Δημόσια Διαβούλευση της ΡΑΕ επί της εισήγησης της ΑΔΜΗΕ Α.Ε. σχετικά με τον γενικό σχεδιασμό της αγοράς για τη συμμετοχή στις ευρωπαϊκές πλατφόρμες MA

(6)of EBGL concerning the implementation of the MARI platform for two years from the legal go-live date (July 24, 2022). Participation in the MARI platform is a highly challenging project that requires significant and extensive modifications to systems, infrastructure, and procedures that affect both the scheduling and the real-time processes, as well as the terms and conditions of market participation. RAE, with its Decision 363/2022, granted IPTO the requested derogation deadline, i.e., until the 24th of July,

1. The mFRR-Platform Accession roadmap for all relevant TSOs is presented below. 1 ENTSOE: https://www.entsoe.eu/network_codes/eb/mari/ 4 Figure 22: mFRR-Platform Accession roadmap Any change in systems, infrastructure, procedures and terms and conditions requires careful planning, adequate consultation with market participants, and, of course, testing, to avoid affecting the smooth functioning of the balancing market and the operational security of the system. Given the magnitude of the modifications required and the fact that competition will increase from the participation of all power resources among Europe in a common market for balancing, sufficient time is needed for market participants to be informed and prepared. 2 https://eepublicdownloads.blob.core.windows.net/public-cdn-container/clean- documents/Network%20codes%20documents/NC%20EB/2022/MARI_Accession_roadmap_October_2022_Upda te_Final.pdf 5
2. MARI platform process overview 3.
3. High level description of mFRR platform The mFRR platform, operated by TSOs, applies a TSO-TSO model with common merit order lists to exchange all balancing energy bids from standard products for mFRR, except for unavailable bids pursuant to art. 29

(14)of EBGL. The MARI platform enables TSOs to activate the most cost-efficient set of mFRR bids to meet their needs, while considering constraints linked to the availability of networks to exchange these reserve products. Pursuant to art. 20

(2)of EBGL, the mFRR platform shall be based on common governance principles and business processes, and shall consist of at least the activation optimisation function (AOF) and TSO-TSO settlement function. In the following figure, the process overview of the mFRR platform is presented. Figure 33: Overview of BSP-TSO and TSO-mFRR platform flows Platform process steps: 1. TSOs receive bids from BSPs in their local market. 2. If required, TSOs transform bids received from BSPs into standard mFRR balancing energy bids by applying a central dispatch model. 3. TSOs forward standard mFRR balancing energy bids to the mFRR platform. 4. TSOs communicate the available cross border capacity limits (CBCLs), network constraints as well as HVDC constraints. 5. TSOs communicate their energy balancing demands (mFRR needs). 6. Activation Optimization Function (AOF): The clearing of the mFRR balancing demands against BSPs bids is performed. 7. Communication of the AOF results: Accepted bids, satisfied demands, prices to the local TSOs as well as the resulting Cross Border schedules. 3 Source: MARI Activation Optimization Function Public Description 6 8. Calculation of the commercial flows between imbalance areas and settlement of the expenditure and revenues between TSOs. 9. Remaining mFRR CBCLs are sent to the relevant TSOs. According to art. 11 of the mFRR IF, the AOF’s first priority when selecting the best set of bids to cover TSOs’ mFRR demands is to maximise the economic surplus for a given set of standard mFRR balancing energy bids and mFRR balancing energy needs while its second priority is to minimise the amount of mFRR power exchange on each mFRR balancing border. In the context of balancing markets, the economic surplus is the total surplus of all TSOs obtained from satisfying their demands and the total surplus of BSPs resulting from the activation of their associated bids, as illustrated in the following figure. On one hand, the curve consisting of positive TSO demands and downward BSP bids constitutes the consumer curve, and therefore indicates the maximum price consumers (TSOs and BSPs) are prepared to pay for consuming mFRR balancing energy. On the other hand, the curve consisting of negative TSO demands and upward BSP bids constitutes the producer curve, and therefore shows the minimum price they are prepared to receive for supplying mFRR balancing energy. Figure 43: Economic Surplus 3.2. MARI platform activation clearings phases As previously stated, the MARI platform organizes and optimizes the exchange of mFRR balancing energy activations between TSOs. The optimization algorithm (MARI AOF) searches for a solution that maximizes economic surplus while minimizing the use of crossborder capacity for mFRR energy exchanges. MARI AOF consists of two different activation clearing phases for each MTU, the Scheduled Activation (SA) clearing which optimizes scheduled balancing energy activations and the Direct Activation (DA) clearing phase(

1. s)which optimizes direct balancing energy activations. Both scheduled and direct clearing phases uses the same MARI AOF algorithm but differ slightly in the processes (GOT, GCT, inputs etc). Once the AOF has completed processing the 7 common merit order list (CMOL), the resulting activations and demand satisfaction, amongst others, are sent back to the relevant TSOs. Resulting activations and demand satisfaction are communicated seperately for scheduled and direct activations. Scheduled activations are typically used to handle forecasted imbalances proactively or to de-saturate activated aFRR bids. Direct activations are required to perform further activations when imbalances occur between two scheduled activations. Direct activations allow for the activation of mFRR bids at any point in time when an unexpected imbalance occurs. The Scheduled Activation is the first process and is run for each MTU period. All available bids and demands in both directions that have been received by the MARI platform are taken into account during the Scheduled Activation clearing phase. SA clearing selects bids to satisfy the demands for scheduled activations, determines the cross-border marginal prices and calculates the cross-border flows. Upward and downward bids and positive and negative demands are included in the SA clearing. The balancing energy bids can be exchanged between scheduling areas provided there is enough Cross Zonal Capacity (CZC) to allow for such exchanges to materialize. If enough cross-border capacity is available, the netting of simultaneous demands in opposite directions can also be executed in SA. Direct activation clearing is run after the SA clearing for the same MTU period. There may be zero, one or many cycles of direct activations for a given MTU period within a specific timeline. DA clearing phase selects bids to satisfy the demands for direct activations, determines the cross-border marginal prices and calculates the cross-border flows. TSO demand from only one direction as well as the remaining bids, available for DA in the same direction are considered per direct activation. During each optimization process, the market is cleared considering the available bids and the TSOs demands. Since the allocated time between the data collection and the activation time is short (less than 2 minutes for the SA processes and less than 1 minute for DA processes), the MARI platform is required to perform the relevant processes extremely efficiently. 8 Figure 53: Example of MARI execution In the following figure common platform’s operational phases are outlined which exhibit the timing in order to satisfy a fifteen-minute scheduled activation period starting at T and ending at T+15 and the timing andactivation of a bid for a direct activation. Alltimes are expressed in minutes and are relative to the start of the MTU for which activations are optimised by the platform. The timings for SA clearing are the following: • T-12’: Each TSO must share the mFRR energy bids received from the BSPs with the mFRR-Platform at the latest 12 minutes before QΗ(t0). • T-10’: Each TSO must submit to the mFRR-Platform the mFRR demands for Scheduled Activation for QH(t0) at the latest 10 minutes before QH(t0). After this point in time, the mFRR-Platform will start the optimization for scheduled activation and no new information can be taken into consideration. • Between T-10’ and T-8,5’: The clearing of SA activation run is triggered. The mFRR platform with its AOF selects bids to satisfy the demands for scheduled activations, determines the cross-border marginal prices and calculates the cross-border flows. The market clearing execution is performed within 60 seconds. Half a minute is allocated to pre-processing of input data and the communication from the platform to the TSOs. After the execution, the results are communicated to the TSOs together with cross-border marginal prices and the bids selected for activation and the satisfied demands. The selected bids for activation by the AOF are communicated by each TSO to their respective BSPs. • The market clearing information is then transferred to BSPs at T-7.5’ and scheduled activation is initiated on T-7,5’. Between T-5’ and T+20’ balancing energy for scheduled activations is delivered. 9 According to the mFRR IF, the Balancing Energy Gate Closure Time for BSPs to submit the mFFR bids to their TSOs (BSP mFRR GCT) is 25 minutes before the start of the relevant quarter-hour, i.e. T-25’. However, this timing is only applicable to TSOs applying a selfdispatching model. Due to time constraints related to the conversion of mFRR bids by IPTO (refer to section 5) this timing may not feasible. Therefore IPTO may propose a different mFRR GCT for BSPs. The timings for DA clearing are presented in the following figure. After T-10’ and up to 5 minutes after the start of QH(t0), TSOs may submit a demand to trigger one Direct Activation where all bids eligible for DA and not activated in the previous activation run of the same MTU period can be used. Processing of such demands will have to wait until the AOF completes the scheduled activations. Likewise, if the AOF is already busy processing one or several demands for direct activations, any subsequently arriving direct demands will have to wait until the AOF completes the running process. The DA market clearing excecution is performed within 15 seconds. Depending on the timing of the DA process, information is transferred to BSPs between T-7.5’ min and T+7.5’, and the delivery of the requested MW lasts until the end of the SA run of the next MTU period (QH(t+1)), i.e., the delivery will always end at T+35’. 10 Figure 63: mFRR platform operational phases and timings overview 11 3.3. Market areas used in mFRR platform AOF Different types of areas are considered in the MARI AOF as presented in the following topology example. Figure 73: Topology example Scheduling Areas A scheduling area is the area level where the different bids and most of the demands are submitted. Scheduling areas cannot include any other areas, whatever their types; they are the most elementary zones modelled in MARI. The interconnectors allow exchange of mFRR energy, coupling the different scheduling areas of the network. The cross-border maginal price (CBMP) will be defined at the end of the activation optimization process for each of the scheduling areas. Each scheduling area is included in at most one control area. Control Areas A control area is defined as a set of scheduling areas operated by a single system operator (TSO). Itcan therefore include one or several scheduling areas. In MARI’s AOF, the control areas are not directly interconnected with one another, as the interconnections are defined at the level of scheduling areas. Aggregated Areas An aggregated area is a set of scheduling areas that can have specific mFRR demand requirements. They include at least 2 scheduling areas. Aggregated areas differ from control areas in the sense that they do not necessarily represent an area controlled by a single TSOTSO (one aggregated area can include several scheduling areas from different control areas). Demands can be submitted at the aggregated area level and are called aggregated demands. 3.4. Market modes used in mFRR platform AOF The MARI AOF is able to perform the following market modes of optimization in parallel: 12
2. a)Coupled optimization: In this market mode, optimization of the resulting cross-border energy flows is permitted up to the CBCLs.
3. b)Decoupled optimization: In this market mode, all areas are optimized in isolation, with CBCL set to zero on borders between them. 3.5. Contingency measures 3.5.1. Decoupling/Disconnection Each TSO can request decoupling for its control area. Decoupling means that the control area is treated like an island. On the borders, cross border capacities will be deemed zero in both directions. Bids and demands originating from the decoupled control area will be matched against each other by the MARI platform, without consideration of bids and demands from other control areas. In this scenario, TSOs effectively do not have full access to the common CMOL. Each TSO can also request disconnection for its control area. Disconnection means that no data submissions will be expected from the TSO, not even bids and demands. Cross border capacities will be deemed zero on the borders of the TSO’s control area(
4. s)and no optimization on the TSOs control areas will be carried out by the MARI platform. 3.5.2. Local fallback and complementary measures Τhe mFRR process will be carried out locally by each TSO for matching bids and demands within its control area(
5. s)in situations where there is a failure in any data exchange between the TSO’s system and the MARI platform, or within the MARI platform itself. Hence, each TSO must disconnect and perform its own complementary fallback measures. On these grounds IPTO will appropriately amend the current mFRR algorithm and process. For more details see chapter 5.3. In addition, in cases that MARI platform does not satisfy all inelastic/elastic demands, each TSO must use its own complementary measures. In any case, the results of the MARI platform are firm and cannot be rejected by TSOs on the grounds of non-satisfaction of demand. 13 4. mFRR balancing energy bids TSOs must use the standard mFRR balancing energy products, as defined in the relevant European regulatory framework in order to connect to the mFRR-Platform. As defined in the mFRR IF, each standard mFRR balancing energy product shall fulfil some characteristics, while other may be defined in the Terms and Conditions of each TSO. The use of specific products is allowed, but only if justified and approved by the National Regulatory Authority. More details are presented in section 4.1. The mFRR balancing energy bids may have different bid characteristics to reflect the conditions for activation as explained in sections 4.1 - 4.5. The characteristics of the mFRR balancing energy product will be determined by IPTO based on integrated scheduling process bids submitted by BSPs following the rules for converting bids of a central dispatching model into standard mFRR balancing energy product bids pursuant to Article 27 of the EB Regulation, as explained in section 5. 4.1. Standard mFRR balancing energy product 4.1.1. Characteristics of standard mFRR energy bids The characteristics of the standard mFRR balancing energy product are defined in art. 7 of the mFRR IF. Regarding central dispatching models, some of the characteristics may be determined by the connecting TSO based on integrated scheduling process bids submitted by BSPs following the rules for converting bids into standard mFRR balancing energy product bids pursuant to art. 27 of the EB Regulation. In the following table the characteristics of the standard mFRR balancing energy product are presented, according to art. 7

