way it had in mind.

One optimistic objection is that industry will find bio-based routes to benzene that bypass fossil feedstocks entirely. But the naphtha that produces benzene rises from the refinery column as a co-product of processes driven by other economics. A dedicated bio-based facility would have to price against benzene emerging from that already-running chain. That competition has never been won. Instead of creating an opening for domestic replacement production, European closures create a dependency on whoever controls the remaining throughput.

The problem may be easy to dismiss given that the cost of raw benzene is a fraction of total pharmaceutical manufacturing expenditure. But so is the cost of rare earths in a weapons system. Price doesn’t reflect the importance of key inputs. The usual strategic miscalculation follows: once the production chain is dismantled, rebuilding it takes decades, which directly undermines Europe’s post-COVID push to reshore pharmaceutical supply chains.

Europe’s ageing population will not run out of statins or cancer therapies tomorrow, but the trajectory is set. Every refinery that closes removes another column from the system. The fantasy that Europe can dismantle the fossil fuel infrastructure it disapproves of while retaining the pharmaceutical feedstocks it depends on collides with a basic reality of chemical engineering.

Pharmaceuticals are one of the few industrial sectors where Europe still holds a genuine competitive edge in research, manufacturing, and export capacity. It survived the hollowing out of steel, semiconductors, and solar. What follows from wilful refinery attrition is a slow transfer of structural power that puts this last stronghold at risk.

None of this was unforeseeable. The Hormuz chokepoint has appeared in every energy security analysis for thirty years. The refinery closures were announced publicly in advance. The benzene dependency was not a secret.

Whether the next pharmaceutical supply disruption traces back to benzene feedstock is now a question worth asking. Mitigation is still possible, but only if the political will exists to reverse a decade of refinery attrition. Rational governments would act. The EU’s track record suggests otherwise. Policy irrationality, when it is this predictable, is itself a tradable opportunity.

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Brower used the money to fund the anti-nuclear group Friends of the Earth. The thinking was that oil would be worth a lot less if more of the world’s energy needs were provided by atomic fission. By surreptitiously funding the movement, the oil sector could establish proxies to do their fighting for them. Within a decade the organization became the leading international voice against nuclear energy.

The arrangement didn’t stop at that one-time payment. In 2019, an internal American Petroleum Institute presentation was obtained, detailing a campaign called No Nuclear Bailouts. This was a coordinated effort to organize ostensibly grassroots opposition to state legislation in Pennsylvania and Ohio that would have kept nuclear plants operating. The influence didn’t stay limited to the U.S. either. Friends of the Earth comprises over 70 national member groups, and its German branch BUND was instrumental in the country’s nuclear exit.

Energy’s non-negotiable demand and its power to shape an economy’s future make any grassroots movement in that space a target for capture. Which brings us to April 18, 2026, and the streets of Berlin, Hamburg, Cologne, and Munich. On that day, a claimed 80,000 people took to the streets. The demonstrations were organized by a coalition of environmental groups under the slogan: “Defend Renewable Energy.” The crosshairs were on Katherina Reiche, Germany’s Federal Minister for Economic Affairs and Energy.

Since early 2026, her ministry has proposed a set of policy changes that would slow down the renewables buildout. Within weeks the machinery of opposition was fully assembled, with her being described as a “lobby minister.” The sun famously “sends no bill” and the promise is that an electrified economy would free the country from fossil fuel dependency. Before taking the ministry, Reiche had spent five years as chief executive of Westenergie, E.ON’s largest German subsidiary. According to one reading, a woman who worked in the energy industry can only be in the ministry as a fossil fuel proxy.

A different perspective is that running the energy infrastructure of Europe’s largest industrial economy requires someone who actually understands how energy systems function. Yet the unfavorable reading is dominating. Calls for her resignation were coming not only from the Greens and the social-democratic coalition partner but from within her own conservative party.

The backlash against her proposals suggests that the country remains committed to running a (still-)industrialized economy on wind and solar. Or it might be an indication that the wave is cresting. Time to take a closer look at the current state of Germany’s energy transition.

The system Reiche wants to fix has a serious problem: It produces electricity nobody wants. On Sunday April 27, nine days after the demonstrations, Germany’s intraday electricity price fell to a record low of €−480/MWh. Across the border, Hungary hit the absolute regulatory floor of €−500/MWh in the day-ahead auctions. The market cannot express a number deeper in negative territory.

However, the intraday market has an even deeper floor. On May 1, a bank holiday, German intraday prices plunged to an all-time record of €−855/MWh.

This was the latest data point in a trend that has been running in one direction for years without interruption. In 2022, Germany logged 69 hours of negative day-ahead electricity prices. In 2025 it logged 575. One in every fifteen hours, the equivalent of twenty-four full days when the market was signalling that electricity had less than zero value. Forecasters project 700 to 900 negative-price hours in 2026.

Normally you’d assume that negative prices would stop producers from flooding the market. But the system was designed to generate this outcome. The majority of Germany’s installed renewable capacity was built under rules that required six, then four, then three consecutive hours of negative prices before remuneration was suspended, meaning isolated negative-price hours triggered no response whatsoever. Some legacy fixed-tariff plants face no suspension mechanism at all.

Grid operators can curtail output when the grid is physically overwhelmed. But they must compensate operators for the lost generation, which means curtailment is an expense, not a market correction. For most operators most of the time, the guaranteed tariff continues regardless of what the market price is doing. The financial incentive to keep generating during negative prices is identical to the incentive during positive prices.

On top of that, renewable operators hold legal dispatch priority: grid operators are obliged to absorb renewable output before curtailing conventional generation, whatever the market price. And for solar installations in particular, the marginal cost of generating is zero whether the price is positive or negative. Solar power is a torrent from a firehose straight into your face when all you want is a glass of water, and a trickle when you’re thirsty.

Reiche proposes a package of measures to mitigate the issue. The most consequential is the “redispatch limitation”. Any grid area where more than 3% of electricity couldn’t be fed into the network in the previous year can be designated capacity-limited for up to a decade. New solar and wind operators connecting in such a zone must waive their right to curtailment compensation for the entire duration of the designation.

