Germany's Power Revolution

On 1 April 2000, Germany's Erneuerbare-Energien-Gesetz (EEG) — the Renewable Energy Act — entered into force. No one suspected that this single law would set in motion the largest energy experiment on the continent. A quarter-century on, in 2025, the German Energiewende reveals itself for what it is: not merely the remaking of one country's power system, but a macroeconomic laboratory in which climate targets, competitiveness and social equity exist in permanent tension.

Over three parts, this series asks what Germany has actually achieved, at what price, and what it all means for any country whose energy-policy choices — from the Paks nuclear plant and its Russian-built Paks II expansion to rooftop solar — turn on the same trade-offs.

1. The starting point: Germany in 2000

At the start of 2000, Germany's electricity mix followed the template of traditional industrial powers. Hard coal (Steinkohle) and lignite (Braunkohle) plants formed the backbone of power generation, with nuclear providing baseload. Renewables — hydro, wind and solar — accounted for just 6.3% of gross electricity output. The snapshot is telling: total wind capacity stood at barely 6 GW, and solar was practically negligible.

Why did change come at all? In the 1990s, Germany's political establishment — conservative and social-democratic alike — increasingly accepted that the country's reliance on fossil and nuclear power was a long-term risk. The memory of the oil shocks, the public unease that lingered after Chernobyl, and the scientific consensus on climate change combined to lay the political foundation for the EEG. The motive was not purely environmental: German policymakers also recognised that the industrial potential locked inside renewable technology could deliver a lasting competitive edge.

2. The EEG Act: the engine starts

When the EEG was introduced in 2000, legislators reached for a simple but economically radical instrument: the feed-in tariff. The state guaranteed every renewable producer — whether a rooftop solar array or a wind farm — a fixed price for 20 years, and spread the cost across all consumers through their electricity bills. At a single stroke this removed investor risk (because revenue was contractually fixed) and created the market demand that the technology needed to mature.

The results were not long in coming. Between 2000 and 2010, installed wind capacity passed 27 GW and solar reached 17 GW. The renewable share leapt from 6.3% to 17%. At the same time, system costs began to creep up: the EEG surcharge was barely noticeable in 2000, but by 2013, it accounted for almost 20% of the household electricity price. That was the first warning shot — the green transition is not free, and the cost is passed on to consumers.

3. The Fukushima turn and the nuclear phase-out (2011)

The Energiewende's real political inflection point came not in 2000 but on 11 March 2011. The Fukushima disaster prompted the Merkel government to abandon its pro-nuclear stance overnight and announce a full nuclear phase-out by 2022 (completed in April 2023 with the shutdown of the last three reactors). Economically, the decision was a milestone: Germany was deliberately removing one of its largest firm, carbon-free baseload sources from the system.

Before 2011, the country was running 17 nuclear reactors with a combined capacity of around 20 GW. They generated roughly 140 TWh a year — close to a quarter of total electricity consumption. The phase-out had two simultaneous effects:

1. In the short term, lignite and hard-coal plants staged a comeback because they were the only fleet that could plug the gap left by nuclear. Between 2011 and 2015, coal's share temporarily rose — apparently at odds with the climate targets.
2. Over the medium term, renewable expansion accelerated. Wind deployment — particularly in the northern Länder and the North Sea — picked up steadily, and solar spread across the sunny south (Bavaria, Baden-Württemberg).

4. The Zeitenwende: when energy policy became security policy (2022)

The second shock arrived on 24 February 2022, with the outbreak of the Russo-Ukrainian war. By then Germany was deeply embedded in Russian fossil supply chains: in 2021, Russian gas still accounted for 55% of German gas imports. The power sector was implicated too, because gas plants were used to balance the fluctuating output of renewables.

Chancellor Olaf Scholz used the term Zeitenwende for the first time in his speech of 27 February 2022. That moment marked the official rewiring of German energy policy: alongside the climate targets, security of supply and independence now took centre stage. In that spirit Germany commissioned its first floating LNG (liquefied natural gas) regasification terminals (FSRUs) at Wilhelmshaven and Brunsbüttel in record time — just 8–10 months from green light to first cargo.

Geographically, gas diversification worked: the Russian share effectively fell to zero, replaced by Norwegian pipeline gas, Dutch–Belgian LNG imports and Germany's own FSRUs. Yet dependence did not vanish; it simply moved. Germany is now exposed to swings in the global LNG price, which hit historic peaks in 2022.

5. The electricity mix in 2025: success and shortfall, in numbers

The numbers tell the story. Preliminary 2025 data from Fraunhofer ISE, the Fraunhofer Institute for Solar Energy Systems, show renewables accounting for 55.9% of German public net electricity generation.

Breaking that down:

• Wind: close to 30% (132 TWh) of gross grid generation, or 28.8% of the public net mix. Onshore wind accounts for the larger share (106 TWh); offshore wind farms contributed 26.1 TWh.
• Solar: total output was 87 TWh (71 TWh to the grid, 16.9 TWh self-consumed), or 15–16% of public net generation. That is 21% growth on 2024, and 2025 was the first year in which solar alone overtook lignite.
• Biomass: about 8% (36 TWh to the grid). This steady, dispatchable renewable is often eclipsed by the headline growth of solar and wind, but it does much of the unglamorous work of holding the system together.