(1)and 7

(2)(a) of the mFRR IF, in comparison to the current local mFRR balancing energy product. local mFRR product as of today mFRR standard product manual manual Scheduled or direct Scheduled or direct FAT 7,5 min 12,5 min Minimum quantity 1 MW 1 MW Bid granularity 0,1 MW 1 MW Maximum quantity n/a 9.999 MW Minimum duration of delivery period 7,5 min 5 min Price resolution 0,01 €/MWh 0,01 €/MWh Validity period The scheduled activation can take place at the point of scheduled activation only. The scheduled activation can take place at the point of scheduled activation only. Mode of activation Activation type 14 A direct activation can take place at any time during 7,5 miinutes after the point of scheduled activation. A direct activation can take place at any time during 15 minutes after the point of scheduled activation. €/MWh €/MWh Location At least the smallest of LFC area or bidding zone At least the smallest of LFC area or bidding zone Bid divisibility Fully divisible for generating units . Both divisible and invisible bids are allowed for demand response. Divisible bids with an activation granularity of 1 MW. Price Linking between bids and complex bids multipart bids Indivisible bids based on national terms and conditions. Technical and conditional linking between bids submitted in consecutive quarter hours. Complex bids. Every bid will be assigned an activation type by IPTO. The activation type, can be one of the following three: • ‘Scheduled only’ means a bid which can be activated at the point of scheduled activation only; • ‘Direct’ means a bid that can be activated at the point of scheduled activation and anytime during the 15 minutes after the point of scheduled activation; • ‘Direct only’ means a bid that is eligible for direct activation only, i.e., anytime during the 15 minutes after the point of scheduled activation. This is theimplementation of the “guaranteed volume” concept. More details are provided in section 4.1.2. The activation type will be determined before the bid gets submitted to the mFRR platform but may be updated subsequently (also refer to section 4.4). Moreover, a bid will always be associated with exactly one direction, which may be either upward (positive) or downward (negative). Each bid will be associated with exactly one scheduling area. According to art. 7 of the mFRR IF, both upward and downward mFRR energy bids have a price resolution of two decimals, i.e., 0.01 €/MWh.The price of the bid can be positive, zero or negative. In addition, according to the Technical Decision “Technical limits for bidding prices and clearing prices in the Balancing Market”, after inclusion of IPTO in one of the European platforms, MARI or PICASSO, and up to 48 months after the legal deadline defined in EBGL, the maximum and minimum price limits set for bidding prices and clearing prices for balancing energy should be equal to +15.000€/MWh and -15.000€/MWh accordingly. After the 48 months period, the maximum and minimum limits set for bidding prices and clearing prices for balancing energy should be equal to +99.999€/MWh and -99.999€/MWh. The bid parameters of the standard mFRR balancing energy product, as defined in article 7

(3)of the mFRR IF, are presented below. 15 ‘divisible bid’ means a standard mFRR balancing energy product bid, which can be activated partially in terms of power activation according to the bid activation granularity pursuant to Article 6

(5); ‘indivisible bid’ means a standard mFRR balancing energy product bid, which cannot be activated partially in terms of power activation according to the bid activation granularity pursuant to Article 7

(2). Therefore, the volume of an indivisible bid is always activated altogether; 'complex bids’ means complex bid structures of a BSP with the purpose of economic optimization, allowing BSPs to offer more flexibility, to reflect efficiently their underlying cost structure in their offered bids, and to maximize the opportunity of being activated; ‘exclusive groups’ are a type of complex bids, consisting of a group of bids, where only one bid can be activated from the list of bids part of the exclusive group; ‘multipart bids’ are a type of complex bids, consisting of a group of bids, where individual upward energy bids can only be activated according to increasing price, or individual downward energy bids can only be activated according to decreasing price; 'technical linking’ means links between bids of a BSP in consecutive quarter hours, needed to avoid the underlying asset performing infeasible activations; 'conditional linking’ means links between bids of a BSP in up to three consecutive quarter hours, needed to represent technical restrictions and cost structure of the underlying assets, due to the unavailability of information on the activation of bids from previous quarter hours at the balancing energy gate closure time. 4.1.1.1 Simple bids As described previously, divisible (partially or fully) and indivisible bids are allowed. Divisible bids have an activation granularity of 1 MW and the bid size may not be smaller than 1 MW. Τhe maximum size of indivisible bids shall be defined in the national terms and conditions for balancing and shall not be higher than the largest technical minimum production or consumption of the pre-qualified generation or load unit of the BSP. Qmin Qmax Only full quantity can be selected Fully Divisible Bid Qmax Only full quantity Any quantity can be selected can be selected Qmax Any quantity can be selected Divisible bids may be activated in incremental steps of 1 MW, from the minimum offered quantity up to the maximum offered quantity. For example, a bid with a minimum offered quantity of 8 MW and a maximum offered quantity of 10 MW may be activated with 8, 9 or 10 MW. Bids must be submitted with integer volumes only. Any remaining quantity of a partially accepted bid will be deemed as unavailable for subsequent activations. Divisible Bid Indivisible Bid Figure 8: Representation of a fully divisible bid, divisible bid and indivisible bid 16 In the current local mFRR balancing market design, only fully divisible bids are allowed for generating units. On the other hand both, divisible and invisible bids are allowed for demand response and pumping units. This design option will remain unchanged. 4.1.1.2 Complex bids Complex Bids consist of groups or families of simple bids, which have specific acceptance behaviors. Two types of complex bids exist, exclusive groups and multi-part bids. In the current local mFRR balancing market only multi-part bids are allowed. Exclusive groups are families of bids in the same scheduling area where at most one bid can be accepted (even partially). When submitting mFRR Energy Bids in an exclusive group, the following rules must be respected: • • • • • An mFRR bid may only be part of one exclusive group for the concerned quarter-hour. mFRR bids in an exclusive group must have the same activation type. mFRR Bids in an exclusive group may not be subject to quarter-hour linking. Some mFRR bids can be upward while others downward. mFRR Bids can be either fully divisible, divisible or indivisible. Figure 93: Exclusive bid group Multipart groups are sets of bids in the same scheduling area, ordered by their price, where their acceptance must follow a price hierarchy deepening on its direction, i.e., acceptance of one bid in the family requires that all preceding bids are accepted. For upward multi-part bids, whenever a bid is accepted, all associated bids with lower prices must be first fully accepted. For downward multi-part bids, whenever a bid is accepted, all associated bids with higher prices must be first fully accepted. Bids in the multi part family must have the same direction, and different prices, but can vary in quantities. In addition, if at least one bid is activated in SA, the remaining volume of the multipart bid is no longer available for DA. Likewise, if at least one bid is activated for DA, the remaining bids are no longer available for any subsequent DA optimizations. 17 Figure 103: Multipart bid group 4.1.1.3 Linked bids There may be links between bids in different MTU periods. Bids that are linked must originate from the same scheduling area. Two different types of links are supported; technical and conditional. Technical and conditional links affects the availability of a bid in QH(t0) based on the outcome of the linked bid(

1. s)in earlier, already optimised, quarter hours. The principle of the linking is to switch the availability status of the bids from available to unavailable (or viceversa) to avoid infeasible activations. TSOs and BSPs will not be aware of all activations in the preceding quarter-hours at the time of bid submission. More specifically, at BSP mFRR GCT for QH(t0), it is possible that scheduled activations for QH(t-1) and direct activations for QH(t-1) and QH(t-2) may still be requested. For this not to happen, linking can be used to indicate that the bid is no longer available if already activated in the quarter-hour(
2. s)before, or alternatively, that a bid only becomes available in case of an activation in the preceding quarter-hour(s). BSPs have the responsibility to link the bids together to avoid infeasible activations but each TSO may facilitate BSPs based on information of underlying assets, the technical constraints of such assets, etc. It is at the discretion of the BSP to choose between technical and conditional linking or combination thereof to achieve the bidding objectives.Linking of bids, for example, may be useful in case of BSEs with energy limitations, for demand response with limitations on duration or frequency of activations, for ramping limitations or a technical constraint between positive and negative mFRR energy bids by the same BSE, if the switch between upward and downward activations is not technically feasible from one quarter-hour to another, etc. In the following figure, infeasible activations related to ramping violations are presented. The example concerns a single asset with the same maximum ramp rate (MW/min) both for upward and downward directions. An upward SA bid for a quantity equal to the maximum MW allowed by the maximum ramp rate, and a downward SA bid for the same MW is submitted to the mFRR Platform for Qh2 and Qh3 respectively. 18 The upward SA bid is fully activated in Qh2. At the end of Qh2 the bid is deactivated pursuant to the standard product characteristics. For Qh3, the downward SA bid is also fully activated. The deactivation of the upward bid in Qh2 and the simultaneous activation of the downward bid in Qh3 will lead to a down regulation over 10 minutes, with a higher gradient than its maximum allowable ramp rate, because both bids are deactivated/activated at the same time (T+7.5). MW Nomination Schedule QH1 QH2 QH3 QH4 Actual ramping capabilty Required ramping capability Figure 11: Example of infeasible activation owning to ramping constraints Technical linking between two bids (simple or complex) in two subsequent quarter hours is possible. Each of the bids within the linked bid must be associated with a unique quarter hour. These links indicate the allowed combinations of direct and scheduled activations of the bids and ensures that a bid that underwent direct activation in QH(t-1) (i.e., for the preceding quarter hour) is not available in QH(t0), neither for scheduled nor for direct activation. This is important in order not to activate the same balancing resource twice. In the following figure an example of technical linking is presented. Figure 124: Example of technical linking 4 Source: MARI-Bid Structure and Linking 19 Conditonal linking between simple bids in two or three adjacent quarter hours is possible. A given conditional bid in QH(t0) will by default be either available or not available. It may have up to three links to bids in QH(t-1) and/or up to three links to bids in QH(t-2). A bid in QH(t0) that is declared as available by default becomes either completely unavailable for both SA and DA or unavailable for DA when at least one of those links indicate unavailability. A bid in QH(t0) that is declared as unavailable by default, becomes either available or available for DA when at least one of those links indicate availability. The following types of links are supported: • • Bid initially available:
3. a)Bid unavailable if linked bid is activated for either SA or DA.
4. b)Bid unavailable if bid is not activated.
5. c)Bid unavailable for DA if linked bid is activated for SA.
6. d)Bid unavailable for DA if linked bid is activated for DA. Bid initially unavailable:
7. a)Bid available if linked bid is activated for either SA or DA.
8. b)Bid available if bid is not activated.
9. c)Bid available for DA if linked bid is activated for SA.
10. d)Bid available for DA if linked bid is activated for DA. In the following figure an example of conditional linking is presented. Figure 134: Example of conditional linking 20 4.1.1.4 mFRR energy bids availability mFRR IF – Article 2. Definitions (
11. a)‘availability status’ means the condition of a bid being available or unavailable for cross-border activation pursuant to Article 29