The renewable industry’s response was unsurprising: lobby group BEE called it poison for investment, the solar lobby called it a de facto connection ban. What neither acknowledged is that grids are deliberately not built to absorb every last kilowatt-hour of output. Reiche’s proposal simply aligns investment incentives with physical reality. The fact that it makes new renewable projects unfinanceable is the inevitable result of alleviating a wealth-transfer mechanism that benefits a few at the expense of many. German taxpayers funnelled €18.5 billion in transfers to renewable operators in 2025 alone.

The standard rebuttal to everything above is batteries. Store the surplus from sunny Sundays, discharge it during cold doldrums, problem solved. Bridging Germany’s interseasonal storage gap requires approximately 36 TWh of storage capacity. According to green think-tank Ember, the current all-in project cost for utility-scale battery storage—including equipment, engineering, and grid connection—is $125 per kilowatt-hour.

That’s $4.5 trillion to fill the gap—for a country with an annual budget of about $590 billion. The renewable lobby’s standard response is that cell prices are falling. They are, but cells are only 20–35% of total system cost. The transformers, inverters, grid connections, civil works, and land that make up the rest have not followed the cell price curve and will not. Even if cells were given away for free, the bill remains in the trillions.

The ferocity with which the renewable lobby has moved to block Reiche’s modest rationalization measures is not the behaviour of a sector confident in its long-term trajectory.

The most expensive feed-in contracts—locked in during the early solar boom years of 2006 to 2009—expire on their twenty-year terms between now and 2029. The broader cohort of legacy contracts, covering the bulk of Germany’s installed capacity, runs off through 2033. As each vintage expires, the operators will face a choice: continue generating into a market where average wholesale prices are a fraction of what they were guaranteed, or decommission. New auction projects receive a market premium to bridge the gap. But that only works as long as the fiscal space exists to bridge that gap.

By BSJ’s read, peak renewables is already here. Take Germany’s solar capture rate, meaning the average price solar generators receive relative to the market price. It has fallen from 98% to 54% between 2022 and 2025. The more capacity the system adds, the lower the average captured price for every operator in the market. Germany’s solar additions fell in absolute terms in 2025: from 15.5 GW to 15.2 GW, the first year-on-year decline in over a decade. Peaks tend to look like this from the inside.

Reiche will likely lose the political battle. But no government can indefinitely subsidize a cage fight against physics. Building a $4.5 trillion battery workaround is not possible in a country whose tax base shrinks with every factory closure. With so many fighting so hard to preserve a system this broken, the financial flows must run deep. Journalists will have a field day untangling the money behind 80,000 people marching in defense of something that makes everyone poorer. Everyone, that is, except Chinese module producers and solar panel operators.

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The calculation looks like it breaks down when you account for who else is paying. With the EU already weighing emergency subsidies against a looming energy shock, every Ukrainian strike makes sustained support fiscally and politically harder for the governments writing the checks. Kyiv knows this, yet the strikes continue.

One recent chapter in this story brings us to the Baltic. In early April, Ukrainian drones struck Primorsk, Russia’s largest oil-loading port in the Baltic Sea. Russia claims the Baltics and Finland opened their airspace to Ukrainian drones, which Ukraine denies. During earlier raids, drones crashed in Lithuania, Latvia, and Estonia. Ukraine apologized and all three Baltic governments attributed the incidents to electronic interference, not deliberate overflight.

Russia’s Security Council Secretary Sergei Shoigu used these incidents to invoke the right to self-defense under Article 51 of the UN Charter, declaring NATO member states direct participants in an attack on Russian territory. His claim rests on the assumption that the flight distance could not be crossed without Baltic airspace. While this can be contested, Shoigu added a second accusation: that Europe is becoming part of Kyiv’s “strategic rear,” a reference to a list published by Russia’s Defense Ministry (MoD).

The document names companies the MoD claims are producing attack drones for Ukraine on European soil. On X, former Russian President Dmitry Medvedev called it “a list of potential targets” for the Russian military and added: “When strikes become a reality depends on what comes next. Sleep well, European partners.”

Ukraine’s energy strikes have paid off doubly. Russia loses revenue, Europe gets drawn deeper into the conflict. Ukraine’s logic is brutal: make yourself impossible to abandon. The question is whether Russia’s threat is real or performative. The answer lies in the rungs Russia has left to climb on the escalation ladder. Time to take a closer look at Russia’s accusations and its options from here.

The MoD’s list includes 11 branches of alleged Ukrainian companies producing drones and components, with locations in the United Kingdom, Denmark, Germany, Latvia. A second list, “Foreign Enterprises Producing Components,” named 10 companies with addresses in Madrid, Venice, and Haifa. According to the MoD, European citizens should know the locations of these enterprises as “true causes of threats to their security.”

Such proclamations can easily be dismissed as propaganda. But the underlying premise—that Europe is actively involved in Ukrainian drone production—is harder to ignore. Euronews, substantially funded by the European Commission and therefore beyond suspicion of Kremlin sympathies, reported in mid-April on expanding collaboration:

About 120,000 drones pledged by the UK, alongside additional funding for PURL and the Czech ammunition initiative, were announced at a meeting of the Ukraine Defence Contact Group in Berlin on Wednesday.

[German defence minister] Pistorius reiterated Berlin’s latest military commitments announced on Tuesday during German-Ukrainian government consultations, where the two sides signed a €4 billion defence package, including hundreds of Patriot missiles and joint drone production, as well as an agreement to share digital battlefield data.

German Chancellor Merz and Ukrainian President Zelensky had met in Berlin the day before to sign a “strategic partnership declaration” explicitly covering offensive capabilities:

The package also includes […] €300 million in investment to develop Ukraine’s long-range strike capabilities.

With the commitment to long-range strike development Germany is crossing a line it spent years refusing to cross. Berlin withheld the Taurus missile—500km (310 miles) range, capable of striking deep into Russian territory—because it feared that made it a co-belligerent. A €300 million long-range strike program is not materially different from delivering the Taurus.

