No Plan: How Germany Is Losing Its Business Model, and Why the Rest of Europe Should Be Worried

In December 2024, German industrial production fell to its lowest level since May 2020, the peak of the pandemic lockdowns. This time there was no lockdown. The factories did not stop because a virus shut them down, but because it was no longer profitable to run them. For context: Germany is the world’s third-largest exporter and Europe’s manufacturing engine. When German industry contracts, European supply chains feel it from Bratislava to Barcelona.

Electricity in Germany costs 17 to 20 cents per kilowatt-hour, compared to roughly eight in the US and China. GDP contracted two years in a row, the first time in over two decades. A country that defines itself as an industrial nation no longer has a viable model for delivering energy that is simultaneously affordable, secure, and climate-friendly.

The electricity mix 2024-2025: Records on shaky ground

First, the good news. Renewables covered roughly 54.4 percent of Germany’s gross electricity consumption in 2024, a record. In terms of public net electricity generation, they reached 62.7 percent according to Fraunhofer ISE. Onshore wind remained the single largest source at around 112 TWh, solar jumped to 75 TWh, up nearly 20 percent year-on-year. Hard coal dropped to 26.4 TWh, its lowest level since 1952. In 2025, wind and solar continued their advance: for the first time, they jointly surpassed all fossil and nuclear sources, with the renewable share rising to around 56 percent of gross electricity consumption.

But the record has a dark side. Gross electricity generation fell to around 489 TWh, a decline of 2.4 percent. Germany became a net electricity importer for the first time since 2002: the import surplus was around 25 TWh in 2024, primarily from France (nuclear), Denmark, and Scandinavia. In 2025, the balance remained negative at 21.9 TWh of net imports. The rising renewable share is partly a consequence of falling total production, not just rising renewable generation. Part of Germany’s emission reductions are being bought through shrinking industrial output.

Natural gas: Norway is the new Russia

Before the war in Ukraine, Germany sourced roughly 55 percent of its natural gas from Russia, primarily through the Nord Stream pipeline system running under the Baltic Sea. For decades, this was considered a pillar of European energy security, cheap Russian gas powering German factories that supplied the world. That dependency was rightly identified as a strategic failure after Russia invaded Ukraine in 2022. What gets less attention is that the dependency was not eliminated, only relocated. Norway now supplies 48 percent of Germany’s gas imports, transported via subsea pipelines in the North Sea. The sabotage of the Nord Stream pipelines in September 2022, the damage to the Balticconnector pipeline in October 2023, and the cable cuts to the C-Lion1 line in November 2024 have demonstrated how vulnerable subsea infrastructure is.

German gas consumption in 2024 was 844 TWh, up 3.5 percent year-on-year but still 14 percent below the 2018-2021 average. Industry consumed 12 percent less gas than before the crisis. This is not a sign of efficiency, but of production decline.

The LNG terminal program paints a sobering picture. The nominal total capacity of German LNG terminals was around 32 billion cubic meters per year by the end of 2024, but only 6.9 billion cubic meters were actually fed into the grid, a utilization rate of barely 22 percent. The Lubmin/Mukran terminal was at times only 8 percent utilized. Government costs for the entire program exceed $4 billion in subsidies plus €4.4 billion for 951 kilometers of new gas pipelines. Of the LNG imports through German terminals, 86 to 91 percent came from the United States.

And the prices? The TTF gas price averaged around €34 per megawatt-hour in 2024, down from the crisis peak of €236 in August 2022, but still far above the pre-crisis level of €13 (2019). The IEA notes: German industrial gas prices are on average five times higher than in the US. In March 2026, driven by the Hormuz crisis, TTF stands at around €52 per megawatt-hour.

Electricity prices as an industrial death sentence

Energy policy is industrial policy. Nowhere is this clearer than in the international comparison of electricity prices. The German industrial electricity price in 2024 was 16.99 cents per kilowatt-hour for mid-sized industrial customers. For large consumers with relief measures, it was 10.5 to 11.7 cents. For comparison: France pays 9 to 11 cents, the US around 8 cents, China also around 8 cents. Even with the new subsidized industrial electricity price of 5 cents, which has applied to around 2,000 energy-intensive companies since January 2026, a structural disadvantage remains that is only bridged by taxpayer money.