(9)and

(14)of the EB Regulation; TSOs must send all mFRR energy bids submitted by the BSPs to the mFRR-Platform. However, in accordance with EBGL and the mFRR IF (article 9), each TSO may declare the balancing energy bids submitted to the AOF unavailable for activation via the MARI-platform because they are restricted due to internal congestions or due to operational security constraints within the TSO’s scheduling area. The unavailability may be general or apply to a particular activation type (schedule or direct). Unavailability for the mFRR-Platform does not necessarily mean that the bid is unavailable for local activation. In such cases, TSOs are obliged to transparently report on such bid unavailability. IPTO can declare an mFRR energy bid as unavailable for selection by AOF for different reasons such as: 1. Intraday total unavailability of entity due to technical reasons (e.g., trip) The bid is unavailable both locally and in the MARI platform. 2. Restrictions due to internal congestion The bid is unavailable both locally and in the MARI platform. 3. Internal congestion management. The bid is available locally but unavailable in the MARI platform. 4. Execution of Dispatch Instructions for mFRR testing. The bid is available locally but unavailable in the MARI platform. 5. Commissiong Schedules. The bid is unavailable both locally and in the MARI platform. 6. Guaranteed volumes. The bid is available only for DA activation in the MARI platform. In addition, bids from entities that that are not scheduled to be synchronized based on ISP results and cannot be activated within the FAT, for example bids from generation units with a synchronization and soak time larger than 12,5 minutes, or bids from generation units that are fully or partially unavailable due to technical reasons (e.g. trip) will not be sent to the MARI platform. For more details please refer to section 5. Note also that complex bids must have the same availability status for the mFRR-platform. Therefore, if IPTO declares one of the associated bids as unavailable, then the associated bids will also have to be declared as unavailable. 21 4.1.2. Guaranteed Volume (GV) When unforeseen incidents or unexpected demands occur in real time, TSOs might need to have access to a certain volume of “direct activatable bids” to perform the Frequency Restoration Process within the Time To Restore Frequency (TTRF). The risks of direct activatable bids’ scarcity in a LFC control area during a quarter-hour, is avoided by the ‘Guaranteed Volume’ concept. TSOs can retain a certain volume of bids eligible for DA by marking some DA bids as not available for activation in SA clearing. For the above reasons, TSOs need to identify locally how much volume of upward and downward direct bids they want to guarantee in their Local Merit Order List (LMOL). In any case, the overall volume that can be marked as “unavailable for GV” shall not exceed the dimensioning of the relevant reserves by the TSO. Once TSOs have identified the volume to be guaranteed (in each direction), they shall identify in their LMOL the bids that need to be marked unavailable for SA (for GV purpose). In order to ensure a better economic efficiency, TSOs can mark as unavailable only the most expensive direct bids of the relevant LMOL. For more details refer to section 5. Βids that are marked as unavailable with the purpose to guarantee the access to a sufficient amount of direct activatable bids, will always be forwarded to the CMOLs of the mFRRPlatform but can only be activated through the Platform during the DA process. From the the mFRR energy bids, only those available for both scheduled and direct activation can be marked as guaranteed volume. Figure 145: Example of Guaranteed Volume 5 https://eepublicdownloads.azureedge.net/webinars/20201218_Stakeholder_Workshop_Final_APPROVED.pdf 22 4.2. TSO-TSO standard mFRR balancing exchanged shape In accordance with the definitions in the mFRR IF and EBGL, mFRR energy offered in standard mFRR energy products must comply with the following characteristics: • The preparation period is the period between the activation request sent by the TSO to the BSP and the start of the ramping period. The preparation period is 2,5 minutes. • The ramping period is the period for linear ramping up to the point of full delivery, during which the input and/or output of active power will be increased or decreased. The ramping period is 10 minutes. • The full activation time (FAT) is 12,5 minutes. FAT is defined as the period between the activation request sent by the TSO to the BSP and the corresponding full delivery. FAT consists of the preparation period and the ramping period. Setting the full activation time for mFRR to 12.5 minutes ensures sufficient time for restoring frequency in accordance with Annex III of the SOGL, which suggests that any frequency incidents have to be dealt with within that 15-minute period. • The minimum delivery period is equal to 5 minutes. During the delivery period, the BSP delivers the full requested change of power (in positive or negative direction). • The maximum duration of delivery period is the period of time during which the BSP delivers the full requested change of power in-feed to/withdrawal from the system. As stated in the previous section, the mFRR IF defines a standardised minimum duration of delivery period of 5 minutes but there are no harmonized conditions set for the maximum duration of the delivery period due to the non-harmonisation of the preparation period, ramping period and the deactivation period. • The deactivation period is subsequent to the delivery period and is the period for ramping from full delivery to a set point, or from full withdrawal back to a set point. The deactivation period will start after the notification of the scheduled auction results for the next quarter hour (QH+1) to the activated BSP taking place at T+7.5. This will allow the BSPs not to deactivate if they are selected again for delivery in the next quarter. For the direct activation, the deactivation will occur around the end of QH+1, regardless of when the activation was initiated. The deactivation period is equal to 10 minutes. The TSO-TSO energy exchange profile for the Scheduled Activations for a specific quarterhour has a specific shape (trapezoid), presented in the following figure. Specifically, the preparation period starts on T-7,5, i.e., 7,5 minutes before the beginning of the quarter-hour QH(t0) and the deactivation period ends on T+20, i.e., by 5 minutes after the end of QH(t0), where ‘T’ is the beginning of the quarter-hour and is considered as the ‘point of scheduled activation’. 23 Figure 153,4: Scheduled Activation: TSO-TSO exchanged shape and timings The delivery of balancing energy for Direct Activations, including ramping, may start at any point in time between T-5 and T+10, depending on when demand(

1. s)arrived on the platform. The delivery will always end at T+35. A Direct Activation (DA) for a specific quarter-hour can be requested by the TSO at any moment after the point of scheduled activation for that specific quarter-hour. Therefore, a direct activation may last at minimum 27,5 minutes and at maximum 42,5 minutes (including FAT). The TSO-TSO energy exchange profile for Direct Activations for a specific quarter-hour has a specific shape (trapezoid), presented in the following figure: Figure 163,4: Direct Activation: TSO-TSO profile and timings It is noted that for directly activated bids, the period when energy is actually delivered will stretch until the end of the following MTU period. The start of this period, referred to as activation period, is determined with a configurable precision, initially set to 1 minute, and will coincide with the point in time when the AOF finishes processing the demand(
2. s)that triggered 24 the activation of the bid, plus a configurable allowance (set to 7.5 minutes) for data exchange and ramping. 4.3. Local mFRR balancing energy product characteristics Following participation in MARI, local mFRR bids’ characteristics submitted in the LMOL are expected to be harmonised with the mFRR standard product characteristics (see section 4.1). However, in order to take into account the differences between the various local markets, some mFRR product bid characteristics may be decided on a national level in the terms and conditions for BSPs. This is foreseen so as to ensure TSOs can securely manage the system while, at the same time, guaranteeing liquidity for the mFRR-Platform. As stated in section 4.1, each bid shall indicate its location (the smallest between the LFC area or the bidding zone). However, more detailed locational information may be required in order to safely manage the system (for example, this information might be needed for solving congestions by filtering bids located in a congested location). The preparation period, the ramping period, the deactivation period and the maximum duration of the delivery period, desribed in section 4.2, are dependent on the tolerated deviation between the TSO-TSO exchanged shape as described in section 4.2 and the BSPTSO delivered shape, which is defined individually by each TSO in accordance with their terms and conditions for BSPs. In the following figure the TSO-TSO exchanged shape (yellow trapezoidal shape) is presented, as well as some indicative TSO-BSP delivered shapes. Figure 176: Illustration of different BSP-TSO delivered shapes and their influence on the duration of the delivery period in the case of a schedule activation. BSPs should follow the activation profile of the TSO-TSO exchanged shape for the requested activations as closely as possible, within a tolerance band. The stricter the tolerance on the deviation between the TSO-TSO exchanged shape and the BSP-TSO delivered shape, the less 6 Source: MARI Implementation Framework Explanatory Document 25 the imbalances that will occur. IPTO may set a tolerance band around the TSO-TSO exchanged shape and perform random checks in order to monitor that the delivered BSP profile is within the prespecified tolarance band. 4.4. Submission of mFRR energy bids TSOs submit to the common platform all balancing energy bids for the standard mFRR product. Bids may be updated up until the TSO mFRR GCT for balancing energy bids at T-12. After this GCT, mFRR energy bids are considered firm and can no longer be modified by the BSPs. However, in exceptional circumstances the TSO (not the BSP) is permitted to modify the volume, activation type and/or availability status of bids as outlined in article 9 of the mFRR IF. More specifically, TSOs shall be able to submit updates concerning the availability of bids, in response to network outages or system constraints, changes to the volume and the activation type until T+5. No other modifications are foreseen. Due to the design of the AOF, updates to bids after TSO mFRR GCT for demands (at T-10) will not be reflected in the CMOL for scheduled activations. The update will be taken into account by the CMOL for any subsequent direct activations. The BSP mFRR GCT for the submission of mFRR energy bids to the RTBM will be modified to be in line with the MARI process. As already mentioned in previous sections, according to mFRR IF, the GCT for BSPs to submit the mFFR balancing energy bids to their TSOs is 25 minutes before the start of the concerned quarter-hour, i.e. T-25. However, due to time constraints related to the conversion of mFRR bids by IPTO this timing is not feasible. The BSP mFRR GCT for the Greek market will depend on the time required for the conversion of bids. The format of the bids also depends on the market design option that will be selected regarding unit commitment, reserve procurement and redispatching. 26 5. Conversion to standard mFRR energy products Article 27 of EBGL sets out the requirements for TSOs using a central dispatching model. Article 27

(2)of EBGL requires that each TSO applying a central dispatching model uses “[…] the integrated scheduling process bids available for the real time management of the system to provide balancing services to other TSOs, while respecting operational security constraints” and, in accordance with Article 27

(3)of EBGL converts “as far as possible the integrated scheduling process bids pursuant to paragraph 2 into standard products taking into account operational security”. Moreover, Article 27

