Germany’s electricity system is entering a crucial period of transition, with the country aiming for greenhouse gas neutrality by 2045. At the same time, the conventional generation fleet is shrinking: Germany’s last three nuclear power plants were closes on April 15, 2023and the Coal Phase Out Act provides for the closing of the last coal-fired power plant no later than 2038.
The policy targets imply an energy system dominated by intermittent renewables by 2030. According to the Renewable Energy Sources Act (EEG) 2023, Germany aims for at least 80% of its gross electricity consumption from renewable sources by 2030, with an expansion path of 215 GW solar PV and 115 GW onshore wind (among others). As weather-dependent generation increases and baseload capacity declines, maintaining adequacy during periods of low renewable resource availability becomes increasingly challenging, driving the need for reliable dispatch capacity.
This is the policy context for the government’s evolving security of supply toolkit. In January 2026, the Federal Ministry for Economic Affairs and Energy (BMWE) announced a agreement in principle with the European Commission on the key parameters for the implementation of the power plant strategy (Kraftwerksstrategie). In parallel, the Bundestag has outlined plans to work towards a technology-neutral capacity mechanism that is intended to be operational by 2028.
In this paper we assess what impact long-duration energy storage (LDES) can have on the cost of the firm’s dispatchable capacity required to ensure security of supply in a German power system with high renewables.
METHODOLOGY
We apply a capacity sufficiency model to calculate the backlog and therefore require robust capacity with and without varying battery energy storage (BESS) durations in the dispatchable capacity mix. The model is based on the open source ECO STOR Dark doze dashboard optimization framework and represents a 2030 German system with renewable construction aligned with the EEG 2023 targets.
The model uses five years of historical weather and demand data (2020 – 2024). These data are used to establish solar, onshore wind and offshore wind (RES) generation profiles and demand profiles, albeit with scaled volumes to meet the 2030 targets. The residual load is defined as LOAD net of base load AND renewable resourceswhere the base load is provided by biomass and hydro plants.
We model a sensitivity with strong capacity provided only by gas plants and some sensitivity with a mixture of gas plants and BESS. In mixed gas and BESS sensing, the battery delivery is optimized to reduce the peak residual charge and therefore the required gas capacity. The installed power capacity of BESS is fixed; only the energy capacity varies from 2-hour to 10-hour durations in 2-hour increments. The analysis focuses on the separate German system; cross-border power flows and internal grid constraints are not modeled. As a result, the analysis captures the value of storage adequacy, but does not reflect the potential additional system benefits of storage located in transmission-constrained areas, such as reduced curtailment and reshipment volume.
Key adequacy outcomes include firm capacity required to meet backlog, energy supplied by that capacity, and the extent to which BESS displaces gas plant capacity. Using these results, we calculate an “all-in” annual cost metric that includes annual CAPEX recovery, fixed operation and maintenance (O&M) costs, and variable costs (fuel and charging costs). This is the full economic cost of meeting the backlog in the model with new resources. It is not intended as a forecast of future contract payments under a power plant strategy or a capacity market, as new plants are expected to participate in standard market revenue streams. Therefore, we focus on the relative cost impacts of introducing BESS to the dispatchable mix.
Fuel costs in the modeling are based on a gas price of approximately €32/MWh (Dutch TTF levels at the beginning of 2026) and a carbon price of €126/tCO2, in line with the published EU ETS outlook for 2030.
Results: Dispatch of battery
In the model, the BESS mainly shaves the peaks of the residual load. It is charged during RES surplus and low residual load hours, and discharged during higher residual load hours. We quantify how effectively the BESS reduces required hard capacity using effective load carrying capacity (ELCC), which measures the amount of fully reliable capacity that storage can replace.
ELCC increases with duration, at first rapidly and then with diminishing returns, from 57% for 2-hour systems to 88% for 6-hour systems, then 97% and 100% for 8- and 10-hour systems. This is because longer duration systems can carry the discharge through periods of high residual load that shorter duration systems cannot fully cover. An ELCC of 100% means that each megawatt of BESS provides the same sustainable capacity contribution as one megawatt of fully reliable generation in the sufficiency model; it does not mean that the storage meets all the peak demand.
