BALANCING Market DETAILED DESIGN - ADMIE · Page vi December 18, 2017 8.5 Obligations of BSPs in the context of the Real-Time Balancing Energy Market

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BALANCING Market

DETAILED DESIGN

Page ii December 18, 2017

Table of Contents

Executive Summary ................................................................................................. 1

1 Introduction ....................................................................................................... 14

1.1 Importance of Balancing Electricity Markets................................................. 14

1.2 Network Code on Electricity Balancing ........................................................ 15

1.3 Architecture of the Balancing and Ancillary Services Market under the Target

Model ........................................................................................................... 15

1.3.1 Balancing and Ancillary Services Market Definition .............................. 15

1.3.2 Balancing Services Procurement ......................................................... 16

1.3.3 Central Dispatch Principle .................................................................... 20

1.3.4 Balance Responsibility and Imbalance Settlement ............................... 22

1.3.5 Summary .............................................................................................. 23

2 RES Participation in the Balancing and Ancillary Services Market .............. 25

2.1 Introduction .................................................................................................. 25

2.2 Specific Features of RES Units .................................................................... 26

2.3 RES Units Categorization in terms of Market Participation .......................... 28

3 Demand Response Participation in the Balancing and Ancillary Services

Market ................................................................................................................ 30

3.1 Introduction .................................................................................................. 30

3.2 Specific Features of DR Resources ............................................................. 30

3.3 DR Units Categorization in terms of Market Participation ............................ 32

3.4 Role of Aggregators in Enabling Market Participation of DR Resources ...... 33

3.5 Contractual Design for the Incorporation of DR Resources in the Greek

Electricity Market .......................................................................................... 34

3.5.1 Model A: Use of bilateral contracts ....................................................... 35

3.5.2 Model B: Settlement Through Regulated Prices .................................. 40

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3.5.3 Model C: Assumption of Market Risk Entirely by DR Aggregator ......... 41

3.6 Baseline Methodology .................................................................................. 44

3.7 Gradual Participation of DR Resources in the Different Areas of the Greek

Wholesale Market ........................................................................................ 45

4 Optimum Integration of RES Units and DR Resources in the Balancing and

Ancillary Services Market ................................................................................ 47

5 Stakeholders in the Balancing and Ancillary Services Market ..................... 56

5.1 Entities ......................................................................................................... 56

5.2 Registries ..................................................................................................... 60

5.2.1 Generating Units Registry .................................................................... 60

5.2.2 Dispatchable Load Portfolios Registry ................................................. 61

5.2.3 Dispatchable RES Portfolios Registry .................................................. 62

5.3 Balancing Services Entities/Providers .......................................................... 63

5.4 Balance Responsible Entities/Parties ........................................................... 64

5.5 Participation Fees ........................................................................................ 65

6 Interface with the Forward, Day-Ahead and Intra-Day Markets .................... 66

7 Integrated Scheduling Process ....................................................................... 68

7.1 Timeframe of the Integrated Scheduling Process......................................... 68

7.2 Balancing Services Products ........................................................................ 71

7.3 Dispatch Period ............................................................................................ 72

7.4 Submission of Non-Availability Declarations ................................................ 72

7.5 Submission of Techno-Economic Declarations ............................................ 74

7.5.1 Contents of Techno-Economic Declarations ......................................... 74

7.5.2 Techno-Economic Declaration submission procedure .......................... 77

7.5.3 Acceptance and rejection of Techno-Economic Declarations by the

TSO ...................................................................................................... 77

7.6 Submission of Balancing Energy Offers ....................................................... 77

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7.6.1 General provisions ............................................................................... 78

7.6.2 Format of the Balancing Energy Offers in the Integrated Scheduling

Process ................................................................................................ 80

7.6.3 Modification and acceptance of the Balancing Energy Offers in the

Integrated Scheduling Process ............................................................ 82

7.6.4 Consequences of non-submission of Balancing Energy Offers ............ 83

7.7 Submission of Reserve Capacity Offers ....................................................... 83

7.7.1 General provisions ............................................................................... 83

7.7.2 Format of the Reserve Capacity Offers in the Integrated Scheduling

Process ................................................................................................ 84

7.7.3 Modification and acceptance of the Reserve Capacity Offers in the

Integrated Scheduling Process ............................................................ 85

7.7.4 Consequences of non-submission of Reserve Capacity Offers ........... 85

7.8 Integrated Scheduling Process Data ............................................................ 86

7.9 Integrated Scheduling Process Solution Methodology ................................. 88

7.10 Mathematical Formulation .................................................................... 89

7.10.1 Objective Function ................................................................... 89

7.10.2 Balancing Energy Cost ............................................................. 89

7.10.3 Reserve Capacity Cost ............................................................ 90

7.10.4 Start-up Cost ............................................................................ 91

7.10.5 Penalty Cost ............................................................................. 91

7.10.6 Dispatch Scheduling and Reserve Capacity Allocation

Concept ................................................................................................ 93

7.10.7 Balancing Services Provider Operating States ........................ 96

7.10.8 Start-up Phase ......................................................................... 97

7.10.9 De-synchronization Phase ..................................................... 101

7.10.10 Logical Status of Commitment ............................................... 101

7.10.11 Minimum Up / Down Time Constraints ................................... 102

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7.10.12 Power Output Constraint ........................................................ 103

7.10.13 Balancing Energy Constraints ................................................ 103

7.10.14 Capacity Constraints .............................................................. 106

7.10.15 Hydro Mandatory Generation ................................................. 109

7.10.16 Maximum Daily Energy Constraint .......................................... 110

7.10.17 Ramping Constraints ............................................................... 111

7.10.18 Reserve Capacity Ramping Constraints ................................. 112

7.10.19 Reserve Capacity Contribution Constraints ............................ 113

7.10.20 Zonal Imbalance covering Constraints (Inter-zonal Transfer

Model) 118

7.10.21 Zonal Imbalance covering Constraints (Flow-Based Model) .. 124

7.10.22 Reserve Requirements Constraints ....................................... 125

7.10.23 Generic Constraints ............................................................... 128

7.10.24 Specific Operating Constraints for the Loading BSEs

(Dispatchable Load Portfolios) ........................................................... 129

7.11 Responsibilities of the Transmission System Operator .............................. 131

7.12 Integrated Scheduling Process Results ............................................. 135

7.13 Integrated Scheduling Process Results Publication ........................... 136

7.14 Integrated Scheduling Process Results Monitoring ............................ 136

8 Real-Time Balancing Energy Market ............................................................. 137

8.1 General ...................................................................................................... 137

8.2 Dispatch Period .......................................................................................... 138

8.3 Balancing Services Products – Dispatch Process ...................................... 138

8.3.1 Balancing Services Products.............................................................. 138

8.3.2 mFRR Process (two executions methods) ......................................... 139

8.4 Modification of Balancing Energy Offers by the Balancing Services

Providers .................................................................................................... 143

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8.5 Obligations of BSPs in the context of the Real-Time Balancing Energy

Market ........................................................................................................ 146

8.6 Real-Time Balancing Energy Market Input Data ........................................ 147

8.7 Real-Time Balancing Energy Market Solution Methodology ...................... 148

8.8 mFRR Process Mathematical Formulation – 1st execution method (Single

Techno-economic Clearing) ........................................................................ 149

8.8.1 Objective Function ............................................................................. 149

8.8.2 Balancing Energy Cost ....................................................................... 150

8.8.3 Penalty Cost ....................................................................................... 151

8.8.4 Power Output Constraint .................................................................... 152

8.8.5 Balancing Energy Constraints ............................................................ 153

8.8.6 Capacity Constraints .......................................................................... 155

8.8.7 Ramping Constraints .......................................................................... 158

8.8.8 Maximum Daily Energy Constraint ..................................................... 159

8.8.9 Mandatory Activation Process prior to the mFRR Clearing ................ 160


Model) 161


8.9 Mathematical Formulation of the 2nd implementation phase of the mFRR

process (Conversion Process / Economic Clearing) .................................. 165

8.9.1 Conversion Process ........................................................................... 166


8.9.3 Capacity Constraints .......................................................................... 167

8.9.4 Ramping Constraints .......................................................................... 169

8.9.5 Maximum Daily Energy Constraint ..................................................... 170

8.9.6 Penalty Cost ....................................................................................... 170

8.9.7 Conversion of the Balancing Energy Offers prior to mFRR Clearing and

Creation of the Final Merit Order ........................................................ 171

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8.9.8 mFRR Clearing – Mathematical Formulation ..................................... 173


8.9.10 Balancing Energy Cost ........................................................... 174

8.9.11 Penalty Cost ........................................................................... 175

8.9.12 Balancing Energy Constraints ................................................ 175


Model) 176


8.10 mFRR Clearing Results ..................................................................... 179

8.11 Dispatch Instructions stemming from the mFRR Problem Solution ............ 180

8.12 Direct Activation of mFRR .................................................................. 182

8.13 Activation of aFRR ............................................................................. 183

8.14 Responsibilities of the Transmission System Operator ...................... 183

9 Settlements...................................................................................................... 185

9.1 General Provisions ..................................................................................... 185

9.1.1 Balancing Market Settlements............................................................ 185

9.1.2 Responsibilities of the Transmission System Operator ...................... 185

9.1.3 Obligations of the Distribution System Operator in the context of the

Settlemnt Procedure .......................................................................... 186

9.1.4 Balancing Market Accounts ................................................................ 187

9.1.5 Settlement Scope ............................................................................... 187

9.1.6 Settlement Input Data ........................................................................ 188

9.2 Balancing Energy and Imbalance Settlement ............................................. 190

9.2.1 Balancing Energy and Imbalance Definitions ..................................... 190

9.2.2 mFRR Balancing Energy Price ........................................................... 193

9.2.3 Remuneration of Provided Balancing Energy .................................... 194

9.2.4 Remuneration of Provided mFRR Balancing Energy ......................... 194

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9.2.5 Remuneration Balancing Energy Offers activated for reasons other

balancing ............................................................................................ 195

9.2.6 Remuneration of Provided aFRR Balancing Energy .......................... 195

9.2.7 Derivation of the Imbalance Settlement Price .................................... 195

9.2.8 Imbalance Settlement ........................................................................ 196

9.3 Balancing Capacity Settlement .................................................................. 197

9.3.1 Balancing Capacity Settlement Period ............................................... 197

9.3.2 Remuneration Calculation .................................................................. 197

9.4 Uplift Accounts ........................................................................................... 199

9.4.1 Uplift Accounts kept by the Transmission System Operator ............... 199

9.4.2 System Losses Uplift Account UA-1 ................................................... 199

9.4.3 Balancing Capacity Uplift Account UA-2 ............................................ 200

9.4.4 Ancillary Services Uplift Account UA-3 ............................................... 201

9.4.5 Contracted Units Uplift Account UA-4 ................................................ 201

9.4.6 Emergency Imports and Exports Uplift Account UA-5 ........................ 201

9.5 Non-compliance Charges Settlement ......................................................... 202

9.5.1 Non-Compliance with Ancillary Services Dispatch Instructions by

Balancing Service Providers .............................................................. 202

9.5.2 Consequences of non-lawful submission of Non-Availability Declarations

........................................................................................................... 203

9.5.3 Consequences of non-lawful Techno-Economic Declaration .............. 204

9.5.4 Consequences of non-submission of Balancing Energy Offers .......... 204

9.5.5 Consequences of non-submission of Reserve Capacity Offers ......... 205

9.5.6 Consequences of significant non-performance of activated upward and

downward Balancing Energy by a Balancing Service Entity .............. 206

9.5.7 Consequences of significant systematic deviations in the demand

purchased by Load Representatives .................................................. 208

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9.5.8 Consequences of significant systematic deviations in the actual

generation of a Non-Dispatchable RES Portfolio ............................... 209

9.5.9 Non-Compliance Charge for import/export deviations ......................... 211

9.5.10 Consequences of non-performance by a Contracted Unit ...... 211

9.5.11 Handling of the Non-Compliance amount .............................. 212

9.6 Balancing Market Settlement Process ....................................................... 212

10 Annex A: Nomenclature ................................................................................. 215

11 Annex Β: Computation of Reserve Requirements ....................................... 244

11.1 Frequency Containment Reserve ............................................................... 244

11.2 Automatic Frequency Restoration Reserve ................................................ 245

11.3 Manual Frequency Restoration Reserve and Replacement Reserve ......... 248

12 Annex C: RES Units Categorization under Greek Law 4414/2016 .............. 250

Page x December 18, 2017

List of Tables

Table 3-1: Settlement Example of model A .............................................................. 38

Table 3-2: Settlement Example of model C .............................................................. 44

Table 4-1: Market design variables and respective decisions for the Greek Balancing

and Ancillary Services Market ........................................................................... 55

Table 7-1: Techno-Economic Declarations’ contents ............................................... 76

Table 10-1: Nomenclature ...................................................................................... 243

Page xi December 18, 2017

List of Figures

Figure 1-1: Successive “layers” of Reserve Capacity activation (Source: ENTSO-E)

........................................................................................................................... 19

Figure 1-2: Balancing in a Central Dispatch system (Source: ENTSO-E) ................ 21

Figure 1-3:Basic elements and interrelations of the Balancing and Ancillary Services

Market ................................................................................................................ 24

Figure 3-1: Relationships between market parties in model A ................................. 36

Figure 3-2: Relationships between entities in model B ............................................. 40

Figure 3-3: Relationships between market parties in model C ................................. 42

Figure 3-4: Indicative Baseline during load curtailment ............................................ 45

Figure 7-1: Timeframe of the Integrated Scheduling Process programmed executions

........................................................................................................................... 70

Figure 7-2: Upward Balancing Energy step-wise function ........................................ 81

Figure 7-3: Downward Balancing Energy step-wise function ................................... 81

Figure 7-4: Dispatch Scheduling in the ISP model ................................................... 94

Figure 7-5: Reserve Capacity allocation in the ISP model ....................................... 95

Figure 8-1: mFRR clearing process (two implementation phases) ......................... 141

Figure 8-2: Real-Time Balancing Energy Market (RTBEM) Gate Closure Times ... 144

Figure 8-3: Conversion of the Balancing Energy Offers prior to their insertion in the

mFRR clearing ................................................................................................. 173

Page 1 December, 2017

Executive Summary

ECCO International (“ECCO”) has been commissioned by the Joint Research Centre

(JRC) of the European Commission to develop a Detailed Level Design, the Market

Codes and the IT Functional Specifications for the Target Model-based energy market

in Greece. This includes the Forward, Day-Ahead, and Intraday Markets for the Market

Operator (LAGIE) and the Balancing Market for the Transmission System Operator

(ADMIE). The proposed market design contained in the report draws upon the High

Level Market Design executed by ECCO in 2014.

The work contained in this report focuses on the detailed market design of the

Balancing and Ancillary Services market (BASM) for the ADMIE. The report specifies

the participating entities and their roles and obligations, the necessary functions and

processes to be implemented by ADMIE, the optimization problems that should be

formulated and cleared in the Balancing and Ancillary Services Market, and the

Balancing Energy and imbalance settlement rules. The market design for the direct

participation of Renewable Energy Sources (RES) and Demand Response (DR)

resources in the new Balancing and Ancillary Services Market in Greece, taking into

account the provisions of the recent Greek Law 4414/2016, are also included.

The harmonization of the Greek electricity market with the provisions of ENTSO-E

Network Codes is mandatory and necessary to achieve Europe-wide coupling with the

other European wholesale electricity markets, in accordance with the so-called “Target

Model”. Based on the RAE Decision 67/2017, ADMIE is requested to implement, inter

alia, the necessary infrastructure for the management and operation of the Balancing

and Ancillary Services Market. The implementation and operation by ADMIE of an

Information System for system Balancing and for the procurement and activation of

Ancillary Services, compatible with the provisions of ENTSO-E Network Codes, which

will ensure the reliable operation of the power system, is of paramount importance and

is considered as a basic prerequisite for the timely achievement of the reorganization

of Greek wholesale electricity market in accordance with the Target Model. The main

target is to achieve a smooth transition and efficient integration of the Greek wholesale

electricity market into the single European electricity market.

The Balancing Market is a very important market function which lies at the junction of

the financial and physical activities that shall take place at the Greek electricity market

and is directly related to the procurement of market products and services that affect

the reliability of the power system. Therefore, special attention must be paid to this

market function, since at the present time there is no actual operational experience of

a separate balancing mechanism - in accordance with the ENTSO-E’s Target Model -

in the Greek electricity sector.

The BASM design constitutes a complex topic, due to the large number of design

variables and its (often) divergent policy objectives of security of supply and economic

efficiency. At a European level, as opposed to the clear target models followed for the

integration of other markets (e.g. European Regulation 2015/1222), the Balancing


Market integration design has not been fully vetted yet. The Commission Regulation

that establishes the directives on electricity balancing1 (stemming from the Electricity

Balancing Network Code – EB NC) has not come into effect yet. Further, the Target

Model itself is a bit vague on important details regarding the desirable end-state of

cross-border balancing, and the clear targets for the different kinds of balancing

services. Hence, rather than detailing a specific target model design, the EB NC lays

out the general processes towards realizing the integrated Balancing Market’s

efficiency gains; namely, a better utilization of the cheapest resources by providing

access to foreign balancing services and thus mitigating concentration levels in

national Balancing Markets, as well as increased operational security2. The

implementation of Balancing Markets spanning across national frontiers constitutes an

important last step towards the full completion of the Target Model.

Dispatch Arrangements

In order to operate a secure and reliable power system in an economic and efficient

manner within the liberalized framework of competitive electricity markets, European

electricity markets have developed different dispatch arrangements, which can be

essentially divided into two high level categories: Self-Dispatch and Central Dispatch

models. These models vary by placing the balancing responsibilities on different

entities. In Self-Dispatch systems, Balance Responsible Parties (BRPs) issue

commitment decisions and determine the desired dispatch position of their resources

(self-scheduling), based on their own economic criteria and taking into account

generating unit technical constraints in conjunction with the demand elements they are

balancing with. In real-time, the BRPs acquire balancing instructions (portfolio-based

instructions) by the TSO, which they then distribute to their resources (self-dispatch)

(e.g., in Germany, Switzerland, Austria and Sweden3). Central Dispatch is based on a

dispatch architecture where the TSO considers all balancing resources and the needs

of the system overall, to determine an efficient operational schedule (central

scheduling) and issue optimal dispatch instructions in real-time (central dispatch)

directly to the available resources (e.g. in Italy, Ireland, Poland and Greece and all the

US ISOs). A hybrid model also applies; participants participate with portfolio-bidding

in the FM, DAM and IDM, determine their own schedule position (self-scheduling) and

self-nominate; then, the TSO centrally issues dispatch instructions per entity in real-

1 ENTSO-E, Draft Network Code on Electricity Balancing, Feb. 2013. Available online at:

https://www.entsoe.eu/Documents/Network%20codes%20documents/NC%20EB/Informal_Service_Level_EBGL_16-03-2017_Final.pdf

2 ENTSO-E, Supporting Document for the Network Code on Electricity Balancing, October 2013. Available online at:

:https://www.entsoe.eu/fileadmin/user_upload/_library/resources/BAL/131021_NC_EB_Supporting_Document_2013.pdf

3 ENTSO-E WGAS, Survey on Ancillary services procurement, Balancing market design 2015, May 2016. Available online at:

https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/WGAS%20Survey_04.05.2016_final_publication_v2.pdf?Web=1



https://www.entsoe.eu/fileadmin/user_upload/_library/resources/BAL/131021_NC_EB_Supporting_Document_2013.pdf

https://www.entsoe.eu/fileadmin/user_upload/_library/resources/BAL/131021_NC_EB_Supporting_Document_2013.pdf




time, on the basis of the submitted Nominations (e.g. in France4).