(3)of EBGL mentions boundary conditions for the conversion rules which must be “fair, transparent and non-discriminatory”, shall “not create barriers for the exchange of balancing services” and shall “ensure the financial neutrality of TSOs”. Therefore, pursuant to EBGL, IPTO will convert the bids received by BSPs into standard products using a dedicated conversion platform. The rules for converting the balancing energy bids into mFRR standard products will inter alia respect the following: • • • the mFRR standard products characteristics, the technical characteristics of the balancing service entities, the system constraints for operational security, including reserves. 5.1. Balancing energy bids conversion rules The rules for converting balancing energy bids into mFRR standard products are indicatevely described below. • The conversion process will consider bids that can be activated within a quarter-hour from: (

1. a)Entities that are online but not in startup or shut down phase (synchronization, soak and de-synchronization phases) or transitioning phase. (
2. b)Entities that are not in commissioning or testing operation. (
3. c)Entities that have been allocated non-spinning mFRR capacity. This is applicable to Dispatchable Generating Units, Dispatchable RES Units Portofolios and Dispatchable Load Portfolios with zero synchronization time and soak time. • The conversion process will consider bids that can be activated within a quarter-hour from entinties taking into account: (
4. a)the technical constraints of the entities that are included in the Declared Characteristics such as Technical Minimum Generation, Maximum Net Capacity, synchronization time, soak time, de-synchronization time, soak profile output, minimum up/down time constraints, transition times, ramp rates etc. (
5. b)Non-availability declarations. (
6. c)allocated FCR and aFRR balancing capacity and AGC limits (min/max entity’s capacity constraints). 27 (
7. d)any restrictions on mandatory injections. (
8. e)Nominated Schedules. (
9. f)minimum acceptance ratio of the bids. (
10. g)System constaints. More specifically, both upward and downward balancing energy bids of a BSE which is contrained by a System constraint will be capped up to the applied limit. Upward and downward balancing energy bids of BSEs for which a group generic constraint applies (System constaint relevant for a group of BSEs) will first be sorted in a merit order list, ascending for upward bids and descending for downward bids, taking also into account the technical constraints of these BSEs and their Nomination Schedules. From the merit order above, the most economic bids will be selected. Bids to shutdown units will be selected last, irrespective of their economic ranking. The bids not selected with the above process will be forwarded to the mFRR-platform but will marked as unavailable both locally and in the MARI platform due to internal congestion (refer to section 4.1). If indivisible bids exist, then those bids will be excluded, even if they are more economic, in cases where the economic selection violates their indivisibility. As an example, let’s assume a group generic constraint applied to three BSEs for a maximum generation limit of 800ΜW for a certain quarter-hour. The balancing energy bids of each Entity are presented below. Entities B and C sumbit an indivisible bid step (3B and 4C accrordingly). After applying the aforementioned rules the available steps to be submitted to the mFRR-Platform are those from the sum of the Nomination Schedules of all entities up to the maximum generation limit (red window), excluding bid 4C even though it has a lower price. 28 Figure 18: Example of handling indivisible bids. 5.2. Local merit order list to be submitted to MARI platform The output of the conversion process will be two local merit order lists, LMOLs, one in the upward direction and one for the downward direction. This set of bids will be sorted according to their price, ascending for upward bids and descending for downward bids. If the prices of two or more balancing energy bids for the same Dispatch Period are identical then the following order of priority shall be applied for upward bids: (
11. a)Dispatchable Load Portfolio, (
12. b)Dispatchable RES Units Portfolio, (
13. c)Dispatchable hydro Generating Units, and (
14. d)Dispatchable thermal Generating Units, and the reverse for the downward bids. 29 Figure 19: Example of positive and negative merit order list. After the creation of the two local MOLs, the volume that has been identified by IPTO to be guaranteed (in each direction), will be matched to the most expensive direct bids of the MOL and will be marked unavailable in SA activation (guaranteed volume). If one bid that is part of a multipart group or an exclusive group is selected for guaranteed volume, all associated bids are also selected for guaranteed volume. In such cases the following rules apply: • • The entire volume of the bids in the multipart group is considered as guaranteed volume. The largest volume of the bids in an exclusive group is considered as guaranteed volume. 5.3. Local merit order list when disconnected from the MARI platform In cases where IPTO is disconnected, or local fallback procedures are invoked, the same local merit order will be used by the local mFRR process, RTBM. Therefore RTBM will need to be modified. For more details refer to section 6.2. 30 6. Activation of mFRR balancing energy bids 6.1. Dispatch instructions As described in section 4.3, if the mFRR profile delivered by the BSP deviates significantly from the cross-border exchange schedule (TSO-TSO exchanged shape), this may result in additional imbalances for the connecting TSO. Therefore, it is important that the delivered mFRR balancing energy is consistent with the cross-border exchange schedule to limit the impact on the local imbalances. Under and over-delivery should be avoided to the extent possible as this additional imbalance may result in an increased use of short-term products, mostly aFRR, which is expected to have higher procurement costs and lower liquidity. Therefore, it is proposed that entities are incentivized to deliver the TSO-TSO exchanged shape. For each selected SA mFRR Energy Bid from the MARI platform, IPTO will transform the selected bid into Dispatch Instructions which will be sent to BSEs as a single setpoint (in MW or in MWh). The BSP must reach the setpoint by the end of the FAT and must automatically deactivate the bid according to the figure below. The BSP must follow the activation profile of scheduled activation as described in sections 4.2 and 4.3. Figure 20: Example of SA Dispatch Instruction. Likewise, for each selected DA mFRR Energy Bid from the MARI platform, IPTO will transform the selected bid into Dispatch Instructions which will be sent to BSEs as a single setpoint (in MW or in MWh). The BSP must reach the setpoint by the end of the FAT and must automatically deactivate the bid according to the figure below. Figure 21: Example of DA Dispatch Instruction. 31 6.2. Local activation principles After connecting to the MARI platform, the mFRR energy bids submitted by IPTO can be activated by the MARI platform based on the European common merit order and the MARI AOF. As described in section 3.5, in situations where the MARI platform is not available for any reason, IPTO must disconnect and activate mFRR energy bids using local selection principles for the fallback procedure. IPTO will need to appropriately amend the current mFRR algorithm and RTBM process to address these situations. 32 7. mFRR balancing energy demands IPTO will submit to the common platform the mFRR demands for balancing energy for scheduled and direct activations, respectively, referring to a specific MTU period. While all demands for scheduled activations have to be submitted by the TSO gate closure at T-10 (relevant to the beginning of the specific MTU period), the demands for direct activations may subsequently be submitted at any point in time up until T+5 (relevant to the beginning of the specific MTU period). Updating of demands, including cancellation, is permitted up to the point in time when the AOF starts processing the submitted demand. 7.1. Characteristics’ of mFRR demands A demand is always associated with exactly one direction, which may be either upward (positive) or downward (negative). The location of the demand is associated with a given scheduling area. All demands are considered to be divisible. Similar to bids, the activation type must be declared and is either for scheduled activation or direct activation. The mFRR demands may be either inelastic (price dependent) or elastic (price independent). An ‘elastic mFRR demand’ is a TSO demand for activation of standard mFRR balancing energy product bid of which the satisfaction depends on the price of standard mFRR balancing energy product bids. An ‘inelastic mFRR demand’ is a TSO demand for activation of standard mFRR balancing energy product bid, which needs to be satisfied irrespectively of the price of the activation of standard mFRR balancing energy product and therefore the price limit is set to the value of the technical price limit defined in the methodology pursuant to Article 30

(1)of the EB Regulation; In other words, an inelastic demand does not have a price and corresponds to a demand that must be satisfied at all costs. TSO demands have also the following features: • Quantity [MW] • Price [€/MWh] • Location of demand • Purpose: balancing purpose or system constraint activation purpose. The demands for “Balancing purpose” have a higher priority for MARI AOF than the demands for “system constraints purpose”. 7.2. Calculation of mFRR demands IPTO will calculate mFRR demands for scheduled or direct activation. In order to to compute the mFRR demands for scheduled activation per quarter hour, IPTO will estimate the zonal imbalances and take into account the required de-saturation of the already used aFRR balancing capacity. 33 For the computation of the mFRR demands for direct activation, IPTO will take into account incidents or unforseen imbalances. In addition, IPTO will also take into account the volumes of mFRR demand not fully satisfied by the MARI platform. 7.3. Satisfied demands After execution of the AOF for scheduled and direct activations respectively, the MARI platform will send the satisfied demands. When processing the LMOL document with the accepted bids and satisfied demands, IPTO may detect that demands are not entirely satisfied. IPTO may have to perform local supplementary measures to address this situation above (refer to section 3.5.2). 34 8. Settlement of mFRR energy and imbalances 8.1. mFRR energy settlement prices Τhe mFRR energy clearing prices are determined by the mFRR-Platform per uncongested area and are called the “Cross-Border Marginal Prices” (CBMP). The CBMP is the price of the last bid of the mFRR standard product which has been activated to cover the energy need for balancing purposes within an uncongested area. In MARI AOF, a set of scheduling areas interconnected by uncongested interconnectors define an uncongested area and a price zone. Within a price zone, all areas are coupled and the price must be the same for all scheduling areas of a given price zone.If there is a congestion on an interconnector connecting two scheduling areas, then there is no price convergence, and price in these two scheduling areas can diverge. The optimization of the scheduled activations produces a single CBMP per MTU and uncongested area for both upward and downward balancing energy whereas the optimization of the direct activations produces two different settlement prices, one for upward and one for downward balancing energy. After completion of the optimization of scheduled activations, the common platform provides the clearing prices (CBMPs) to the TSOs and after completion of the optimization of scheduled activations for the following quarter hour, the common platform distributes to TSOs the clearing prices for direct activations. The methodology to determine prices for mFRR balancing energy is based on marginal pricing. Generally, the marginal price represents the price of the last bid of a standard product that has been selected by the mFRR-Platform to cover the energy need (demand) for balancing purposes within a specified area. Given that there may be various optimizations for each quarter-hour, i.e., mFRR with scheduled activation and mFRR with direct activation, multiple mFRR energy clearing prices can be determined. More specifically: • one for mFRR SA for both positive and negative directions, • none or more for mFRR DA for positive direction, and • none or more for mFRR DA for negative direction. 8.1.1. mFRR energy clearing price for Scheduled Activation For mFRR SA there is only one time point of Scheduled Activation for each quarter-hour. This results in a list of mFRR energy bids to be activated, both in positive and negative directions, and in one clearing price that satisfies the conditions of all selected bids. This clearing price is applicable for the determination of the energy remuneration of all mFRR energy bids selected for Scheduled Activation with delivery in the QH(t). 35 Figure 22: SA clearing example 8.1.2. mFRR energy clearing price for Direct Activation For mFRR DA, there can be multiple moments of Direct Activations for each quarter-hour. Every DA activation results in two lists of mFRR energy bids to be activated, one in positive and one in negative direction, and accordingly one clearing price that satisfies the conditions of all selected bids for positive direction and one clearing price that satisfies the conditions of all selected bids for negative direction. Of the selected bids in the DA clearing phase, the one with the highest price sets the marginal bids price for all the bids selected for Direct Activation in positive direction whereas the one with the lowest price sets the marginal bids price for all the bids selected for Direct Activation in negative direction. Given that Direct Activations may require delivery in the concerned quarter-hour Qh(

