In Part One, we traced how Germany rebuilt its electricity mix over a quarter-century. The renewable share leapt from 6% to 56%. Now we turn to what that means in practice: how stable is the power supply, how is industry coping with the cost, and how energy prices have reshaped everyday life — in Hungary and Germany alike.
1. Grid stability: the shadow of the Dunkelflaute
Ask any German electricity bill-payer what they lived through in November and December 2024, and many will recall the price spikes. The winter months brought prolonged stretches of still, overcast weather — the trade calls it Dunkelflaute. When that happens, wind and solar output falls close to zero just as household and industrial demand peaks.
The market consequences were immediate: spot prices — that is, the wholesale market's real-time prices — exceeded €300/MWh in some hours, and on 12 December 2024, in the costliest hours of that year, day-ahead contracts briefly spiked to close to €900/MWh while intraday contracts neared €1,000/MWh. That is about ten times the average €80–100/MWh wholesale baseline. Germany imported power at scale from France, Denmark, Switzerland and Norway to plug the gap. Later investigations by the Bundesnetzagentur and the Bundeskartellamt found no evidence of market manipulation behind the spike — the supply squeeze alone was enough to trigger the price explosion.
What is the Dunkelflaute?
The Dunkelflaute (literally "dark doldrums") describes winter weather in which mornings and evenings deliver neither sun nor meaningful wind. When that happens, renewable output is close to zero, and the entire load must be met by coal, gas or imports. In Germany, prices can stay high for two to three weeks at a stretch during such episodes. The phenomenon shows why simply building more solar and wind is not enough without dispatchable baseload or storage alongside.
But the problem is not confined to winter peaks. The system is dogged by grid bottlenecks all year round. In Germany, much of the wind power is generated in the north (the North Sea coast, Schleswig-Holstein, Lower Saxony), while the biggest consumers — the industrial belts and major cities — sit in the south and west (Bavaria, Baden-Württemberg, the Ruhr). The high-voltage lines needed to carry that north-to-south flow have simply not kept pace with the wind turbines.
2. The "tenth of a Hertz": when the whole of Europe shook
Grid instability shows up not only in price spikes but in frequency instability too. The European power grid's "heartbeat" is the 50.00 Hz system frequency. It tracks the real-time balance between generation and demand. If generation exceeds demand, the frequency rises; if demand exceeds generation, it sags. The continental European synchronous area covers 26 countries, all oscillating in unison — a disturbance in one country jolts the whole system.
Why is falling frequency so dangerous?
Frequency is the grid's "heartbeat". The heavy rotating masses of traditional coal, gas and nuclear generators provide inertia: if demand spikes or a unit trips, that inertia resists the change for a few seconds, buying time for control systems. Solar panels and classic "grid-following" wind-turbine inverters are not rotating masses — they have no natural inertia. New-generation "grid-forming" inverters and large battery farms can provide synthetic inertia, but their share is still small. As renewables spread, the system grows "softer": any sudden imbalance shifts frequency faster and deeper. If frequency drops below 49.5 Hz, automatic protection relays start tripping consumers and power plants — the catastrophic cascade towards total blackout.
In recent years, there have been several cases in which the European system came dangerously close to the edge:
At 21:02 CET, the continental European system frequency sagged to 49.80 Hz for nine seconds — the largest absolute frequency deviation since 2006, according to the ENTSO-E report. Two factors collided: a large jump in trading schedules at the top of the hour — the so-called deterministic frequency deviation — plus a "frozen measurement" on four German–Austrian high-voltage interconnectors that blinded operators to the real power flow. Across the 26-country synchronous area, FCR reserves and interruptible industrial-load contracts in France had to be activated. The emergency 49.50 Hz threshold was not breached, but the safety margin had shrunk to just 0.30 Hz.
At 14:04:25, a 400 kV coupling busbar at the Ernestinovo substation in Croatia tripped on overcurrent protection, triggering a cascade of further transmission-line disconnections. The continental synchronous area split in two: in the north-west (Germany, France, the Benelux) a shortfall of roughly 6.3 GW opened up, driving frequency down to 49.74 Hz; in the south-east the same surplus piled up, pushing frequency above 50.6 Hz. Amprion in Germany, Swissgrid and the south-eastern European TSOs together resynchronised the two islands roughly an hour later. The event proved that the whole continent's synchronous area can fracture after a single local disturbance — and with weaker inertia from renewables, stitching the system back together is harder.