Although most of the energy markets in Europe are based on a Self-Dispatch principle,

the EB NC envisions an efficient integration of Central Dispatch and Self-Dispatch

systems within the integrated Balancing Market in Europe, without jeopardizing the

efficient functioning of Central Dispatch systems. Self-Dispatch provides firmness of

market positions, provided that the interventions of the TSO to maintain system

security are small.

A rigorous treatment of the comparison between Self-Dispatch and Central Dispatch

models is outside the scope of this work, but based on ECCO’s extensive experience

in designing and implementing both over the course of two decades worldwide we can

summarize the debate as follows: Proponents of the Self-Dispatch architecture

claim that this model is the most efficient in the long-term given the freedom it

affords to participants to determine their own dispatch positions, even though

it may result in loss of efficiency in the short-term. We believe that decentralized

designs can overcome to some extent these issues but, in general, suffer

efficiency losses due to the loss of spatial and temporal coordination among

resources. On the other hand, proponents of the Central Dispatch models claim

that this model is the most efficient exactly because of the optimal coordination

and optimization of all system resources by the TSO, the entity which has full

visibility of the system constraints and the generating resources.

The dominant player in Greece (PPC) seeks flexibility in the portfolio-bidding

approach, scheduling and dispatch, due to the short- and medium-term constraints

faced, as follows:

a) lignite units: for better handling of environmental constraints (e.g. constraints on

NOx, SOx emissions of lignite plants, and limited number of working hours from 1st

January 2016 till 31st December 2023);

b) gas units: for better handling of take-or-pay constraints on the gas supply contract;

and,

c) hydro units: for better handling of the hydro reservoir constraints, especially for

cascading units in the same river.

However, given the physical and technical characteristics of the Greek electricity

market (system size, market structure, plant portfolios, RES penetration, etc.), along

with policy objectives (transparency, competition issues, small participants’ aversion

for risk in balancing their positions), ECCO strongly recommends the adoption of the

central scheduling and dispatch market architecture as an important principle to be

4 RTE, Rules relative to Programming, the Balancing Mechanism and Recovery of Balancing Charges, April

2016. Accessed 20.12.16:

http://clients.rte-france.com/htm/an/offre/telecharge/Section_1_Ma_20160706_EN.pdf

http://clients.rte-france.com/htm/an/offre/telecharge/Section_1_Ma_20160706_EN.pdf


maintained in the new market design in Greece. Specifically, we recommend the

Central Dispatch architecture for the following reasons:

1) A self-scheduling scheme would result in participants making decisions on the

basis of their own criteria. This means that, all units would be scheduled to suit

their producers’ preferred profiles with no consideration of the overall system

needs or interactions with system conditions or other generators. On the contrary,

in central scheduling the TSO will have all the information for the entire system to

execute an overall optimal schedule for the generating fleet.

2) With a relatively small number of units and only one major portfolio available (the

PPC portfolio), in the Greek system, the likelihood of system balancing actions

that would require action by the TSO in real-time is greater compared to a larger

system. The degree of intervention required by the TSO is largely due to (a) the

physical attributes of the system, (b) the security constraints that need to be

observed by the TSO in terms of maintaining / engaging the adequate reserves,

c) the availability of one major portfolio, and (c) the engagement of participants. In

general, a Self-Dispatch market causes significantly more concern to the TSOs

due to lack of coordination and visibility of the individual resources by the TSO

[34].

Thus, focusing on the choice of Central Dispatch, the Supporting Document of the EB

NC [32] describes a Central Dispatch process generally consisting of two phases: (a)

the scheduling phase referred to as Integrated Scheduling Process (ISP), and (b) the

Real-Time Balancing Energy Market (RTBEM). Before proceeding with the analysis of

these two phases, the timing of the Reserve Capacity procurement along with the

relevant options for the Greek electricity market is analyzed and presented.

Timing of the Reserve Capacity procurement

There are two options for the timing of the Reserve Capacity procurement: (a) Reserve

Capacity and Balancing Energy can be procured in the same – compulsory for the

balancing resources – scheduling process in the daily timeframe (following the Italian

approach), or (b) explicit auctioning of Reserve Capacity in different timeframes from

year- to week-ahead can be considered. The first option seems to be more familiar

with the current day-ahead procedures in the Greek electricity market (co-optimization

of energy and reserves in the DAM), while the second seems to be more consistent

with the spirit of the Target Model and the EB NC, which promote independent market-

based mechanisms for different standard products (for Reserve Capacity and

Balancing Energy).

This design variable has a large impact on availability of balancing resources and

utilization efficiency, and a very large impact on price efficiency5. Generally, a short

5 R.A.C. Van Der Veen, Designing Multinational Electricity Balancing Markets, PhD thesis, September 2012.

Accessed 20.12.16:

http://repository.tudelft.nl/islandora/object/uuid:e1c5777e-be4c-4df3-a764-

f622c828c709/?collection=research

http://repository.tudelft.nl/islandora/object/uuid:e1c5777e-be4c-4df3-a764-f622c828c709/?collection=research



contracting period for Reserve Capacity appears preferable for efficiency reasons. If it

does not jeopardize the availability of balancing resources, a daily Reserve Capacity

procurement after the DAM clearing appears the best option. Such option is also

preferable for facilitating the participation of RES and demand response resources in

the Reserve Capacity procurement process. The gate closure for Reserve Capacity

offers submission should be as close as possible to the Reserve Capacity

procurement, to enable balancing resources to bid with as much certainty on

availability and prices as possible. A possible combination of the daily market for

Reserve Capacity with a longer-term (month, annual) pre-qualification of services,

guaranteeing the TSO enough reserve potential, can also be considered, although it

may act as an entry barrier for two reasons: a) unavailability of certain resources for

long periods of time and b) potential high administrative costs. However, the main goal

here is to attain simplicity of the overall market procedure (at least in the first stage of

the reformed Greek electricity market), which will serve as a tool for the adaptation of

all involved parties to the new market regime and consequently enhance liquidity. To

this end, a daily Reserve Capacity procurement process shall be implemented,

which will be part of the Integrated Scheduling Process (ISP).

Integrated Scheduling Process (ISP)

The 1st phase of the Central Dispatch process is the Integrated Scheduling Process

(ISP). The ISP shall be performed by the TSO to:

a) allocate various types of Reserve Capacity to the eligible balancing resources,

b) procure upward and downward Balancing Energy for the relief of anticipated

system imbalances6,

c) perform congestion management, and

d) adjust appropriately the resources’ previous market positions, so as to produce a

technically feasible schedule for each resource.

The ISP essentially involves the execution of a unit commitment model and solves a

co-optimization problem of Balancing Energy and Reserve Capacity, which constitutes

a Mixed-Integer Linear Programming (MILP) model with both binary and continuous

variables. A day-ahead scheduling phase (ISP1) shall be executed, followed by two

scheduled respective executions repeated successively in the intraday stage (ISP2 –

ISP3), appropriately coordinated with the respective Intra-Day Market sessions. The

length of the scheduling time unit in the ISP should be as short as possible, in order

to more accurately accommodate (a) sub-hourly resource technical limitations, and (b)

renewable generation and load variability in the scheduling results. A half-hourly

scheduling time unit has been decided for the ISP.

6In the ISP stage, the upward and downward Balancing Energy quantities are proactively scheduled on top of the

latest market positions of the eligible resources, and are not firm and not subject to any resource -TSO

settlement; they are only indicative of the actual Balancing Energy that shall be activated in real-time.


The same offers for ISP1 shall be taken into account also for the following ISPs, (no

new re-bidding process for Reserve Capacity and Balancing Energy during the ISP),

a provision which is similar with the current dispatch scheduling of the Greek TSO.

Despite the three “scheduled” ISP executions, in case a major event takes place

during day D, or even in the afternoon of day D-1, which effects in a major way the

unit scheduling and reserve allocation during day D, the TSO shall be allowed to

execute the ISP problem “on-demand”, in order to derive an updated schedule for the

available resources. The eligible resources to participate in the Greek ISP comprise

the generating units (including auto-producer conventional units), the Demand

Response (DR) resources, and the RES units and portfolios, in case the latter have

the technical capabilities to provide the required balancing services.

Most Reserve Capacity products described in the EB NC and in the draft Commission

Regulation establishing a guideline on electricity transmission system operation7

(including the Load Frequency Control and Reserves Network Code) shall be procured

in the ISP: (a) Frequency Containment Reserve (FCR), (b) Frequency Restoration

Reserve with automatic activation (aFRR) and manual activation (mFRR). Also,

according to Article 19 of the EB NC, the procurement of each type of Reserve

Capacity should be carried out separately in the upward and downward directions.

In the above context, the results of any given ISP execution contain the

following: (a) half-hourly schedules (i.e. preliminary schedules) of all balancing

resources (per entity), (b) commitment decisions and prospective payments for

the start-up costs of the resources, (c) AGC status for the resources providing

aFRR, and (d) Reserve Capacity awards and prices for the settlement of Reserve

Capacity.

Real-Time Balancing Energy Market (RTBEM)

According to the NC EB, the RTBEM shall be a separate market for procuring mFRR

and aFRR Balancing Energy in real-time, balancing supply and demand while

considering all applicable real-time system conditions. There will be two different

processes for the procurement of mFRR Balancing Energy and aFRR Balancing

Energy, namely an “mFRR process” and an “aFRR process”, respectively.

The mFRR process shall be executed every 15 minutes, for the dispatch of the

Balancing Service Providers for the following 15-minute period. The mFRR process

shall not be a unit commitment application, but rather an economic dispatch process

which respects and follows the ISP commitment decisions, unless a relevant resource

suffers a forced outage. In that respect, the mFRR process shall refine the half-hourly

ISP schedules of the dispatchable resources at a more granular level, by activating

upward and downward mFRR Balancing Energy appropriately, to address continuous

changes in the system load, renewable generation and resource availability. The half-

7 Draft Commission Regulation establishing a guideline on electricity transmission system operation. Accessed

20.07.17:

https://ec.europa.eu/energy/sites/ener/files/documents/SystemOperationGuideline%20final%28provisional%2

904052016.pdf

https://ec.europa.eu/energy/sites/ener/files/documents/SystemOperationGuideline%20final%28provisional%2904052016.pdf



hourly schedules of inter-tie resources (imports and exports) shall not be re-dispatched

in the mFRR process, unless due to an outage, as is the current situation.

Moreover, within the spirit of the EB NC and the Target Model itself, the clearing

engine of the mFRR process shall not procure any additional Ancillary Services.

Indeed, (a) the mFRR awards determined in the ISP shall be effectively released

by the eligible resources in the mFRR process, in order to be optimally activated

as Balancing Energy for the relief of the very short-term system forecasted

imbalances, while (b) the FCR and aFRR awards determined in the ISP shall

remain in effect; they shall then be released closer to real-time (i.e. within the

RTBEM dispatch period, e.g. through the operation of AGC for aFRR) to manage

the load and renewable production variability and any unforeseen events taking

place at a more instant timeframe. The decision to release the capacity of the

mFRR awards in the RTBEM market is driven by the objective to ensure

sufficient liquidity in that market.

A15-min time-step shall be applied in the Greek RTBEM, even though higher aFRR

requirements may be needed (as compared to the 5-min time-step). In this context,

the RTBEM shall produce 15-min dispatch instructions for the dispatchable resources.

The various balancing resources in the Greek RTBEM shall be able to update their

Balancing Energy offers (until the RTBEM gate closure) only with “better” prices (as

compared to the respective offers submitted at the ISP), namely with lower offers for

upward Balancing Energy and higher offers for downward Balancing Energy. The

rationale behind this decision is that substantial changes of offers during RTBEM might

lead to sub-optimal dispatch and could expose the TSO and energy consumers to high

costs; knowing in advance some results of the ISP (e.g. start-up decisions),

participants may use this knowledge to abuse market power in the RTBEM (e.g.

submit high bids in the RTBEM knowing that they will be probably cleared upon their

commitment in the ISP). Finally, Producers representing Generating Units that

participate in the RTBEM shall be obligated to submit offers for Balancing Energy

according to their maximum availability, regardless of whether they have been

awarded Reserve Capacity or not during the ISP, so that the TSO has more balancing

options in real-time.

It should be stressed that the above design concerns mainly the introduction of

the internal RTBEM in Greece, since discussions for a common pan-European

RTBEM optimization function have not been finalized yet in Europe. An

adaptation of the internal RTBEM shall be needed when cross-border balancing

is established, as analytically described in this report.

aFRR Balancing Energy is activated using the Automatic Generation Control (AGC)

function of the Transmission System Operator for frequency control as defined in

COMMISSION REGULATION (EU) 2017/1485 of 2 August 2017 establishing a

guideline on electricity transmission system operation. All Balancing Service Entities

with aFRR awards in the latest Integrated Scheduling Process are activated almost

simultaneously by the Transmission System Operator for the provision of aFRR


Balancing Energy. The criteria for the activation of aFRR Balancing Energy include

the aFRR Balancing Energy Offer prices and the ramp-rates of the Balancing Service

Entities.

Phased approach for the Balancing Market in Greece

The new Balancing and Ancillary Services Market in Greece shall be implemented in

two phases, as follows:

1) In the 1st implementation phase, an internal RTBEM in Greece shall be

implemented without cross-border balancing activities with the neighbouring

TSOs. The mFRR process shall be executed locally by the TSO running a Mixed

Integer Linear Programming model that optimizes the balancing cost under system

constraints and technical constraints of the Balancing Service Providers. The

binary variables shall be used solely for the facilitation of minimum acceptance

ratio of mFRR Balancing Energy Offers in the mFRR process. The TSO shall then

send the Dispatch Instructions to the Balancing Service Providers.

The initiation of this phase relates with the 1st phase of the Intra-Day Market

implementation.

2) In the 2nd implementation phase, cross-border balancing activities shall

commence in the Greek RTBEM. The mFRR process shall change, and shall

comprise of two distinct steps: (a) the conversion of mFRR Balancing Energy

offers/bids in order to create a merit order list in each balancing direction (upwards,

downwards) for mFRR, and (b) the clearing of the mFRR process and possibly the

aFRR process in pan-European level, including cross-border transfer of Balancing

Energy. Such scheme shall foster cross-border competition and liquidity, and

avoid undue market fragmentation (in the European control areas).

Settlement of Reserve Capacity

The balancing resources shall be awarded the various types of Reserve Capacity

(upward / downward FCR, aFRR and mFRR) during the ISP executions, however their

remuneration shall be based on the actually provided reserves in real-time. The

remuneration shall be computed per half-hourly interval (in consistency with the ISP

time-step) and should be equal to the product of the Reserve Capacity (availability)

provided in real-time (maybe lower or higher than the reserved capacity in the ISP)

multiplied by the respective Reserve Offer Price of each BSP.

The recovery of the Reserve Capacity costs shall be performed through an uplift

account by the Load Representations pro-rata to their represented demand.

Settlement of Balancing Energy

The mFRR Balancing Energy activated during the mFRR process by a given resource

(instructed deviation) is equal to the difference between the relevant dispatch

instruction issued by the TSO directly to the resource (Central Dispatch) and the

resource’s latest market position. Since the mFRR and the respective instructions


follow a 15-min time-step, the eligible resources shall be compensated for their

activated mFRR Balancing Energy based on the 15-min Balancing Energy Price

derived ex-post based on their activated Offers of the BSPs8. In case of upward mFRR

Balancing Energy, the provider shall receive the product of the activated quantity

multiplied by the upward mFRR Balancing Energy Price, whereas in case of downward

mFRR Balancing Energy, the resource shall return an amount to the TSO, equal to

the product of the activated quantity multiplied by the downward mFRR Balancing

Energy Price.

With regard to the pricing regime, all balancing resources receive one price for the

marginally accepted upward / downward mFRR Balancing Energy offer. This pricing

scheme has the obvious advantage of reflecting costs at the margin and gives better

incentives to bid at marginal costs9. Furthermore, this pricing scheme provides more

encouragement for resources to invest in appropriate generation capacity, and gives

robust price signals and incentives for the development of Demand Response.

It should be noted, though, that the activation of Balancing Energy offers for non-

balancing purposes (e.g. system constraints) shall not define the marginal price and

shall be paid-as-bid. Such provision is consistent with international practices where

zonal network representation applies (e.g. in European markets)10.

The remuneration / charge for each BSE per Imbalance Settlement Period for the

Provided Upward aFRR Balancing Energy shall be calculated as the product of:

a) the Provided Upward aFRR Balancing Energy of the BSE during the Imbalance

Settlement Period, and

b) the maximum of the mFRR Balancing Energy Price and the relevant aFRR

8 In case there is no congestion between the Bidding Zones, the Upward Balancing Energy Price (in €/MWh) for

each Imbalance Settlement Period for upward activation of Balancing Energy is the price of the most expensive

bid of mFRR which has been activated to cover the System Imbalance. In case there is congestion between the

Bidding Zones, the Upward Balancing Energy Price for each Imbalance Settlement Period for upward

activation of Balancing Energy for each Bidding Zone is the price of the most expensive bid of mFRR which

has been activated to cover the Zonal Imbalance of the specific Bidding Zone.

In case there is no congestion between the Bidding Zones, the Downward Balancing Energy Price for each

Imbalance Settlement Period for downward activation of Balancing Energy is the price of the least expensive

bid of mFRR which has been activated to cover the System Imbalance. If there is congestion between the

Bidding Zones, the Downward Balancing Energy Price for each Imbalance Settlement Period for downward

activation of Balancing Energy for each Bidding Zone is the price of the least expensive bid of mFRR, which

has been activated to cover the Zonal Imbalance of the specific bidding zone. 9 A. Weidlich, D. Veit, A critical survey of agent-based wholesale electricity market models, Energy Economics,

Volume 30, Issue 4, July 2008, 1728–1759.

P. Cramton, S. Stoft, Why We Need to Stick with Uniform-Price Auctions in Electricity Markets, The Electricity

Journal, Volume 20, Issue 1, January–February 2007, 26–37. 10 The pay-as-bid principle in this case aims to provide make-whole payments to higher-cost units that are

obligingly committed to contribute to certain system constraints (e.g. voltage control), when the zonal marginal

price (i.e. shadow price obtained by market clearing) does not fully cover their costs. Apparently, this is

irrelevant in the case of nodal markets (like the US markets), where the nodal price fully compensates the

respective costs.


Balancing Energy Offer price of the BSE.

The charge / remuneration for each BSE per Imbalance Settlement Period for the

Provided Downward aFRR Balancing Energy shall be calculated as the product of:

a) the Provided Downward aFRR Balancing Energy of the BSE during the Imbalance


b) the minimum of the mFRR Balancing Energy Price and the relevant aFRR


Imbalance Settlement

The Imbalance Settlement function essentially allocates the balancing costs incurred

to the TSO (when activating Balancing Energy in real-time) to the market (i.e. to the

ones that caused the imbalances). As such, and according to EB NC, the Imbalance

Settlement shall be based on cost-reflective prices (i.e. from a market design point of

view, the imbalance prices shall be “linked” with the marginal prices obtained in the

RTBEM). In brief, and following standard European practices, Balance Responsible

Entities (BREs) with an uninstructed shortage shall pay the short imbalance price to

the TSO, whereas BREs with an uninstructed surplus shall receive the long imbalance

price from the TSO.

There are various possible imbalance pricing options that are compatible with the

above spirit11. Single pricing comes out the pricing regime leading to the lowest actual

imbalance costs for the BREs (but also giving weaker incentives to balance), not

discriminating against small players, and theoretically implying a “zero-sum game” for

the TSO (cost allocation efficiency). However, high system imbalance problems (or

congestion management problems) might put forward the need for a mechanism that

provides stronger incentives for BREs to be balanced. The two-price settlement

mechanism constitutes a good choice to attain the above goals in the Greek electricity

market, and it shall be used for the Imbalance Settlement function in Greece.

