Capacity Expansion Model

How we build future supply stacks for European markets

Our European capacity expansion forecast builds on the general Capacity Expansion Model framework, applying it specifically to European power markets with zonal granularity.

Our European forecast includes an annual capacity expansion loop through 2060, producing a zonal build‑out for every country covered by the fundamentals model. Each model year couples investment decisions with an hourly dispatch pass so new and existing assets are operated according to realistic system conditions.

The capacity expansion workflow reuses the same inputs, assumptions, and modelling choices as the fundamentals/dispatch model (generator technicals, fuel & carbon, renewable profiles, outages, transmission limits). In practice, that means expansion decisions are made in the context of the system the dispatch model actually sees, not a simplified proxy.

At a glance

What technologies are included in the model?

• Gas CCGT
• CCS Gas CCGT (retrofits)
• Solar PV
• Onshore wind
• Offshore wind
• Hydrogen peakers (H₂)
• Battery energy storage (BESS): 2h, 4h, 6h, 8h

Note: Storage is modelled with power/energy limits, round‑trip efficiency, and state‑of‑charge tracking. Retrofit options (e.g., CCGT → CCS) are constrained by age, size, and retrofit-ability rules where applicable.

External datasets we align to

We use widely referenced national and European planning sets as context for our capacity expansion modelling. Where the expansion model does not include a technology as a build option (e.g. nuclear, large hydro), we look to official TSO/DSO datasets and national development plans to guide sense-checks on installed capacity levels.

GB‑specific

• FES 2023 (Future Energy Scenarios) — Scenario pathways for GB capacity/demand to 2050 (National Grid ESO)
• Summer Outlook 2025 — Near‑term operational margins and available capacity
• SOR25 (System Operability Report 2025) — System needs (inertia, voltage, frequency response) under the projected 2025 mix

EU‑wide

• FES 2025 – EU Green — Decarbonisation‑forward capacity pathway adapted to an EU scope
• ENTSO‑E TYNDP scenarios — Pan‑EU generation, demand, and grid development outlooks to 2050
• ERAA 2024 — Probabilistic adequacy framing and cross‑border resource sufficiency

Country plans

• Germany – NEP 2037/2045 — Grid development and capacity scenarios
• France – RTE “Futurs énergétiques 2050” — Pathways for nuclear/RES mix and neutrality
• Luxembourg – Creos scenarios — National capacity and interconnection outlooks
• Spain – ESIOS 2025 update — Updated capacity/demand projections
• Norway – NVE publications — Hydropower expansion and market‑integration assumptions

Medium‑term adequacy

• ENTSO‑E Mid‑term Adequacy (now within ERAA) — Ten‑year adequacy framing for stress testing

What financial data sources are used?

Temporal sampling & rolling window

Hourly resolution on 20 representative days per year

Days are selected to capture a broad span of conditions across each year (peak demand, low‑renewables, high‑renewables, shoulder periods, etc.) so investment choices are robust to the operating realities the system faces.

One‑year rolling window

Each year’s build/retire decisions feed into the next year’s fleet, preserving stateful elements (e.g., storage fleet size, retrofit commitments) and allowing policies/limits to evolve over time.

Reliability constraints

Energy unserved (EUE) limits

This refers to the maximum amount of electricity demand that can go unmet before it becomes unacceptable to the system operator or regulator. In practice, no grid runs with zero risk of shortages—because building to meet every possible peak demand would be prohibitively expensive. Instead, markets or regulators define an acceptable “energy unserved” threshold. EUE limits are applied to every country in the model.

Planning reserve margin (PRM)

This is a reliability standard that defines how much “extra” generation capacity the system must have above expected peak demand. For example, if peak demand is forecast at 100 GW, and the reserve margin is set at 15%, the system needs 115 GW of available capacity (de-rated capacity).

• De-rating factors (or capacity credits) are applied to the nameplate capacities of different generators to reflect that not all capacity is firm or available in every hour. The de-rating factors vary by technology
• The PRM is framed to be conceptually consistent with capacity market mechanisms used in GB, Poland, Ireland, and France
• The PRM is enforced annually across countries in scope

Technology Cost Projections

Our capacity expansion model uses capital and operational cost projections based on industry-standard sources including NREL’s Annual Technology Baseline and Modo Energy’s BESS CapEx Survey.

Capital Expenditure (CapEx) by Technology

Operational Expenditure (OpEx) by Technology

Example Capacity Buildout

The model produces annual capacity expansion pathways for each technology across all modeled countries.

Geographic Distribution of Capacity Expansion

The interactive choropleth map below illustrates how capacity additions are distributed across European zones over time. The visualisation reflects regional differences in resource quality, demand growth patterns, interconnection constraints, and policy frameworks.

Use the selectors to explore capacity buildout by technology and year.</p ## Utility Scale BESS Buildout in Germany