Russia applies a similar logic when evaluating participation but stops short of the word “co-belligerent,” despite having already upgraded the conflict from special operation to war in its own communication. Last year, Kremlin spokesman Dmitry Peskov has explicitly stated that the conflict “became a war” the moment the collective West joined Ukraine’s side. However, when it comes to specific strikes, Russia shows deliberate restraint. When Ukraine struck Bryansk in March:

The Kremlin on Wednesday accused British specialists of involvement in a deadly Ukrainian strike on the Russian city of ‌Bryansk that used British Storm Shadow missiles and said it would take Britain’s role “into account.”

The immediate next step is not an attack on European soil. It is supply chain disruption, ensuring that the weapons being manufactured in Europe never reach the front. Russia is already climbing:

Attacks by Russian drones on transport are forcing Ukraine to change safety rules even for passengers. Ukrainian Railways (Ukrzaliznytsia) has already introduced evacuation procedures directly during train movement.

Russia is systematically attacking Ukrainian logistics – from ports and airfields to railways and road routes. Maritime logistics is under constant pressure: the ports of Odesa, Chornomorsk, and Izmail are regularly hit by missiles and drones, directly affecting exports.

The next kinetic rung would be to intensify attacks on chokepoints such as the Beskydy Tunnel in the Carpathian Mountains, Ukraine’s most vital rail link to the West. This corridor has so far been spared since a 2022 strike. An Oreshnik strike could put it out of service for months. As the weapons packages grow larger, the pressure to climb higher increases.

In line with Ukraine’s attacks on hydrocarbon infrastructure, Russia is also turning the energy dial. The Druzhba pipeline carries Kazakh oil westward through Russian territory before it reaches Germany, meaning Moscow controls the tap. This week, the Kazakh Energy Minister announced that tap would close from May 1. Russian officials did not make the connection to the Berlin weapons package explicit. Deputy Prime Minister Alexander Novak explained:

The volume of Kazakh oil supplies earlier directed to Germany will indeed go to other logistic destinations, the free ones, from May 1. This is related to technical capabilities to date.

The pipeline supplies the PCK refinery in Schwedt, which provides fuel for nine out of ten cars in Berlin, the surrounding Brandenburg region, and the city’s airport. A complete halt would reduce its refining volumes by approximately 17%. Officially Germany does not see the security of supply at risk, but such statements are usually issued right before the opposite turns out to be true.

Tellingly, Russia resumed oil flows to Hungary and Slovakia this week through the same pipeline. None of the companies on the MoD list are located in either country. European leaders may not be connecting the dots, or may be choosing not to say so publicly. Either way, Russia is climbing the escalation ladder one rung at a time. The ladder has rungs left.

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That situation likely reignited one of Ankara’s most persistent infrastructure ambitions: a pipeline from Qatar’s North Field to Turkey. A 1,500-kilometre (930 miles) route that would connect Gulf gas reserves to European markets for the first time without a single tanker. For Turkey, which has long sought to become Europe’s primary energy hub, it would represent a generational opportunity.

Turkish and Qatari leaders publicly endorsed the idea back in 2009, but the project was blocked by Syria’s Bashar al-Assad. This was reportedly due to Russian pressure. When Assad fell in December 2024, Turkey moved to revive it. Qatar’s foreign ministry called the idea “media speculation” in January 2025.

Then came March 2026. Qatar has now lost 17% of its export capacity and an estimated $20 billion in annual revenue. Its main export route has been mined and may remain problematic long after the conflict subsides. A pipeline to Turkey would circumvent the world’s most critical energy chokepoint. The logic seems compelling. And yet Qatar remains silent.

The project would require sustained alignment among multiple countries from start to endpoint: Qatar, Saudi Arabia, Jordan, Syria, and Turkey. That’s a high bar, but just one problem. The more fundamental obstacle to Turkey’s energy hub ambitions becomes visible on the other side of the Atlantic. Let’s hop to Texas for the bigger picture.

Twelve days after the Ras Laffan attack, another piece of QatarEnergy news got drowned in the noise. On March 30, Golden Pass achieved first production of LNG at its Sabine Pass terminal in Texas. The facility started life in 2010 as an LNG import terminal, built to bring gas into the United States. QatarEnergy and ExxonMobil took the final investment decision to convert it into an export facility in February 2019, committing more than $10 billion to the project. QatarEnergy holds 70%, ExxonMobil 30%.

The feed gas comes from American shale, primarily the Haynesville and Permian basins. Notably, Golden Pass, once at full capacity, will produce 18.1 million tonnes per year (mtpa), significantly exceeding the 12.8 mtpa knocked offline at Ras Laffan. With the Sabine Pass sitting on the Gulf of Mexico, this project also has the obvious advantage of being outside a war zone.

Golden Pass is the most prominent piece of a portfolio that QatarEnergy has been assembling for over a decade across four continents. The company holds exploration and production stakes in more than twenty countries—Namibia, Guyana, Brazil, Egypt, Mozambique among them—almost all of them outside the Persian Gulf. The logic running through every acquisition is to hold production equity beyond the reach of any single chokepoint.

Geographic diversification is only half the architecture. The other half is the structure of customer relationships. Here too Qatar has built in layers of protection for itself that its buyers do not share. When supply is disrupted, not all customers are treated equally.

QatarEnergy declared force majeure on contracts with Italy, Belgium, South Korea, and China, meaning delivery obligations are suspended and damage claims barred. Of the European buyers, Italy and Belgium face the greatest pressure due to their heavier reliance on Qatari supplies. According to Kpler, Qatar accounted for around 30% of Italy’s LNG imports and 8% of Belgium’s last year. Italy’s Edison will have to forgo 10 contracted cargoes mid-June alone.

The lost revenue from the Ras Laffan disruption makes a pipeline to supply these customers look attractive. But it would also be a permanent surrender of what QatarEnergy’s strategy is designed to preserve: non-commitment.

Commitment is the concept Qatar’s customers seem to have not properly taken into account. An LNG long-term contract binds the buyer. It binds the seller to a lesser extent. The decisive question is commitment depth: how physically bound is the supplier to deliver. An LNG long-term contract contains force majeure escape clauses created for the conditions when supply matters most: war, infrastructure damage, Hormuz closure.

A pipeline is different in kind. It requires billions in upfront capital that only pays back over decades of throughput at a negotiated price. That investment is a costly, physical signal that the seller has tied its return to one buyer, one route, and one price.