The consequences are already visible. Chemical production excluding pharmaceuticals shrank by 3.3 percent in 2025, capacity utilization fell to 72.5 percent, the lowest since 1991. 20 percent of VCI member companies are planning to relocate or shut down production. BASF, the world’s largest chemical company, cut around 4,800 jobs at its Ludwigshafen headquarters, the single largest integrated chemical complex on Earth, and closed adipic acid, ammonia, and methanol plants, while simultaneously investing €10 billion in a new complex in Zhanjiang, China. ThyssenKrupp Steel, one of Europe’s largest steelmakers, announced 11,000 job cuts and is reducing capacity from 11.5 to 8.7-9 million tonnes. Crude steel production fell to 37.2 million tonnes in 2024, 13 percent below the pre-crisis average.

The list is long: Volkswagen (up to 35,000 jobs), Bosch (~22,000), ZF Friedrichshafen (14,000), Continental (7,000+), Audi (7,500), Mercedes (~10,000). Between May 2019 and February 2025, roughly 361,000 industrial jobs were lost.

Renewables: Solar on track, wind behind, storage missing

The expansion of renewables presents a split picture. Photovoltaics grew by 16.2 GW in 2024, then by another 16.4 to 17.7 GW in 2025, reaching a total capacity of around 117 GW. The target of 215 GW by 2030 requires annual additions of nearly 20 GW, an ambitious but plausible pace.

Onshore wind accelerated significantly: from 3.25 GW (2024) to 5.2 GW (2025). Permits reached a historic record of 20.8 GW in 2025. But the 2030 target of 115 GW requires 9.4 GW per year, nearly double the current rate. Offshore wind remains far behind at only around 500 MW of additions per year, against a required 4.1 GW annually. The 30 GW target by 2030 is effectively unreachable; realistically it will be 2031 or 2032.

The most severe deficit concerns storage infrastructure. Installed battery storage capacity grew to around 25.5 GWh by end of 2025, with utility-scale storage reaching only 3.5 GWh. For adequate system integration, an estimated 100 to 400 GWh is needed by 2030. The 575 hours of negative electricity prices in 2025 are direct evidence of the mismatch: electricity is generated when nobody needs it, and cannot be stored for when it is needed. Pumped hydro storage remains stuck at 9.4 GW with no expansion in sight.

On grid expansion, there is progress: around 2,000 kilometers were approved in 2025, all four major HVDC corridors (SuedLink, SuedOstLink, A-Nord, Ultranet) are under construction. SuedLink is expected to become operational in 2028. But grid expansion trails generation expansion by years, sometimes decades.

Nuclear: 4.1 GW lost, €170 billion in disposal costs

On April 15, 2023, Germany’s last three reactors went permanently offline: Isar 2 (1,410 MW), Emsland (1,335 MW), and Neckarwestheim 2 (1,310 MW). Germany is the only major industrial nation to have voluntarily shut down its entire nuclear fleet. The decision, rooted in decades of anti-nuclear sentiment that intensified after the 2011 Fukushima disaster, remains one of the most controversial energy policy choices in European history. The lost capacity totaled around 4.1 GW. At its peak, Germany operated 19 simultaneous reactors with roughly 22 GW of installed capacity, supplying 30 percent of electricity generation.

One can disagree about the nuclear phase-out. What cannot be disputed is the sequence: Germany shut down its nuclear plants first, then tried to fill the gap with renewables, rather than first shutting down fossil plants. A PwC counterfactual analysis shows: with the 2010 nuclear fleet, 94 percent of electricity generation in 2024 could have been emission-free, instead of the actual 61 percent.

The costs of the phase-out are enormous. Decommissioning costs are estimated at roughly €47.5 billion. The search for a permanent waste repository, originally planned for a site decision by 2031, will not be completed until 2046-2068, possibly 2074. Total nuclear disposal costs through 2100 are estimated by the federal government at around €170 billion. The KENFO disposal fund grew from its initial €24.1 billion deposit (2017) to around €25.5 billion by end of 2024 and must reach €169.8 billion by 2099. Whether investment returns will suffice is an open question.