1. t)as well as the next quarter-hour Qh(t+1), the energy delivered for direct activation is remunerated differently depending on the quarter-hour of delivery and the relevant clearing price for scheduled activation. More specifically, the price used to remunerate positive energy in response of a direct activation, is the maximum between the ‘Clearing Price for SA’ and the ‘Marginal bid for DA positive direction’ of the same quarter-hour of delivery. Accordingly, the marginal price used to remunerate negative energy in response of a direct activation, is the minimum between the ‘Clearing Price for SA’ and the ‘Marginal bid for DA negative direction’ of the same quarter-hour of delivery. Consequently, the energy delivered in the first quarter-hour of a Direct Activation may be remunerated differently from the energy delivered in the second quarter-hour. 36 MWh SA Activation 150MWh Clearing Price: 300€/MWh Bid DA A : DA Activation 100MWh Price: 350€/MWh Bid DA B : DA Activation 80MWh Price: 260€/MWh SA Activation 200MWh Clearing Price: 280€/MWh Bid DA C : DA Activation 80MWh Clearing Price: 190€/MWh SA Activation 120MWh Clearing Price: 170€/MWh Prices Calculation for volumes requested in each QH QH1 QH2 Clearing Price for SA: 300€/MWh Clearing Price for SA: 280€/MWh Clearing Price for Bid DA A: Max(300; 350)=350€/MWh Clearing Price for Bid DA A: Max(280; 350)=350€/MWh Clearing Price for Bid DA B: Max(300; 350)=350€/MWh Clearing Price for Bid DA B: Max(280; 350)=350€/MWh Clearing Price for Bid DA C: Max(280; 190)=280€/MWh QH3 t Clearing Price for SA: 280€/MWh Clearing Price for Bid DA C: Max(170; 190)=190€/MWh Figure 23: Example of mFRR energy prices determination 8.1.3. mFRR energy prices in congested areas As explained previously, in case of cross-zonal capacity limitations between adjacent areas, a price split can occur. This means that in each uncongested area the highest selected bid sets the marginal price for the respective area. The uncongested areas can be different among the different balancing processes. For example, the uncongested areas for mFRR activations can be different from the uncongested areas for aFRR activation. Moreover, as mFRR with direct activation and aFRR are continuous processes, the definition of the uncongested areas for this process may change at any point in time, also within an Imbalance Settlement Period or the quarter of an hour for which the bid is submitted. 8.2. mFRR energy and imbalances calculation For each entity, e, the selected mFRR energy bids for activation via the mFRR-Platform are remunerated based on the clearing prices for the relevant quarter-hour as follows: 37 mFRR Energy Remuneration(e,
2. t)= mFRR Energy Requested(e,t)∗ mFRR Energy Clearing Price(e,
3. t)Scheduled Activation The mFRR Energy Requested (MWh) for the relevant quarter-hour corresponds to the expected balancing energy provision for the net selected bids by MARI of a specific entinty 𝑈𝑝−𝐷𝑛 for the concerned QH(
4. t)in MW for SA, 𝑀𝐴𝑅𝐼_𝑆𝐴MW . If the Dispatch Instruction is received at the point of scheduled activation (i.e. a Scheduled Activation), then the mFRR Energy Requested is remunerated for the red area and the yellow areas correspond to imbalances as depicted in the following figure. Figure 24: Renumerated volume settlement for SA For QH(t0) mFRR Energy remunerated is equal to: 𝑈𝑝−𝐷𝑛 𝑈𝑝−𝐷𝑛 𝑀𝐴𝑅𝐼_𝑆𝐴MWh = 𝑀𝐴𝑅𝐼_𝑆𝐴MW * 1/4 * 15/15 [MWh] Direct Activation If the Dispatch Instruction is received before the point of scheduled activation (i.e. a Direct Activation was requested for the previous quarter-hour), then the mFRR Energy Requested (MWh) for the concerned quarter-hour is reduced in proportion to the delay of the activation request in relation to the point of scheduled activation, as depicted in the green area in the following diagram. The mFRR Energy Requested (MWh) corresponds to the expected balancing enegy provision for the net selected bids by MARI of a specific entinty for the 𝑈𝑝−𝐷𝑛 concerned QH(
5. t)in MW for DA, 𝑀𝐴𝑅𝐼_𝐷𝐴MW . The mFRR Energy Requested is remunerated 38 for the green and red area and the the yellow areas correspond to imbalances as depicted in the following figure. Figure 25: Renumerated volume settlement for DA For QH(t0) mFRR Energy remunerated is equal to: 𝑈𝑝−𝐷𝑛 𝑈𝑝−𝐷𝑛 𝑀𝐴𝑅𝐼_𝐷𝐴MWh = 𝑀𝐴𝑅𝐼_𝐷𝐴MW * 1/4 * (15-t)/15 [MWh] where t is the time delay between point of scheduled activation and the time of the direct activation request. For QH(t+1) mFRR Energy remunerated is equal to: 𝑈𝑝−𝐷𝑛 𝑈𝑝−𝐷𝑛 𝑀𝐴𝑅𝐼_𝐷𝐴MWh = 𝑀𝐴𝑅𝐼_𝐷𝐴MW * 1/4 * 15/15 [MWh] Instructed Energy The Instructed Energy for an Imbalance Settlement Period t will be calculated as follows: 𝑈𝑝−𝐷𝑛 𝑈𝑝−𝐷𝑛 𝑈𝑝−𝐷𝑛 INST [MWh] = NS𝑀𝑊ℎ + 𝑀𝐴𝑅𝐼_𝑆𝐴MWh + 𝑀𝐴𝑅𝐼_𝐷𝐴MWh + 𝐿𝑜𝑐𝑎𝑙_𝑆𝐴MWh 𝑈𝑝−𝐷𝑛 + 𝐿𝑜𝑐𝑎𝑙_𝐷𝐴MWh Where, NS𝑀𝑊ℎ : corresponds to the Nomination Schedule of the entity (in MWh), i.e., the nominated energy schedule resulting from the entity’s participation in the previous markets that is technically feasible according to the technical characteristics of the asset and the nominated Balancing Capacity. 39 𝑀𝐴𝑅𝐼_𝑆𝐴MWh : 𝑈𝑝−𝐷𝑛 corresponds to the expected balancing energy provision for the selected bids for SA, by the MARI platform, of a specific entity, for the concerned QH(t), in MWh (mFRR Energy Requested). 𝐿𝑜𝑐𝑎𝑙_𝑆𝐴MWh : 𝑈𝑝−𝐷𝑛 corresponds to the expected energy provision for the selected bids for SA, by the local mFRR-Platform, of a specific entity, for the concerned QH(
6. t)in MWh. 𝑀𝐴𝑅𝐼_𝐷𝐴MWh : 𝑈𝑝−𝐷𝑛 corresponds to the expected balancing energy provision for the selected bids for DA, by the MARI platform, of a specific entity, for the concerned QH(t), in MWh. 𝑈𝑝−𝐷𝑛 corresponds to the expected energy provision for the selected bids for DA, by the local mFRR-Platform, of a specific entity, for the concerned QH(t), in MWh. 𝐿𝑜𝑐𝑎𝑙_𝐷𝐴MWh : 8.3. Imbalance price calculation No changes are expected in the imbalance price calculation. Specifically, the imbalance price for an Imbalance Settlement Period shall be calculated as the weighted average of the prices of the activated Balancing Energy, via the MARI Platform and via local mFRR process, in the predominant direction (upward or downward) for manual and automatic FRR. If there has been no activation of balancing energy, the imbalance price ia calculated as the value of avoided balancing energy activation. 8.4. Financial settlement 8.4.1. Price formation If there is no congestion on the borders between the various scheduling areas then the highest activated bid price defines the price for the TSO-TSO settlement as well as the price for the TSO-BSP settlement for all scheduling areas. Every BSP receives the same price for the activated balancing energy from the connecting TSO and every TSO pays/receives the same marginal price for imported/exported (cross-border) balancing energy. If a congestion occurs on some borders, the capability of exchanging balancing energy is limited and less energy than economically optimal can be exchanged. This leads to the dermination of various uncongested areas, which are defined as a set of scheduling areas interconnected by uncongested interconnectors. Different prices are set in each uncongested area. Specifically, the highest activated bid in each uncongested area sets the marginal price of that specific uncongested area. The price difference due to the congestion on the border creates a congestion income, which is handled in a way that guaranties financial neutrality of both TSOs. 40 8.4.2. Financial Settlement timeline The TSO-TSO settlement is performed monthly by a Billing Agent who sends invoices to the TSOs before the end of the 5th working day of the month M+1, where M refers to the delivery month for which the settlement is performed. The payments by the TSOs to the Billing Agent are performed no later than thirty

(30)calendar days after the date of issuance of the invoice and the payments by the Billing Agent to the TSOs are performed no later than thirty-two

(32)calendar days after the date of issuance of the invoice. Finally, the correction of invoices is possible up to thirty-six months after the month of delivery. The aforementioned timeline affects the timeline of the local balancing market settlement as performed today. Two options have been identified. The first is to switch to monthly local settlement cycles in order to take into account MARI settlement results in the initial settlement. This option increases the risk for the Clearing House and will increase the required guarantees by the BSPs, but reduces the need for corrective settlements. The second option is to continue with weekly local settlement cycles. In this case, financial exchanges with other TSOs will initially (on the weekly local settlement) be credited/debited to the Uplift Account 3 (Financial Neutrality Account) and will be corrected with a local corrective settlement performed after the finalization of the TSO-TSO settlement. This could create large variations in the cost of Uplift Account 3 depending on the direction of the energy flows by the MARI platform. The monthly settlement cycle of MARI also affects corrective settlement timing which is now performed in week W+6 and will have to be performed after the receipt of the monthly MARI settlement statement. Moreover, the local Final Settlement will also have to be performed after the finalization of the MARI settlement which may performed up to thirty-six months after the month of delivery. 41 High-level design of the aFRR process in the Greek balancing energy market for participation in the European aFRR platform, PICASSO, for the exchange of balancing energy from frequency restoration reserves with automatic activation Table of Contents 1 Abbreviations.................................................................................................................... 3 2 Introduction ...................................................................................................................... 5 3 General description of PICASSO ........................................................................................ 7 4 aFRR energy bids .............................................................................................................. 9 4.1 aFRR energy standard product characteristics ..................................................................... 9 4.2 aFRR energy local product characteristics .......................................................................... 10 4.3 Submission of available aFRR energy bids to PICASSO ..................................................... 11 4.4 Non-contracted aFRR balancing energy bids ...................................................................... 12 5 Conversion to standard aFRR energy products ................................................................. 14 6 aFRR Cross-Zonal Capacity Limits ................................................................................... 15 7 8 6.1 Limits per LFC Area border ................................................................................................... 15 6.2 Profile Limits .......................................................................................................................... 15 6.3 Other CZC limits ..................................................................................................................... 15 Activation of aFRR .......................................................................................................... 16 7.1 PICASSO process overview .................................................................................................. 16 7.2 Main information flows under PICASSO operation ............................................................. 17 7.3 Local Activation of aFRR balancing energy under PICASSO .............................................. 19 7.4 Local Activation of aFRR balancing energy without PICASSO ........................................... 22 Pricing and Settlement .................................................................................................... 23 8.1 TSO-TSO settlement .............................................................................................................. 23 8.1.1 Volume Matching Process .................................................................................................... 23 8.1.2 Settlement amounts calculation........................................................................................... 23 8.1.3 Settlement procedure ............................................................................................................ 24 8.2 TSO-BSP Settlement .............................................................................................................. 24 2 1 Abbreviations ACE Area Control Error aFRR FRR with automatic activation aFRR IF Implementation framework for the European platform for the exchange of balancing energy from frequency restoration reserves with automatic activation AGC Automatic Generation Control AOF/INF Activation optimisation function / Imbalance netting function BMR Balancing Market Rulebook BSE Balancing Service Entity BSP Balancing Service Provider BSP aFRR GCT Gate Closure Time for aFRR bids submission by BSPs to the TSO CBCL Cross-border Capacity Limits CBMP Cross-border Marginal Price CMOL Common Merit Order List CMOL Common Merit Order List CSP Commοn Service Provider. It is a TSO that provides a common service (e.g. the PICASSO platform) to all other participating TSOs. CZC Cross-zonal Capacity EBGL Regulation (EE) 2017/2195 (Electricity Balancing Regulation) FCR Frequency Containment Reserve FRR Frequency Restoration Reserves GCT Gate Closure Time IGCC The International Grid Control Cooperation ISP Integrated Scheduling Process LFC Area Load Frequency Control Area LMOL Local Merit Order List LMOL Local Merit Order List mFRR FRR with manual activation MTU Market Time Unit PCorr Corrected aFRR demand for local activation, after AOF/INF optimization PICASSO Platform for the International Coordination of Automated Frequency Restoration and Stable System Operation TSO aFRR GCT Gate Closure Time for LMOL submission by the TSO to PICASSO platform 3 WD Working day 4 2 Introduction This document presents the high-level design of the participation of the Hellenic Balancing Energy Market (specifically regarding the aFRR balancing energy) to the “Platform for the International Coordination of Automated Frequency Restoration and Stable System Operation” (PICASSO). The Greek participation in this platform is mandatory as per Regulation (ΕΕ) 2017/2195 (EBGL), art.21 and ACER Decision 02/2020 (“ACER Decision on the Implementation framework for aFRR Platform”). The PICASSO platform is an ambitious project involving more than 30 European TSOs as presented in the map below. FIGURE 11: PICASSO IMPLEMENTATION PROJECT Pursuant to the provisions provided in article 62 of the EBGL, IPTO has requested a derogation from the provisions of art. 20

