How the bidding behaviour of thermal generation is modelled
Thermal generation technologies are the largest category of price-sensitive generation on today’s grid. Unlike renewables, which have very little marginal cost once built, thermal generators must cover fuel, start-up, and carbon costs when they run.
We model five categories of thermal generators
The model includes five main categories of thermal generators:
- Biomass — Burns organic material to generate electricity
- Coal — Traditional fossil fuel plants (declining across Europe)
- Gas — CCGTs and OCGTs, the most common flexible thermal plants
- CCS — Carbon capture and storage variants of biomass and gas
- H2 peakers — Hydrogen-fuelled plants for peak demand periods
Running costs determine dispatch order
The bidding behaviour of thermal generation has a significant impact on price shape and volatility. Thermal generation is modelled by first calculating the short-run marginal cost (SRMC) — what it costs each unit to generate one MWh.
Fuel costs are calculated based on each plant’s efficiency:
- Lower-efficiency gas CCGTs have higher fuel costs than high-efficiency ones (they use more fuel per MWh)
- Gas and hydrogen prices vary monthly
- Biomass and coal prices vary annually
Carbon costs are also included, using carbon price projections and each plant’s efficiency.
The chart below is interactive—hover over data points to see exact values.
Accounting for start-up costs
Start-up costs reflect the real costs of bringing a plant online from an offline state. These costs influence unit commitment decisions — whether it’s economical to start a plant for short periods.
Start-up costs have three components:
- Fuel consumption: Based on baseline data for each plant type, adjusted for whether the start is hot, warm, or cold
- Start type: The model assumes warm starts for all technologies
- Carbon emissions: CO₂ costs based on the plant’s carbon intensity and the prevailing carbon price
The final start-up cost combines fuel cost and carbon cost for each plant type.
Plant availability and outages affect dispatchable capacity
Thermal load factors represent the proportion of a unit’s nameplate capacity expected to be available for dispatch at each interval.
For new thermal units with no operating history, outages are simulated by extending historical averages for the specific technology type and country.
Load factors are applied to each unit’s nameplate capacity in the supply stack to determine dispatchable capacity. This ensures the simulation reflects the limited and variable availability of thermal units.
Combined heat and power plants in Germany
Combined heat and power plants (CHPs) represent a large share of Germany’s installed capacity. These plants supply both heat and electricity, so they follow heating demand as well as power market signals.
To account for this behaviour, CHPs are modelled as must-run units. They generate even during low price periods, with bids set at the market floor price.
CHP load factors are modelled using weather-driven profiles from 2023-2024, projected forward in the forecast.
The chart below is interactive—hover over data points to see exact values.