The rest comes from fossil sources and imports:

• Coal (hard + lignite): around 20%. Lignite net generation was 67.2 TWh (on a falling trend), hard coal 26.7 TWh (slightly up). Together they still matter.
• Natural gas: 10–12% (52.4 TWh of net public supply). Used mostly in combined-cycle plants, it remains the most important dispatchable backup capacity.
• Imports: gross imports in 2025 were 76.2 TWh and gross exports 54.3 TWh, leaving net imports at 21.9 TWh — down on 2024. The pattern has shifted: the largest shares of imported electricity came from Denmark (12.4 TWh), France (11.2 TWh), the Netherlands (8.4 TWh) and Norway (7.0 TWh).

Set against the targets, however, the picture is less flattering. The federal government has set an 80% renewable share for 2030. To hit that, wind build-out would have to accelerate sharply. By the end of 2025, installed onshore wind capacity stood at 68.1 GW. Against earlier plans (Fraunhofer ISE figures once cited a 76.5 GW marker), and even under the current EEG 2023, the sector is running behind: the law sets 69 GW by 2024, 84 GW by 2026 and 115 GW by 2030. Slow permitting, local opposition (the NIMBY phenomenon — "Not In My Backyard") and a shortage of grid connections mean the build-out is falling short. Offshore wind is growing faster, but construction costs and subsea-cable rollout are causing delays there too.

6. Electricity prices: the costly transformation

If one number had to sum up the cost of Germany's transition, it would be the electricity price. German household tariffs have moved into the European top tier over the past decade and a half, and in 2024, they remained among the highest on the continent.

Eurostat data for the second half of 2024 put the German household price at an average €0.3943/kWh (roughly HUF 155/kWh, in the Hungarian forint, HUF). That is almost four times Hungary's household price of €0.1032/kWh (roughly HUF 40/kWh) in the same period. Part of the gap comes from taxes and levies; the rest reflects the climb in underlying system costs.

On the wholesale (spot) market, the 2025 day-ahead average sat around €89/MWh (SMARD data show €89.32/MWh, 13.8% above the 2024 reading of €78.51/MWh). The real story, though, is volatility: on sunny, windy days prices can drop to €20–30/MWh, while on still, overcast winter days they spike to €300–400/MWh. In 2025 the spot price breached €300/MWh in 40 separate hours; the annual peak was €583.40/MWh.

The composition of German household electricity bills compounds the problem. An average bill has four parts:

The implication is uncomfortable: even if the wholesale price fell to zero, German consumers would still pay at least €0.25–0.30/kWh in fixed costs.

7. Diversification: the import-dependence paradox

Diversification has to be read on two levels: geographical and technological.

Geographical diversification. Having phased out Russian gas, Germany switched to Norwegian pipeline gas, Dutch–Belgian LNG imports and its own FSRUs. The import map has both widened and shifted towards politically more stable suppliers. On a security-of-supply test, that is a success.

Technological diversification. Here the picture is more mixed. In the power sector, the rising renewable share has cut fossil-import dependence. Yet system stability still depends on dispatchable capacity, which today is overwhelmingly gas. Because domestic gas production is negligible, the gas-technology dependence remains — only the Russian supplier has been swapped out for Norwegian and American ones.

On top of that, the EU Emissions Trading System (EU ETS) keeps pushing up the cost of fossil generation. In 2024–2025, the EU carbon allowance traded in a €60–90/tonne range, materially raising the operating costs of coal and gas plants. That alone keeps a floor under prices, quite apart from the Russo-Ukrainian war.

8. A Central European comparison: the electricity mix and the hit to households

How does this look from a Central European vantage point? The comparison is instructive.

The structural difference is plain: Germany has built a decentralised, weather-dependent (intermittent) system dominated by solar and wind, neither of which is dispatchable. Hungary, by contrast, has stuck with a centralised, dispatchable system in which nuclear carries the baseload, backed up by natural gas and rapidly growing solar.

This is not a back-of-the-envelope thought experiment: were Hungary to drop nuclear power and regulated tariffs tomorrow and adopt the German model wholesale, household costs would rise in similar proportion. The German model bundles the technology with market pricing, under which the consumer carries every system cost.

The Hungarian model has its own dark side, of course. Behind the low, regulated prices lie heavy fiscal burdens: financing the state-capped household energy price scheme cost HUF 1,000 billion in 2022, covered by the state budget and the losses of utility companies. That is hidden debt, borne by the Hungarian state — and ultimately by taxpayers. In the German model, those costs show up on the bill; in the Hungarian model, they are buried in the budget.

But households are not the only ones paying for the green transition. In the second part of this series, we examine how the German "miracle" has strained the country's economic backbone: why heavy industry is leaving, what happens to the grid in a windless winter, and what "green inflation" looks like in practice.

The bottom line. Germany has shown that a drastic rise in the renewable share is possible — but the price is household tariffs at the top of the European table and system costs that have grown exponentially. For Hungary, the question is whether stable utility bills are worth giving up for a first-mover advantage. So far, the German example suggests that climate targets and economic reality have to be reconciled — otherwise the green transition runs straight into popular resistance.