The obvious objection to the pipeline as a deeper commitment argument is Russia. In 2022, it demanded ruble payments, then cited a missing turbine, then suspended supply indefinitely in September 2022. Officially for technical reasons which the EU disputed, and four months after the EU had announced its intention to end Russian gas dependency.

Whichever version is correct, the physical result is the same: Gazprom posted a net loss of $6.9 billion in 2023—its first since 1999—because the Yamal fields that supplied Europe are not connected to China and have nowhere else to go. More than twenty trillion cubic meters of reserves, staying in the ground.

While pipeline dependency makes you vulnerable to a supplier's political will, LNG dependency makes you vulnerable to a supplier's commercial logic. Neither approach is safe. But a pipeline embodies deeper reliance than any LNG contract can match. It’s worth noting that Russia has repeatedly signaled that it stands ready to resume long-term cooperation with European customers if they are willing. A pipeline from an “enemy” is more committed than LNG from a “friend.”

Given Europe’s insistence on never returning to Russian gas, Turkey might hope that the EU will lobby for its pipeline project. After all, the EU’s only relevant pipeline supply comes from one country: Norway. The pipeline share of total gas imports fell from 77% in 2021 to 52% today.

Yet Qatar’s strategy demands it keep saying no to the project. Its commercial model depends on preserving optionality. Golden Pass is the tell: additional LNG capacity, different ocean, no long-term customers. QatarEnergy invested $10 billion to build 18.1 mtpa of new capacity and left the Golden Pass volumes uncontracted. A pipeline customer is the opposite: permanently tied to one route. Qatar would be cannibalizing its own LNG revenue while permanently surrendering a tranche of production to one buyer. Every molecule in the pipe is a molecule withdrawn from the global arbitrage.

Watch Europe’s post-Hormuz policy response. The right lesson would redirect capital toward constraint-side infrastructure: pipelines, storage, nuclear restarts. These are the only solutions that hold when force majeure arrives. Increasing the reliance on suppliers whose business model depends on flexibility is the absence of a security strategy. If Europe’s primary response is more LNG contracts, it will have repeated the same mistake with different suppliers: the commitment depth denominator ignored again.

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RWE is now obliged to flood the pit fifteen years earlier than originally planned. Starting in 2030, Rhine water will create Germany’s second deepest lake over the course of four decades. The project is not uncontested on environmental grounds. Critics cite excessive strain on the region’s water reserves and long-term chemical risks to the groundwater, among other issues.

Drowning a billion tonnes of coal under a recreational lake—making future access economically impossible—is not unlike dynamiting functioning nuclear cooling towers. Both amount to the irreversible destruction of a strategic reserve, executed by politicians who seem to price energy security at zero. It may not be a coincidence that both the economics and environment ministries of North Rhine-Westphalia are led by the Green party. Neither of them sees the current energy situation as a reason for renewed debate on whether this plan should really be set in motion.

Just weeks after the groundbreaking for the pipeline to channel water into the pit, Europe’s energy security met another critical deadline. April 10 was the date JP Morgan’s shipping analysis marked as the day the last pre-closure tankers from the Persian Gulf reached European ports. A growing share of every barrel burned from here on comes out of storage. According to the Financial Times, European airports face “systemic” shortages of jet fuel if the Strait of Hormuz is not fully reopened within three weeks.

The Hormuz closure and the mine flooding may seem unrelated until you consider that for nearly a century, a proven industrial process has been turning coal into synthetic diesel, gasoline, and jet fuel.

At their peak in 1944, Germany’s synthetic fuel plants produced a combined 124,000 barrels per day. Synthetic fuel supplied 92% of the Luftwaffe’s aviation gasoline and more than half of its total motor vehicle fuel. It’s hardly surprising the Allies identified these plants as truly strategic targets.

The technology that worked then still works today. Modern plants prove that coal-to-liquids works commercially, not just under wartime desperation. Time to take a closer look at the potential Europe is drowning along with its coal.

Industrial chemistry offers something markets can’t: optionality in a crisis. The Fischer–Tropsch process, developed in 1925, converts coal into liquid fuels (CTL). Energy-intensive and water-hungry but with one underappreciated advantage: virtually all conventional pollutants are stripped out at the source. No particulates, no mercury, no SOx, no NOx. The only significant emission is CO₂. The usual air quality argument against coal doesn’t apply.

The largest CTL plant is in South Africa. Sasol Secunda was built for energy security after the 1970s oil crises exposed the country’s heavy reliance on imported oil—a vulnerability that became existential during peak apartheid sanctions in the 1980s. The plant produces 150,000 barrels per day from sub-bituminous coal.

China reached a similar conclusion. With 70% of its crude oil imported, most of it by sea, its vulnerability is obvious. The Shenhua Ningxia plant in Inner Mongolia—Beijing’s flagship CTL facility—reached full capacity of roughly 80,000 barrels per day in December 2021 (4 million tonnes per year according to Chinese media). A second facility at Ordos, with matching capacity, has operated since 2010.

While tiny relative to China’s overall liquids consumption, CTL provides a domestic buffer that contributes to national security, which is why Beijing is intent on expanding its capabilities. In late 2024, CHN Energy Investment Group launched a 170 billion yuan (about $24 billion) CTL project, slated to come online around 2027 with a name‑plate capacity of another 4 million tonnes per year of synthetic fuels.

The engineering is proven, the question is what it costs. The answer depends on whether you’re running an existing plant or building a new one. For an existing, depreciated plant, the economics are surprisingly workable. Sasol reported an oil breakeven price of $59 per barrel for its 2025 fiscal year and is targeting $50 per barrel by 2028—well below current Brent prices.

Building a new one is a different proposition. Total plant costs are estimated to run $90,000 to over $300,000 per barrel per day of installed capacity, with a mean around $145,000. That’s ten to fifteen times more capital-intensive than a conventional refinery. Amortise that capex over a 30-year plant life, add European construction costs, labour, and permitting timelines, and by my math the investment breakeven climbs to $80 to $140 per barrel.

