## 1 Introduction  
Transmission system operator (TSO) and distribution system operator (DSO) interactions become essential for avoiding unnecessary bottlenecks in opening market participation and will be strengthened due to the expected energy transition. One trend towards the energy transition is the increasing connection of renewable energy sources (RES)--intrinsically intermittent and not programmable--to reducing CO2 emissions and reaching climate goals. In the last 5-10 years, RES have been changing the power system by making it more challenging to balance the generation and demand at every single point in time. The increasing penetration of distributed generation (DG) and new electric loads with high coincident peaks (e.g., electric vehicles, heat pumps, induction cookers, etc.) that impact the exploitation of existing distribution assets represent another trend at the distribution level. In this context, the flexibility of distributed energy resources (DERs) connected to the distribution systems may play an important role. DERs, as RES-basedgenerators, fuel generators (e.g., combined heat and power, CHP), energy storage systems, as well as active users, can offer flexible products to the TSO to ensure reliable system operation and to the DSOs, to better operate their networks. Purposes related to such flexibility may be avoiding massive infrastructural investments for network reinforcement, not jeopardising the achieved high levels of system stability and security of supply, system balancing, voltage regulation and power congestion relieving, etc. Flexibility is usually defined as the possibility of modifying generation and/or consumption patterns in reaction to an external signal (price or activation signals) to contribute to the power system stability cost-effectively [1]. The flexibility products from DERs are represented by variations in their scheduled/expected active and reactive power setpoints. By considering the transmission grid point of view, these variations in the scheduled/expected working points of DERs result in bids of flexibility services that, if awarded in the ancillary service (AS) market, produce a variation in the power profile at the first point of common coupling (PCC) of the distribution system with the transmission grid. Such a PCC is the HV/MV (high voltage/medium voltage) transformer located in the primary substations (PSs), where the MV distribution system, managed by the DSOs, is connected to the HV transmission system and, thus, it represents the interface between the two operators. At the same time, the DERs can offer flexibility to the DSOs for fixing distribution network issues, such as voltage regulation or local power congestion management. Nevertheless, when using flexibility to cope with one grid operation challenge, this might impact other grid operation issues. For instance, the activation of distribution-connected flexibility for system balancing might cause congestion on the distribution grid or local voltage regulation issues. Theoretically, the activation of distribution-connected flexibility to mitigate congestion on the distribution grid may also affect system balancing. However, in practice, this impact can be expected to be small when assuming that the activation for distribution grid purposes would not be simultaneous for different parts of a distribution grid. Nonetheless, a mutual impact exists. Recently, regulatory bodies suggested many proposals and undertook actions for enabling new players, as the DERs connected to the distribution systems, to provide both system and local services. However, currently, there are still barriers that might limit their effective involvement. Market schemes have been proposed for opening the participation of DERs in the service markets. The main drawbacks that arise from this opening are related to the significant modification in the role of the DSO and, indeed, in the interactions between system operators.