Network Operation Constraints on the Path to Net Zero

Operating a reliable electricity system requires strict safety and security criteria such as avoiding grid congestion, minimum levels of inertia, maintaining voltage levels, and minimum adequacy reserves. However, large scale integration of intermittent renewables, namely inverter-based resources (IBR), is creating operational challenges. When operational security criteria are not met, system operators use ancillary services (redispatching) to activate or curtail scheduled units to manage the flows. In Spain, the volumes and costs of redispatching have multiplied by two and nine times between 2019 and 2023, respectively. In 2023, the total costs amounted to 2 b€, for curtailing 3 TWh wind and 0.9 TWh photovoltaics. A similar picture is emerging in other countries. This is the first study to examine the determinants of network constraints associated with redispatched volumes at country level. We use the seasonal autoregressive ARIMA time-series estimators with hourly operational and market data (2019–2023). Results show that actions to alleviate grid bottlenecks amount to one-third of the volumes, and increasing every year with addition of wind, photovoltaics and thermosolar generation. Volumes for solving voltage issues (reactive energy needs) represent one-half. Scheduled MWh from IBR (wind and photovoltaics) increases volumes for voltage problems (+0.05 MWh) and congestion issues (+0.01 MWh). Scheduled MWh from CHP contributes to congestion issues (+0.18 MWh), while thermosolar to grid reliability (N-1) problems (+0.25 MWh). The day-ahead and intraday markets can make economically efficient allocation of units, but massive connection of renewables requires increasing actions by system operators. Operational and regulatory decisions must be taken in advance to avoid the issue in the future.