But are standard breakeven comparisons adequate in a multipolar world of contested sealanes and lingering conflict? China doesn’t seem to think so. As economies shift from efficiency to resilience, the question is no longer what fuel costs at the margin, but whether it is available at all. Guaranteed fuel doesn’t trade at the same price as cheap fuel.

Beyond price, there is a quality problem. The coal in the Hambach pit has roughly 50% moisture and less than half the energy density of the sub-bituminous coal Sasol uses at Secunda. Stack those losses and two-thirds of the energy in the coal never reaches the fuel tank. Terrible by any commercial standard. But comparable to green hydrogen’s round-trip efficiency of 25 to 30%. The EU is still spending billions subsidising the latter.

What would European CTL actually yield? Sasol’s empirical record gives a real-world yield of 1.9 barrels per tonne (1.5 billion barrels from approximately 800 million tonnes of coal). Adjust for Hambach’s lower energy lignite and the range drops to 0.5 to 1.0 barrels per tonne. Applied to about one billion tonnes of extractable reserves, that yields 500 million barrels at the low end and up to one billion at the high end. A midpoint of 700 million barrels is equivalent to one year of Germany’s total oil consumption.

But Hambach is just one mine. The EU’s total anthracite and bituminous coal reserves—higher quality than lignite, yielding 1.5 to 2.5 barrels per tonne through Fischer-Tropsch—amount to 25.5 billion tonnes according to the Statistical Review of World Energy. At even the conservative end of the yield range, that represents over 38 billion barrels of potential synthetic fuel, a decade of the EU’s total oil consumption.

Add the continent’s far larger lignite reserves on top and the feedstock base is not a rounding error. In principle, that’s one of the world’s largest untapped domestic liquid fuel reserves.

The biggest constraint is self-imposed: the EU’s carbon arithmetic. The Emissions Trading Scheme makes Fischer-Tropsch economically impossible even at elevated Brent prices. Any domestic fuel production is being taxed into oblivion while hundreds of billions flow into wind and solar in a world that will run overwhelmingly on hydrocarbons on any timescale that matters.

But as 1940s Germany, South Africa, and now increasingly China have shown, physical constraints always override political preferences. What happened in Australia this week is instructive. The Guardian reports:

Hundreds of service stations across Australia have run empty, fuel prices are elevated and oil shipments have been cancelled. Australia is battling a fuel crisis as Iran’s closure of the strait of Hormuz continues to bite. The federal government has released fuel reserves, cut fuel excise taxes and rolled out a national fuel security plan.

As a result, the Australian opposition is calling on the government to adopt coal-to-liquid fuel. Politicians spent decades assuming global markets would always deliver. Now a shadow minister is standing in parliament arguing for Fischer-Tropsch. This is how the turn begins. The deeper the pain, the faster the post-Hormuz world will produce proposals that looked unthinkable six months earlier. In hindsight, it won’t be the subsidising of CTL plants that looks irrational. It will be the flooding of the mines.

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Meloni announced that Italy and Algeria would “deepen their already strong partnership” through Italy’s ENI and Algeria’s Sonatrach, including new cooperation on shale gas and offshore exploration. No volumes, no timeline. Albares pushed for increased pipeline flows to Spain. Same warm words, same lack of specifics.

The impending gas crunch will hit both countries substantially. Spain generates about 20% of its electricity from gas, while Italy is at 40%, according to The Statistical Review of World Energy. In 2024, 45% of Italy’s LNG imports came from Qatar. With Qatar LNG offline, courting suppliers is a matter of political survival.

In principle, rushing to Algeria makes sense. According to the U.S. Energy Information Administration, Algeria sits on 159 trillion cubic feet (Tcf) of proved gas reserves, the eleventh-largest endowment on the planet. Three pipelines connect Algeria to Europe: TransMed runs under the Mediterranean to Sicily and onward into Italy’s gas grid. MedGaz links Algeria directly to Spain’s southeast coast. A third, the Maghreb-Europe pipeline, once carried gas to Iberia via Morocco, but it’s been shut since 2021 over a diplomatic rupture between Algiers and Rabat. Today it runs in reverse, sending Spanish gas south to Morocco.

Algeria isn’t the only supplier European leaders are pinning their hopes on. Officials are running the same playbook with Azerbaijan and Egypt: collecting handshakes and memoranda from every producer willing to take the meeting. None of these meetings fail to tick off the usual boxes of commitment to climate targets and renewables—a strange incantation of a luxury belief that entirely misreads the correct priorities ahead of what could become the biggest energy crisis in history.

For clues whether such efforts can actually ease Europe’s energy woes, the Algerian case will almost certainly be instructive. Let’s find out why.

Start with the potential that European planners love to cite. TransMed, the main pipeline to Italy, runs at roughly 60% utilization (nameplate capacity of 33.5 bcm per year vs. 21 bcm flows in 2024). Algeria’s LNG terminals run at 46% utilization (25 million tonnes per year vs. actual output in 2024: under 12 million tonnes). MedGaz, the pipeline to Spain, is the only piece of infrastructure running near capacity, at roughly 90% utilization (9.4 out of 10.5 bcm).

The logic seems obvious: the pipes are half empty, so the upside is built in. However, the pipes aren’t half empty because the deals haven’t been struck. It’s because the gas isn’t there to fill them. The utilization gap is the result of a production deficit that’s been getting worse for twenty years.

Algeria’s gas exports peaked in 2005 at 64 bcm. Last year they came in at 49 bcm. That’s a 24% decline over two decades—not because production collapsed, but because domestic consumption absorbed any growth. In 2005, Algeria consumed roughly 22 bcm of its own gas. By 2024, that figure had more than doubled to roughly 50 bcm. The exportable surplus has been shrinking every year.

The drivers are self-reinforcing. Algeria has 47 million people, a median age of 28, and a population growing at 1.4% per year. Gas generates 99% of the country’s electricity, and electricity demand is growing at over 5% annually. Most critically, domestic gas is priced at a tiny fraction of its market price.

The price typically lands between $0.30 and $1.10 per MMBtu for households, and even lower for specific industrial sectors. One-tenth to one-thirtieth of what the same molecule fetches at the Italian border. At that price, there is zero demand-side discipline. And no Algerian government that remembers the civil war of the 1990s—200,000 dead—is going to touch energy subsidies to free up molecules for European buyers.