Coal: The market does what politics won’t

The statutory coal exit is scheduled for 2038. In the Rhineland (RWE), it was brought forward to March 31, 2030 by agreement. In Lusatia, LEAG is sticking to the 2038 timeline. But the market is outpacing politics. Coal generation fell to its lowest level since 1957 in 2024. In April 2024, 15 coal units totaling 4.4 GW were permanently retired. The Federal Network Agency confirms: forced shutdowns are unnecessary, the EU Emissions Trading System (price 2024/2025: €60-84 per tonne of CO₂) is making coal uncompetitive.

For structural transformation in coal regions, the federal government is providing around €41 billion through 2038. The EU approved compensation payments of up to €1.75 billion to LEAG and €2.6 billion to RWE. The question is no longer whether the coal exit will happen, but whether the affected regions will find economic alternatives in time.

Hydrogen: 10 GW target, 185 MW reality

The National Hydrogen Strategy sets a target of 10 GW of electrolyzer capacity by 2030. As of early 2026, only around 185 MW were installed, less than 2 percent of the target. An EWI analysis considers only 8.7 GW realistic by 2030, with nearly 3 GW of announced projects already canceled or paused.

The cost gap is fundamental. Green hydrogen in Germany currently costs €5 to €10 per kilogram, gray hydrogen from natural gas only €2 to €2.50. The target cost of €3 to €5 by 2030 is ambitious even for Germany; cheaper production is possible in North Africa or the Middle East (around €3.10 per kilogram including transport). Hydrogen demand is projected at 95 to 130 TWh by 2030, of which 50 to 70 percent is expected to be imported, establishing yet another massive import dependency.

On the positive side: the H₂ core network was approved in October 2024: 9,040 kilometers of pipelines, estimated investment costs of €18.9 billion, phased completion by 2032. The first 400 kilometers went into operation in December 2025. Salzgitter (SALCOS) is the most advanced green steel project, with a €2.5 billion investment. ThyssenKrupp, by contrast, suspended its hydrogen procurement tender due to excessive offer prices.

Hormuz 2026: The stress test nobody wanted

Following the US-Israeli strikes on Iran on February 28, 2026, tanker traffic through the Strait of Hormuz collapsed by roughly 70 percent. QatarEnergy declared force majeure on some LNG contracts after drone strikes on Ras Laffan, the world’s largest LNG liquefaction facility, damaged around 17 percent of Qatari export capacity. Bruegel estimates the shortfall at a minimum of 10 million barrels of oil per day, while the IEA described it as the largest supply disruption in the history of the global oil market.

For Germany, the crisis hit when gas storage was at its lowest point. Storage levels stood at just 30.2 percent in February 2026, the lowest since systematic monitoring began. The TTF gas price jumped to €52 per megawatt-hour. European natural gas futures rose roughly 71 percent since the start of the war.

The Hormuz crisis reveals what analysts have warned about for years: Germany’s new energy system is less dependent on any single supplier, but no less vulnerable to geopolitical shocks. And Germany is not alone in this. The entire European energy architecture, built on the assumption that global markets would always provide affordable fossil fuels, is being stress-tested simultaneously. LNG from Qatar flows through the Strait of Hormuz. Oil from the Persian Gulf likewise. And the Norwegian pipelines, Germany’s most important gas lifeline, run through a sea that is increasingly becoming a geopolitical flashpoint. What happens to German energy prices cascades through European electricity markets within hours, pushing up costs from Poland to Portugal.

Critical raw materials: The next dependency is already here

The energy transition itself is creating new dependencies. Germany imported around 5,200 tonnes of rare earths in 2024, of which 65.5 percent came directly from China. For the elements critical to wind turbines and electric motors, neodymium and praseodymium, Chinese dependency stands at nearly 100 percent. The ECB warned in 2025: over 80 percent of major European companies are no more than three intermediaries away from a Chinese rare earth producer. China’s export restrictions starting April 2025 on seven REE materials have already caused production stoppages in the European automotive industry.

In lithium, China controls around 80 percent of the processing stage, 98 percent of battery anodes, and 85 percent of global battery cell capacity. Solar modules are 70 to 95 percent manufactured in China. The EU Critical Raw Materials Act (March 2024) sets targets of 10 percent domestic extraction and 40 percent processing by 2030, but implementation is only just beginning.