(6)of EBGL concerning the implementation of the PICASSO platform for two years from the legal go-live date (July 24, 2022). Participation in the PICASSO platform is a highly challenging project that requires significant and extensive modifications to systems, infrastructure, and procedures that affect both the scheduling and the real-time processes, as well as to the terms and conditions of market participation. RAE, with its Decision 363/2022, granted IPTO the requested derogation deadline, i.e., until the 24th of July 2024. 1 ENTSOE: https://www.entsoe.eu/network_codes/eb/picasso/ 5 The aFRR-Platform Accession roadmap for all relevant TSOs is presented below. aFRR-Platform Accession Roadmap 1 2 3 Last updated on 25/10/2022 based on latest information available. 2023 2024 4 5 6 Q3 Q4 Q1 Q2 Q3 Q4 1 2 3 4 2022 aFRRIF 5.4.(b)(

1. ii)AOF (done) 5.4.(b)(
2. ii)TSO-TSO settlement (done) 5.4.(b)(
3. vi)Testing functions & aFRR operation (done) 5.4.(b)(iii) TSOs Interoperability test (done) 5.4.(b)(
4. iv)Operational test (parallel run) (done) 5.4.(b)(
5. v)TSOs Connection to aFRR platform / Go-live 5.4.(b)(
6. vi)aFRR-Platform Go-live (done) 7 8 Country Derogation deadline EU: Austria 1 24.07.2024 Belgium Bulgaria 30.06.2024 Croatia 24.07.2024 Czech republic 2 24.07.2024 Denmark 24.07.2024 Finland 2 France 24.07.2024 Germany Greece 24.07.2024 Hungary 24.07.2024 Italy 24.07.2023 24.07.2024 Netherlands 3 Poland 24.07.2024 Portugal Romania 01.10.2023 Slovakia 24.07.2024 Slovenia Spain 24.07.2024 24.07.2024 Sweden 2 EEA: 2 24.07.2024 Norway Non-EU: 4 Switzerland 7 8 9 10 11 12 2022 5.4.(b)(
7. i)5.4.(b)(
8. i)5.4.(b)(iii) 5.4.(b)(
9. v)5.4.(b)(vii) 9 10 11 12 2023 5 6 2024 Q3 Q4 Q1 Q2 Q3 Q4 TSO APG Elia ESO HOPS ČEPS Energinet Fingrid RTE 50Hz,AMP,TNG,TTG ADMIE MAVIR Terna Tennet BV PSE REN Transelectrica SEPS ELES REE SVK Statnett Swissgrid National terms and conditions development National terms and conditions entry info force Interoperability tests between TSO and aFRR-Platform TSO connection to aFRR-platform / Go-live EBGL Article 62 Derogation considered (no deadline listed) / requested (no deadline listed) / granted (new deadline listed) 1) A first version of the T&C has entered into force early May w hen local bidding has been adapted and a second one w ill enter into force w hen ELIA w ill connect to PICASSO. The plan presented in this roadmap shall be regarded as a preliminary, non-binding estimate. The planned connection time is expected in Q4 2023 - Q1 2024. 2) The plan presented in this roadmap shall be regarded as a preliminary, non-binding estimate. The planned connection time is expected in Q2 2024. 3) TenneT NL aims for implementation and go-live by July 2024 and has been granted a derogation until then. How ever, there is a real risk that the final derogation w ill take place even later than the requested derogation period. If TenneT takes these risks into account, TenneT expects to participate in the summer of 2025 to participate in the aFRR platform and TenneT w ill enter into discussions w ith relevant stakeholders if it becomes clear that the risks already in the planning manifest themselves. 4) The technical readiness of Sw issgrid has been acknow ledged. The participation of Sw itzerland in the aFRR-Platform is regulated based on article 1.6 and 1.7 of the EB Regulation and currently the subject of litigation by Sw issgrid at the General Court of the European Union. FIGURE 22: AFRR-PLATFORM ACCESSION ROADMAP Any change in systems, infrastructure, procedures and terms and conditions requires careful planning, adequate consultation with market participants, and, of course, testing, to avoid affecting the smooth functioning of the balancing market and the operational security of the system. Given the magnitude of the modifications required and the fact that competition will increase from the participation of all power resources among Europe in a common market for balancing, sufficient time is needed for market participants to be informed and prepared. 2 221025_PICASSO_6th_Accession_roadmap_ext.pdf 6 3 General description of PICASSO The Platform for the International Coordination of Automated Frequency Restoration and Stable System Operation (PICASSO) is the implementation project endorsed by all TSOs to establish the European platform for the exchange of balancing energy from frequency restoration reserves with automatic activation or aFRR-Platform. Participation in PICASSO will facilitate cross-border activation of aFRR to maximize the economic surplus of all participating LFC Areas. Currently, aFRR activations are triggered automatically for each LFC Area based on its ACE. The ACE is calculated based (
10. i)on the difference between the total interconnector active power flow and the control program and (
11. ii)the FCR activations in the LFC Area (K∆f). Afterwards, the local aFRR Controller calculates the control target and sends the control request to the BSPs. Control demand model Following participation in PICASSO, the aFRR activation process shall be modified to consider a correction signal that corresponds to the PICASSO optimization (AOF/INF) results which reflect aFRR exchange with other LFC Areas. aFRRActivation aFRR LFC Area Balance aFRR Demand aFRR Demand Correction LFC Area 1 aFRR aFRRActivation Correction LFC input aFRR-Request LFC Area Balance LFC input frequency restoration controller frequency restoration controller aFRR-Request LFC Area 3 AOF/INF LFC Area 2 aFRR-Request other LFC Areas frequency restoration controller LFC input aFRRActivation aFRR LFC Area Balance Correction Correction aFRR Demand aFRR Demand aFRR activation in multiple LFC Areas under PICASSO 7 A simplified diagram of the process of aFRR activation using the PICASSO platform is presented below. 8 4 aFRR energy bids 4.1 aFRR energy standard product characteristics The characteristics of the standard product bids for aFRR are specified according to the provisions of article 25