With regard to the calculation of the BRE imbalance quantities (uninstructed

deviations), the perimeter for counting such quantities in each Settlement Period shall

be considered per (a) conventional generating unit (including auto-producer

conventional units and units in commissioning operation), (b) Dispatchable Load

Portfolio, (c) Non-Dispatchable Load Portfolio, (e) Dispatchable RES Portfolio, (f) Non-

Dispatchable RES Portfolio, and (g) interconnection for imbalances outside the Greek

TSO's control area (TSO-to-TSO settlement). Apparently, this design variable is

directly related to the applied Central Dispatch model.

Finally, one of the most crucial design variables in Imbalance Settlement is the length

11 R.A.C. Van Der Veen, Designing Multinational Electricity Balancing Markets, PhD thesis, September 2012.

Accessed 20.12.16:

http://repository.tudelft.nl/islandora/object/uuid:e1c5777e-be4c-4df3-a764-

f622c828c709/?collection=research




of the Settlement Period. In order to comply with Article 46 of the EB NC, the

Settlement Period should be 30 minutes or shorter, which is already the case in some

NWE markets (e.g. Belgium has a 15-min Settlement Period12, alongside hourly

settlement in the DAM). The shortest the Settlement Period, the more charges shall

have to be levied on participants operating entities prone to imbalances (e.g. RES,

demand). The trend in European markets is to lower the Settlement Period to 15

minutes13. For this reason, and given that the current metering infrastructure in Greece

can accommodate 15-min measurements (but not less), a quarterly Settlement Period

shall be applied in the Greek electricity market.

The Imbalance Settlement Price (in €/MWh) per Imbalance Settlement Period shall be

calculated as follows:

a) The zonal Upward Imbalance Price upztIP is computed for an Imbalance

Settlement Period t, in which the respective Bidding Zone z was short, as the

weighted average price of all activated upward Balancing Energy quantities

(aFRR and mFRR).

b) The zonal Downward Imbalance Price dnztIP is computed for an Imbalance

Settlement Period t, in which the respective Bidding Zone z was long, as the

weighted average price of all activated downward Balancing Energy quantities

(aFRR and mFRR).

c) The Reference Price ztRP shall be used in an Imbalance Settlement Period t:

(1) for all settlements with the BRPs, if the respective Bidding Zone z is

neutral (neither short nor long), or

(2) for the settlement of any BRP Imbalance, if this Imbalance is in the

opposite direction as compared to the direction of the zonal imbalance,

namely if the BRP Imbalance passively contributed to restore the zonal

balance (“passive balancing”).

The Reference Price ztRP shall be equal to the Day-Ahead Market clearing

price for the corresponding Market Time Unit, namely the Market Time Unit

within which the given Imbalance Settlement Period lies.

The Imbalance pricing regime is presented in the following Table.

12 ENTSO-E WGAS, Survey on Ancillary services procurement, Balancing market design 2015, May 2016. Available online at:


13 ENTSO-E, Public consultation document for the design of the TERRE (Trans European Replacement Reserves Exchange) - Project solution, March 2016. Available online at:

https://consultations.entsoe.eu/markets/terre/





Zonal imbalance

Negative (Short) Zero Positive (Long)

BR

E

Imb

ala

nc

e

Negative (Short) + upztIP + ztRP + max{ up

ztIP , ztRP }

Zero - - -

Positive (Long) -min{ upztIP , ztRP } - ztRP - dn

ztIP

Structure of the Report

Chapter 1 provides a general framework of the Balancing and Ancillary Services

Market as promoted by the Target Model and the Network Code on Electricity

Balancing, and the Balancing Services (Balancing Energy and Ancillary Services)

procurement is briefly discussed. The particular processes that should be

implemented in Central Dispatch systems are also briefly described, including the

solution of an Integrated Scheduling Process (ISP) and a Real-Time Balancing Energy

Market (RTBEM).

Chapter 2 presents in brief the specific features / characteristics of RES units (as

compared to conventional units), which place their participation in the wholesale

market in a different perspective, and presents the categorization of RES units in terms

of market participation taking into account the provisions of the recent Greek Law

4414/2016.

Chapter 3 presents in brief the specific features / characteristics of DR resources (as

compared to conventional units), which place their participation in the wholesale

market in a different perspective, and presents the categorization of DR resources in

terms of market participation.

Chapter 4 presents specific design features in order to facilitate the optimum

integration of RES units and DR resources in the Balancing Market.

Chapter 5 introduces the stakeholders associated with the operation of the Balancing

Market, either participating directly in the market (Balancing Services Providers) or

being responsible for their imbalances (Balance Responsible Parties).

Chapter 6 describes the interface between the Forward, Day-Ahead and Intra-Day

Markets with the Balancing Market.

Chapter 7 presents the Integrated Scheduling Process (ISP), concerning its timing,

the procured products, the provisions for the submission of Offers and Declarations by

the Participants for their Balancing Services Providers, the ISP data, clearing process

and results. Additionally, the analytical problem formulation of the ISP is provided in

this Chapter.

Chapter 8 presents the operation of the Real-Time Balancing Energy Market (RTBEM)

in the new market design in Greece. Additionally, the analytical problem formulation

of the RTBEM is provided in this Chapter. Such RTBEM shall be applicable until the

transition into a common real-time Balancing Market solver in the future, since some

changes / adjustments will need to be implemented thereafter (two-step process,


namely conversion process and clearing), which are also described in this Chapter.

The latter design is closer to the Target Model for the Balancing Market and the

incorporation to a common Balancing Market solver with other European countries

(performing also cross-border balancing).

Chapter 9 presents the settlement of Balancing Energy and Ancillary Services for the

Balancing Services Providers, the Imbalance Settlement and the settlement of

penalties (non-compliance charges) that shall be applied in the new market design in

Greece.

Annex A tabulates the nomenclature of all symbols found in this report.

Annex B describes the dimensioning rules for the provision of Frequency Containment

Reserve, the automatic and the manual Frequency Restoration Reserve.

Finally, Annex C describes the RES Units categorization remunerated under a sliding

Feed-in Premium under the Law 4414/2016.

Page 14 December 2017

1 Introduction

1.1 Importance of Balancing Electricity Markets

Maintaining a real-time balance between electrical power generated and consumed is

essential for safeguarding a power system’s security. Due to the non-storability of

electricity in large scale at the present time, disturbances of the equilibrium between

generation and load cause the system frequency to deviate from its set value. This can

affect the behavior of electrical equipment and - in the case of large deviations - may lead

to protective disconnection of generation units and load, and eventually a system black-

out. Well-known examples of large-scale black-outs in Europe during the previous years

include the one in Italy and Switzerland (28 September 2003) and - at least an almost

black-out - in Central Europe (4 November 2006).

Imbalances between generation and load not only occur because of unforeseen events

like generation or transmission outages, but also because actual real-time deliveries may

differ from market-based committed ones due to uncertainties like weather conditions or

simply due to Participants’ trading behavior. Given their potential implications to the power

system, such deviations must be handled instantly. Imbalances are initially offset by the

kinetic energy of the rotating generating sets and motors connected to the system. The

more generators and motors are directly coupled to the transmission system, the more

kinetic energy the system has and the larger the system’s inertia is. However, regardless

of the size of the system’s inertia, the latter can only slow down and arrest frequency

deviations and is not able to restore the power balance.

The task of restoring the power balance and guaranteeing system security is

entrusted to the Transmission System Operators (TSOs). Since after the

liberalization of the electricity market they do not own any generation assets, the

TSOs are expected to guarantee system reliability by procuring Balancing Services

in the Balancing and Ancillary Services Market, from eligible Balancing Services

Providers (BSPs) that are able to meet the necessary technical requirements to

deliver such services. In order to ensure the widest possible range of BSPs, the

European Network Code on Electricity Balancing does not refer to any specific technology

type; the Balancing Services can be provided by a wide range of potential sources of

Balancing (e.g., conventional thermal and hydro generating units, energy storage,

demand side response and renewable resources), something that also fosters

competition and thus maximizes the social welfare gain.

A well-designed Balancing and Ancillary Services Market is not only important to provide

the TSO with sufficient Balancing Services at all times and at the right places in order to

safeguard secure system operation, but is also essential to ensure an efficient functioning

of the overall electricity market. In fact, the other markets are all “forward markets” that

trade derivative products maturing in real time. Put it differently, providing Participants


with a “last resort” for energy transactions, prices expected to be brought forth by the

Balancing Market are reflected in wholesale prices and consequently affect Participants’

decisions in the forward market timeline. This makes the economic signal conveyed by

the Balancing Market extremely important to the overall market behavior of the

Participants.

1.2 Network Code on Electricity Balancing

The adoption of the European Commission’s “Third Package for Electricity and Gas

Markets” provided the legislative instruments aimed at achieving security of supply and

economic efficiency at a European level through (a) the establishment of ACER, whose

target is to eliminate the cross-border “regulatory gaps”, and (b) the subsequent

establishment of ENTSO-E, whose target is to develop the binding European Network

Codes (following ACER’s guidance) as a harmonized framework of operation for all

European TSOs.

However, while the integration of the remaining electricity markets apart from the

Balancing Market (e.g., Day-ahead and Intraday Markets) is following rather clear target

models (European Regulation 2015/1222), the Balancing Market integration is still is a

state of flux. The Network Code on Electricity Balancing has not yet been finalized as a

European Regulation, and the Target Model itself is a bit vague on important details of

the desirable end state of cross-border Balancing.

1.3 Architecture of the Balancing and Ancillary Services Market under the Target Model

Despite the need for further improvement and clarification of the final design features

regarding the cross-border provision of Balancing Services in Europe, the fundamental

design architecture of the internal (national) European Balancing and Ancillary Services

Market has already been defined. This design architecture is expected to be adopted by

all Member States (thus also Greece), as a starting point to facilitate further integration in

the future. In this Section, we introduce the basic components of such Balancing and

Ancillary Services Market structure, taking into account the special conditions of the

Greek electricity market, and in particular, the principle of Central Dispatch, which is

recognized as an important principle to maintain in the new market design of the BASM.

1.3.1 Balancing and Ancillary Services Market Definition

In accordance to the Network Code on Electricity Balancing, we define the Balancing and

Ancillary Services Market as a market architecture model that establishes a transparent

and market-based Balance Management in a liberalized electricity market. Balance

Management covers all the actions and activities performed by a TSO to ensure the

continuous real-time Balancing of electricity demand and supply in a power system, which

is necessary to safeguard the security of electricity supply. In the Balancing and Ancillary


Services Market promoted by the Network Code on Electricity Balancing, many

institutional provisions are needed for the “public good” of Balance Management:

1) First, the size of the system balances (volume of MW cleared in the Real-Time

Balancing Energy Market) must be limited for reliability purposes, and the TSO

must be able to anticipate system imbalances. As a matter of fact, a high volume

of MW cleared in the Real-Time Balancing Energy Market is an indication of a

flawed market design. This requires the Balancing Market to have an

administrative system of Balance Responsibility and Imbalance Settlement,

where the Participants are responsible for delivering their wholesale energy

schedules, by being penalized for any schedule deviations.

2) Second, even if the above incentives for the Participants to limit individual

imbalances are adequate, deviations will always occur in real time, which shall

eventually be resolved by the TSO. Thus, there must be enough balancing

resources available to the TSO to restore the system balance at all times. This

requires the Balancing and Ancillary Services Market to have a market-based

system of Balancing Services Procurement, where the TSO procures the

required Balancing Services from the market (i.e., from the eligible BSPs); namely

the TSO procures the Balancing Energy needed to cope with real-time imbalances,

and the Reserve Capacity required to ensure a minimum availability of the

balancing resources at all times.

1.3.2 Balancing Services Procurement

The Balancing Services Procurement function is about the provision of Balancing

Services from eligible Balancing Services Providers (BSPs), and the procurement and

dispatch of these services by the TSO within the scope of Balance Management.

Balancing Market

Firstly, the TSO needs to ensure that it will always be able to activate a sufficient amount

of energy to balance the deviations between supply and demand in real time. This defines

the concept of “Balancing Energy”, which is dispatched by means of real-time upward or

downward adjustment of balancing resources in order to resolve the system imbalance.

In general, Balancing Energy can be provided by a wide range of technologies including

small-scale generation, energy storage, demand side response, renewable and

intermittent resources.

In the Balancing Market, the BSPs will typically offer for activation their capacity which

was secured in advance from contracted Reserve Capacity or any residual capacities that

are still available after the closure of all the other wholesale markets. In general, each

offer consists of a volume in MW and a price in €/MWh. More complex product formats

(regarding the Standard Products promoted by ENTSO-E, or the products discussed


within the scope of the TERRE project) may involve additional product attributes to allow

for activation through the central balancing algorithm, such as a minimum offered

quantity, a minimum duration of the delivery period of the requested power, or linked

blocks of Balancing Energy offers.

In any case, Balancing Energy offers are submitted by the BSPs in both directions,

upwards and downwards. Therefore, for each Dispatch Period, at least two bid ladders

can be formed; one for upward and one for downward activation. The TSO will have to

look at the system imbalance and activate the required amount of offers (in the direction

needed) to remove that system imbalance. The Balancing Energy offers are activated

according to economic criteria (the less expensive offers activated first), however also

depending on system conditions (e.g. congestion), and on possible limitations incurred

due to the BSPs’ operating constraints (e.g. ramping constraints) or due to the above-

mentioned product attributes (e.g., minimum delivery period). If there is a power shortage

in the system, the TSO will activate upward offers so that more power is generated in the

system (from generating Entities) and/or less power is withdrawn from the system (from

demand Entities) to resolve the shortage. In case of a power surplus in the system, the

TSO will activate downward offers so that less power is generated in the system (from

generating Entities) and/or more power is consumed in the system (from demand Entities)

to resolve the surplus.

The Balancing Market is cleared for each real-time Dispatch Period, which leads to

Balancing Energy prices (utilization payment) that are paid to successful providers (in

€/MWh/Dispatch Period). As per the adopted compensation methodology in the

Network Code, the selected BSPs shall be compensated by the market price (price

of the marginal Balancing Energy offer). Marginal pricing has the obvious

advantage of reflecting costs at the margin and gives better incentives to bid at

marginal costs. Also, the marginal pricing regime provides more encouragement

for resources to invest in appropriate generation capacity, and gives robust price

signals and incentives for the development of Demand Response (DR). Only out-

of-order Balancing Energy offers (e.g. offers activated due to congestion or BSPs’

technical / operating constraints) shall be compensated based on their offer price

(pay-as-bid principle).

Notably, if downward Balancing Energy is activated to resolve a system surplus, the TSO

shall receive - rather than pay - a revenue. That is, the generating (or demand) Entities

will pay the TSO for the profits they gain because they have to generate less (or consume

more) compared to their wholesale Market Schedules, thus avoiding variable generation

costs (or consuming energy for which they have not previously paid). In any case, the

Balancing Energy prices shall form the proper incentive for BSPs to offer their resources

in the Balancing Market.

Finally, we should mention that the Balancing Market by nature is a real-time market,

since the respective quantities shall be activated as a response to the deviations


occurring in real-time operation, in order to restore the system balance. Under certain

national Balancing Market regimes however, as is the case in Central Dispatch

systems, the TSO may act “proactively” and schedule an amount of Balancing

Energy in advance of real time, namely during the day-ahead or intraday

scheduling process (referred to as the Integrated Scheduling Process), in order to

update the positioning of the various resources and optimally arrange the latest

load and renewable injections forecasts. Such process (Integrated Scheduling

Process) constitutes the main design pillar of the Greek Balancing and Ancillary

Services Market, which shall also consider the Dispatchable RES Portfolios and

the Dispatchable Load Portfolios (additionally to conventional Generating Units) in

the provision of Balancing Services. The Integrated Scheduling Process will be

thoroughly analyzed - along with the functionality of the Real-Time Balancing Energy

Market - in the remaining of this report.

Ancillary Services Market

Furthermore, as the TSO is faced with the risk that it will not have enough Balancing

Energy offers from BSPs to cope with real-time deviations (occurring, for example, due

to forecast errors or unit outages), the TSO shall hedge this uncertainty by securing in

advance a sufficient amount of reserves available in its responsibility area.

An option which gives the TSO the possibility to activate a certain amount of Balancing

Energy within a certain timeframe is referred to as “Reserve Capacity”. It is typically

defined as the available generation or demand capacity which can be activated either

automatically or manually to balance the system in real time. “Balancing Capacity”, as

defined in the Network Code on Electricity Balancing, refers to the contracted part of the

Reserve Capacity. Thus, Balancing Energy in real time can be provided either by the

balancing resources which were secured in advance as Balancing Capacity, or by other

balancing resources that can offer Balancing Energy based on their Availability in real

time.

According to the Network Code on Electricity Balancing, the different types of Reserve

Capacity that shall be secured by the TSO as Balancing Capacity, namely, that shall be

procured in the Ancillary Services Market and maintained for real-time activation, are the

following:

a) Frequency Containment Reserve (FCR),

b) Frequency Restoration Reserve with automatic activation (aFRR),

c) Frequency Restoration Reserve with manual activation (mFRR), and

d) Replacement Reserve (RR).


The above types of Reserve Capacity essentially reflect the successive “layers” of control

that are activated to ensure system security after a disturbance of the balance between

generation and demand. As depicted in Figure 1-1 (from ENTSO-E), these layers of

control are accordingly the:

a) Frequency Containment Process,

b) Automatic Frequency Restoration Process,

c) Manual Frequency Restoration Process, and

d) Reserve Replacement Process.

Strict sequential rules are applied for the deployment and exhaustion times of the

successive layers of control, and the “replenishment” (or releasing) of there spective

reserves, once the next layer takes over. This is because those reserves with the fastest

response time are usually the more valuable and therefore should be replaced by

successively “cheaper” resources. Respective technical specifications can be found on

the draft European Regulation establishing a guideline on electricity transmission system

operation14.

Figure 1-1: Successive “layers” of Reserve Capacity activation (Source: ENTSO-E)

14https://ec.europa.eu/energy/sites/ener/files/documents/SystemOperationGuideline%20final%28provisional%29040

52016.pdf




In this context, the BSPs shall offer their free capacity to the TSO, by submitting offers for

the above types of Reserve Capacity, according to their technical capability to provide

each type of Reserve Capacity.

As stated by the Network Code, the offers for each type of Reserve Capacity shall be

submitted in both directions, upwards and downwards. Each offer consists of a volume in

MW and a price in €/MW. The demand in the Ancillary Services Market is the “reserve

requirement” of the system (determined by the TSO for each type of Reserve Capacity)

which represents the minimum amount of reserves that needs to be available at all times

to ensure system security. Thus, the TSO buys the required amount of Reserve Capacity

in the Ancillary ServicesMarket by selecting the cheapest offers submitted by the BSPs.

The clearing of the Ancillary Services Market results in Reserve Capacity prices

(availability payment), which are paid to successful providers (in €/MW/Dispatch Period).

The selected BSPs shall be compensated by pay-as-bid, according to the respective

practice of many European countries.

Finally, it should be noted that the Ancillary Services Market by nature is rather not a real-

time market, since the respective quantities shall be secured in advance of real time.

Indeed, the Ancillary Services Market in the new market design shall be established as

part of the scheduling process (Integrated Scheduling Process) to be performed by the

Greek TSO at the day-ahead and intraday timeframes, as further discussed in the

following Sections.

1.3.3 Central Dispatch Principle

During the elaboration of the project for the “High Level Market Design for Reorganizing

the Wholesale Market in Greece”, the principle of Central Dispatch was recognized as an

important principle to maintain in the new market design.