Sonatrach’s own commercial behavior confirms the trajectory. ENI, Enel and Edison—Italy's three long-term buyers—hold supply agreements with the Algerian state company totaling roughly 13 bcm per year, all expiring in 2027-28.

When those contracts were last renegotiated in 2019, the buyers held the leverage. ENI nearly halved its volumes and Enel cut by more than half. Sonatrach tried to find additional buyers and couldn’t. The market was loose and Algerian oil-indexed gas looked expensive.

Today the situation has flipped with Europe being desperate for molecules. But Sonatrach isn’t offering expanded long-term commitments. Bloomberg reported in March that Algeria is pushing Italy toward spot purchases rather than higher contract volumes. That’s not just a supplier seizing a seller’s market, it’s a producer rationing a declining exportable surplus.

Can Algeria drill its way out of the squeeze? First, there are natural obstacles to production growth. The gas is locked under the Sahara, where freshwater availability stands at just 295 cubic meters per capita, far below crisis thresholds. Fracturing demands massive volumes of water, not a method that works well in the desert.

Second, the economics of the Algerian state work against export. A cubic meter of gas priced at $0.30 for a domestic household buys more political stability than the same cubic meter sold at $10 to ENI. Algeria isn’t hoarding gas out of spite, the regime’s survival calculus and the physical constraints pull in the same direction: the molecules stay home.

In the foreseeable future, Algeria can’t deliver what Europe needs. But the question isn’t just whether Algeria can export more gas. It’s whether any of the suppliers Europe is courting are capable of being long-term exporters at all. There’s a simple ratio that separates structural exporters from wasting ones. European planners don’t seem to use it.

Take a country’s proved gas reserves and divide by its population. Call it reserves per capita. It won’t tell you exactly when a country flips from exporter to importer. But it tells you which direction gravity is pulling.

Qatar: 295 Tcf per million. Qatar could export gas for centuries and not notice. Russia: 12 Tcf per million and improving every year as its population declines. These are structural exporters, countries where the resource base so vastly exceeds domestic demand that no plausible consumption trajectory can absorb it.

Now look at where the gradient turns. Algeria: 3.4 Tcf per million and falling. Egypt: 0.5 Tcf per million. Egypt was a gas exporter a decade ago, a net importer today. The lower the ratio, the stronger the pull toward domestic absorption. Azerbaijan sits at 6 Tcf per million. Higher than Algeria, but already importing Russian gas to backfill domestic demand while maintaining export commitments to Europe. Even at that level, the treadmill has started.

Europe’s post-Russia diversification strategy has systematically selected suppliers near the bottom of the gradient. Algeria, Azerbaijan, Egypt—these are young, growing countries with legitimate development ambitions and populations that need cheap energy. Meanwhile, the countries with ratios an order of magnitude higher—the ones with reserves so deep that domestic demand could never absorb them—are the ones Europe has either sanctioned or lost to war. Russia is cut off by choice. Qatar is cut off by bombs. The diversified import model fails because the suppliers Europe can still access are developing economies on the wrong side of the arithmetic.

The outlier and test case is the United States. It is now Europe's single largest LNG supplier with a ratio of 1.4 Tcf per million—lower than Algeria. Right now, record exports seem to contradict the ratio because new capacity happened to come online just as Qatar went offline. But forces that tend to keep molecules at home—AI-driven power consumption, petrochemicals, and industrial reshoring—are accumulating.

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This creates a binary. Either the ratio holds, and US exports to Europe plateau or decline once the crisis normalizes—in which case Europe’s largest supplier isn’t a structural lifeline. Or the US proves to be an exception to the pattern, which would itself be a major finding: it would mean the world’s largest gas consumer can defy the gravitational pull.

Until falsified, the geopolitical direction of travel seems to confirm the ratio’s logic. In a world of contested shipping lanes, reshoring, and transactional alliances, the incentive to lock up molecules for domestic use only strengthens. Next time a European leader flies south to sign a partnership agreement, run the ratio. It will tell you more than the communiqué.

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The numbers are not comfortable reading. According to estimates compiled by Montel, a six-month Hormuz closure would push European gas prices to an average of €160/MWh. In the worst-case scenarios: €240/MWh. For context, €300/MWh in 2022 nearly broke the European industrial economy. Filling storage for next winter would be, in the words of one analyst, “close to impossible.” Demand destruction—factories closing, industries relocating—becomes the only balancing mechanism.

The IEA calls this the most severe energy shock since the 1970s. That era is instructive. Faced with the same chokepoint dependency, one country made a decision that still defines its economy fifty years later.

In the immediate aftermath of the 1973 embargo, France decided its electricity supply could not depend on resources that could be cut off by decisions made in the Middle East. It built nuclear aggressively and at scale. Today, 70% of its electricity comes from nuclear reactors and it exports €3 billion of electricity annually to its neighbors.

Germany, in contrast, drew the opposite conclusion. It shut down its last three reactors in April 2023 and now imports almost twice as much electricity as it exports. It is more exposed to a Hormuz shock than at any point in its postwar history.

Ursula von der Leyen, who voted for the nuclear exit as a member of the German Bundestag in 2011, now calls it a strategic mistake. Chancellor Merz agrees. The question that follows is obvious: can Germany reverse course? A lot of commentators brush away the question with a no. Merz himself claims the phase-out is “irreversible.”

You don’t need specialized knowledge in nuclear technology to answer that question. Enrico Fermi—the physicist who made nuclear reactions possible—was famous for making precise estimates in situations where very little information seems available, using nothing more than deduction and simple arithmetic. Run the irreversibility claim through Fermi’s method and the results aren’t what most people would expect.

After Germany switched off its last three nuclear reactors in 2023—Emsland in Lower Saxony, Isar 2 in Bavaria, Neckarwestheim 2 in Baden-Württemberg—operating companies have been busy decommissioning them. Decommissioning is a slow process that may take until the 2040s, which means these three plants are also the most intact and therefore the most viable candidates for restart.

