Germany’s gas dependence: An energy security risk / Chapter 2
Germany’s unrealistic shift from gas-fired power to hydrogen
Key findings
Germany’s decarbonisation strategy relies heavily on hydrogen produced using renewable energy. Yet hydrogen production costs and project execution risks cast doubt on converting gas power plants to hydrogen at the required scale and speed.
Despite these challenges, Germany aims to have hydrogen power capacity equivalent to 87% of its current gas-fired fleet by 2045.
If Germany significantly scales up renewables, battery storage, cross-border grid connections and demand-side management, IEEFA estimates that the country could potentially source about 5% of its electricity from natural gas and hydrogen combined by 2045.
Government subsidies for gas power plants might delay investment in renewables and grid upgrades, locking in carbon-intensive assets and undermining the energy transition, in IEEFA’s view.
Natural gas-fired power generation continues to play a key, though increasingly contested, role in Germany. While the country’s energy transition prioritises renewables, natural gas and hydrogen are the federal government’s preferred sources of dispatchable electricity capacity to balance the intermittency of solar and wind.
German government strategies frame natural gas as a temporary “bridge fuel”, progressively replaced by hydrogen-ready infrastructure. However, persistent gas generation, extensive public support mechanisms and uncertainties surrounding the supply of hydrogen produced using renewable energy (green hydrogen) raise fundamental questions about the credibility, cost and coherence of Germany’s pathway to reaching net-zero emissions by 2045.
Germany’s planned transition from gas to hydrogen power
Germany’s natural gas-fired power capacity is entering a structural transition as the country moves toward a climate-neutral electricity system by 2045. The political discussion about the role of gas power intensified after Germany’s 2011 announcement to phase out nuclear and the energy security shocks of recent years. Successive federal governments have argued that maintaining a pool of controllable, fast-ramping capacity is essential to avoid electricity shortfalls during so-called “dunkelflaute” events — prolonged stretches of low wind and sunlight that can strain the grid.
Germany’s current natural gas power capacity is roughly 31–32 gigawatts (GW). The fleet includes both combined- and open-cycle gas turbine plants. The country relies more heavily on the higher efficiency combined-cycle plants.
Germany plans to retrofit existing gas plants to burn hydrogen to help meet its decarbonisation goals. By 2030, the country plans to replace part its gas fleet with 10GW of hydrogen-ready plants, designed to run initially on natural gas and convert to clean hydrogen as hydrogen supply increases. Beyond 2030, Germany’s Network Development Plan’s three scenarios for 2045 do not have exact gas power capacity values but show a clear trajectory: conventional gas capacity steadily declines as hydrogen-capable and fully hydrogen-fuelled plants grow. Hydrogen power plant capacity will rise to 17–28GW by 2040–2045 in the three Network Development Plan scenarios, according to the Federal Network Agency. This means the country aims to have hydrogen power capacity equivalent to about 87% of its current gas-fired fleet by 2045. This reflects hydrogen plants’ role as firm, dispatchable capacity backing a predominantly renewable system.
Across all pathways, the system shifts from relying on natural gas plants to provide baseload and flexible generation toward hydrogen assets that run only when renewables are insufficient.
However, the feasibility of using green hydrogen to decarbonise gas generation remains highly uncertain. Germany’s strategy relies heavily on the large-scale availability of green hydrogen, yet production of the fuel needs to be scaled up significantly to meet future demand. Production costs, import dependencies, infrastructure constraints and project execution risks cast doubt on whether gas-to-hydrogen conversion can occur at the required scale and speed.
Germany plans to import green hydrogen from projects including Hyphen in Namibia, for example. But projects such as these are overambitious and may never materialise because hydrogen transportation costs make them uncompetitive.
Will gas power undermine Germany’s energy security?
The disruption in natural gas supply following Russia’s 2022 invasion of Ukraine highlighted the energy security risks for Germany of relying on fossil fuel imports. Germany’s plan to construct at least 10GW of new gas power plants will increase the country’s dependence on gas imports. This could expose Germany to gas supply disruptions caused by geopolitical issues as well as high and volatile LNG prices. In 2025, Germany sourced 92% of its LNG imports from the US, the most expensive LNG for EU buyers.
Germany plans to switch its gas power plants to run on hydrogen. If Germany’s hydrogen pipeline network is delayed or if hydrogen production or imports fall short, the country could extend its reliance on gas as a fuel. Successfully switching its gas plants to run on hydrogen may still involve relying on foreign suppliers. This would effectively replace one import dependence with another, meaning energy security issues could persist.