In general, Central Dispatch (cf. Self-Dispatch) is a dispatch arrangement where the TSO

considers all balancing resources (BSPs), and the needs of the system overall, to

determine an efficient operational schedule and issue optimal Dispatch Instructions

directly to the available resources. The Network Code on Electricity Balancing visions an

efficient integration of Central-Dispatch and Self-Dispatch systems within the integrated

Balancing Market in Europe, without jeopardizing the efficient functioning of Central

Dispatch systems. In this context, the Code describes a Central Dispatch process

consisting of two phases, as follows:

1. Integrated Scheduling Process

The first phase is the scheduling phase referred to as the Integrated Scheduling Process

(ISP). This phase essentially involves the execution of a unit commitment model at the

day-ahead timeframe (day D-1), followed by a number of respective executions repeated

successively in the intraday stage.


Figure 1-2: Balancing in a Central Dispatch system (Source: ENTSO-E)

More specifically, with reference to the Figure 1-2 (ENTSO-E), the Participants initially

submit for the BSPs their own/represent the Balancing Services bids (Balancing Energy

and Reserve Capacity bids) along with their Techno-Economic Declarations and Non-

Availability Declarations to the TSO, prior to an ISP Gate Closure Time (GCT) at the day-

ahead stage. In parallel, the TSO is notified by the Market Operator about the latest

wholesale Market Schedules of all Entities within its responsibility area (i.e., combined

forward, day-ahead and latest intraday Entity schedules regarding Dispatch Day D).

In the afternoon / evening of day D-1, the TSO takes into account these nominated Entity

Market Schedules (as initial Entity positions) along with all BSP technical and operational

constraints, and together with the Balancing Energy / Reserve Capacity offers and the

latest demand forecast / system conditions, simultaneously optimizes (over the

scheduling horizon of the Dispatch Day D) the following (see first purple text box in Figure

1-2):

a) Balancing Energy. As already discussed, the optimization of Balancing Energy in

the ISP does not concern a “real-time activation” of Balancing Energy. The

incremental / decremental Balancing Energy quantities are rather “scheduled”

(proactively procured) on top of the Market Schedules (initial net positions) of the

eligible BSPs. Such Balancing Energy is intended to resolve the forecasted

imbalances at the time of the ISP execution. The selected Balancing Energy at this

stage is not firm and not subject to any BSP-TSO settlement; it is only indicative of

the actual Balancing Energy that shall be activated in real time. However, it may

affect the commitment decisions of the ISP model (e.g., a proactive procurement


of upward Balancing Energy in the ISP, targeted to cover an increase in the

demand forecast, may result in the commitment of an additional Generating Unit).

b) Reserve Capacity. The required reserve for each type of Reserve Capacity is

procured from the eligible BSPs. The Ancillary Services Market is essentially part

of the ISP.

c) Congestion management of the Transmission System.

As shown in the Figure 1-2, the solution of the ISP model provides preliminary Dispatch

Schedules for all dispatchable Entities (namely the BSPs, e.g. Generating Units),

including synchronization instructions and reserve allocation.

Closer to real-time (namely, in subsequent intraday executions of the ISP) the TSO

makes dispatch corrections which may adjust earlier dispatch indications, to allow for

changes to forecast data and system conditions.

An analytical description and detailed design provisions regarding the ISP (timeframe,

Balancing Services products, Dispatch Period, etc.) are provided in Chapter 7 of this

report. The involved analysis also incorporates provisions regarding the RES and

Demand Response (DR) resources’ participation in the ISP.

2. Real-time phase

In the real-time phase, the TSO essentially operates the Balancing Market. The TSO

eventually activates the Balancing Energy offers needed to balance the real-time

deviations between supply and demand (in the context of cross border balancing in Figure

1-2, the TSO rather engages in economic exchange of Standard Products). This, in turn,

requires a further adjustment to the BSPs’ positions as dispatched by the TSO.

The activated Balancing Energy is now firm and subject to a BSP-TSO settlement,

according to the respective prices produced in the Real-Time Balancing Energy Market

(RTBEM).

An analytical description and detailed design specifications regarding the operation of the

RTBEM in the new market design in Greece are provided in Chapter 8 of this report. The

involved analysis pays special care to the participation of the dispatchable RES and DR

resources in the RTBEM.

1.3.4 Balance Responsibility and Imbalance Settlement

As previously discussed, the latest wholesale Market Schedule of each Entity in the

responsibility area of the TSO is notified to the TSO and considered as binding thereafter,

thereby incurring the Entity’s responsibility for delivering such schedule in real-time

operation (this defines the notion of Balance Responsibility).


The binding nature of the Market Schedules is established by penalizing any schedule

deviations in real time, as follows:

a) The non-dispatchable Entities (e.g., Non-Dispatchable Load Portfolios) are

penalized for their imbalances in real-time operation, which are calculated as the

difference between their real metered quantities and their Market Schedules.

b) The dispatchable Entities acting as BSPs (e.g., Generating Units, Dispatchable

Load Portfolios) receive real-time Dispatch Instructions by the TSO, which

incorporate the Balancing Energy activated over their Market Schedules

(instructed deviations); they are then penalized for their imbalances, which are

calculated as the difference between their real metered quantities and their real-

time Dispatch Instructions (uninstructed deviations).

In this context, all Entities (whether they are BSPs or not) are considered as Balance

Responsible Parties (BRPs), which shall be penalized for their imbalances through an

Imbalance Settlement process.

The Imbalance Settlement essentially allocates the balancing costs incurred to the TSO

(when activating / purchasing Balancing Energy in real time for the relief of imbalances)

to the market (i.e., to the ones that caused the imbalances). For this reason, the

Imbalance Settlement shall be based on cost-reflective prices (i.e., from a market design

point of view, the imbalance prices shall be “linked” with the marginal prices obtained in

the real-time Balancing Market). In brief, BRPs with an uninstructed shortage pay their

short imbalance price to the TSO, whereas BRPs with an uninstructed surplus receive

their long imbalance price from the TSO.

As all final mismatches between planned and actual energy shall be settled with the

imbalance prices, the BRPs will try to be balanced (namely, follow their Market Schedules

/ Dispatch Instructions in real time) to prevent imbalance costs, if they expect those to be

higher than the costs of their balancing efforts. Ideally, the imbalance prices shall provide

adequate incentive for BRPs to limit individual imbalances, allowing for a minimum TSO

intervention to balance the system in real time.

1.3.5 Summary

It becomes clear from the above description, that the main stakeholders in the Balancing

and Ancillary Services Market are the TSO, the BRPs and the BSPs, with the TSO acting

as the central counterparty, both in the Balancing Services Procurement (with the BSPs)

and the Imbalance Settlement (with the BRPs), and guaranteeing an adequate provision

of all types of Balancing Services at all times and to all locations within its area of

responsibility.

Figure 1-3 provides a graphic representation of the basic elements of the Balancing and

Ancillary Services Market described above, and emphasizes the central role of the TSO.


Figure 1-3:Basic elements and interrelations of the Balancing and Ancillary Services Market

TS

O

Balancing

Market (Proactively ISP &

Real time)

BRP

BRP

BSP BSP

Balance Responsibility Balancing Services Procurement Imbalance Settlement

BRP

Cost-reflective

imbalance

pricesAncillary

Services Market (ISP)

BSP BSP

BRP Metered

Data


2 RES Participation in the Balancing and Ancillary Services Market

2.1 Introduction

Conventional power systems have been operated satisfactorily for over a century under

the basic two-level control approach: (i) a local, decentralized droop control which keeps

the system running synchronously even under emergencies, however not optimally, and

(ii) a central control which achieves optimal system operation (and frequency restoration

after disturbances). This hierarchical control structure is designed around conventional

generating units utilizing their inertia and droop characteristics. Future low-carbon power

systems are based on low inertia or inertia-less and droop-less resources, e.g.

Renewable Energy Sources (RES), and cannot take advantage of the natural

synchronizing forces around which the present system control structure was designed.

However, utilizing emerging flexibility resources, such as Demand Response (DR),

Electrical Energy Storage (EES) and Electric Vehicles (EVs), and with the help of power

electronics technology, it is possible to plan and operate the future low-carbon power

system in a similar secure and economic way under the smart grid paradigm. The large-

scale integration of RES and the respective coordination with DR, EES and electric

mobility within a smarter grid operation constitutes a total novelty in the power systems

worldwide, so the respective market arrangements have to be decided “here and now”

for their efficient integration in the future years.

Until now, Renewable Energy Sources (RES) have been treated in Greece as a special

type of market participant due to their non-dispatchable nature and have been

compensated for their final production based on a feed-in-tariff mechanism, dependent

on the RES technology. Although such risk-free subsidization scheme has been widely

deemed as necessary for the entry level of RES technologies in the Greek power system

(but also in other national power systems across Europe), as RES penetration

progressively reaches large scale it is becoming evident that they distort market prices

(giving wrong economic signals to the various market participants) and downgrade market

efficiency. In this respect, the traditional subsidization mechanism approach has recently

drastically changed, in order to ensure a level-playing field for all large generators. Under

the EC State Aid Guidelines for Environmental Protection and Energy15, RES producers

shall be compensated through a market-based mechanism (feed-in-premium scheme)

and they shall be balance responsible (penalized in case that their forecasted power

production is different from their actual generation level). Balance responsibility is a very

strong incentive for optimal participation in the appropriate market sessions, in order to

maximize their market revenues.

15EC State Aid Guidelines for Environmental Protection and Energy. Available online at:

http://eur-lex.europa.eu/legal-content/EL/TXT/?uri=CELEX%3A52014XC0628(01)

http://eur-lex.europa.eu/legal-content/EL/TXT/?uri=CELEX%3A52014XC0628(01)


The European Commission’s guidelines are mandatory and essential for all national

European markets, including the Greek market, and their inclusion in the Greek legislation

has been implemented in the recent Greek Law 4414/2016.

This Chapter takes into account market participation of RES in this context, and provides

specific provisions for RES participation in the new Balancing and Ancillary Services

Market in Greece.

2.2 Specific Features of RES Units

The RES units exhibit specific features / characteristics (as compared to conventional

units), which place their participation in the wholesale market in a different category.

These characteristics include the following:

a) Production uncertainty / variability

The major difference between variable renewable generation and conventional thermal

generation is the additional variability and uncertainty associated with the plant output.

The uncertainty (forecast errors) can be managed with better forecasting and bidding in

the market (especially as real-time approaches), but even if the forecast is perfect, there

is still additional variability that must be managed in real-time. Additional flexibility is

required from the remaining portfolio of plants to maintain schedules and keep the load

and generation balanced under the conditions of higher variability.

b) Portfolio effect

The variability in generation from a single RES unit can be high, but this variability can

smooth out considerably as the level of aggregation increases. As an example, wind

power generation from a single turbine has quite high variation and includes many hours

of zero and full outputs. However, this is not important from the perspective of a power

system, as the output from one wind turbine is miniscule in comparison with the average

power system size. Under normal operation, the output from a wind power plant with

multiple turbines is more stable than the output from a single turbine, as wind gusts are

smoothed out over many wind turbines. Furthermore, wind shade from other turbines and

non-operational turbines decrease the time with full output. It is therefore undisputable

that aggregation of RES plants in terms of participation in the market and balance

responsibility is definitely a key factor for the better integration of these resources in the

Greek power system.

Also, from the perspective of the TSO, it can become challenging and costly to negotiate

with a large number of autonomous decentralized RES units individually. The use of an

intermediate aggregator is one approach to solve effectively restrictions that are caused

by quantity and size. Commercial aggregation of individual decentralized units via ICT

forms a multi-fuel, multi-location and multi-owned power plant in this sense.


c) Energy resource (cf. capacity resource)

Taking into account the uncertain and variable character of the variable RES units (i.e.

wind plants, PV stations), it is obvious that these units can be mainly considered as

energy resources and not so much as capacity resources. The TSOs cannot always count

on their capacity availability and they need backup capacity in order to face the non –

availability events.

However, this does not necessarily exclude dispatchable RES units (and especially

aggregated RES units), such as biomass units, from being considered as reserve

providers in the Ancillary Services Market, in case they bear the respective technical

capability to provide / activate the respective reserve.

d) Non-dispatchable resources

Even though technology has provided solutions for variable RES units to provide

Balancing Energy and Ancillary Services to the system, the full deployment of such

services (provided by RES units) is still far from reality. Nevertheless, the adopted market

design in this document considers the technological advances to come, and includes full

capability of RES units to participate in the markets and provide Balancing Services

(voluntarily) to the power system in the future.

e) Techno-economic characteristics

The techno-economic characteristics of the RES units are quite different from the

conventional units, in terms of the following:

their capability to provide Balancing Energy and Ancillary services (upon existence

of remote control, they could provide downward Balancing Energy, and only in

case of biomass, geothermal and CSP technologies, or in case of variable RES

units with storage – hybrid station, they could be able to provide upward Balancing

Energy),

their ramp rates (e.g. in the provision of downward Balancing Energy to the

system),

their (most probably) zero start-up costs,

their (most probably) zero technical minimum, and

their very-low operation (variable) cost.

f) Subsidized resources

The objective of the European Union (EU) is to increase the share of RES in the electricity


systems. More precisely, the RES Directive 2009/28/EC16 determined binding targets of

20% share of RES in final energy consumption. In order to comply with the European

Directives concerning a de-carbonized energy supply and the integration of RES in the

system, the EU Member States have implemented heterogeneous types of support policy

instruments. There is already considerable experience available with the use of support

schemes, but changing market and commercial conditions requires the continuous

adaptation and reform of the currently applied support schemes. It should be noted that

as the RES penetration levels are increased, the trend of these support schemes is to

assign more and more responsibilities to RES producers by limiting the magnitude of the

subsidy or by setting constraints such as their direct participation in the energy markets.

g) Dispatch Priority (for the RES FiT Portfolio)

Priority dispatch is the obligation on TSOs to schedule and dispatch energy from

renewable producers ahead of the conventional producers due to their nearly zero

marginal cost. The purpose of priority dispatch is to further promote the objective of RES

integration into the electricity system, in order to promote sustainability and security of

supply in the European region. Also, this guaranteed grid access maximizes the use of

energy from RES units and facilitates the achievement of EU RES targets where access

to grid does not suffice for effective integration.

Given the above, RES units need certain special provisions so that their full integration in

the market is not prohibited. Such provisions are discussed in Chapter 4 of this report.

2.3 RES Units Categorization in terms of Market Participation

The categorization of RES Units having concluded a Contract for Differential State-Aid

Support with the RES and CHP Unit Registry Operator is described in Annex C.

Considering these categories of RES units (under Law 4414/2016), the broader RES

groups that can be defined in terms of market participation and which shall be used in the

rest of this report are as follows:

1st group (RES FiT Portfolio): This group includes RES units’ categories 1

(except from case (b) in this category) and 3(a) of Annex C, aggregated on a single

portfolio (RES FiT Portfolio), for which (independently of the remuneration scheme

in each separate case) the TSO (ADMIE) shall be responsible for the injection

forecasting (in all individual markets), LAGIE shall be responsible for the

16 Official Journal of the European Union, Directive 2009/28/EC of the European Parliament and of the Council, 23rd

April 2009. Available online at:

http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32009L0028&from=en

http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32009L0028&from=en


submission of the respective price-taking energy offers in the markets (Day-Ahead

Market and possibly Intra-Day Market), and the TSO shall bear the balance

responsibility (through an uplift account, as already discussed). In terms of

participation in the Balancing and Ancillary Services Market, the units included in

the RES FiT Portfolio group cannot contribute to any type of Reserve Capacity

nor can they be subject to Dispatch Instructions by the TSO in real time.

2nd group (Dispatchable RES Portfolios or Non-Dispatchable RES

Portfolios): This group includes RES units’ categories 1(b), 2, 3(b) (whenever this

provision becomes active), 4, 5 and 6 of Annex C, either on a per-unit basis (RES

Portfolios with only one RES Unit) or aggregated in portfolios (RES Portfolios with

many RES Units), for which (independently of the remuneration scheme in each

separate case) the RES Operators (RES Producers, RES Aggregators or the Last

Resort Aggregator) shall be responsible for the injection forecasting and bidding

in the wholesale markets, and shall bear the foreseen balance responsibility

(either through the TMOFA or through the Imbalance Settlement provisions).

In terms of participation in the Balancing and Ancillary Services Market,

Dispatchable RES Portfolios shall voluntarily contribute to the various types of

Reserve Capacity and shall be subject to Dispatch Instructions by the TSO in real

time (on a per-unit basis for RES Portfolios with only one RES Unit or on a portfolio

basis for RES Portfolios with many RES Units) according to their respective

technical capabilities.

Therefore, in the analysis included in the following Chapters of this report, the above

broader groups of RES units (RES FiT Portfolio, Dispatchable RES Portfolios and Non-

Dispatchable RES Portfolios) shall be taken into account and handled appropriately in

terms of market design rules.


3 Demand Response Participation in the Balancing and Ancillary Services Market

3.1 Introduction

As referred in the previous Chapter, the introduction of DR resources in the Greek

electricity market will assist to provide the essential flexibility for the incorporation of the

RES units in the various segments of the wholesale electricity market, but at the same

time can create also new sources of risk for the existing Participants. For example, the

Load Representatives’ demand forecast (for electricity to be consumed by their

customers) in the Day-Ahead Market may fail.

Some of the customers may actually consume less because of their participation in a DR

event / DR program. In addition, customers may later increase consumption beyond the

level forecasted by their Load Representatives, in order to compensate for the earlier

reduction in consumption. These changes in the consumption pattern may create

imbalance costs for the Load Representatives if the latter are not appropriately informed

and if appropriate market arrangements are not in place. Thus, it is necessary that all

market parties that participate in the electricity market are treated equally with regard to

balancing responsibilities. This means that in order for the DR Aggregators to have

access to the services of the consumers, certain arrangements and rules should be in

place to ensure not only the security of the system, but also fair treatment of all market

parties (including the consumers) and increased competition between the service

providers (Load Representatives and DR Aggregators).

In this Chapter the market participation of DR resources is presented, along with the

specific features of DR resources, the role of DR Aggregators, the contractual

relationships between Load Representatives, DR Aggregators and consumers, along with

the adopted baseline methodology.

3.2 Specific Features of DR Resources

Accordingly, the DR resources exhibit specific features / characteristics (as compared to

conventional Generating Units), which place their participation in the wholesale market in

a different perspective. These characteristics include the following:

a) Decentralized Nature

To a great extent, DR resources involve small individual residential and commercial loads

(such as fans, electric heating and cooling, water boilers, grinders, freezers, etc.) that are

independent and disconnected to each other, concerning a wide variety of loads with

different properties.

In order for each individual resource to be able to offer its load to the system, specific pre-

requirements need to be met to ensure that performance levels fulfill market


requirements. Among others this means that each of these diverse customers need to

possess specific communication / technical infrastructure (hardware and software), in

order to be able to receive signals for load curtailment (from the TSO) as well as metering

capabilities/infrastructure to determine the magnitude of the curtailed load. In addition,

each individual load must ensure that it can provide a minimum size of load to participate

in the market, while it must fully assume of the risks (financial) when unable to perform.

As it may be understood, the aforementioned involves a significant amount of complexity

that small consumers most probably may not manage and thus would choose not to

participate in a DR program initiative. Such barriers to entry for small and medium

individual loads may be tackled through aggregation, the role of which in the success of

DR is deemed pivotal.

b) Consumption pattern rigidities

The essence of DR is a temporary change of consumption pattern in response to market

factors. In contrast to Generating Units whose main function is to produce energy and sell

it in the market, the providers of the DR services are consumers who buy energy in the

retail market in order to run businesses, households etc. As a result, DR resources may

be able to participate only if a small distortion of their consumption patterns is required.

By distortion of consumption pattern we mean four key elements:

Most DR resources may not be available for extended periods of time, thus being

practically excluded from the market in case of extended delivery / availability

periods required (e.g. specific reserves in Germany with availability requirements

of 12 hours, result in non-existent DR participation).

There is also the case that DR resources may not be able to initiate a DR event

unless for a minimum period of time (e.g., 1 hour). This feature resembles the

minimum period of time that some Generating Units require to stay open.