Nukem, a German nuclear engineering firm specializing in the dismantling of nuclear facilities, put the reactivation cost at €1 to €3 billion per plant, with completion possible by 2030, in a March 2025 statement. The company puts the total number of reactivable reactors in Germany at six.

Nukem’s figures are more conservative than a parallel feasibility study by US-based Radiant Energy Group, which identified up to nine reactors suitable for restart at costs ranging from €320 million to €1.5 billion per unit. Take the conservative end. Six reactors, €3 billion each: €18 billion total. Roughly 9 GW of capacity back online.

These numbers don’t say much without denominators. Starting with the cost, the arithmetic coincidence is almost too neat: in 2024 alone, German taxpayers spent €18.5 billion in renewables surcharge that funds wind and solar. One year of renewable subsidies therefore covers the cost of restarting Germany’s six most viable nuclear reactors. Note that the €18.5 billion figure only covers generation capacity. The additional billions required for grid expansion, storage, and frequency stabilization that intermittent renewables demand are not included.

The second denominator is displacement. What does 9 GW of nuclear actually replace? Germany currently generates roughly 15% of its electricity from natural gas. That LNG dependency—exposed, volatile, and as the Hormuz crisis is demonstrating in real time, potentially catastrophic—is Germany’s most dangerous energy vulnerability.

9 GW of nuclear running at 90% capacity factor produces approximately 71 TWh of electricity annually. According to the Statistical Review of World Energy, Germany generated 78.4 TWh from natural gas in 2024. Restarting Germany’s nuclear fleet eliminates gas-fired power generation almost entirely—save for roughly 10 TWh per year of peaker generation that must respond in minutes to renewable intermittency.

Critics will say that Nukem’s cost estimate may be wildly optimistic. Take the UK’s most recent nuclear project, Hinkley Point C. Factoring in delays and inflation, costs have soared from an estimated £18 billion in 2015 to approximately £46 billion by 2030.

Let’s stress-test Nukem’s numbers with an even larger overrun. Assume their high-end figure is off by a factor of three. The total cost rises to €54 billion. That’s three years of renewable subsidies, for 9 gigawatts of stable baseload capacity. For a country staring down the biggest energy crisis since the 1970s—one that nonchalantly amended the constitution to put up €500 billion in new debt in 2025—that’s not a crazy number.

After cost, the next objection to restart is staffing. The engineers, technicians and operators who ran Germany’s nuclear plants are gone, the argument goes. This is factually wrong and the proof is visible at the plants themselves.

Decommissioning a nuclear reactor is not a job for generalists. It requires exactly the same expertise as running one: deep knowledge of reactor systems, radiation protocols, fuel handling, containment integrity. The people currently dismantling Germany’s reactors are the people who built and operated them. This is not a staffing constraint. It is a staffing allocation and allocations can be changed.

The third objection is insurance. Opponents claim nuclear’s liability exposure from a worst-case accident runs potentially into the billions, making it unbankable. Consider the Banqiao dam collapse in China in 1975. It killed approximately 200,000 people, more than every nuclear accident in recorded history combined. By the logic applied to nuclear, German hydropower is catastrophically underinsured. Nobody says that.

German reactors were all insured while they operated. The law imposed strict, unlimited civil liability on nuclear operators for nuclear accident damage, with a mandatory financial security requirement of approximately €2.5 billion per plant, beyond which the state backstopped residual liability.

The insurance argument also has a structural flaw that its proponents rarely acknowledge: the “uninsurability” of nuclear is not a market verdict, it is a legislative choice. The parliament that designed that framework is the same parliament that can redesign it.

Which brings us to the ban itself—and the most elegant test of whether the cost and insurability objections are genuine constraints or political cover. Germany’s nuclear energy law (Atomgesetz), prohibits the commercial generation of electricity from nuclear power. Amending it requires a simple Bundestag majority. Not a supermajority, not a constitutional amendment. A Tuesday vote.

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If nuclear power is truly uneconomic—too expensive to build, too risky to insure, too technically demanding to staff—then lifting the ban costs nothing. The market will confirm the objection. No investor will step forward. No utility will file a permit application. The Greens get to say “we told you so” with actual evidence rather than circular reasoning.

So here is the question that rarely gets asked: why does the Green lobby fight so hard against lifting a ban that—if their economic arguments are correct—is doing no work?

The market has started answering that question. Finnish-Estonian startup Steady Energy and Fermi Energia are so convinced of the commercial logic of nuclear in Germany that they are engineering around the ban. The Atomgesetz bans nuclear electricity generation. It says nothing about nuclear heat. So they are developing the LDR-50—a small modular reactor dedicated purely to heat production—to exploit that legal gap. The target market is district heating networks. Apparently the commercial opportunity is compelling enough to justify building around a legal obstacle that most companies would walk away from.

Those opposing to lift the ban understand that the market might not confirm their objections and that the interest likely would be there. Nuclear in Germany isn’t being kept out by economics. It is being kept out by a law. And laws are not physics.

A reversal would have market consequences beyond Germany’s borders. Gas-fired electricity represents roughly 10% of Germany’s total gas consumption. Restarting six reactors eliminates that demand slice almost entirely. In a European LNG market already facing a structural supply shock, removing Germany as a gas-for-power buyer doesn’t just solve a strategic problem. It materially loosens the continent’s most dangerous supply constraint. For anyone trading European energy that’s a structural shift in the demand curve.

Ultimately, Germany’s nuclear debate is about a political preference that has learned to speak the language of technical necessity so fluently that even serious people have stopped questioning it. The Hormuz crisis is asking the question again. The exit isn’t irreversible. The consequences of maintaining it are.

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If the direction does not change, we are going to have to consider and reconsider Sweden’s role in the Energy Union. I don’t say this lightly. I am a warm, dedicated friend of the EU. But we will then have to investigate all viable national measures to protect Swedish citizens and companies. And this includes a moratorium for new connections to continental Europe and for renewal of existing interconnections. And we are prepared with harsher and further actions apart from that.

The trigger: the EU plans to cash in on Sweden’s grid congestion revenue—the profits created by price differences in the electricity market. Last year it amounted to €3 billion, most of it generated inside Sweden’s own grid. The Commission wants to redirect 25% of that stream toward financing cross-border infrastructure elsewhere in the EU. The message to member states: build a system that works, and Brussels will treat it as a communal asset.

