## 1 Introduction
A significant assumption made to facilitate the M & Q is the following: the distribution grid has defined physical limits and there is a single POI with the upstream transmission grid. This assumption is realistic for the majority of the distribution grids and enables the evaluation of the contribution of each DRES to a specific service. Apart from the measurement and quantification, the financial costs and benefits associated with each service are roughly presented. Their quantification is essential for the development of viable business models based on the AS, but this is part of ongoing and, yet, unfinished research. Given the fact that AS are offered during transient conditions, suitable measuring specifications are required for their proper measurement and quantification with respect to the starting and ending point of each AS. Hence, modern metering devices will need to be installed and be fully in line with the new measurement standards. This is particularly emphasized in [17], as one of the technical challenges that the DSOs have to deal with due to the increasing DRES penetration. Currently, measuring systems installed in distribution networks do not serve for the DSOs to gain access over particular quantities, which are essential for enacting any control over DRES, e.g., active power reduction or reactive power adjustment, so as to maintain the system balance. Moreover, the measuring devices within the distribution grids include SCADA systems, smart meters and line measurement systems [23]. A drawback of these devices is that they can only measure data related to the steady-state network operation [24]. Consequently, their use for capturing AS related to the dynamic network operation (e.g., the provision of inertial response, dynamic reactive power support) is not acceptable. Furthermore, the measurements should be synchronized to determine the contribution of each DRES to the overall distribution system behavior, something that cannot be implemented by the existing devices due to the lack of a synchronization mechanism, [23]. It should be noted at this point that according to the requirements for the interconnection of DRES mentioned in the IEEE Standard 1547\(-\)2018, [10], their built-in metering infrastructure presents limited measurement capability with respect to dynamic phenomena. Therefore, the inverters of DRES are usually equipped with devices that focus on the accurate detection of changes and not on the accurate calculation and measurement of absolute values, [25]. Finally, phasor measurement units (PMUs) [26] are usually used at the transmission system level. PMUs act on a fast timescale with reporting rates up to 50/s and are able to provide synchronized measurements. However, PMUs are considered expensive enough to be installed at each DRES connected in a distribution grid and have specific limitations, as highlighted in [27]. In order to enable the development of new business models in a quantified and monetary way, new metrics for the quantification of the AS will be proposed in this section together with an initial definition of various AS (and a brief review) that can be offered by DRES either at distribution system level or towards the upstream transmission system. In the latter case, they are assumed to be aggregated and offered at the single POI of the distribution system with the transmission system. To enable the proper definition and quantification of AS the following assumptions are made:  
* At the distribution system level (Figure 1), one or more individual control areas (ICAs) are foreseen, where the DRES with the newly developed functionalities are optimally orchestrated by suitable ICT infrastructure. Generally, the whole distribution grid can be considered as an ICA, hosting loads and DRES in the medium voltage (MV) level and microgrids in the low voltage (LV) level. * The DRES within the distribution system have new advanced functionalities enabling them to provide the AS shown in Figure 2[18; 27; 28].