There are often limitations on the period between successive activations of DR

events. For example, a business may not be able to turn off a refrigerator twice

within an hour.

The frequency of activations is critical to the participation of DR resources. Again,

in contrast to Generating Units, DR activations are typically constrained by the

number of load curtailment events that can be called during the course of a day,

week, month or year.

c) Load curtailment uncertainty / Baseline load profiling

One of the most crucial issues regarding the DR activations concerns the accuracy of

load curtailment measurements. The magnitude of a DR event (i.e. the energy curtailed)

is determined as the difference between the electricity that would have been consumed

by the DR event resources, in the absence of the DR event (i.e., the Baseline), and the


actual consumption as a result of the DR event. In other words the Baseline is a measure,

which needs to be accurate, transparent and standardized using an agreed, robust

methodology.

d) Ramp rates

DR resources respond to instructed variations of their load between successive time

intervals with certain ramping capability. Full provision of response of DR resources may

take some time, which resembles the respective ramp rates of the Generating Units.

e) Techno-economic Characteristics

Finally, depending on the type of consumer providing a DR service (industrial,

commercial, residential), corresponding voltage levels are curtailed from the system

depending on the per case requirements and the capabilities of the consumer. That has

two implications for participants: (a) each participant may have a maximum technical

capability to provide a DR service and (b) the cost (and involved opportunity cost) for

providing the service is very much different depending the type of customer, provided that

all remaining factors remain equal (e.g. required time of curtailment, number of

curtailments, etc.).

As with the decentralized nature characteristic of DR resources, such techno-economic

disparities may be smoothed out through the use of aggregators, which have the

capability to pull together loads of different properties and characteristics and provide

them in the market as a single unit.

The above particularities need special attention, in the market design field, so that the DR

resources’ full integration in the market is not prohibited. Corresponding provisions are

discussed in the following Chapters of this report.

3.3 DR Units Categorization in terms of Market Participation

Given their operational and market participation characteristics, DR resources may be

categorized as follows:

1st category: Based on market areas in which DR resources participate for the

purpose of providing Balancing Services.

In this respect, DR resources can participate either in the form of Interruptible

Loads or directly in the Balancing and Ancillary Services Market. The

discriminatory point has to do with the fact that Interruptible Loads (both availability

and utilization) are procured by the TSO ahead of time (e.g. on an annual basis)

and do not participate in the Balancing and Ancillary Services Market (ISP and

RTBEM). In this context, the Interruptible Loads are activated in the event that the

remaining Balancing Services may not cover the real-time system imbalance


needs.

Interruptible Loads concern the simplest / most immature form of DR participation.

According to examples in the rest of Europe, as more market areas become

available for DR integration, Interruptible Loads tend to be partially or fully replaced

by the direct participation of DR resources in the Balancing and Ancillary Services

Market.

2nd category: Dispatchable vs. Non-Dispatchable Load Portfolios

Demand Response loads are considered by default as dispatchable, in the sense

that the load increase or decrease can be performed in real time following a

Dispatch Instruction issued by the TSO, subject to their pre-defined technical

constraints. For this reason, there are no provisions for the participation of Non-

Dispatchable Load Portfolios in DR events.

3rd category: Aggregated vs. Individual Dispatchable Loads

Consumers can offer their load responsiveness to the markets:

a) either individually, in which case they are designated as Dispatchable Load

Portfolios with only one load (represented by a DR Aggregator, which can be

either a third party aggregator, or the Load Representative which assumes the

DR Aggregator’s responsibilities),

b) or aggregatedly with other Dispatchable Loads included in a wider DR Portfolio

represented again by a DR Aggregator. Most consumers do not have the

means to trade directly into the energy markets, because e.g. their individual

loads are too small to qualify for such participation. For this reason, they usually

require service by a DR Aggregator, to help them participate in the electricity

market and offer them a clearly-defined offer, which is both simple to use and

contains clear benefits.

In the following of this report, the above-mentioned groups of DR resources (Dispatchable

Load Portfolios, Non-Dispatchable Load Portfolios) are taken into account and handled

appropriately in terms of market design rules.

3.4 Role of Aggregators in Enabling Market Participation of DR Resources

As already mentioned in the previous Section, consumers may offer their load to the

markets either individually or through a DR Aggregator. The role of the DR Aggregator is

viewed as critical for the participation of DR resources in the markets, since it successfully

handles multiple issues that individual loads face and consequently work as deterring

factors for their participation. More specifically, by aggregating different loads of varying

characteristics, the DR Aggregator manages to:


Minimize the unpredictability of individual dispatchable loads, through

diversification of the load portfolio, treated as a single source. The diversification

of the aggregated loads ensures that the committed capacity will be delivered

even if some individual loads may not be able to perform.

Make the separation of consumers’ voltage level unnecessary, since the technical

characteristics of multiple individuals are grouped together under a single

(equivalent) load and are provided to the electricity system / market as such.

Remove prequalification and testing requirements from “small” consumers that

would otherwise find it difficult to offer their load flexibility to the market; however,

a DR Aggregator’s success is entirely dependent upon the successful

participation of individual dispatchable loads in the respective DR programs.

Provide the required communication / technical infrastructure (hardware and

software), in order to be able to receive signals for load curtailment (from the

TSO) as well as metering capabilities/infrastructure to determine the magnitude

of load curtailed, that would otherwise would have to be possessed by each

individual alone.

As already mentioned, the role of the DR Aggregator can be played by the Load

Representative, however, cases from other EU markets have shown that for the DR

aggregation service to be successful and lead to market growth, the DR service

should be preferably unbundled from the sale of electricity. As such, and in order to

enable the participation of independent aggregation service providers, the relationship

between the Load Representatives, Balancing Responsible Parties (BRPs) and the

independent DR Aggregators must be clearly defined. Standardized processes for

information exchange, transfer of energy, and financial settlement between these parties

constitute a critical requirement, in order to facilitate the smooth functioning of the

electricity markets.

3.5 Contractual Design for the Incorporation of DR Resources in the Greek Electricity Market

Three main business models have been developed at European level, with regard to the

relationships between the DR Aggregators, the consumers, the Load Representatives

and the TSO. Although contractual relationships between the DR Aggregator, the Load

Representative and the consumer fall mostly under the retail electricity market

arrangements, it is necessary to describe some of the features of these relationships so

that the analysis of the optimum integration of the DR resources in the Greek wholesale

electricity market is facilitated. In the following Sections, three models (A, B and C) are

presented in detail and a recommendation is proposed for the model that is more suitable

for implementation in the Greek electricity market.


In all three models, a DR Aggregator enters into a flexibility contract with a consumer.

This contract specifies the relationship between the DR Aggregator and the consumer.

The consumer provides services to the DR Aggregator and is remunerated by the latter

for these services. More specifically, the consumer can be compensated for the

availability of reducing energy consumption in case he is asked to do so. The

compensation could be expressed in €/MW. The consumer can also be compensated for

participation in an actual DR event. For instance, if the DR Aggregator asks the consumer

to reduce consumption and the latter does so, then the consumer can be compensated

proportionally to the energy curtailed, in which case he would receive a payment in

€/MWh. The consumer can also be penalized in case he is asked to participate in a DR

event but fails to do so. In this case the consumer would compensate the DR Aggregator.

Depending on the model followed, the flexibility contract needs to include an agreement

on the Baseline methodology used to determine the energy curtailed (see Section 3.6

below for the adopted Baseline methodology).

The three models are differentiated as follows:

Model A requires a bilateral contract between the DR Aggregator and the Load

Representative for settling the transfer of energy. Essentially, this means that the DR

Aggregator will have access to the services of a consumer only if its Load Representative

agrees so. Models B and C do not require such contract, but are differentiated on whether

the Load Representative bears any imbalance risk due to a DR event. The design of these

three models is presented in the following sub-sections.

3.5.1 Model A: Use of bilateral contracts

In Model A, which is valid for some products in Belgium, the consumer signs a flexibility

contract with a DR Aggregator. In case of a DR event, the consumer is invoiced by his

Load Representative only for the actual energy consumed. A DR Aggregator may bid the

flexibility of the DR resources he represents in the Day-Ahead, Intra-Day or Balancing

Markets; essentially, in such case the DR Aggregator is selling the energy that shall not

be consumed to third parties (Participants) or to the TSO for balancing purposes. The

energy that was bought by the Load Representative to serve his consumers, but was

ultimately not used, is sold by the Load Representative to the DR Aggregator so that the

former avoids the unpredictable Imbalance Prices. For that reason, the Load

Representative and the DR Aggregator enter into a bilateral contract. This contract can

provide a specific methodology that determines the price at which the Load

Representative sells the non-consumed energy to the DR Aggregator.

Finally, in order for the DR Aggregator to be incentivized to participate, the price that the

DR Aggregator is paid by the TSO or the Participants for the non-consumed / curtailed

energy should be higher than the price that the DR Aggregator pays the Load

Representative, as specified in the bilateral contract. Similarly, the Load Representative

is incentivized to enter into the bilateral contract, only if the purchased energy price in the


wholesale market is lower than the price received by the DR Aggregator for the curtailed

energy.

The above arrangements are presented in the following Figure 3-1.

Figure 3-1: Relationships between market parties in model A

The numerical example below allows for a better understanding of the above

relationships.

Settlement Example:

This example illustrates the interaction between all market parties in model A, both in

terms of the traded product and the financial flows. The following assumptions are made:

1) There is one Load Representative, one Generating unit, one DR Aggregator and one

consumer.

2) The Load Representative buys 100 MW for the first hour of the following day in the

Day-Ahead Market. The Load Representative has perfect load forecast.

3) The Day-Ahead Market MCP for the first hour equals 10 €/MWh.

4) There is a flexibility agreement between the consumer and the DR Aggregator.

Compensation of the consumer by the DR Aggregator equals to 1 €/MWh. There is

no availability payment for the services provided by the consumer.


5) Generating Unit failure means that only 80 MWh are produced.

6) Upward Balancing Energy Offer by the DR Aggregator equals to 13 €/MWh and

offered quantity is 20 MWh (assuming that the Balancing Energy Offer is valid for the

whole hour).

7) Compensation of Load Representative by the DR Aggregator is specified in the

bilateral contract and is equal to 11 €/MWh.

8) The Generating Unit does not make a profit in the Day-Ahead Market and the retail

price is equal to the wholesale market price17.

All the physical and cash transactions are summarized in Table 3-1 below.

17 This assumption serves to isolate the effect of the DR event on the financial flows between the market parties.


Generating

unit

Load

Representative Consumer

DR

Aggregator TSO

Cleared day-ahead schedule -100 MWh 100 MWh

Day-Ahead Market MCP equals 10

€/MWh 1000 € -1000 €

Actual generation is 80 MWh. Variable

generation cost equal to 10 €/MWh -800 €

The TSO buys 20 MW in the Balancing

Market by the DR Aggregator -20 MWh 20 MWh

Upward Balancing Energy price equals

13 €/MWh 260 € -260 €

Consumer curtails consumption by 20

MW. Actual delivery of energy equals

80 MWh

-80 MWh 80 MWh

Consumer is billed by the Load

Representative for the Energy

consumed at 10 €/MWh

800 € -800 €

DR Aggregator buys 20 MWh by the

Load Representative -20 MWh 20 MWh

Price specified in the bilateral contract

between the DR Aggregator and the

Load Representative equals 11 €/ MWh

220 € -220 €

DR Aggregator compensates the

consumer for the services provided at 1

€/ MWh

20 € -20 €

Generating Unit is penalized by the

TSO at an Imbalance Price equal to 13

€/MWh

-260 € 260 €

Net financial position -60 € 20 € 20 € 20€ 0 €

Table 3-1: Settlement Example of model A

According to the assumptions, the Load Representative buys 100 MWh from the

Generating Unit and compensates the Generating Unit with 1000 €. Due to a failure of

the Generating Unit, the latter generates only 80MWh. The TSO activates the available


Upward Balancing Energy Offer of the DR Aggregator entirely. Therefore, the DR

Aggregator is compensated 260 € for the 20 MWh of upward Balancing Energy provided.

In order to provide the upward Balancing Energy, the DR Aggregator instructs the

consumer to reduce consumption by 20 MWh. The consumer does so successfully and

the DR Aggregator pays the consumer 20 € for this service. The consumer has consumed

only 80 MWh and pays 800 € to the Load Representative. The Load Representative sells

to the DR Aggregator the part of the energy that was bought in the Day-Ahead Market,

but that was not sold to the consumer. Depending on the terms of the bilateral contract

between the DR Aggregator and the Load Representative, the former needs to

remunerate the latter for the sold energy. Under the assumptions of this example, this

compensation amounts to 220 €. Finally, the TSO penalizes the Generating Unit through

the Imbalance Settlement process. In order for the TSO to be financially balanced, the

TSO charges the Generating Unit 260 €.

After all settlements take place, the consumer has a profit of 20 € for the curtailed energy

(20 MWh). The DR Aggregator has received 260 € from the TSO, has paid 220€ to the

Load Representative and has paid 20 € to the consumer, which leaves him with 20 €

profit. The Load Representative has made by assumption no profit from the energy sold

to the consumer. However, he paid in the Day-Ahead Market 200 € for energy not

consumed by his customer and sold this energy to the DR Aggregator for 220 €. As a

result the Load Representative has made a profit of 20 €. The Generating Unit has already

been paid 200 € in the Day-Ahead Market for the energy that failed to deliver to the Load

Representative, but has also paid 260 € to the TSO for that imbalance through the

Imbalance Settlement process. Therefore, the Generating Unit has made a loss of 60 €

which has been distributed (in this example) as a profit equally to the consumer, the DR

Aggregator and the Load Representative.

Since the DR Aggregators must enter into a bilateral contract with the Load

Representatives in order to have access to the services of the consumers, the Load

Representatives could secure very high prices, which would limit participation of

independent DR Aggregators and as a result competition. Furthermore, a Load

Representative can refuse to sign any contract with independent DR Aggregators, which

essentially means that only the Load Representative himself can take advantage of the

flexibility of the consumers. This effect can be mitigated by the fact that some consumers

may opt to switch to Load Representatives that are more willing to enter into bilateral

contracts with independent DR Aggregators.

Thus, although the presence of the bilateral contract protects the Load Representatives

from potential imbalances, as the DR Aggregator is required to buy the curtailed energy

from the Load Representative, it also hinders competition by giving the opportunity to the

Load Representatives to secure a monopoly on the potential flexibility of their customers.

This issue is mitigated in models B and C.


3.5.2 Model B: Settlement Through Regulated Prices

In model B, there is no need for a bilateral agreement between the DR Aggregator and

the Load Representative. The price at which the Load Representative is compensated by

the DR Aggregator is regulated by a separate entity. The TSO can assume such a role.

For example, model B is used for some products in France where, depending on the case

/ season, the regulated prices range between 28.06 €/MWh and 60.86 €/MWh. As a result,

there are fewer entry barriers for the DR Aggregators, who can enter into flexibility

contracts with the consumers without prior agreement of the Load Representatives. As in

model A, the consumer is still invoiced only for the energy consumed. The Load

Representative sells the part of the energy that was not consumed to the DR Aggregator.

The product and financial flows are not differentiated in this model compared to model A,

and therefore the numerical example of model A is also representative of model B with

the exception that the price paid by the DR Aggregator to the Load Representative is not

specified in a bilateral contract but is regulated by a separated entity.


Figure 3-2: Relationships between entities in model B

Although this arrangement is more beneficial for the participation of the DR Resources

(as compared to model A), the Load Representatives will still be hostile to the entry of

independent DR Aggregators in the electricity market, because they still face some of the

risk of any imbalance that is created by the reduction in demand by the consumer. More


specifically, a Load Representative has purchased energy that was not paid by his

customers. An issue arises if the Load Representative is not sufficiently remunerated for

this amount of energy, which induces financial risk. For example, the DR Aggregator is

likely to participate in the market when wholesale prices are high. If the regulated price is

relatively low, then the DR Aggregator has a high profit. Similarly, the Load

Representative may purchase expensive energy in the wholesale market, but he may be

compensated at a lower regulated price.

This issue is solved only when the Load Representative is compensated entirely by the

consumer for the perfectly forecasted quantity that was curtailed. This leads to model C

in the following Section.

3.5.3 Model C: Assumption of Market Risk Entirely by DR Aggregator

In model C, there are no products or financial flows between the DR Aggregator and the

Load Representative. The consumer is invoiced by the Load Representative both for the

energy consumed and for the energy that was curtailed due to a DR event. In this way,

the Load Representative’s imbalance is settled directly. The TSO is notified on the part

of the energy that the Load Representative directly sold to the consumer and the part of

the energy that was curtailed by the DR Aggregator. In this way, the TSO considers the

Load Representative balanced. The Load Representative faces no imbalance or financial

risk. The consumer is compensated by the DR Aggregator for the previously invoiced but

not consumed energy, as well as for the provided service of load curtailment. Such

arrangements fall again under the flexibility contract between the DR Aggregator and the

consumer. As in models A and B, the DR Aggregator is paid for the curtailed energy in

accordance to the wholesale market clearing process.



Figure 3-3: Relationships between market parties in model C

The numerical example below allows for a better understanding of the above

relationships.

Settlement example:

The example below illustrates the interaction between all the parties both in terms of

traded product and financial flows. The following assumptions are made, which are similar

to those in the settlement example of model A:

1) There is one Load Representative, one Generating unit, one DR Aggregator and one

consumer.

2) Load Representative buys 100 MW for the first hour of the following day in the Day-

Ahead Market. Load Representative has perfect load forecast.

3) Day-Ahead SMP for the first hour equals 10 €/MWh.

4) There is a flexibility agreement between the consumer and the DR Aggregator.

Compensation of the consumer by the DR Aggregator equals to an amount equal to


the price paid by the consumer to the Load Representative plus a mark-up to

incentivize the consumer to sell part of the energy bought to the DR Aggregator

through load curtailment. Assume that the total price is 11 €/MWh for the energy sold.

There is no availability payment for the services provided by the consumer.

5) Generating Unit failure means that only 80 MWh are produced.

6) Upward Balancing Energy Offer by the DR Aggregator equals to 13 €/MWh and

offered quantity is 20 MWh (again, assuming that the Balancing Energy Offer is valid

for the whole hour).

7) As in model A, the Generating Unit does not make profit in the Day-Ahead Market

and the retail price is equal to the wholesale market price.

All the interactions are summarized in Table 3-2 below.

Generating

Unit

Load

Representative Consumer

DR

Aggregator TSO

Cleared day-ahead schedule -100 MWh 100 MWh

Day-Ahead Market MCP equals 10

€/MWh 1000 € -1000 €

Actual generation is 80 MWh.

Variable generation cost equal to 10

€/MWh

-800 €

The TSO buys 20 MWh in the

Balancing Market by the DR

Aggregator

-20 MWh 20 MWh

Upward Balancing Energy price

equals 13 €/MWh 260 € -260 €

Consumer curtails consumption by

20 MWh. Actual delivery of energy

equals 80 MWh

-80 MWh 80 MWh

Consumer is billed by the Load

Representative for the Energy

forecasted at 10 €/MWh

1000 € -1000 €

DR Aggregator buys 20 MWh by the

consumer. Essentially, bought

Energy is transferred through the

consumer to the DR Aggregator

-20 MWh 20 MWh

-20MWh 20 MWh


DR Aggregator compensates the

consumer for the energy transferred

to him at 11 €/ MWh

220 € -220 €

Generating Unit is penalized by the

TSO at an Imbalance Price equal to

13 €/MWh

-260 € 260 €

Net Financial Position -60 € 0 € 20 € 40 € 0 €

Table 3-2: Settlement Example of model C

In model C, the Load Representative does not interact with the DR Aggregator. There is

only information exchange between them, as the DR Aggregator informs the Load

Representative that his customer participated in a DR event and that otherwise

consumption would have been different based on the agreed Baseline methodology.