(1)of the EBGL and article 7 of the aFRR IF. The main characteristics of the standard aFRR product and the current local product are presented below: Description Current Local Product Standard aFRR product Full Activation Time The time period between the activation request by TSO and the corresponding full activation of the standard product. 7.5 minutes 5 minutes Minimum bid size The minimum bid size of the energy bid volume offered. 1 MW 1 MW Maximum bid size The maximum bid size of the energy bid volume offered. limited by BSE max capacity limited by BSE max capacity, up to 9,999 MW Granularity The possible increment of bids above the minimum bid size. 0.1 MW 1 MW Maximum Price The maximum price of the standard balancing energy product bid. +9.999 EUR/MWh 99,999.00 EUR/MWh Minimum Price The minimum price of the standard balancing energy product bid. -9.999 EUR/MWh - 99,999.00 EUR/MWh Price resolution The minimum resolution for the price of the standard balancing energy product bid. 0.01 EUR/MWh 0.01 EUR/MWh Validity Period The time when the balancing energy bid offered by the BSP can be activated, whereas all the characteristics of the product are respected. The amount of time for which a bid is valid and firm. The first validity period of each day begins right at 00:00 market time. Validity periods are consecutive and not overlapping. 15 minutes 15 minutes Bid Characteristics Direction Positive or negative Volume MW Price EUR/MWh LFC Area IPTO LFC Area Divisibility aFRR balancing energy bids are fully divisible. Activation/deactivation aFRR balancing energy bids can be activated and deactivated at any moment within the bids’ validity period, Minimum delivery time There is no Minimum delivery time 9 In addition to the above, some product characteristics are not harmonized within PICASSO, but can be decided at a national level. 4.2 aFRR energy local product characteristics Following participation in PICASSO, local aFRR bid characteristics submitted in the LMOL will be harmonised with the aFRR standard product characteristics. However, in order to take into account the differences between the various local markets, some aFRR product bid characteristics may be decided at a national level in the terms and conditions for BSPs. This is foreseen to ensure TSOs securely manage the system while, at the same time, guaranteeing liquidity for the aFRR-Platform. The deactivation period and the maximum duration of the delivery period will be defined individually by each TSO in accordance with their terms and conditions for BSPs. The bid structure is as follows: i. Bids will contain price-volume pairs that refer to the energy cost (in €/MWh) of the offered aFRR Power (in MW). ii. Total bid volume (aggregation of all bid steps) should not exceed the maximum aFRR Capacity of the BSE, as declared in the standing data. iii. Only fully divisible bids are allowed. According to art. 7 of the mFRR IF, both upward and downward mFRR energy bids have a price resolution of two decimals, i.e., 0.01 €/MWh and price of the bid can be positive, zero or negative. In addition, according to the Technical Decision “Technical limits for bidding prices and clearing prices in the Balancing Market”, after inclusion of IPTO in one of the European platforms, MARI or PICASSO, and up to 48 months after the legal deadline envisaged in EBGL, the maximum and minimum prices limits set for bidding prices and clearing prices for balancing energy should be equal to +15.000€/MWh and -15.000€/MWh accordingly. After the 48 months period the maximum and minimum limits set for bidding prices and clearing prices for balancing energy should be equal to +99.999€/MWh and -99.999€/MWh. In contrast to the current aFRR bid format, the volume of the aFRR energy bid when IPTO joins PICASSO will be equal to the technical capability of the BSE to provide aFRR. Moreover, the selection of the bid will start from the point of 0 MW, according to the following example regarding a BSE with a Market Schedule of 90MW, an mFRR activation of 30 MW (MARI schedule of 120MW) and an aFRR activation of 30MW upwards aFRR. • In the current market, the aFRR bid concerns the range from 0MW up to the Technical Maximum of the BSE (200MW in this example) and the part of the bid that is taken into consideration is the part starting from the RTBM basepoint and up to the AGC setpoint. 10 MS = 90MW | RTBM Schedule = 120MW | AGC INST = 150MW mFRR Activated Power = 30MW | aFRR Activated Power = 30MW 300 €/MW 250 200 150 RTBM Basepoint AGC Setpoint mFRR Balancing Energy aFRR Balancing Energy 100 Market Schedule 50 0 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 MW • Under PICASSO, the aFRR bid concerns the technical capability of the BSE to provide aFRR (60 MW in this example) and the part of the bid that is taken into consideration starts from 0 MW up to the AGC setpoint. MS = 90MW | MARI Schedule = 120MW | AGC INST = 150MW mFRR Activated Power = 30MW | aFRR Activated Power = 30MW 300 €/MW 250 200 150 100 AGC Activated Power aFRR Balancing Energy 50 0 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 MW 4.3 Submission of available aFRR energy bids to PICASSO Each LMOL is created after the BSP aFRR GCT and submitted to PICASSO up to 10 minutes before the start of its validity period. An LMOL may be complete or incremental: 11 • • Complete LMOL: contains all valid bids for the respective validity period and replaces previously submitted LMOLs. It is possible to modify, add or remove bids compared to the previous LMOL. Incremental MOL: contains only bids which shall be changed in comparison to previously submitted LMOLs. It is possible to add and modify bids; however, it is not possible to remove bids compared to the previous LMOL. In case of outages or other events that can lead to a bid being unavailable for activation (e.g. due to activation of the BSE bids in MARI, being suspended or disconnected from the AGC, etc.), this bid is flagged as unavailable, the LMOL is amended and resubmitted to PICASSO without delay. If an amendment to an LMOL is required after TSO aFRR GCT, only the availability status and the volume of bids may be amended. In that case, the TSO must also submit a Bid Availability Market Document that includes the amendment and the reason for this change. This information will be published by PICASSO. After each submission or resubmission of an LMOL, PICASSO acknowledges its successful receipt and subsequently combines all valid LMOLs into a common list that incorporates all submitted data from all participating TSOs. This list is named CMOL (combined merit order list) and is used from PICASSO to optimize aFRR activation. The LMOL submission and the respective CMOL creation processes timings are shown in the following picture: Validity period TSO aFRR Platform D-1 12:00 LMOL first submission and (possible updates) by TSOs LMOL updates by TSOs BSP aFRR GCT t-? min CMOL update & activation CMOL update CMOL creation and update TSO aFRR GCT t-10min t t+14min 4.4 Non-contracted aFRR balancing energy bids Currently, aFRR Balancing Energy is provided only by the BSEs that have been awarded aFRR Balancing Capacity in the ISP. Following participation in PICASSO, provision of aFRR by noncontracted BSEs is also being considered, i.e. BSEs will have the right to provide aFRR Balancing Energy even if they were not awarded aFRR Balancing Capacity (submission of non-contracted balancing energy bids). The main principles for provision of aFRR by non-contracted BSEs are the following: • All prequalified for aFRR provision BSEs may submit non-contracted aFRR balancing energy bids for voluntary aFRR provision. • Submission of non-contracted aFRR Balancing Energy bids is allowed for BSEs that have already been awarded aFRR Balancing Capacity for the remainder of their available aFRR capacity. 12 • Submission of non-contracted aFRR Balancing Energy bids, for their available aFRR capacity, is allowed for BSEs that have not been awarded aFRR Balancing Capacity. • Activation of non-contracted aFRR bids will be remunerated for the provision of aFRR Balancing Energy with the same rules as contracted aFRR bids. • Non-contracted balancing energy bids will not be remunerated for Balancing Capacity. • BSPs have to submit non-contracted aFRR Balancing Energy bids before the relevant BSP aFRR GCT. An indicative procedure to manage non-contracted aFRR bids is described below: • The selection among contracted and non-contracted aFRR balancing energy bids will be performed on an hourly basis. • BSEs willing to provide non-contracted aFRR for each hour shall submit aFRR balancing energy bids to IPTO ahead of time. For each hour, IPTO will select the most economic bids corresponding to the aFRR Balancing Capacity need for the hour. These bids will be available for activation in real time for the specific hour. • IPTO may reject non-contracted aFRR balancing energy bids providing a justification in case of rejection. 13 5 Conversion to standard aFRR energy products For an MTU (15 minutes period) a selection process is required in order to identify the bids that are available for activation. The selection process is presented below. A bid (or bid part) from a BSE is considered available if in a given MTU: i. The BSE is synchronized (for those BSEs that synchronization is relevant) and not scheduled to start-up, shut-down or transition to another configuration. ii. The BSE is not in commissioning or testing operation. iii. The bid part concerns activation of upward aFRR energy up to the AGCmax of the BSE. iv. The bid part concerns activation of downward aFRR energy not below the AGCmin of the BSE. v. The bid part concerning activation of aFRR energy in any direction is less or equal to the maximum aFRR capacity of the BSE. vi. The bid part concerns activation of aFRR energy that would not violate any applicable constraints (e.g. network constraints, mandatory water constraints etc.). In case a constraint is applicable to a group of BSEs instead of a specific BSE, only the most economic bid parts with an aggregate volume up to the constraint are considered available from these BSEs. vii. The bid part concerns activation of aFRR energy up to the aFRR quantity selected by the process described in section 4.4. For each MTU, following the above selection process, all the aFRR energy bid steps considered available are sorted based on their price, and combined into a merit order list (Local Merit Order List – LMOL) for each direction (upward, downward). Each LMOL can concern only one MTU. In accordance with the EBGL (article 29) and the aFRR IF (article 9) it is possible to mark specific bids as unavailable for activation due to internal congestion or due to operational security constraints. These bids will be included in the LMOL but will not be available for activation from PICASSO. 14 6 aFRR Cross-Zonal Capacity Limits 6.1 Limits per LFC Area border The activation of aFRR from other LFC Areas to cover local needs is limited by the cross-border capacity limits (CBCL) which depend on the interconnecting lines. This information is an input to the PICASSO platform. This information will be provided to PICASSO centrally for all LFC Areas from the Capacity Management Module (CMM). Until the CMM is operational, IPTO will send the CBCL for each border adjacent to its LFC Area to PICASSO, considering the available capacity after the Intraday market results and considering all cross-border schedules and reserved capacity. The PICASSO platform expects CBCLs to be provided via real-time signals and does not process any scheduled values. Temporary additional restrictions related to operational safety (according to SOGL 149

(3)) can be specified. The same applies to (permanent) HVDC restrictions if applicable. The submission of negative CBCL values to enforce a flow is not allowed. For each border, the CBCL is provided by the two TSOs that are responsible for the adjacent LFC areas. The AOF will use the minimal value of the CBCL received from these two TSOs. By this, it is ensured that each TSO can unilaterally set effective additional limits for the interchange on these borders. 6.2 Profile Limits In addition to CBCLs, limits can be provided in the form of net profiles or directed profiles that limit the total flow on a predefined set of borders (e.g. all borders surrounding a given LFC area, LFC block or any other arbitrarily defined region). • A net profile can be used to limit the net position (net of import and export flows) of a region and does not block transit flows through the region. • A directed profile limits the total import or export of a region without taking into account flows in the opposite direction. Directed profile limits can be used to effectively limit transit flows. 6.3 Other CZC limits Ensuring operational security remains the responsibility of IPTO for its control area. The “affected TSO procedure”, described below, is implemented to fulfil the requirements from SOGL to implement balancing platforms in a way that ensures operational security. Under the “affected TSO procedure”, an affected TSO is allowed to limit borders that are not under his responsibility. The TSOs shall strive to coordinate themselves as much as possible to avoid unnecessary and uncoordinated limitations. 15 7 Activation of aFRR 7.1 PICASSO process overview

1. Each BSE may submit to IPTO or update his aFRR bids starting from the BSP aFRR Gate Opening Time (BSP aFRR GOT) and up to the BSP aFRR Gate Closing Time (BSP aFRR GCT). The BSP aFRR GCT will be decided in the future, but it shall be not later than 20 minutes before the aFRR delivery time. The bids shall adhere to the specifications stated in section
3. IPTO converts the BSE bids to standard aFRR product bids as specified in section 5 and submits them to the PICASSO platform before the TSO aFRR GCT, which is 10 minutes before the aFRR delivery time.
4. PICASSO validates and merges all received bids into a Common Merit Order List (CMOL), until the start of the aFRR delivery time.
5. During the aFRR delivery time which has a duration of 15 minutes: i. Each TSO informs PICASSO about the local aFRR Demand. ii. PICASSO, considering the CMOL, selects the offers that satisfy the total aFRR need across all LFC Areas in a way that maximizes social welfare, given cross-zonal capacity constraints. iii. PICASSO informs each TSO regarding the required aFRR power interchange (exchange of aFRR energy with LFC areas). The sum of the local aFRR demand and the received aFRR power interchange reflects the amount of aFRR which the individual LFC area should provide. iv. The local AGC system activates aFRR in the LFC Area in a market-based manner in accordance with the LMOL. v. The responsible BSEs activate the requested aFRR.
6. PICASSO publishes its results to the Transparency Platform 30 minutes after the aFRR delivery time.
7. The aFRR exchanges scheduled via PICASSO are settled between participating TSOs, in the following month. A more detailed description of the aFRR activation procedure is presented in section 7.
8. minimum BSP aFRR GOT BSP aFRR GCT TSO aFRR GCT 16 PICASSO Timing 7.2 Main information flows under PICASSO operation No Name Description/Notes Sender Receiver Frequency 1 TSO aFRR & IN participation status Used to determine TSO participation in the TSO next PICASSO AOF & INF run PICASSO real-time (on each change of state) 2 aFRR crossThe aFRR CBCL for each of the aFRR TSO border capacity balancing border the TSO is responsible limits for, as the export and the import limit for aFRR interchange. PICASSO real-time (each control cycle) This function will be done via the CMM when it is implemented (see section 4.1) 3 Profile limits The profile limits for import and export for TSO each managed profile. PICASSO real-time (each control cycle) Profile limits can either be set to limit the total flow for either PICASSO, or IGCC, or both. 4 LMOL Local Merit Order List. TSO PICASSO For each 15’ period, submission before TSO aFRR GCT. Not used by the AOF / INF for the TSO optimization and capacity allocation, only to provide an estimation of the real flows on the borders of the TSO’s providing it. PICASSO Ideally hourly, at least on a daily basis May be updated after TSO aFRR GCT due to operational security reasons or locally conditional bids. 5 Power transfer distribution factor (PTDF) The PTDFs have an hourly resolution. Sent on a voluntary basis 6 7 local aFRR demand Provided for each LFC area. TSO PICASSO real-time (each local control cycle) • Activated aFRR or Provided for each LFC area, negative for TSO downward activation, positive for upward activation. PICASSO real-time (each local control cycle) • FRCE without the influence of cross-border aFRP and INP The local aFRR demand is defined as the sum of the already activated aFRR and the FRCE without the influence of the intended exchange of balancing energy resulting from the cross-border aFRP or INP 17 8 AOF & INF status Status of the AOF and the INF (online, PICASSO TSO offline) real-time post & ex- 9 TSO AOF & INF participation status Participation status of all TSOs to the AOF PICASSO TSO & INF (online, offline) real-time post & ex- 10 aFRR demand satisfaction The satisfied and unsatisfied demand for each LFC area real-time post & ex- 11 aFRR correction value & IN correction value Provided for each LFC area. Values are PICASSO TSO negative for imports, positive for exports. real-time (each optimization cycle) 12 CBMP Provided for each LFC area. Used for TSO- PICASSO TSO TSO settlement and as input to the local TSO-BSP settlement. real-time (each optimization cycle) and expost 13 Total aFRR interchange Provided for each balancing border of each PICASSO TSO LFC area. (PICASSO & IGCC) real-time (each optimization cycle) 14 IN interchange Provided for each balancing border of each PICASSO TSO LFC area. (IGCC) real-time (each optimization cycle) 15 Adjusted aFRR interchange Provided for each LFC area. This is the PICASSO TSO estimation of actual import or export for the respective LFC area based on the activated aFRR. Values are negative for imports and positive for exports. (PICASSO) real-time (each optimization cycle) 16 Adjusted aFRR for local purpose Provided for each LFC area. This is the PICASSO TSO adjusted aFRR corresponding to the aFRR activation for local purpose of the LFC area(s). Values are positive for upward activation and negative for downwards activation. real-time (each optimization cycle) 17 FRCE Provided for each LFC area. Values are PICASSO TSO positive for power surplus (need for downwards aFRR) and negative for power deficit (need for upwards aFRR). real-time (each optimization cycle) 18 Corrected Provided for each LFC area. Values are PICASSO TSO demand (Pcorr) negative for power surplus (need for downwards aFRR) and positive for power deficit (need for upwards aFRR). real-time (each optimization cycle) aFRR PICASSO TSO 18 This value can be used in the local AGC system for dynamic limitation of the LFC output. 7.3 Local Activation of aFRR balancing energy under PICASSO The PICASSO process is presented below:
9. IPTO calculates the local aFRR demand which is determined according to the following calculation: 𝑃demand = 𝑃LFCinput − 𝑃Corr_aFRR − 𝑃corr_IGCC + 𝑃aFRR , where: • 𝑃LFCinput is the current local aFRR need, as determined from the local AGC. • 𝑃𝑐𝑜𝑟𝑟 for aFRR and IGCC is the current corrected demand for AOF and INF as received by PICASSO • 𝑃aFRR is the amount of already activated aFRR. It is determined based on the measured volumes.
10. The local aFRR demand is sent as an input to the PICASSO AOF/INF function.
11. The PICASSO AOF/INF function selects the bids that satisfy the total aFRR need across all LFC Areas in a way that maximizes social welfare, based on the CMOL and given constraints such as the available cross-zonal capacity. This selection is done by the PICASSO AOF/INF optimization function and concerns cycles of 4 seconds.
12. PICASSO informs each TSO regarding the required aFRR power interchange, separately for IGCC (PCorr_IGCC) and PICASSO (PCorr_aFRR), as per the AOF/INF function results. The sum of the local aFRR demand and the received aFRR power interchange values for IGCC and PICASSO reflects the amount of aFRR, which the individual LFC area has to provide. The correction values PCorr_IGCC and PCorr_aFRR are sent without taking into account the activation dynamics of the assets delivering balancing energy.
13. The local AGC system finally activates aFRR in the LFC Area, in order to satisfy the local aFRR demand plus the additional PICASSO activation requirements reflected in the corrected demand (PCorr_IGCC + PCorr_aFRR) in accordance with the SOGL, art. 147