At 12:33 CEST (midday, not evening), a total mainland blackout hit Spain and Portugal. The ENTSO-E expert panel's final report identified a complex trigger: shortcomings in voltage and reactive-power control, renewable plants running in fixed-power-factor mode, rapid active- and reactive-power ramps, oscillations, and rapid generator disconnections all combined. Mainland Spain and much of Portugal were without power for about 10 hours, and in some areas longer. The German Energiewende did not directly cause this event, but the structural pattern is the same: as the share of inverter-connected renewables rises and rotating-mass synchronous generators decline, the system's soft spots get worse. The lesson applies to the whole continent.
The lesson is clear: the Energiewende weighs not only on German consumers and industry but, indirectly, on the stability of the entire European synchronous grid. The missing natural inertia from renewables, grid measurement errors and slow-ramping reserve plants together open security gaps that were less of a concern two decades ago. The 2025 Iberian blackout showed this is not a theoretical worry — it can actually happen.
3. Redispatch: when wind power must be switched off
Redispatch exists to manage this geographical imbalance and the grid bottlenecks. The grid operators tell northern wind farms to curtail output because the lines cannot carry the power. At the same time, gas plants in the south are ramped up to meet demand. Owners of curtailed wind farms receive compensation, and dispatched gas plants are paid a premium. All of it lands on consumer bills via the grid charge.
What is redispatch?
Redispatch (re-dispatch) is an operator instruction: "curtail plant X, ramp up plant Y" so the lines do not overload. If, for example, northern Germany is producing more wind power than the lines can move south, wind farms there are curtailed and gas plants in the south are ramped up. Consumers pick up this tab too, through the grid charge. In Germany, annual redispatch costs have already crossed €3 billion in 2024 and 2025.
The numbers speak for themselves. In 2024, the German transmission system operators (TSOs) spent €2.95 billion in total on keeping the system stable — redispatch, countertrading and reserve power plants. That cost has doubled over the past decade. Costs rose again in 2025, hitting €3.07 billion.
Of that, roughly €1.18 billion covered conventional-plant redispatch, €433 million compensated renewable curtailments, and the remainder went on reserve-plant capacity and operating costs (preliminary data put this at close to €1 billion). In 2024, roughly 9 TWh of renewable output was curtailed — about 3.4% of total renewable generation, simply because the grid could not absorb it. A Clean Energy Wire report notes that compensation payments to renewables dropped 22% in 2025 against 2024 levels, because the grid took up more renewable output — but costs for reserve plants and redispatch kept climbing.
The upshot is that consumers do not just pay for the green power generated; they also pay for the green power wasted because the grid cannot take it. As Dietmar Bartsch, former co-chair of the Bundestag's Left (Die Linke) faction, put it: "The government is responsible for Europe's highest electricity prices — while electricity is being wasted. This must end."
4. The industrial crisis: in the shadow of energy prices
High power prices and uncertain supply strain households and undermine industrial competitiveness alike. Chemicals, automotive and steel are the backbone of the German economy — and all are energy-intensive industries. If energy costs three to four times as much as it does for rivals, plants either shut or relocate. Economists call this process Deindustrialisierung, or deindustrialisation.
What is Deindustrialisierung?
Deindustrialisation describes a situation in which factories do not close for lack of demand, but because energy, labour and regulatory costs make it cheaper to produce elsewhere — say, in China or the US South. Since 2020, the German chemicals industry has relocated much of its production to Asia and the United States. It costs jobs, tax revenues and technological know-how.
BASF: the chemical giant's two faces
The world's largest chemicals company, BASF, runs its global Verbund (integrated) hub at Ludwigshafen. The complex is a city in its own right: some 200 production plants, about 39,000 employees and interlocked supply chains. In the chemicals industry, electricity is not merely "energy" but a core production input — petrochemical processes need electrically powered steam generators and reactors.
BASF's response to the cost pressure has been a two-pronged strategy:
- Ludwigshafen's retrenchment: Since 2022, the company has been running a €500 million-a-year savings drive across Europe. As part of it, BASF shuttered the TDI (toluene diisocyanate, a polyurethane foam feedstock), adipic acid and caprolactam plants at Ludwigshafen. These are basic chemicals used in cars, plastics and textiles. The rationale is clear: European energy and carbon prices make production here many times more expensive than in China or the Middle East.