Gas and hydrogen power generation
Germany’s gas-fired electricity generation has fluctuated over the years, influenced by the availability of renewable energy and the price of natural gas. In recent years, Germany’s gas generation has been about 80–100 terawatt-hours annually, roughly 15–16% of the country’s total electricity production. It is concerning that this share remains stable and shows no sign of decreasing. Gas plants mainly cover peak demand and provide flexibility to accommodate renewable generation.
Germany’s energy transition plan envisions a transformation of the country’s power generation mix by 2045, when it aims to have 80–90% of its electricity come from renewables.
Germany's goals require 2045 hydrogen power generation to be lower than current natural gas generation. The exact figures for 2045 depend on the extent to which the country uses green hydrogen and other low-carbon gases, such as biogas, in the generation mix. The government expects that hydrogen-fired generation will contribute around 10–15% of Germany’s total electricity production in 2050, with a significant planned shift toward hydrogen and synthetic methane in the gas mix. In IEEFA’s view, the country is unlikely to achieve such a high percentage.
Gas plant subsidies distort EU state aid rules
The German government has introduced schemes to support the development of new natural gas power plants, such as the capacity reserve mechanism (Kapazitätsreserve). This mechanism and the subsidies it provides are crucial to the financial viability of gas plants.
The German government also offers state aid for investments in power plants that use gases such as hydrogen. While this aligns with the country’s broader climate goals, the government has faced criticism for breaching EU state aid rules. These subsidies effectively prop up fossil fuel-based generation and could hinder Germany's energy transition and distort the energy market. The European Commission has expressed concerns that the state aid could undermine efforts to decarbonise and lead to excess gas generation, making it more difficult to achieve long-term climate goals.
State support for new fossil fuel infrastructure could be seen as inconsistent with the EU’s European Green Deal and European Climate Law, which call for ambitious decarbonisation efforts. In IEEFA’s view, these subsidies might delay investment in renewables and grid upgrades, locking-in carbon-intensive power generation.
Planned capacity mechanism
Germany also plans to introduce a capacity mechanism (CM) by 2028 to incentivise gas-fired plants to play a backup role, compensating them to be on standby even if they are not generating electricity. The CM will support the operation of gas plants that may otherwise become economically unviable as the cost of renewables and battery storage continues to fall. The CM could prolong the life of inefficient or polluting assets and delay the transition to a carbon-neutral grid.
In IEEFA’s view, Germany should review the CM design to avoid keeping gas plants open that would otherwise exit the market based on their marginal costs, thus allowing higher renewables penetration.
Firstly, the CM should be capacity neutral. All generation types, including renewables, should be eligible for payments. Allowing the CM for thermal only is discriminatory.
Secondly, Germany should update its capacity eligibility assessments to reflect more than just firm capacity. Using the current firm capacity definition (more than 95% probability of availability) implicitly excludes wind and solar from the CM. Germany should use a new definition of firm capacity: a compromise between the current one and nameplate capacity, so that wind and solar can have some, even minimal, share of their capacity eligible for the CM.
Thirdly, Germany should reduce the hours eligible for capacity payments. The CM is actually needed for less than 300 hours a year, corresponding to the one or two winter weeks with very low solar and wind generation. It is irrational for a combined-cycle gas turbine to receive a capacity payment for 8,760 hours when it supplies energy to the grid for less than 300 hours a year. Capacity payments reflect a much higher cost to the system than remunerating these winter hours on an energy-only basis. Therefore, in IEEFA’s view, the capacity payment should be entirely reassessed to reflect the actual costs the system should bear: an energy-only remuneration during dunkelflaute winter hours.
Alternatives to a gas- and hydrogen-dependent future
While hydrogen-capable gas plants are the government's preferred solution for dispatchable power, several alternatives could significantly reduce the need for natural gas and hydrogen in the long term:
1. Massive expansion of renewables. The most straightforward path to reducing gas and hydrogen reliance is to overbuild wind and solar capacity. A significant surplus of renewable generation would reduce the impact of dunkelflaute events.
2. Battery storage. Combining renewables with large-scale battery storage (both utility-scale and distributed) can smooth over short-term power imbalances of up to a day. Batteries can also reduce peak demand. Germany is actively promoting battery storage, with capacity growing rapidly, but the technology is still insufficient for multi-day periods of low renewables output.