(4a). The corrected demand (sum of PCorr) reflects the amount of aFRR, which the individual LFC area has to provide to other LFC Areas. In the event of a step change in the aFRR demand of the requesting LFC area, the full step change would be induced in the uncorrected FRCE (𝑃LFCinput ) of the connecting TSO. By this, it will increase the uncorrected FRCE of aFRR exporting LFC areas.

1. In order to activate the required aFRR, the local AGC system selects bids to activate in accordance with the LMOL in a market-based manner, following merit-order principles. Because of the dynamics of the aFRR process, the actual aFRR activation may differ from the PICASSO results, which makes it is possible to activate bids that are above the PICASSO CBMP, if these are needed to meet the actual aFRR demand.
2. The local AGC instructs the BSPs to activate aFRR in accordance with the selected aFRR bids, at the end of the local AGC cycle.
3. Both the PICASSO AOF/INF cycle and the local AGC cycle have a duration of 4 seconds.
4. The LMOL and CMOL lists are kept always in sync, meaning that in case of BSP outages, the LMOL is updated and sent to PICASSO to be merged into the CMOL. 19 As already stated in point

(6)above, due to the dynamics of the aFRR process, it is possible that a bid that has not been selected for activation by the PICASSO AOF/INF, will be activated by the local AGC system. This bid could have a price higher than the PICASSO CBMP. The figure below presents an example. BSE dynamic aFRR Response BSEs should follow the profile of the requested activations as closely as possible. IPTO may set a tolerance band around the requested activation profile and perform random checks in order to monitor that the delivered profile by the BSEs is within the prespecified tolerance band. Deviations of the delivered profile exceeding the tolerance band (yellow area in the graph below) are considered imbalances and non-compliance charges may apply. aFRR tolerance band 20 The model of the local AGC system when operating within PICASSO is shown in the following pictures: Local control demand model under PICASSO in one LFC Area aFRRActivation aFRR LFC Area Balance aFRR Demand aFRR Demand Correction aFRRActivation LFC input frequency restoration controller LFC Area 1 aFRR Correction LFC input aFRR-Request LFC Area Balance frequency restoration controller aFRR-Request LFC Area 3 AOF/INF LFC Area 2 other LFC Areas frequency restoration controller aFRR-Request LFC input aFRRActivation aFRR LFC Area Balance Correction Correction aFRR Demand aFRR Demand Control demand model under PICASSO in multiple LFC Areas An example regarding the timing of the AOF/INF optimization cycle (OC) and the local AGC optimization cycle (LC) as well as the applicable Pcorr and CBMP is presented below: 21 Local AGC Cycle (4sec) (LC) PICASSO AOF/INF Optimization Cycle (4 sec) (OC) OC Pcorr used in LC calculation LC 0 OC 1 LC 1 OC 2 LC 2 OC 3 Pcorr OC 1 LC 3 OC 4 Pcorr OC 2 Pcorr OC 3 7.4 Local Activation of aFRR balancing energy without PICASSO In case that for any reason (e.g. temporary disconnect) the PICASSO results (Pcorr, CBMP) are not available, aFRR is activated locally by the AGC in order to satisfy the local aFRR demand (not the corrected demand). In such cases, the aFRR bid activation process does not change. Local control demand model when disconnected from PICASSO 22 8 Pricing and Settlement 8.1 TSO-TSO settlement The TSO-TSO settlement for the aFRR energy activated within PICASSO is done monthly, following the procedure stated below. 8.1.1 Volume Matching Process Daily, on the first working day after the aFRR energy exchange, a matching process is performed to facilitate the determination of volumes used for the TSO-TSO settlement. In this process, IPTO compares the sum of aFRR activated under PICASSO (Pcorr) in every AGC cycle within an MTU (15’ period), per LFC Area under his responsibility and direction (import or export). This volume is compared to the corresponding volume calculated by the CSP regarding the corrected demand sent to IPTO. In case of a mismatch greater than a tolerance band, a bilateral investigation or an investigation involving more TSOs is triggered in order to solve the issue and determine the volume to be settled, as shown in the following figure. The tolerance band is defined within a bilateral agreement between IPTO and the CSP. 8.1.2 Settlement amounts calculation Until the third working day of each month, PICASSO calculates the settlement amounts per MTU and border. For each optimisation cycle, the aFRR congestion income generated on each aFRR balancing border is equal to the price difference of the importing and exporting areas multiplied with the aFRR quantity exchanged on the border. PICASSO calculates and the Invoicing Agent 23 collects the balancing congestion income per aFRR balancing border and ensures that the collected balancing congestion income is transferred to the TSOs or appointed entities. The settlement results are included in the monthly settlement report and sent to the TSOs via email, ECP or Webservices (initially via email). In case a TSO finds an error or an inconsistency in the monthly settlement report, the TSO will communicate it promptly to the Host TSO between the third and fifth working day of the month. After the investigation, in case a new corrected settlement report is needed, it will be sent to all the TSOs and the validation period will be shifted accordingly. 8.1.3 Settlement procedure The validated reports are sent to the Invoicing Agent before the end of the 7th WD. If an investigation process is ongoing and one or more TSOs cannot solve the error by the 7th WD: • • By default, the report is sent to the Invoicing Agent on 7th WD and invoices are issued. TSOs continue investigating. If the data in the settlement report are not correct, the Host TSO issues a corrected settlement report and invoices are adjusted accordingly. If this practice leads to frequent invoice corrections, the TSOs can agree on adjustments in the settlement process so that the settlement report is sent to the Invoicing Agent only after solving the error but not later than on the 18th WD of the following month. Each TSO is also allowed to argue for holding the invoicing process until the deviation has been solved. If this is acceptable, only after solving the mismatch (not later than the 18th WD) the report can be sent to the Invoicing Agent. The objective of this process is to mitigate the number of errors and corrections. TSOs will have the chance to open a dispute through the reconciliation process in case there is an issue detected once this validation period has finished. 1. Payments from TSOs to the Invoicing Agent are cleared not later than 30 (thirty) calendar days after the invoice’s date of issue. 2. Payments from the Invoicing Agent to the TSOs are cleared not later than 32 (thirty-two) calendar days after the invoice’s date of issue. 8.2 TSO-BSP Settlement The TSO-BSP settlement is not harmonized across TSOs, rather, it is decided on a national level. It is proposed to settle the activated aFRR energy as described below: For each 1-minute period and BSE: 24 1. The settlement volume for upward aFRR balancing energy equals the average measured energy per AGC cycle in this 1-minute period minus the volume of the mFRR instruction in the same 15’ MTU, when the difference is positive. 2. The settlement volume for downward aFRR balancing energy equals the average measured energy per AGC cycle in this 1-minute period minus the volume of the mFRR instruction in the same 15’ MTU, when the difference is negative. 3. The settlement volume per direction cannot be greater than the average requested volume per direction. Activated quantities above that limit will be settled as imbalances. 4. The weighted average price (UPCBMPWAE, and DNCBMPWAE) of all CBMPs that were calculated by PICASSO for the 1-minute period is determined. 5. The settlement price for upward aFRR balancing energy equals the maximum of UPCBMPWAE, and BSE’s bid price that corresponds to the BSE’s average measured upward aFRR balancing energy. 6. The settlement price for downward aFRR balancing energy equals the minimum of DNCBMPWAE, and the BSE’s bid price that corresponds to the BSE’s average measured downward aFRR balancing energy. 7. The settlement amount per 1-minute period equals the settlement volume multiplied by the settlement price for both directions. The settlement amount per MTU for each BSE equals the sum of the related settlement amounts per 1-minute cycle within the MTU. Local AGC Cycle (4sec) (LC) LC 0 PICASSO AOF/INF Optimization Cycle (4 sec) (OC) LC 1 OC 1 OC Pcorr used in LC calculation aFRR INST volume applicable for TSO-BSP settlement aFRR CBMP applicable for TSO-BSP settlement LC 2 OC 2 INST LC0 LC 3 OC 3 OC 4 Pcorr OC 1 Pcorr OC 2 Pcorr OC 3 INST LC1 INST LC2 INST LC3 CBMP OC1 CBMP OC2 CBMP OC3 Timing of applicable CBMP per AGC cycle More details regarding the TSO-BSP settlement timeline are presented in the MARI preliminary design document. 25