Figure 1: ELCC by BESS duration
These ELCC scores are averaged over the five weather years studied. Importantly, the longer-duration systems show consistent results across the full sample: the 10-hour ELCC reaches 100% in all five years, while the 8-hour ELCC remains above 90% in each year. Shorter durations indicate greater year-to-year variation.
ELCC affects the economic value of shelf life. In the case of natural gas, the resulting cost savings stabilize around the 8-hour duration (Figure 2); under higher cost fuels such as hydrogen, the economic case for extended duration increases (Figure 3).
Results: Natural gas
We first calculate the adequacy cost of filling the entire backlog with natural gas power plants and then allow BESS to replace a portion of that gas capacity and quantify the cost difference.
The introduction of BESS lowers the sufficiency cost per kW of the firm’s procured capacity, with savings improving over time. For the 2-hour duration BESS, the cost saving per kW of firm capacity procured is around €7/kW per year, rising to around €12/kW per year for the 8-hour BESS. In percentage terms, this is a 1.5% (2-hour) to 2.6% (8-hour) reduction in total sufficiency cost compared to a gas-only basis.
Figure 2: Percentage cost savings by duration BESS – Natural Gas
For the 12 GW of firm capacity set to be procured under the power plant strategy, this equates to annual savings of around €90 million per year (2 hours) to €140 million per year (8 hours). Between 2030 and 2050, well within the service life of contemporary LFP BESS, which is in the order of €2 – 3 billion of avoided sufficiency cost compared to gas-only sensitivity (with today’s typical funding assumptions).
These savings, although modest in percentage terms, would be material in the sufficiency procurement framework. A reduction of around €12/kW per year represents a significant fraction of typical capacity reward levels observed in the European capacity markets and show that a cost-minimization fit-out strategy for Germany is likely to include a portfolio of conventional gas and multi-hourly BESS capacity. As fuel prices rise or become more volatile, the economic value of storage increases further, a dynamic explored in the sensitivity of hydrogen to power below.
Results: Hydrogen in power
Germany aims to become carbon neutral by 2045, by which time the gas plants procured under the power plant strategy and subsequent capacity markets are expected to operate with carbon-zero hydrogen sources such as blue hydrogen (steam reformed with carbon capture) or green hydrogen (RES-powered electrolysis). BMWE expects this shift to happen sooner, around the year 2035.
Hydrogen is significantly more expensive than natural gas, so this fuel transition has major implications for the costs of adaptation and therefore the potential value of BESS inclusion. We test this by considering an upper bound on the cost of hydrogen by 2030 of €5.5/kg (the lower end of current green hydrogen production costs) and a the lower limit of €4.0/kg (in accordance with the current cost of gray hydrogen production).
The result is that BESS becomes materially more valuable. At the lower bound, BESS reduces the adaptation costs by €18/kW per year (2 hours) to €42/kW per year (8 hours and 10 hours). At the upper limit, this becomes €25/kW/year (2 hours) to €63/kW/year (10 hours), indicating that the increase in the cost of hydrogen now offsets the jump in CAPEX from the 8-hour to 10-hour BESS.
In percentage terms, this is a 1.9% to 4.4% cost reduction compared to hydrogen alone at the lower bound and 2.0% to 4.9% at the upper bound.
Figure 3: Percentage cost savings by duration of Bess – Hydrogen in effect
For 12 GW of hard capacity, this equates to an annual cost saving of EUR 220 – 500 million (lower bound) and EUR 300 – 750 million (upper bound). In addition to its value in the case of natural gas, the longer duration BESS acts as an effective hedge against hydrogen price risk.
Germany’s evolving framework for security of supply will be judged on maintaining high reliability at the lowest possible cost as the scale of renewables and conventional capacity decline. This analysis shows that multi-hour BESS materially reduces the cost of meeting sufficiency needs by reducing the volume of dispatchable gas capacity required and exposure to high and uncertain fuel costs. The implication for procurement design is clear: including longer duration BESS alongside gas is a less regrettable way of reducing security of supply costs.
Authored by Sam Secher and Andrew Pimm.
Sam Secher is a System Modeling Engineer at Envision Energy, working on battery storage modeling and with experience in energy market policy, system planning and investment advisory.
Dr Andrew Pimm is Head of Modeling and Simulations at Envision Energy, leading the development of tools for system sizing, performance guarantees and simulation analysis.