Sweden’s threat might not be entirely empty. In the summer of 2024, the country cancelled the Hansa PowerBridge—a €600 million subsea cable planned to carry 700 MW between Sweden and Germany. Stockholm’s stated reason was that Germany’s electricity market exported inefficiency into Sweden. The unstated reason is one that’s been building in Swedish politics for years: Germany’s renewable grid works partly because countries like Sweden stabilize it with dispatchable power and Swedish voters are noticing the bill.

The European energy market is about to dominate Swedish politics ahead of the parliamentary election in September 2026. In the 2022 campaign, electricity prices, European market integration, and exports to Germany already emerged as a hinge of Swedish politics—particularly in southern Sweden, where continental price spikes hit household bills hardest. The proposals that came up were telling: Sweden’s Left Party called for a separate export price—the “Sweden price”—to shield Swedish consumers from continental demand.

That problem got worse in late 2024. A prolonged Dunkelflaute—windless, sunless periods that are every renewable-heavy grid’s nightmare—gripped central Europe. Wind generation collapsed just as cold weather pushed demand higher. German wholesale electricity prices briefly hit more than €1,000 per megawatt-hour. Through the interconnected grid, the shock traveled north, forcing Norwegian and Swedish households to pay prices they hadn’t seen since the energy crisis that followed Russia’s attack on Ukraine. In other words, Sweden was being punished for providing a weather-independent buffer.

Busch’s warning might be dismissed as electioneering. But the Hansa PowerBridge cancellation suggests otherwise. What happens to Europe’s grid when its most reliable exporter decides the relationship no longer works? That question has a physical answer and the numbers are not reassuring.

Sweden exports a larger share of its electricity than any other country in Europe—nearly one fifth of everything it generates crossed a border in 2024. This share has grown 187% since 2000, roughly ten times faster than Sweden’s own growth in electricity production over the same period, according to data from the International Energy Agency.

While other European member states have spent that same period systematically dismantling dispatchable capacity and replacing it with weather-dependent generation, two thirds of Sweden’s electricity comes from hydropower and nuclear. In a continent increasingly running on wind and sun, Sweden is one of the few places that’s operating non-fossil baseload at scale.

Sweden’s total direct export capacity to continental Europe—through the Baltic Cable to Germany, SwePol to Poland, NordBalt to Lithuania, and onward flows through Denmark—amounts to 3.5 to 4 GW. Now consider what Germany was asking that capacity to help cover during the 2024 Dunkelflaute. Germany has installed almost 73 GW of wind capacity, but on a normal winter day it operates at around 25-30% of that, delivering 18 to 22 GW. During the 2024 event, output collapsed. As the German economy ministry wrote:

Due to unusual doldrums, the average output of wind power at 3.1 gigawatts (GW) has been nearly 85 percent lower than the 19.2 GW usually seen during this time of the year.

In other words, less than 5% of installed capacity. That’s a 16 GW hole. Filling it drew massively from Germany’s gas reserves: in early November they stood at 98% full, by mid-December they had dropped to 85%. Coal and oil generation had to be ramped up along with whatever neighboring countries could spare.

Sweden’s 4 GW of export capacity toward continental Europe could cover around one quarter of that gap. In the highly inelastic world of electricity demand, one quarter can make the difference between a manageable crisis and emergency grid interventions. The price signals showed it. As Busch tweeted at the time:

The rollercoaster of electricity prices is horrible […] This is a result of decommissioned nuclear power. When there’s no wind, we get high electricity prices with this failed electricity system.

Sweden has repeatedly demanded that Germany internalizes the costs it has been exporting northward. The main mechanism it has pushed for is zone-splitting: dividing Germany’s single electricity bidding zone into multiple smaller zones with distinct prices reflecting local supply, demand, and grid constraints. Export-heavy northern Germany, stuffed with wind capacity, would see lower prices. Import-reliant southern Germany, home to the automotive plants and chemical facilities, would pay more. This would accurately reflect the scarcity of their location.

Unsurprisingly, Germany has refused to comply with that request. Expanding wind and solar while dismantling nuclear has not delivered cheap energy. The opposite is the case. German industrial electricity prices are among the highest in the developed world, a slow-motion catastrophe for a manufacturing economy that built its competitiveness on energy-intensive production. Zone-splitting, in that context, is not a technical market reform, it’s a political grenade. Bavaria’s Minister-President Markus Söder pushed back: “Our country must not be divided.” A slightly silly way of saying: our industrial base is already bleeding, don’t ask it to pay even more.

As Swedish households effectively subsidize the suppressed energy costs of German industry, Stockholm’s pushback is equally understandable. Sweden divided its grid into four pricing zones to reflect its own internal bottlenecks. It invested in infrastructure that works. And it is being asked to expand the cables connecting it to a market that refuses to fix itself. Of course, Sweden isn't purely a victim of this arrangement given its electricity export revenues in the amount of €1.5 billion in 2024.

But acknowledging this doesn't resolve the core problem: the cost of running a continent on intermittent energy has to land somewhere. Germany is ensuring it doesn’t land on Bavaria. Stockholm has decided it won’t land on Sweden either. Two countries, both acting rationally, both trapped by the same broken system. The Commission’s proposal to redirect congestion revenues, under the circumstances, is not only politically tone-deaf. It actively discourages countries from providing system stability going forward.

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Sweden’s interconnectors are a potent instrument of coercion in this context. Threatening curtailment, blocking new capacity, making zone-splitting a non-negotiable condition for cooperation—each of those moves inflicts direct pain on German industry, which is already struggling to survive the consequences of the country’s poor energy choices.

As Germany is unlikely to give way, Sweden’s September election will push any government to shield consumers from continental prices. The consequence is physical: the next time a Dunkelflaute hits central Europe, the buffer is smaller. A smaller buffer pushes the adjustment elsewhere: more gas burn, faster storage drawdowns, and a sharper scramble for spot LNG cargoes in a market already tightened by disruptions in the Strait of Hormuz.

The decisive fissure points are rarely where anyone is looking. Right now they run along the cables under the Baltic Sea.

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