3. Demand-side management and vehicle-to-grid technology. Leveraging the flexibility of demand from industrial loads to smart electric vehicle (EV) charging can significantly reduce the need for peak generation plants. A future fleet of millions of EVs could act as a massive distributed battery through vehicle-to-grid technology, feeding power back to the grid during periods of high demand.
4. Long-duration energy storage. Hydro pumped storage power plants (PSPPs) are the best solution to store power for extremely long durations. They allow for seasonal and even annual water storage for power generation, depending on the reservoir capacity. While PSPPs are usually built in mountainous regions to take advantage of natural elevation gaps, even relatively flat countries can use this technology with less than a 100-metre difference in elevation between two reservoirs. Lithuania’s Kruonis PSPP is one of the best examples, with only a 60-metre elevation difference. PSPPs require significant initial capital expenditure. The technology’s potential to respond to the intermittency of wind and solar remains untapped. Advanced compressed air energy storage and thermal energy storage are also promising long-duration solutions.
5. Geothermal power. Deep geothermal energy has the potential to provide carbon-free baseload power and heat. While geothermal power only provides a small share of Germany’s electricity generation, technological advances could significantly expand its role.
6. Enhanced grid interconnections. Strengthening cross-border connections with neighbouring countries would allow Germany to import electricity from regions with different weather patterns (for example, hydropower from Scandinavia or solar from Southern Europe), effectively diversifying the risk of a localised dunkelflaute.
What is the role of gas and hydrogen power plants in Germany's 2045 electricity system?
Solar and wind generation will dominate Germany’s future electricity system. The country plans to rely on natural gas power plants to support these technologies. But it will need to decarbonise its fleet of gas plants as it moves towards its 2045 climate neutrality target. It aims to achieve this by both converting existing natural gas power stations to run on hydrogen and constructing new hydrogen-ready gas plants.
But hydrogen power plants will likely play a smaller role than German government forecasts because of their high costs and low efficiency. Converting gas plants to run on hydrogen may also take longer than expected. The country may instead consider decarbonising gas plants with carbon capture and storage (CCS) technology. However, the lack of commercial‑scale gas CCS reference projects, substantial subsidy requirements and long development timelines mean this is a high-risk strategy. Therefore, given the high costs and uncertain timescales of decarbonising gas power stations, Germany should prepare for a 2045 power mix with minimal gas or hydrogen generation by significantly scaling up renewables, storage, grid connections and demand response.
A vision for 2045: A power mix with minimal gas and hydrogen
Germany should aim for a 2045 power mix with minimal natural gas- and hydrogen-fired generation. This would require a reliance on the technologies below. Such a strategy would see Germany spearhead Europe’s energy transition and would forge pathways for the rest of the continent to follow.
In this scenario, Germany’s 2045 power mix would look like this:
- Renewables (~95–98% of capacity). Onshore wind (~150–200GW), offshore wind (70GW) and solar photovoltaics (~400–600GW) would form the bedrock, generating most of the year’s electricity.
- Long-duration and seasonal storage (~5% of annual generation and a large share of capacity needs). Hydrogen salt caverns, filled via electrolysis during sunny and windy summers, would feed hydrogen into turbines or large-scale fuel cells during the winter. This would be complemented by about 5GW of pumped storage power plants. These two technologies would provide the terawatt-hours of energy storage needed for periods of low wind and sunlight lasting several weeks.
- Short-duration storage. Gigawatt-hours of utility-scale, industrial and commercial, and residential battery storage would smooth out daily variations in renewables generation and regulate grid frequency.
- Demand response. A smart grid would see industrial processes, EV charging and household appliances automatically adjust their consumption to match renewable energy availability, creating a flexible and efficient system.
- Baseload from geothermal and biomass. A mature geothermal sector (potentially 10–20GW) and sustainably managed biomass plants would provide the final layer of firm, predictable power.
- Enhanced grid interconnections. Stronger grid connections with neighbouring countries would allow Germany to import more electricity when domestic renewables output dips. This would enhance energy security and could lower electricity prices.
In this scenario, electricity system security no longer rests on combustion turbines but on the intelligent interplay of a diversified, resilient and overwhelmingly renewable-based system backed by multi-faceted storage solutions.
Figure 8 shows the share of renewables and gas/hydrogen in Germany’s power mix if all the developments mentioned above materialise.