Structural failure: Why politics keeps failing

The diagnosis is not that Germany is doing nothing. Solar expansion is impressive. The hydrogen backbone is taking shape. The coal exit is proceeding faster than planned. The diagnosis is that each of these measures is being pursued in isolation, without a coherent overarching model that addresses energy security, affordability, and climate protection simultaneously.

Three structural patterns run through two decades of German energy policy.

Sequence instead of simultaneity. The nuclear exit was completed before the coal exit, not the other way around. Renewable expansion was accelerated before storage expansion, not in parallel. Grid expansion trails generation expansion by years. Each individual decision may have had defensible reasons. In sequence, they produce gaps that must be filled by imports, fossil backup capacity, and higher costs.

Crisis management instead of strategic planning. The LNG terminals were built in a panic reaction to the 2022 gas price shock, creating overcapacity that now sits at 22 percent utilization. The subsidized industrial electricity price of 5 cents is an emergency measure, not a solution. The Hormuz crisis hits a country with gas storage at its lowest level in years. Germany’s energy policy reacts to crises instead of preventing them.

Conflicting goals without prioritization. Climate policy demands a rapid exit from fossil fuels. Industrial policy demands affordable energy. Security policy demands diversification and self-sufficiency. These three goals exist in tension that can only be resolved through massive investment in storage, grids, and domestic production. Instead, each goal is pursued by a different ministry, a different coalition, a different legislative term, with no overarching authority setting priorities. Germany’s federal system, with 16 states that each have veto power over wind farm permits and grid routes, and coalition governments that typically involve three parties with competing agendas, makes long-term energy planning structurally difficult in ways that centralized states like France or China do not face.

What a realistic scenario requires

A sustainable German energy model is possible. But it requires something German politics has avoided for decades: an authority that decides across departmental boundaries, faster than legislative terms and more binding than coalition agreements.

Storage as a system priority. The 25.5 GWh of installed battery storage must grow to at least 100 GWh by 2030. Without storage, every additional GW of solar capacity is a drop disappearing into the sea of negative electricity prices. This requires regulatory incentives (storage quotas for grid areas), accelerated permitting, and industrial policy support for domestic battery cell manufacturing.

Focus hydrogen, don’t spread it thin. The 10 GW electrolysis ambition should be concentrated on core industrial processes: steel, chemicals, refining. Not on space heating, not on passenger vehicles, where more efficient alternatives exist. Import contracts via H2Global must be accelerated as long as domestic production remains too expensive.

European integration instead of national solo efforts. Germany’s net electricity imports are not a sign of weakness, but an argument for a deeper European energy market. French nuclear, Scandinavian hydro, Spanish solar, and German wind complement each other. What is missing is sufficient interconnectors and a reformed market design that favors long-term supply contracts, not just spot markets.

Raw material diversification as a security imperative. 65 percent of rare earths from China, 48 percent of gas from Norway, 86 percent of LNG from the US: any single dependency above 40 percent is a strategic risk. This requires European raw material partnerships, recycling infrastructure, and strategic stockpiling.

Honest cost transparency. The subsidized industrial electricity price of 5 cents costs billions in taxpayer money. LNG terminals at 22 percent utilization tie up capital. €170 billion in nuclear disposal costs continue to accumulate. Honest energy policy quantifies all of these costs transparently, instead of distributing them across special funds, grid fees, and intergenerational contracts.

Germany does not have a knowledge problem. It has an implementation problem. The diagnoses have been on the table for years, in reports from scientific academies, in data from the Federal Network Agency, in the numbers this article compiles. What is missing is not another strategy paper. What is missing is a political architecture capable of aligning four ministries, sixteen federal states, and a four-year legislative term toward a goal that takes decades. This is not only a German problem. Every industrialized democracy faces some version of this tension between short electoral cycles and long infrastructure timelines. Germany just happens to be the most visible case study of what happens when that tension is not resolved.

Other countries have managed this. France built its nuclear fleet in 15 years. Denmark became a wind energy exporter in 20. China built a solar industry that dominates the world market in a single decade. In each case, there was a central authority with decision-making power and a time horizon beyond the next election.

Germany does not need an energy minister. It needs an energy architect.