Therefore, the Load Representative does not face any risk. This also implies that the Load

Representative will not make any profit or loss due to a DR event, as shown in the

example above. The profit will be distributed between the DR Aggregator and the

consumer depending on their negotiating power in the flexibility contracts.

As already discussed, models B, C allow greater participation of independent DR

Aggregators in the Greek Electricity Market compared to model A. Moreover, model C

removes the financial risk from the Load Representative since the latter is compensated

only by the consumer and is never imbalanced financially or otherwise. The DR

Aggregator assumes all of the risk, which is shared with the consumers based on the

flexibility contracts.

Therefore, the contractual relationships between all the market parties shall be formed

according to model C.

3.6 Baseline Methodology

As it was already mentioned above, one of the most crucial issues regarding the DR

activations concerns the accuracy of load curtailment measurements. The magnitude of

a DR event (i.e. the energy curtailed) is determined as the difference between the

electricity that would have been consumed by the DR event resources, in the absence of

the DR event (i.e., the Baseline), and the actual consumption as a result of the DR event.

In other words the Baseline is a “theoretical” measure, which needs to be accurate,

transparent and standardized using an agreed, robust methodology.

There are numerous methodologies currently used in different markets that provide robust

calculations, and as such, it is not necessary to reinvent the wheel when implementing

DR into the Greek market design. A “10-in-10” adjusted methodology shall be

adopted for the calculation of the Baseline by the TSO. According to this


methodology, a consumer's Baseline shall be calculated as the average of that

consumer's energy use during the 10 previous non-event days of similar load profile. The

Baseline is further adjusted to compensate for possible artificial inflation of a customer’s

usage prior to the execution of a DR event. The so-called "default morning-of adjustment”

foresees the up or down adjustment of the calculated average in accordance to the

customer's usage in the four hours immediately before the event. In any case, the

robustness of the Baseline calculation methodology should be tested against normal

meter data (i.e. meter data of loads not involved in DR events), and adjustments should

be made appropriately.

Figure 3-4: Indicative Baseline during load curtailment

3.7 Gradual Participation of DR Resources in the Different Areas of the Greek Wholesale Market

The EU Demand Response Market is still in the early development phase and variations

are observed in its implementation and progress in each Member State. At its simplest

form customer participation is being provided only in the form of Interruptible Loads,

isolated from any other Market Area, this is the case in year 2017 for Greece as well as

for Italy and Spain. In more advanced models, Demand Resources are also available in

the Balancing Market, in the form of Balancing and Ancillary Services, while finally in

mature models customer flexibility is also open in the rest of the wholesale market

segments, again with varying levels of integration.


As more Market Areas become available for DR products, Interruptible Loads tend to be

partially or fully replaced.

Such gradual adoption of DR resources shall take place in the Greek Market as well.

Initially, DR resources may be allowed to participate in the Balancing and Ancillary

Services Market, in parallel to Interruptibility Contracts. As DR resources are well

established in the specific market and certain levels of maturity are reached, gradually,

the remaining wholesale markets should become available for DR.


4 Optimum Integration of RES Units and DR Resources in the Balancing and Ancillary Services Market

In this Paragraph, some general guidelines are provided on the detailed design of the

Balancing and Ancillary Services Market under the new market structure in Greece, in

order to facilitate the optimum integration of RES units and DR resources in this market.

1st design variable: Formation of RES and DR Aggregators

RES / DR operators shall be allowed to form RES / DR Aggregators, which shall be able

to handle RES plants of different technologies / DR resources as an aggregated portfolio

in all markets, namely they shall be able to forecast, bid in all markets and be balance

responsible for the whole portfolio as one RES / DR Entity (i.e., the RES / DR Portfolio).

Additionally, the TSO shall take over the representation of the RES FiT Portfolio, namely

the TSO shall be responsible for the forecasting, bidding and balancing of its represented

portfolio per RES category and per Bidding Zone. The balancing cost may afterwards be

distributed pro-rata to all suppliers, through an uplift account.

2nd design variable: Significant technological upgrades by RES Operators

An increased market participation of RES units in all constituent markets of the wholesale

electricity market, and mainly in the Balancing and Ancillary Services Market:

may be easier for “controllable” RES units (e.g. small hydros with a reservoir,

biomass units, or small co-generation units), which -for instance- shall be able to

incorporate a controller in order to get connected with the Control Center of the TSO

for providing aFRR (namely operating under Automatic Generation Control - AGC),

or in order to contribute to upward and downward mFRR and the deployment of such

reserve(s) in real-time following a Dispatch Instruction; however,

it requires significant technological upgrades before “non-controllable” RES units

(e.g. wind plants without storage) can participate in the Balancing and Ancillary

Services Market. Such upgrades shall include the use of synthetic inertia of wind

plants for providing FCR, and/or the incorporation of controllers in RES units in order

to get connected with the Control Center of the TSO for providing aFRR.

3rd design variable: Voluntary participation in the Balancing Energy Market

The Participants representing the RES units and the DR resources shall be able to submit

Balancing Energy Offers and consequently provide Balancing Energy in real-time on a

voluntary basis, according to their respective technical capabilities.An obligatory

participation based on the maximum availability of these resources (similar to the one

applying for conventional Generating Units) would be expected to prove a major entry


barrier for RES units and DR resources in this market. The voluntary submission of

Balancing Energy Offers during the ISP and the RTBEM is further discussed in Section 8

of this report.

4th design variable: Voluntary participation in the Ancillary Services Market

Additionally, the Participants representing the RES units and the DR resources shall be

able to submit Reserve Capacity Offers on a voluntary basis, according to their respective

technical capabilities. An obligatory participation based on the maximum availability of

these resources (similar to the one applying for conventional Generating Units) would be

again expected to prove an entry barrier for these resources in the Ancillary Services

Market. The voluntary submission of Reserve Capacity Offers during the ISP is further

discussed in Section 7 of this report.

It is expected that the participation of RES units (depending on their technical capability)

and DR resources shall first take place in tertiary control (mFRR), then in the provision of

aFRR (operation in AGC mode, after connection to the Control Center), and shall be

afterwards enhanced by utilizing the technologies of synthetic inertia of wind plants in the

provision of FCR.

5th design variable: Daily procurement of Ancillary Services

There are two options for the timing of the Ancillary Services procurement:

a) Reserve Capacity and Balancing Energy can be procured in the same scheduling

process in the daily timeframe (following the Italian approach), or

b) explicit auctioning of the Ancillary Services in different timeframes from year- to

week-ahead can be considered (following respective approaches of markets in the

North Western European (NWE) region).

The first option seems to be more familiar with the current day-ahead procedures in the

Greek electricity market (co-optimization of energy and reserves in the Day-Ahead

Market), while the second seems to be more consistent with the spirit of Network Code

on Electricity Balancing, which promotes independent market-based mechanisms for

different standard products (for Reserve Capacity and Balancing Energy).

This design variable has a large impact on availability of BSPs and utilization efficiency,

and a very large impact on price efficiency. Generally, a short contracting period for

Reserve Capacity appears preferable for efficiency reasons. If it does not jeopardize the

availability of BSPs, a daily Reserve Capacity procurement after the Day-Ahead Market

clearing appears the best option. Such option is also preferable for facilitating the

participation of RES units and DR resources in the Ancillary Services Market. The gate

closure for Reserve Capacity Offers submission must be as close as possible to the

Ancillary Services Market clearing, to enable BSPs to bid with as much certainty on

availability and prices as possible. A possible combination of the daily market for the


Ancillary Services with a longer-term (month, annual) pre-qualification of services,

guaranteeing the TSO enough reserve potential, can also be considered, although it may

act as an entry barrier in case of high administrative costs. However, the main target here

is to attain simplicity of the overall market procedure, which will serve as a tool for the

adaptation of all involved parties to the new market regime and consequently enhance

liquidity. To this end, a daily Ancillary Services Market shall be applied as part of the

Integrated Scheduling Process (ISP),as analytically described in the following Chapters.

6th design variable: Duration and timing between events for DR resources

As already discussed, in contrast to Generating Units, for DR resources the duration of a

required / instructed event (e.g. provision of Balancing Energy) must usually be short.

Most DR resources may not be available for extended periods of time, thus being

practically excluded from the market in case of extended delivery / availability periods

required (e.g. specific reserves in Germany with availability requirements of 12 hours,

result in non-existent DR participation). Analysis of experiences and best practices with

the integration of DR resources in European electricity market has shown that DR

resources will be greatly engaged when the requirement (if any) does not exceed 4 hours.

In any case, no such minimum delivery / availability period requirement shall be imposed

by the Greek TSO, neither in the procurement of Balancing Energy nor in the contribution

to any type of Reserve Capacity by the BSPs (other than the time-step of the respective

clearing procedures), thereby facilitating the maximum integration of DR resources in the

market.

On the contrary, the Participants (representing the DR resources) shall have the ability to

submit a maximum delivery period for the provision of Balancing Energy (as part of their

Declared Characteristics), so as to limit the relevant event durations in the ISP and the

RTBEM according to their own “willingness”.

There is also the case that DR resources may not be able to initiate a DR event unless

for a minimum period of time (e.g., 1 hour). In this case, the Participants (representing the

DR resources) shall also have the ability to submit a minimum delivery period for the

provision of Balancing Energy (as part of their Declared Characteristics) (like the

minimum up time constraint), so as to set a lower threshold on the relevant event duration

in the ISP and the RTBEM.

Further, there are often limitations on the period between successive activations of DR

events. In this respect, the longer the period between consecutive activations, the greater

the participation of DR resources. The Participants (representing the DR resources) shall

have the ability to submit a corresponding minimum baseload period (as part of their

Declared Characteristics), namely a minimum period between two successive activations

of Balancing Energy (like the minimum down time constraint).

In correlation to events’ durations, the frequency of activations is critical to the

participation of DR resources. Again, in contrast to Generating Units, DR activations are

typically constrained by the number of load curtailment events that can be called during


the course of a day, week, month or year. In this respect, the fewer the requests for

activation, the greater the participation of DR resources. The Participants (representing

the DR resources) shall have the ability to submit a corresponding maximum frequency

of activations for the provision of Balancing Energy in the course of a day (as part of their

Declared Characteristics).

Further, there are often pre-defined limitations on the window of hours of the day during

which the events can be called, and sometimes even on the number of days in a row that

an event may be called. These limitations shall be taken into account by the Participants

(representing the DR resources) themselves, when bidding either in the Day-Ahead and

Intra-Day Market or participating voluntarily in the Balancing and Ancillary Services

Market.

The above characteristics should be combined with correspondingly low minimum bid

requirements, either in the Day-Ahead and Intra-Day Market or in the Balancing and

Ancillary Services Market. That is, if the minimum bid requirements are kept relatively

high, stand-alone units may not be able to meet them over the event duration period,

while DR Aggregators (as described in the 1st design variable) may require to pool a

significant number of individual dispatchable loads.

Provisions regarding the maximum delivery period, the minimum DR event duration, the

minimum period between successive DR events, and the maximum frequency of

activations constraints are taken into account in the ISP clearing algorithm in Chapter 7.

7th design variable: Low minimum capacity requirement in the Balancing and


The minimum capacity requirement for participation in the Balancing and Ancillary

Services Market shall be small enough (e.g. 1 MW), in order to facilitate the integration of

smaller RES units and DR resources in this market.

8th design variable: Low minimum bid sizes in the Balancing and Ancillary

Services Market

The minimum bid sizes for Balancing Energy and Ancillary Services shall be small enough

(e.g. 1 MW), so as to facilitate the lower offering capabilities of RES units and DR

resources for Balancing Services in the Balancing and Ancillary Services Market.

9th design variable: Marginal pricing in the Real-Time Balancing Energy Market

(RTBEM)

With regard to the pricing regime in the RTBEM, marginal and pay-as-bid pricing are the

two possible options. The former ensures that all BSPs receive the price for the marginally

accepted upward / downward Balancing Energy offer, whereas the latter implies that

BSPs are remunerated based on their own offer prices. Marginal pricing has the obvious

advantage of reflecting costs at the margin and gives better incentives to bid at marginal


costs. Furthermore, marginal pricing provides more encouragement for resources to

invest in appropriate generation capacity (including RES capacity), and gives robust price

signals and incentives for the development of DR. In view of the above mentioned

advantages and taking into account that the marginal pricing regime is clearly promoted

by the Network Code on Electricity Balancing, this pricing scheme shall beapplied in the

Greek RTBEM.

It should be noted, though, that the activation of Balancing Energy offers for non-

balancing purposes (e.g. system constraints) shall not define the marginal price and shall

be paid-as-bid. Such provision is consistent with international practices.

10th design variable: RES curtailments in real-time

RES curtailments in real-time (i.e., in the RTBEM clearing engine) shall be allowed not

only for security reasons, but also for economic reasons (upon a decision of the TSO,

who shall issue the respective Dispatch Instruction). In such case, the curtailed RES units

shall be remunerated with the downward Balancing Energy marginal price obtained in the

RTBEM (or pay-as-bid in specific cases), as further discussed in Chapter 8 of this report.

11th design variable: Decentralized dispatch for RES units and DR resources

The large-scale RES and DR penetration can be facilitated with decentralized dispatch

arrangements, namely individual RES units or DR resources to receive Dispatch

Instructions by their respective RES Aggregators or DR Aggregators, which in turn

receive portfolio-based Dispatch Instructions (i.e., for the whole portfolio) in real-time by

the TSO. This is the current dispatch scheme in some North Western European (NWE)

markets, with a significant share of RES in the overall production portfolio, and this

arrangement shall also be applied in the Greek electricity market (i.e. for the RES and DR

Portfolios).

12th design variable: 15-min Imbalance Settlement Period

A 15-min Imbalance Settlement Period shall be utilized in the Imbalance Settlement

process with the BRPs, which is the current trend in European markets, but is also

mandated by the existing metering infrastructure in HV and MV in Greece. This is also

appropriate in terms of market design and cost allocation efficiency (between the costs

incurred to the TSO when activating Balancing Energy in the RTBEM and the costs

allocated by the TSO to the BRPs for the respective imbalances in the Imbalance

Settlement process), since a 15-min time-step shall also be used when activating

Balancing Energy in the new RTBEM; in this way, no averaging of prices shall be

implemented for Imbalance Settlement purposes, as would be the case if a 5-min time-

step would be utilized in the RTBEM while a 15-min Imbalance Settlement period would

be considered instead.


It is also noted, that the shorter the length of the Imbalance Settlement Period, the more

imbalance charges are expected to be levied on Entities prone to imbalances, like RES

and demand. Thus, the quarterly (e.g. instead of 5-min) Imbalance Settlement Period

provisioned in this report constitutes a measure that is expected to facilitate the

integration of resources like RES and DR in the Greek electricity market.

13th design variable: Portfolio-based perimeter for the calculation of imbalances

The portfolio-based balance responsibility for aggregated RES units or aggregated DR

resources is in line with the standard practice in most European markets. Portfolio-based

balance responsibility provides the ability to the RES Aggregator or the DR Aggregator

acting as a Balance Responsible Party (BRP) to net the imbalances caused by different

RES plants / technologies or DR resources, within a single portfolio. Thus, it leads to

lower incurred imbalance costs to the RES or DR Aggregators and consequently to the

RES or DR resource owners.

The portfolio-based perimeter shall not be active for the conventional Generating Units,

but it shall be active (a) aggregately for the RES units per RES category within a portfolio

and (b) aggregately for the DR resources within a portfolio. Such portfolio-based

perimeter for the calculation of imbalances for the RES and DR Portfolios, but also for the

RES FiT Portfolio, is presented for the Greek Imbalance Settlement process in Chapter

9.

14th design variable: Tolerances in the calculation of the Imbalance Settlement

credits/debits, the imposition of penalties for significant imbalances, and the

imposition of penalties concerning non-delivery of Balancing Energy

Until the milestone of attaining a satisfactorily liquid Intra-Day Market:

In case of tolerances in the calculation of the Imbalance Settlement credits/debits,

such tolerances for the imbalances of RES units and DR resources shall be higher

than the respective tolerances of conventional units.

In case there are no tolerances in the calculation of the Imbalance Settlement

credits/debits, but there are tolerances in the imposition of penalties for significant

imbalances, then such tolerances for the imbalances of RES units and DR

resources shall be higher than the respective tolerances of conventional units.

When a satisfactorily liquid Intra-Day Market is established (based on appropriate

indicators, such as the traded consumption in the Intra-Day Market with respect to the

total traded consumption in all markets), all resources (either conventional or RES, or DR

resources) shall be subject to the same regulatory provisions concerning Imbalance

Settlement and penalties.

Finally, when RES units and DR resources acquire the technical capability to provide

Balancing Energy, and declare such capability in their Techno-economic Declarations to


the TSO, they shall be subject to the same penalties as conventional units concerning the

non-delivery of Balancing Energy by RES units in real-time.

15th design variable: Specific characteristics regarding the procurement and

activation of Ancillary Services

With respect to the procurement and activation of Ancillary Services, additional market

design features of the reformed Greek electricity market are provided in the following

Table 4-1.

It should be noted that currently there is no provision in Greece for the procurement (in

the ISP) and activation (in the RTBEM) of RR (having a Full Activation Time of 30 minutes

prior to the respective delivery period according to the TERRE project18).

18 ENTSO-E, Public consultation document for the design of the TERRE (Trans European Replacement Reserves

Exchange) – Project solution, March 2016. Available online at: https://consultations.entsoe.eu/markets/terre/



Market design

variable

Frequency

Containment Reserve

(FCR)

automatic Frequency

Restoration Reserve

(aFRR)

manual Frequency

Restoration Reserve

(mFRR)

Procured product Capacity

Capacity& energy

separately(ISP and AGC,

respectively)

Capacity& energy

separately(ISP and

RTBEM, respectively)

Possible Providers

Generating Units, RES

Units, RES Portfolios,

storage units, DR

resources



pumping storage units,

DR resources



pumping storage units,

DR resources

Capacity procurement

scheme

Organized market

(ISP)

Organized market

(ISP)

Organized market

(ISP)

Capacity minimum bid

size (MW) 1 MW 1 MW 1 MW

Capacity product

resolution (in time)

30 min

(ISP time-step)

30 min

(ISP time-step)

30 min

(ISP time-step)

Gate closure for

capacity bids 16:30 D-1 16:30 D-1 16:30 D-1

Product differentiation

(up/down) Asymmetrical Asymmetrical Asymmetrical

Capacity settlement

rule Pay-as-bid Pay-as-bid Pay-as-bid

Energy product

resolution (time) - 1 h in ISP

1 h in ISP

15 min in RTBEM

Energy minimum bid

size (MW) - 1 MW 1 MW

Gate closure for

energy bids - 30 min before real time

D-1 (16:30 EET),

updates until 30 min

before real time


Market design

variable

Frequency

Containment Reserve

(FCR)

automatic Frequency

Restoration Reserve

(aFRR)

manual Frequency

Restoration Reserve

(mFRR)

Activation rule Automatic AGC instructions

Dispatch Instructions

stemming from RTBEM

solution

Activation time < 30 s for generation &

<5 s for DR ≤ 2 min 15 min

Energy settlement rule -

Maximum between (a)

Balancing Energy price

for mFRR and (b) BSP

bid price for aFRR

Marginal price

Cost recovery scheme BRPs (capacity) BRPs (capacity) & BRPs

(energy)

BRPs (capacity) & BRPs

(energy)

Monitoring Ex-post check19 Hybrid20 Hybrid

Table 4-1: Market design variables and respective decisions for the Greek Balancing and


19 Since real-time monitoring requires metering infrastructure with a granularity of seconds, which is not currently

available in the Greek power system. 20The hybrid monitoring implies the combination of real-time monitoring and ex-post check.