- Zhanjiang: the Asian bet: At the same time, BASF is building the world's third-largest Verbund complex in Guangdong province, China. Originally announced as a €10 billion investment, the total capital outlay eventually came in at around €8.7 billion, per the company's 2025 guidance. The Zhanjiang site's steam cracker started up in November 2025 with annual ethylene capacity of 1 million tonnes, and the company claims it is the world's first cracker whose main compressors run entirely on renewable power.
BASF's strategy thus highlights the problem: the German chemicals industry is not dying — it is emigrating. The know-how and capital stay with the company, but production — and with it the jobs and the tax revenues — moves abroad.
Volkswagen: the electric transition stalls
The Volkswagen Zwickau plant is steeped in symbolism: East German Trabants were once built here, and by 2020, it had gone fully electric. The plant currently builds six different electric models for three group brands: Volkswagen ID.3, ID.4, ID.5, Audi Q4 e-tron, Audi Q4 Sportback e-tron and Cupra Born, with capacity for 300,000 cars a year. It is one of Europe's biggest all-electric vehicle plants.
In autumn 2025, however, VW announced it was halting production for several days at Zwickau and Dresden because of weak demand. Output of the ID.4 and ID.7 at the Emden plant is also being cut. Under a December 2024 employee agreement, the Volkswagen Group plans to shed around 35,000 German jobs by 2030 — via retirement and voluntary redundancy, with no compulsory redundancies or plant closures.
The problem is not only that European consumers are buying electric cars more slowly than expected. It is also that VW's EVs are pricier than Chinese rivals', partly because batteries and electricity cost more in Germany. In China, BYD and CATL build batteries cheaply, with state subsidy; German factories must import the raw materials and pay dearly for their power.
The general state of industry
German industrial production suffered repeated declines in 2025. Destatis data show that in September 2025, industrial output fell by 1.0% month on month and by 2.5% year on year. In August, output dropped 2.9%, and the car industry saw an eye-watering 18.5% monthly plunge.
The energy-intensive sectors — aluminium, steel, chemicals, fertiliser, glass — have been hit hardest. ThyssenKrupp's Duisburg steelworks, for example, wants to switch from traditional coking processes to hydrogen-based (green steel) technology, but that requires cheap green hydrogen and cheap power — and neither is available at competitive prices in Germany.
5. Inflationary effects: the dual role of energy prices
Energy prices hurt factories and households alike. Germany's inflation path over the past five years has tracked energy prices closely.
The post-pandemic recovery and rising raw-material prices were already pushing prices up by then.
The Russia–Ukraine war and the withdrawal of Russian gas drove natural-gas prices to historic highs. Energy prices contributed 3–4 percentage points directly to inflation.
Gas prices eased, but utility bills and services-sector prices kept climbing. Core inflation (excluding food and energy) remained sticky.
Falling energy prices dragged the headline rate down. Services (+3.5%), however, kept rising fast.
Destatis's January 2026 correction put annual inflation for 2025 at 2.2%. By December, energy prices were already below a year earlier, and electricity was down 1.8%. Household bills nevertheless remained structurally higher than the pre-2021 level, partly because of high grid fees.
The German inflation experience carries a twofold lesson:
- The fall in energy prices in 2024–2025 did drag inflation down — proof that renewable expansion and LNG diversification can stabilise prices over the long run.
- Yet household bills did not revert to the pre-2021 level, because grid fees, taxes and system costs (redispatch) have structurally raised the baseline cost of household energy. Consumers therefore "paid once" for the transition in the form of an inflationary shock, and now "pay a second time" through high fixed charges.
6. Utility policy: German market vs. Hungarian price cap
To manage high prices, Germany and Hungary took two diametrically opposed paths. The gap is striking: German household electricity in 2025 averaged around 39.6 cents/kWh — one of the highest tariffs in Europe. By contrast, Hungarian households pay a net 36 Ft/kWh under the state-capped household energy price scheme (rezsicsökkentés) for up to 210 kWh a month. At the current 388–390 HUF/EUR rate, that works out at roughly €0.09–0.10/kWh.
- Consumers see the real costs on the bill, which drives energy efficiency.
- In 2023, the Strompreisbremse (electricity price brake) capped 80% of household consumption at €0.40/kWh, with the state picking up the tab for the rest.
