Assessment of Flexibility from MV and LV Distributed Energy Resources for Enhanced TSO–DSO Interaction: Insights from a Real-World Case Study

Distributed Energy Resources (DERs), such as wind and photovoltaic plants, Combined Heat and Power (CHP) units, Battery Energy Storage Systems (BESS), Electric Vehicles (EVs), and

Demand Response systems (DRS) complicates grid management. Moving toward a low-carbon electricity system raises issues like congestion, voltage control, observability, controllability, forecasting, and stability in terms of angle, frequency, and voltage. As more generations connect to Distribution System Operators (DSOs) networks, Transmission System Operators

(TSOs) face growing difficulties in maintaining system security. Decentralized, nonsynchronous generation reduces the availability of conventional units that traditionally provide essential services such as frequency response, voltage control, short-circuit power, and inertia.

This scarcity of system services will worsen, requiring new operational frameworks between

TSOs and DSOs to leverage DER flexibility and compensate for these gaps. Coordinated actions between TSOs and DSOs offer a promising solution, for example, DSOs can support

TSOs during contingencies on the HV/EHV grid by using DERs, reconfiguring MV-LV networks, and adjusting transformer tap changers to prevent technical constraint violations.

This paper presents a feasibility study on TSO-DSO coordination to exploit DER flexibility at the distribution level for resolving transmission network issues in both operational and shortto medium-term horizons, without exchanging sensitive data. After reviewing technical regulations governing TSO-DSO interactions, we propose a simple algorithm to evaluate DER flexibility in active and reactive power and estimate, through a statistical approach, the aggregated capability curve at the point of common coupling, representing flexibility downstream of an HV/MV substation in terms of timing and intensity. To assess mid- to longterm potential (e.g., 2030), the algorithm incorporates development plans and National Trend

(NT) scenarios applied to the Milano case study, which represents the interface between the

Italian transmission grid and the local distribution network. The algorithm outputs the flexibility available at a given instant, which can be used in a coordinated Optimal Power Flow (OPF) across transmission and distribution networks to address technical challenges such as reverse power flows. The proposed algorithm was tested using real data from the Milano DSO and the

Italian TSO, by applying area sensitivity indices we analyzed DER impacts on TSO and DSO networks and quantified the flexibility offered downstream of primary substations. Results highlight the potential of DER-based flexibility to enhance system security and support the energy transition.