5 Stakeholders in the Balancing and Ancillary Services Market

In this Chapter, we record all the stakeholders associated with the operation of the

Balancing Market in Greece, either participating directly in the market (Balancing Services

Providers) or being responsible for their imbalances (Balance Responsible Parties).

5.1 Entities

The Entity is a physical unit or a portfolio of physical units which is subject to Imbalance

Settlement. Each Entity bears a Market Schedule from the Forward, Day-Ahead and Intra-

Day Markets.

The Entities are differentiated in Balancing Service Entities (BSEs) and Balancing

Responsible Entities (BREs). The Balancing Service Entities are represented by

Balancing Service Providers (BSPs), whereas the Balance Responsible Entities are

represented by Balance Responsible Parties (BRPs). A Participant can simultaneously

be Balancing Service Provider for some Entities and Balance Responsible Party for other

Entities for which it is the Registered Participant in the respective Entities’ registries.

In the current (2017) market design there are three (3) different types of Contracted Units,

namely: (1) Contracted Units for providing Ancillary Services (“Συμβάσεις Επικουρικών

Υπηρεσιών”), (2) Contracted Units for providing Supplementary System Energy

(“Συμβάσεις Συμπληρωματικής Ενέργειας Συστήματος”), and (3) Contracted Units for

providing Emergency Energy (“Συμβάσεις Εφεδρείας Εκτάκτων Αναγκών”).

For simplicity reasons, in this document there is only one type of Contracted Unit.

These units shall be used in cases of deficits in the imbalance covering constraints

and/or the reserve requirements constraints in the ISP clearing results. Such cases

are herein called “Extreme Conditions”. As further analyzed in the following, in

such cases the TSO shall execute a new (second) ISP solution, considering also

such Contracted Units, in order to resolve efficiently the resources’ shortage

situation. Even though such Contracted Units offer only Balancing Energy to the system

(in such Extreme Conditions), the commitment of a Contracted Unit shall also release

BSPs’ resources to provide reserves; therefore, their utilization attains both the coverage

of the Balancing Energy requirements and the coverage of the Reserve Capacity

requirements. That’s why a separate category of “Contracted Units for providing Ancillary

Services” is not necessary. Such simplification does not aim at “shrinking” the different

cases / options of Contracted Units that may be useful for the TSO, but rather at the

simplification of the market design rules needed for handling such Contracted Units.

The Balancing Service Entities are qualified to provide Balancing Energy and/or

Balancing Capacity and comprise of the following categories:


a) Generating Unit: A conventional dispatchable generating unit with an installed

capacity above 5 MW, which can provide Balancing Services to the Transmission

System Operator. This category includes also the Dispatchable CHP Units above 35

MWe, as referred to in the Independent Transmission System Operation Code. A

Generating Unit is represented by a Producer

b) Dispatchable RES Portfolio: A portfolio of individual RES Units, comprising a set of

physical RES units having concluded a Contract for Differential State-Aid Support

with the RES and CHP Unit Registry Operator, of a specific RES technology

connected at a specific Bidding Zone, which, based on its technical capability, can

provide Balancing Services on a portfolio basis to the Transmission System Operator.

A Dispatchable RES Portfolio can be represented by a RES Producer, a RES

Aggregator or by the Last Resort RES Aggregator. For simplification purposes, in this

Code where the term RES Aggregator is used in the following when referring to the

representative of a Dispatchable RES Portfolio, is shall also include the Last Resort

RES Aggregator, unless explicitly written differently. A Dispatchable RES Portfolio

can include one or more RES Units.

c) Dispatchable Load Portfolio: A portfolio of individual loads connected at a specific

Bidding Zone, which can provide Balancing Services on a portfolio basis to the

Transmission System Operator. A Dispatchable Load Portfolio is represented by a

DR Aggregator or a Self-Supplied Consumer. A Dispatchable Load Portfolio can

include one or more individual loads.

The Contracted Units are also included in the Entities, but not mentioned in the above

list, since they do not have any responsibility to establish their Balancing Schedule for the

Balancing Market processes. The Contracted Units shall be contracted with the

Transmission System Operator to provide additional services in any foreseen situation in

the Integrated Scheduling Process (ISP) which may lead to the expectation of not

covering the system load and/or the reserve requirements for any reason.

The Balance Responsible Entities are all Balancing Service Entities, plus the following:

a) Non-Dispatchable RES Portfolio: A portfolio of individual RES Units, comprising a

set of physical RES units having concluded a Contract for Differential State-Aid

Support with the RES and CHP Unit Registry Operator, of a specific RES technology

connected at a specific Bidding Zone that cannot provide Balancing Services to the

Transmission System Operator. A Non-Dispatchable RES Portfolio is represented by

a RES Producer or by a RES Aggregator.

b) Non-Dispatchable Load Portfolio: An individual load or a portfolio of individual

loads, which cannot provide Balancing Services to the Transmission System

Operator. A Non-Dispatchable Load Portfolio is represented by a Supplier or a Self-

Supplied Consumer.


c) RES FiT Portfolio: A portfolio (aggregation) of RES units of a specific RES

technology and connected at a specific Bidding Zone, remunerated under a Feed-in

Tariff system, which does not provide Balancing Services to the Transmission

System Operator. A RES FiT Portfolio is represented by the RES and CHP Units

Registry Operator.


The imports / exports scheduled by Participants (traders) among bidding areas do not

participate in the Balancing Market, but they are subject to imbalances in case the finally

nominated import/export is different from the Market Schedule (e.g. in case an import /

export quantity that has been cleared at the Greek wholesale electricity market has not

been cleared at a neighboring country’s PX).

For this reason, traders performing imports / exports among bidding areas have not been

incorporated in the above list of Entities, but in such case they are subject to Imbalance

Settlement, as described in Chapter 9.


5.2 Registries

For the scope of execution of the Integrated Scheduling Process (ISP) and the Real-Time

Balancing Energy Market (RTBEM), the TSO shall keep a separate Registry for all

Entities, as per the provisions of this Section. It is noted that all technical operating

characteristics of Entities in the following Registries that involve timings (e.g. time off load

before going into longer standby conditions, time to synchronize, soak time, time from

technical minimum generation to de-synchronization, etc.), should be converted to half-

hours from hours (that they currently are) to facilitate the half-hourly time resolution of the

ISP.

5.2.1 Generating Units Registry

In this registry, the following information shall be maintained and continuously updated

(when needed) for each Generating Unit directly connected to the Transmission System:

a) the Generating Unit EIC Code;

b) the Generating Unit’s geographical location;

c) the Generating Unit operators’ contact details;

d) the information described in Article 4 of the Independent Transmission System

Operation Code;

e) the Registered Operating Characteristics of the Generating Unit according to the

provisions of Article 241 of the Independent Transmission System Operation Code,

amended with the following technical characteristics:

1) maximum contribution to downward FCR;

2) maximum technical capability to provide upward and downward mFRR; and

3) the soak trajectory of each Generating Unit, namely the exact production level

of up to ten (10) half-hourly steps;

f) the identity of the Meter(s) recording the output of that Generating Unit;

g) the Node at which the Generating Unit is electrically located, or in the case of a

Generating Unit not connected at a Node, the Node which is electrically nearest to

the Generating Unit;

h) the Bidding Zone to which the Generating Unit belongs;

i) the information if the Generating Unit is a Contracted Unit, an Auto-Producer

Conventional Unit or a Dispatchable CHP Unit;

j) the Producer Account to which the Generating Unit is allocated (the “Registered

Participant”).

It is noted that Auto-Producer Conventional Units and Dispatchable CHP Units shall be

treated as simple Generating Units with regard to all procedures in this Balancing Market.

The Producers representing Generating Units with a capability to use an alternative fuel

are obliged to additionally submit the technical data of the respective Generating Units

using the alternative fuel.


The Producers representing multi-shaft combined-cycle Generating Units are obliged to

additionally submit the technical data of the respective Generating Units in all possible

configurations.

5.2.2 Dispatchable Load Portfolios Registry


(when needed) for each individual Dispatchable Load Portfolio (represented by a DR

Aggregator or a Self-Supplied Consumer):

a) the Entity EIC Code;

b) the geographical location(s);

c) the Registered Operating Characteristics of the Dispatchable Load Portfolio

according to the provisions of Article 242 of the Independent Transmission System

Operation Code, amended with the following technical characteristics:

1) maximum technical capability to provide upward and downward FCR,

2) Automatic Generation Control (AGC) technical maximum power output when

providing aFRR,

3) Automatic Generation Control (AGC) technical minimum power output when

providing aFRR,

4) maximum technical capability to provide upward and downward mFRR,

5) technical minimum, corresponding to “minimum load reduction”, if non-zero,

6) minimum up time and down time, similarly to the Generating Unit respective

characteristics, if non-zero,

7) minimum and maximum delivery period for the provision of Balancing Energy,

8) minimum baseload period (i.e., minimum period between two successive

activations of Balancing Energy),

9) maximum frequency of activations for the provision of Balancing Energy during

a day,

10) ramp up rate (“load pickup rate”) and ramp down rate (“load drop rate”), and

11) the rate of demand change while operating under Automatic Generation

Control (AGC), if applicable;

d) in case of a Dispatchable Load Portfolio, the individual loads included in the

Dispatchable Load Portfolio;

e) the identity of the Meter(s) recording the consumption of the consumption of each

individual load belonging to the Dispatchable Load Portfolio;

f) the Node(s) at which each individual load belonging to a Dispatchable Load

Portfolio is electrically located in case it is connected directly to the Transmission


System, or in the case it is connected at the Distribution System, the Node(s) which

is(are) electrically nearest to it;

g) the Bidding Zone to which the Dispatchable Load Portfolio belongs; and

h) the DR Aggregator Account to which the Dispatchable Load Portfolio is allocated

(the “Registered Participant”).

5.2.3 Dispatchable RES Portfolios Registry


for each individual Dispatchable RES Portfolio (represented by a RES Producer or a RES

Aggregator):

a) the Entity EIC Code;

b) the geographical location(s),

c) the information described in Article 4 of the Independent Transmission System

Operation Code,

d) the RES technology,

e) the Registered Operating Characteristics of the Dispatchable RES Portfolio

according to the provisions of Article 241 of the Independent Transmission System

Operation Code (i.e., as these characteristics are valid for the conventional

Generating Units), amended with the following technical characteristics:

1) maximum contribution to downward FCR,

2) maximum technical capability to provide upward and downward mFRR,

3) the soak trajectory, namely the exact production level of up to six (6) half-hourly

steps, if non-zero;

f) the technical characteristics included in the current Power Exchange Code and/or

its Market Manual;

g) the identity of the Meter(s) recording the output of the output of each individual

RES Unit belonging to the Dispatchable RES Portfolio,

h) the Node(s) at which each individual RES Unit belonging to a Dispatchable RES

Portfolio is electrically located in case it is connected directly to the Transmission

System, or in the case it is connected at the Distribution System, the Node(s) which

is(are) electrically nearest to it,

i) the Bidding Zone to which the Dispatchable RES Portfolio belongs, and

j) the RES Producer Account or the RES Aggregator Account to which the

Dispatchable RES Portfolio is allocated (the “Registered Participant”).


5.3 Balancing Services Entities/Providers

All Entities that can receive and follow Dispatch Instructions by the TSO constitute the

Balancing Services Entities (BSEs) which are represented in the Balancing and Ancillary

Services Market by their respective Balancing Services Providers (BSPs). A BSE can

essentially be one of the following:

a) a Generating Unit;

b) a Dispatchable Load Portfolio; and

c) a Dispatchable RES Portfolio

It is noted that Contracted Units may (under Extreme Conditions) also provide Balancing

Energy (in this case called Supplementary System Energy) to the TSO. However, in the

context of this document, we have not included them explicitly in the group of BSPs, in

the sense that they do not participate (with Balancing Energy Offers) in the Integrated

Scheduling Process and the Real-Time Balancing Energy Market.

The following general provisions apply regarding the participation of BSEs (through their

BSPs) in the Balancing and Ancillary Services Market:

1) Participation in the Balancing Market shall mean in particular:

a) the submission of Total or Partial Non-Availability Declarations by BSPs for their

BSEs, according to the provisions of Section 7.4,

b) the submission of Techno-Economic Declarations by BSPs for their BSEs,

according to the provisions of Section 7.5,

c) the submission of Upward / Downward Balancing Energy Offers by BSPs for their

eligible BSEs, based on their Available Capacity and their Market Schedule,

according to the provisions of Sections 7.6 and 8.4, and

d) the submission of Reserve Capacity Offerspertype ofReserve Capacity by BSPs

for their eligible BSEs, based on their Declared Characteristics, according to the

provisions of Section 7.7.

2) In brief, the participation rights / obligations of the BSEs are as follows:

a) Producers are obliged to submit for the Generating Units registered in their BSP

or BRP Account Total or Partial Non-Availability Declarations and Techno-

Economic Declarations to the TSO.

b) RES Producers are obliged to submit Total or Partial Non-Availability Declarations

for the RES Units registered in their BSP Account or BRP Account, in case the


RES Unit’s Registered Capacity is above a specific threshold defined by the

Regulator.

c) RES Aggregators and the Last Resort Aggregator are entitled to submit Non-

Availability Declarations for the RES Units registered in their BSP Account or BRP

Account.

d) DR Aggregators, RES Producers and RES Aggregators are obliged to submit,

accordingly, for the Dispatchable Load Portfolios and the Dispatchable RES

Portfolios registered in their BSP Account Techno-Economic Declarations to the

Transmission System Operator.

e) Producers are obliged to submit for the Generating Units registered in their BSP

Account Upward and Downward Balancing Energy Offers in the Balancing Energy

Market.

f) DR Aggregators, RES Producers and RES Aggregators are entitled to submit,

accordingly, on a voluntary basis for the Dispatchable Load Portfolios and the

Dispatchable RES Portfolios registered in their BSP Account Upward and

Downward Balancing Energy Offers in the Balancing Energy Market.

g) Producers are obliged to submit for the Generating Units registered in their BSP

Account Reserve Capacity Offers per each type of Reserve Capacity in the

Integrated Scheduling Process, provided that they have the technical capability to

contribute to a given type of Reserve Capacity based on their Declared

Characteristics.

h) DR Aggregators, RES Producers and RES Aggregators are entitled to submit,

accordingly, on a voluntary basis for the Dispatchable Load Portfolios and the

Dispatchable RES Portfolios registered in their BSP Account Reserve Capacity

Offers for each type of Reserve Capacity in the Integrated Scheduling Process,

provided that they have the technical capability to contribute to a given type of

Reserve Capacity based on their Declared Characteristics.

5.4 Balance Responsible Entities/Parties

In the context of Imbalance Settlement, each Entity referred in Section 5.1 is designated

as a Balance Responsible Entity (BRE) being responsible for settling its imbalances with

the TSO, through the respective Balance Responsible Party (BRP) representing such

Entity. A BRP can represent any of the following Entities:

a) a Generating Unit;

b) a Dispatchable Load Portfolio;


c) a Non-Dispatchable Load Portfolio;

d) a Dispatchable RES Portfolio;

e) a Non-Dispatchable RES Portfolio; and

f) a RES FiT Portfolio.

Thus, all BSEs offering their Balancing Services in the Balancing Market should designate

a BRP to take the responsibility for their imbalances in the Imbalance Settlement process;

the same is true for Contracted Units, when being dispatched in Extreme Conditions. The

BSEs’ imbalances (uninstructed deviations) are calculated as the difference between their

real metered quantities and their real-time Dispatch Instructions (outcome of the RTBEM),

according to the provisions of Chapter 9.

Nevertheless, also the Entities that cannot provide Balancing Services to the TSO yet

being responsible for meeting their wholesale Market Schedules in real time, should

designate a BRP to take the responsibility for their imbalances. Their imbalances are

calculated as the difference between their real metered quantities and their nominated

Market Schedules, according to the provisions of Chapter 9.

Additionally, the responsibility for the import / export schedule deviations of traders, are

also assigned to BRPs, according to the provisions of Chapter 9.

5.5 Participation Fees

The fees for the participation in the Balancing Market shall be proposed by the TSO,

decided by the NRA and charged to BRPs and possibly BSPs.


6 Interface with the Forward, Day-Ahead and Intra-Day Markets

The information that should be transferred from the Intra-Day Market (from the Energy

Trading System of the Market Operator) to the Balancing Market (to the Balancing Market

System of the Transmission System Operator) comprises the following:

I1: The already Scheduled Exchanges (imports/exports) on each interconnection

shall be submitted to the TSOs, in order to compute the Cross Zonal Capacity left

unused after the Intra-Day Market solution. This Cross Zonal Capacity may be used

in the Balancing Market for cross-border balancing purposes.

I2: The Market Schedule (Net Position) of each Generating Unit or Generating Unit in

Commissioning or Testing Operation, namely the energy schedule resulting from the

Intra-Day Market results. This, in conjunction with information transferred from the

Day-Ahead Market to the Intra-Day Market, shall be used as the starting point (initial

position) for each subsequent solution of the Integrated Scheduling Process problem,

as detailed in Section 7.

I3: The Market Schedule (Net Position) of each RES Unit in Commissioning or Testing

Operation, namely the energy schedule resulting from the Intra-Day Market clearing.

This, in conjunction with information transferred from the Day-Ahead Market to the

Inra-Day Market, shall be used in order to compute the RES Units’ and Net Position,

which shall be used as input data in each subsequent solution of the Integrated

Scheduling Process problem, as detailed in Section 7.

I4: The Market Schedule (Net Position) of each Non-Dispatchable RES Portfolio in

each Bidding Zone, namely the energy schedule resulting from the Intra-Day Market

clearing. This, in conjunction with information transferred from the Day-Ahead Market

to the Inra-Day Market, shall be used in order to compute the Net Position of the Non-

Dispatchable RES Portfolio which shall be used as input data in each subsequent

solution of the Integrated Scheduling Process problem, as detailed in Section 7.

I5: The Market Schedule (Net Position) of each Dispatchable RES Portfolio in each

Bidding Zone, namely the energy schedule resulting from the Intra-Day Market

clearing. This, in conjunction with information transferred from the Day-Ahead Market

to the Intra-Day Market, shall be used in order to compute the Net Position of the

Dispatchable RES Portfolio which shall be used as input data in each subsequent

solution of the Integrated Scheduling Process problem, as detailed in Section 7.

I6: The Market Schedule (Net Position) of each Non-Dispatchable Load Portfolio in

each Bidding Zone coming from the Intra-Day Market clearing, which shall be used


in conjunction with information transferred from the Day-Ahead Market to the Intra-

Day Market in order to compute the load imbalances that shall be inserted in each

subsequent solution of the Integrated Scheduling Process problem, as detailed in

Section 7.

I7: The Market Schedule (Net Position) of each Dispatchable Load Portfolio in each

Bidding Zone coming from the Intra-Day Market clearing, which shall be used in

conjunction with information transferred from the Day-Ahead Market to the Intra-Day

Market as input data in each subsequent solution of the Integrated Scheduling

Process problem, as detailed in Section 7.

I8: The Market Schedule (Net Position) of the RES FiT Portfolio in each Bidding Zone

coming from the Intra-Day Market clearing, which shall be used along in conjunction

with information transferred from the Day-Ahead Market to the Intra-Day Market, in

order to compute the RES FiT Portfolio injection imbalances that shall be inserted in

each subsequent solution of the Integrated Scheduling Process problem, as detailed

in Section 7.


7 Integrated Scheduling Process

7.1 Timeframe of the Integrated Scheduling Process

The ISP consists of three programmed on the clock consecutive scheduling phases

designated as follows:

a) one day-ahead scheduling phase (ISP1) performed at calendar day D-1

concerning all Dispatch Periods of Dispatch Day D;

b) a second one (ISP2) performed at the last hour of calendar day D-1 concerning

all Dispatch Periods of Dispatch Day D; and

c) an intra-day scheduling phase (ISP3) performed during the Dispatch Day D to

allow for changes in forecasted data and system conditions affecting the last

twenty-four (24) Dispatch Periods of the Dispatch Day D.