- In 2024, the subsidy expired and the full market price returned — transparent, but expensive.
- Household electricity up to 210 kWh of monthly consumption is 36 Ft/kWh (about €0.09/kWh) — one of the lowest residential tariffs in Europe. Above the limit, the market price leaps to 70.1 Ft/kWh.
- The gap is funded by the state budget and by losses at the utility companies — independent estimates put the cost of the price-cap scheme at around HUF 1,500–2,000 billion in 2022, and almost HUF 5,000 billion in total over recent years.
- The hidden budgetary burden adds to state debt and distorts consumer choices (weaker incentives to save energy).
What is the Strompreisbremse?
The Strompreisbremse (electricity price brake) was a rescue package passed by Berlin in 2022 and in force during 2023: "Pay the market price, but if it exceeds €0.40/kWh, the state pays the difference on 80% of the previous year's consumption." It temporarily shielded households during the crisis but carried a significant budgetary burden running into tens of billions of euros (in the end, the sum drawn fell short of the headline ceiling because prices dropped faster than expected). By 2024, it had expired, and the full market price was back on bills — which is why German household costs jumped again.
The two models' economic balance is interesting:
- Germany: market pricing is transparent and efficient, but it generates social tensions. With tariffs so high, energy poverty (energetische Armut) is rising: more and more households are falling behind on their electricity bills. In the German model, costs appear directly on the bill — politically risky, but economically candid about the true price.
- Hungary: the price cap is popular in the short run and stabilises household budgets. Over the long run, however, it distorts the market: there is less incentive to buy an energy-efficient fridge or install solar panels when power is cheap anyway (at least up to the cap). The budgetary burden also diverts resources from other public investment.
7. A view from Hungary II — Paks II and the solar boom
How does all this look from the Hungarian vantage point? In 2024, two opposing processes unfolded in Hungary at the same time:
- The solar explosion: small-scale household and industrial solar plant capacity exceeded 6 GW by the end of 2024, and solar's share of total domestic power generation grew to roughly 24%, overtaking gas (18.7%). This growth pace is faster than Germany's 2000s boom, and signals that Hungarian households and firms are highly receptive to renewables — provided the state subsidises installation.
- Paks II as a backstop: at the same time, work is under way on two new reactors (2×1,200 MW, total 2,400 MW) at the Paks nuclear plant (the Russian-built Paks II expansion). Originally slated for around 2030, the first reactor is now expected around 2032–2033, according to recent government and Rosatom statements. The planned operating life runs to 2060, and the plant is meant to provide baseload. While Germany has phased out nuclear entirely, Hungary is betting precisely on expanding renewables alongside controllable, carbon-free baseload.
Risk comparison:
| Risk factor | German model (nuclear-free) | Hungarian model (nuclear + solar) |
|---|---|---|
| Weather dependence | High — when the wind drops, Germany needs gas and imports | Low — nuclear delivers stable baseload |
| Import reliance | High — net power imports of ~25 TWh in 2024 | Medium — significant gas and net power imports (~15+ TWh) |
| System stabilisation cost | €3+ bn/year | Lower — more centralised system |
| Standard residential unit rate | ~€0.396/kWh (market, 2025) | ~€0.09/kWh (state-capped, up to 210 kWh) |
| Frequency stability | High risk — ever more inverter-based renewables | More favourable — nuclear inertia in the domestic mix |
| Technology risk | Low — proven wind and solar tech | High — Paks II delay and cost risk |
The Hungarian model therefore promises lower system costs, steadier supply and better frequency stability, because the heavy rotating masses of nuclear generators provide inertia to the system. That partly offsets the missing natural inertia of solar panels. It is worth adding, however, that Hungary sits on the same continental synchronous area as Germany, so a major system-wide frequency event can still ripple across into Hungary. In Germany, the gap is currently plugged with expensive gas reserves and €3 billion a year in system stabilisation costs — but the 2019 and 2021 events, and above all the April 2025 Iberian blackout, showed that this fix is imperfect.
The takeaway: for Hungary, the German example shows that expanding renewables on its own is not enough. Controllable capacity (nuclear, gas, hydro, storage) is needed alongside, or system costs will spiral and frequency stability will be at risk too. The Hungarian "dual strategy" — nuclear plus solar — looks more economically rational than the German "wind-and-solar maximalism", but only if Paks II is completed on time and on budget, and grid development keeps pace with the solar boom.