In case a major event takes place during day D, or even in the afternoon of day D-1, which

affects at a great extent the unit scheduling and the reserve allocation during day D (e.g.,

a unit outage or a major non-expected increase in the system load, etc.), the TSO is

allowed to execute the ISP problem on-demand (in this case called “on-demand ISP”), in

order to derive a new schedule (energy & reserves) for the available BSEs. Therefore,

the three programmed sessions of the ISP (ISP1, ISP2 and ISP3) should be considered

as the minimum number of the ISP executions that shall be implemented by the TSO

regarding the Dispatch Day D.

It should be noted that the number of ISP scheduled runs depends on the number of Intra-

Day Market auctions that will be performed, which depends on all TSOs’ proposal for the

intra-day auctions (and subsequently ID continuous sessions) and the respective decision

of the NRAs. Therefore, the number and timing of ISP scheduled runs may be revised in

the following years.

Timeframe provisions

Specific provisions regarding the timeframe of the ISP are provided in the following; it is

noted that all times and critical deadlines referred hereinafter are subject to the

Decision of the Regulator according to the TSO recommendations:

1) All procedures and actions regarding the ISP refer to one Dispatch Day (day D), and

are completed in the day pre-ceding (day D-1) or within the Dispatch Day and within

the deadlines provided for herein.

2) The Dispatch Day of the ISP coincides with the Delivery Day of the Day-Ahead Market

and Intra-Day Market. Therefore, the Dispatch Day shall mean the 24-hour period (48

half-hourly intervals) starting from 01:00 of calendar day D and ending at 01:00 of


calendar day D+1. This provision will assist ADMIE with the integration of the Greek

market with the balancing markets in Europe and the transition to the cross-border

balancing activities (in European level).

3) With reference to Figure 7-1, the Gate Closure Time (GCT) for the submission of all

Offers and Declarations in the ISP opens at 14:00 EET D-1 and closes at 16:00 EET

in day D-1, corresponding to the Dispatch Day D. Within this period, the BSPs can

submit their Offers and Declarations for their BSEs as many times as they wish. The

last validated Offers / Declarations shall be considered for the ISP problem solution.

4) The same Offers submitted before the execution of the ISP1 shall be taken into

account for the execution of ISP2 and ISP3, as well as any other ISP execution

triggered by the TSO on demand. Thus, there shall be no new re-bidding process

within the ISP.

5) The last validated Techno-Economic Declarations before the ISP1 GCT shall be

considered for all ISP runs.

6) The last validated Non-Availability Declarations before the ISP1 GCT shall be

considered for ISP1. However, the most recent Non-Availability Declarations shall be

considered for all subsequent ISP runs, in order to take into account any unexpected

outages or any partial unavailability of the BSEs.

7) According to Figure 7-1:

a) the ISP1 is executed at 16:00 EET D-1, the market solution is obtained at the

latest at 16:55 EET D-1 (critical deadline), and the results are published until

17:00 EET D-1,

b) the ISP2 is executed at 00:00 EET D, the market solution is obtained at the latest

at 00:40 EET D (critical deadline), and the results are published until 00:45 EET

D,

c) the ISP3 is executed at 10:30 EET D, the market solution is obtained at the latest

at 11:10 EET D (critical deadline), and the results are published until 11:15 EET

D, and finally,

d) any additional ISP is executed on demand by the TSO, the market solution is

obtained at the latest 40 minutes after the time of the initialization of the execution

(critical deadline), and the market results are published at the latest 5 minutes

after the solution has been obtained..


Figure 7-1: Timeframe of the Integrated Scheduling Process programmed executions


8) According to the Figure 7-1:

a) the scheduling horizon of the ISP1and ISP2 problem coincides with the whole

Dispatch Day D,,

b) the scheduling horizon of the ISP3 problem corresponds to the period 12:00 -

24:00 CET of Dispatch Day D (or, equivalently, 13:00 EET of calendar day D until

01:00 EET of calendar day D+1),

c) the scheduling horizon of any additional ISP executed on demand corresponds to

the period between (a) the first hour following the initialization of the execution (in

case the first hour starts after more than 40 minutes from said initialization) or the

second hour following the initialization of the execution (in case the first hour starts

after less than 40 minutes from said initialization) and (b) the end of the Dispatch

Day D (01:00 EET in calendar day D+1).

9) Each subsequent ISP execution considers as initial position (state and MW level) of

all BSEs, the respective position obtained during the last binding Dispatch Period of

the previous ISP execution. For example, in case an ISP is executed for the

scheduling horizon 13:00 EET of calendar day D – 01:00 EET of calendar day D+1

(i.e., ISP3), then as initial position of all BSEs shall be taken their position obtained

by the previous ISP execution (namely either ISP2 or an on-demand ISP executed

after ISP2 and before ISP3) for the 26th half-hour of the calendar day D.

This provision is not valid only in the following cases:

a) in case of an outage (total non-availability) of a BSE that was scheduled to

operate at the 26th half-hour in the previous ISP execution; in such case, the

declared Available Capacity is set to zero and shall be taken as the initial position

of this BSE, and

b) in case of a partial non-availability of a BSE that was scheduled to produce at a

higher level (for generating Entities, e.g. Generating Units) or to consume at a

higher level (for demand Entities, e.g. Dispatchable Load Portfolios) than his

declared Available Capacity at the 26th half-hour in the previous ISP execution; in

such case, the declared Available Capacity shall be taken as the initial position of

this BSE.

7.2 Balancing Services Products

The ISP model involves the simultaneous procurement of the following Balancing

Services products:

a) Upward and Downward mFRR Balancing Energy (BE) and aFRR Balancing


Energy.

b) Different types of Reserve Capacity (RC):

Upward and Downward Frequency Containment Reserve (FCR);

Upward and Downward Frequency Restoration Reserve with automatic

activation (aFRR); and

Upward and Downward Frequency Restoration Reserve with manual

activation (mFRR) .

7.3 Dispatch Period

The following provisions apply with regard to the Dispatch Period in the ISP:

1) The time-step of the ISP model is half-hourly21.

2) Accordingly, all Balancing Services Offers (Balancing Energy and Reserve

Capacity Offers) have an half-hourly validity period.

3) There are 48 Dispatch Periods in each Dispatch Day. Dispatch Periods commence

at 01:00 on the calendar day D and end at 01:00 EET of calendar day D+1.

7.4 Submission of Non-Availability Declarations

The Participants (BSPs) are responsible for submitting Non-Availability Declarations to

the TSO, in order to inform the latter in good time about possible total or partial non-

availabilities of the BSEs they operate / represent due to technical cause. The following

provisions with regard to the submission of Non-Availability Declarations apply to

Producers for the Generating Units included in their BSP Account and RES Producers for

the RES Units included in their BSP Account or BRP Account and in case the RES Unit’s

Registered Capacity is above a specific threshold defined by the Regulator. RES

Aggregators are not obligated to submit Non-Availability Declarations for the RES Units

they represent:

1) In case of an outage exclusively due to technical causes related to the operation

or safety of a Generating Unit, or a RES Unit installation, and which renders energy

generation and/or provision of Balancing Ancillary Services by the Generating

Unit, or the RES Unit impossible, the respective Participant must submit to the

TSO a Total Non-Availability Declaration for the Dispatch Day as soon as

reasonably possible after such inability appears, establishing the Dispatch Periods

21The shorter the time-step the more accurate scheduling is performed in the ISP, which is further adapted in the

RTBEM. Another reason for adopting higher (than hourly) time resolution in the ISP is to better accommodate /

facilitate possible products (and resulting Market Schedules) in future regional Intraday Markets (that Greece might

join) having shorter (than hourly) delivery periods (e.g. half-hourly products).


in the Dispatch Day or Dispatch Days the non-availability is anticipated to last.

2) In case of an outage exclusively due to technical causes related to the operation

or the safety of a Generating Unit, or a RES Unit installation, or in case of other

reasons, such as ageing deration, operation in different conditions than ISO

conditions, or reservoir levels for hydro units, causing a Generating Unit, or a RES

Unit inability to generate energy – and/or provide Ancillary Services corresponding

to such Entity’s Registered Capacity (as this is listed in the Generating Unit

Registry, or Dispatchable RES Portfolio Registry), the respective Participant must

submit to the TSO a Partial Non-Availability Declaration for the Generating Unit, or

the RES Unit, on which such inability exists, indicating the Available Capacity in

each Dispatch Period of the Dispatch Day on which there is reduced Available

Capacity. The Partial Non-Availability Declaration may establish a time period of

more Dispatch Days during which it is anticipated that there shall be reduced

generation capacity. In that case, a single reduced Available Capacity shall be

established for the entire period.

3) It is clarified that if there is no valid Partial Non-Availability Declaration for a

Dispatch Period, the Available Capacity of a Generating Unit, or a RES Unit is

equal to the Registered Capacity, as this is listed in the Generating Unit Registry,

or the Dispatchable RES Portfolio Registry, whereas if there is a valid Total Non-

Availability Declaration for a Dispatch Period, the Available Capacity of such Entity

is zero.

4) Total or Partial Non-Availability Declarations shall include a description of the

causes for the non-availability.

5) The most recent information submitted in the Total or Partial Non-Availability

Declarations before the ISP GCT determines the Available Capacity of Generation

Units and RES Units for this ISP. A Total or Partial Non-Availability Declaration

issued past a ISP Gate Closure Time for the Dispatch Day for which Total or Partial

Non-Availability is stated shall be considered in the next ISP solution, if any, and

in the Real-Time Balancing Energy Market.

6) The term of validity of Partial or Total Non-Availability Declarations shall be the total

number of Dispatch Periods listed in them. Such declarations shall remain in force

until the end of their term of validity, unless revoked earlier by the respective

Participants. A Non-Availability Declaration shall cease to be in force before its

term of validity has elapsed, if the TSO cancels such declaration, in accordance

with the provisions of the Hellenic Transmission System Operation Code.

7) The maximum continuous generation capability of the Generating Units for each

Dispatch Period of the Dispatch Day D that will be used in the Integrated

Scheduling Process runs and in the Real-Time Balancing Energy Market shall be


calculated by the Transmission System Operator based on a methodology

approved by the Regulator.

.

7.5 Submission of Techno-Economic Declarations

The Participants (BSPs) are responsible for submitting Techno-Economic Declarations to

the TSO, separately for each BSE (registered at the respective Registries) they operate /

represent. The following provisions apply with regard to the submission of Techno-

Economic Declarations by the Participants:

7.5.1 Contents of Techno-Economic Declarations

Techno-Economic Declarations include the information given in the following tables. The

technical information in the Techno-Economic Declaration must correspond to the real

operation technical information for each BSE. The economic information in the Techno-

Economic Declaration must reflect the expenses actually incurred by the Participant as

these are allocated in each case and computed in accordance with the definition of each

economic figure in the Techno-Economic Declaration.

The BSPs representing Generating Units, Dispatchable Load Portfolios, Dispatchable

RES Portfolios (essentially all BSEs) are obliged to submit Techno-Economic

Declarations per their BSE to the TSO. Such obligation is valid as follows:

a) For each Generating Unit, the Techno-Economic Declaration should contain all

elements of the above table except from part A3.

b) For each Dispatchable RES Portfolio, the Techno-Economic Declaration should

contain only Tables A1 and A2.

c) For each Dispatchable Load Portfolio the Techno-Economic Declaration should

contain only Tables A1, A2 and A3.

A. Technical parameters

A1. Balancing Services Entities’ operation technical information

Description Numerical value Measuring unit

Minimum additional time (in addition to the synchronization

time) in case of recall from total non-availability state half-hours

Maximum daily energy injection MWh

A2. Balancing Service Entities’ technical information

for Balancing Energy and Ancillary Services


Technical capability to provide upward FCR MW

Technical capability to provide downward FCR MW

Automatic Generation Control (AGC) technical maximum power

output (for providing aFRR)

MW

Automatic Generation Control (AGC) technical minimum power

output (for providing aFRR)

MW

Rate of generation/demand change while operating under

Automatic Generation Control (AGC)

MW/minute

A3. Technical information for Dispatchable Load Portfolios

Minimum and maximum delivery period for the provision of

Balancing Energy half-hours

Minimum baseload period half-hours

Maximum frequency of activations for the provision of Balancing

Energy in the course of a day Times/Day

B. Variable Cost Parameters for Generating Units

Fuel cost by fuel type

Fuel A

€/quantity

measuring unit Fuel B

Fuel C

Fuel Lower Heating Value (LHV)

Fuel A

GJ/quantity

measuring unit Fuel B

Fuel C

Percentage fuel composition at each

capacity interval of the Fuel Specific

Consumption Stepwise Function

Net Generation

Level (MW) Fuel A (%) Fuel B (%) Fuel C (%)


Special cost for raw materials besides fuel

for all capacity intervals of the Fuel Specific


Net Generation Level (MW) Cost (€/MWh)

Special cost of additional maintenance

expenses due to operation (with the

exception of fixed maintenances expenses)

for all capacity intervals in the Fuel Specific



Special cost for additional workforce

expenses due to operation (besides

workforce fixed expenses) for all capacity

intervals in the Fuel Specific Consumption

Stepwise Function


Table 7-1: Techno-Economic Declarations’ contents

The fuel cost stated in Techno-Economic Declarations corresponds to all expenses

incurred by Producers to supply fuel regardless of the type of individual cost elements.

Supply is defined as if the Producer were supplied with fuel from an independent person,

which uniformly charges a fuel price for each unit of fuel quantity it supplies. Where there

is lack of documentation through purchase invoices or other equivalent documents, fuel

cost shall be computed as the ratio of total fuel supply expenses or cost, as such

expenses or cost have been registered for a sufficient time period to the total fuel quantity

a Producer is supplied with for the Generating Unit during such time period.

In order for the TSO to establish the Generating Unit Variable Cost, it processes the

information in Techno-Economic Declarations as follows:

a) the Variable Cost curve is taken by part B of Techno-Economic Declarations; and

b) the minimum numerical value of the Variable Cost curve is established, which

corresponds to optimum Generating Unit operation. This value establishes the Unit

Minimum Variable Cost for a Generating Unit for any given Dispatch Day.

Important note: The Unit Minimum Variable Cost is solely used under the new market

design for the validation of the Balancing Energy Offers (both upward and downward)


submitted by BSPs operating Generating Unit(s). The Generating Unit Variable Cost is

not used in terms of a cost-recovery mechanism, since such mechanism is not present

under the new market design.

Techno-Economic Declarations submitted for an Auto-Producer Conventional Unit shall

concern only the part of the unit’s capacity corresponding to such unit’s Registered

Capacity, as defined in the Generating Unit Registry.

As Declared Characteristics shall be taken the characteristics established as a

combination of the following technical and operational characteristics of a BSE, and

represent the applicable technical capabilities of such BSE for a specific Dispatch Period

and Dispatch Day:

a) Registered Operating Characteristics,

b) Techno-Economic Declaration, and

c) Non Availability Declaration (Total or Partial), where applicable.

7.5.2 Techno-Economic Declaration submission procedure

Techno-Economic Declarations are binding and are submitted until the ISP1 GCT for the

first Dispatch Day to which they refer. The submission of Techno-Economic Declarations

after the ISP1 GCT (for the first Dispatch Day to which they refer) is not acceptable.

Techno-Economic Declarations refer to one or more Dispatch Days and apply if found

acceptable. Newer Techno-Economic Declarations if lawfully submitted shall replace all

previous ones.

7.5.3 Acceptance and rejection of Techno-Economic Declarations by the TSO

The TSO shall consider lawfully submitted all Techno-Economic Declarations submitted

in a timely manner and in accordance with Paragraphs 7.5.1 and 7.5.2 of this Section.

Where a Techno-Economic Declaration is considered unlawfully submitted, the latest

lawfully submitted Declaration shall be in force. Where there is no lawful declaration for a

BSE, the TSO shall inform the Regulator to that respect in view of the imposition of

possible sanctions and shall admit as Declared Characteristics for such BSE its

Registered Operating Characteristics.

7.6 Submission of Balancing Energy Offers

The following provisions apply with regard to the submission of Balancing Energy Offers

by the BSPs in the ISP:


7.6.1 General provisions

The gate for the submission of Balancing Energy Offers in the ISP opens at 14:00 EET in

calendar day D-1 and closes at 16:00 EET in calendar day D-1, corresponding to the

Dispatch Day D. Within this period, the Participants (BSPs) can submit Balancing Energy

Offers for each BSE they represent as many times as they wish. The last validated

Balancing Energy Offers shall be considered for the ISP problem solution.

The same Balancing Energy Offers submitted before the execution of the ISP1 (as per the

previous paragraph) are taken into account for the execution of ISP2 and ISP3, as well as

any other ISP execution triggered by the TSO on demand.

A Balancing Energy Offer refers to an upward or downward deviation from the latest

Market Schedule (aggregation of the traded quantities corresponding to an Entity from

the Forward, Day-Ahead and Intra-Day Markets) of a given BSE (Generating Unit,

Dispatchable Load Portfolio, Dispatchable RES Portfolio). Such Market Schedule shall

be automatically transferred (prior to each ISP execution) from the Market Operator to the

Transmission System Operator in order to be used as the initial position of the BSE in the

ISP problem, as referred in Section 6.

Especially with regard to the Dispatchable Load Portfolios, the aforementioned Market

Schedule shall be rather considered as being equal to their Baseline calculated by the

TSO for the period concerned (i.e., the electricity that would have been consumed by the

Dispatchable Load Portfolio, in the absence of an activation of a Balancing Energy Offer),

as referred in Section 3.6. The Baseline calculated by the TSO is a transparent measure,

which can be the basis for (a) the activation of Balancing Energy Offers in the ISP

execution, and (b) the ex-post verification of activation of the Balancing Energy Offers

submitted by the DR resources in the Balancing Market. The Baseline of a Dispatchable

Load Portfolio is calculated as the average of the Dispatchable Load Portfolio’s energy

use during the 10 previous non-event days of similar load profile. The Baseline shall be

further adjusted using the "default morning-of adjustment” technique (up or down

adjustment of the calculated average in accordance to the Dispatchable Load Portfolio’s

usage in the four hours immediately before the event), in order to compensate for possible

artificial inflation of a customer’s usage prior to the execution of a DR event.

A different approach would necessitate that the Load Representative supplying the given

DR resources should provide the Market Schedule of these DR resources (as obtained

by wholesale market trades concluded by the Load Representative for said DR resources)

either directly to the TSO, or to the TSO through the independent DR Aggregator (in the

latter case, a respective relationship should be established between the Load

Representative and the independent DR Aggregator, regarding the transfer of the

relevant Market Schedule). This approach, however, is not opted in theGreek market

design, since it can act as an entry barrier for DR for the following reasons: (a) the Load

Representative may not be willing to provide other parties (e.g. the independent DR

Aggregators) with sensitive commercial information regarding its represented demand


(i.e., he may not be willing to provide the respective Market Schedule), and (b) the

Baseline calculated with a transparent and concrete methodology by the TSO is expected

to be more accurate than any other Market Schedule calculated by the market parties,

thereby not causing any “fictitious” imbalances to the DR Aggregators, incurred due to

wrong initial estimations of the Market Schedule.

Thus, for the sake of simplicity in the hereinafter description, we shall refer to the Market

Schedule uniformly for all types of BSEs, while rather implying the Baseline calculated by

the TSO in the case of Dispatchable Load Portfolios.

Specifically, an Upward Balancing Energy Offer refers to:

a) an increase in the production level (MW) of a Generating Unit or a Dispatchable RES

Portfolio with regard to its Market Schedule,

b) a decrease in the consumption level (MW) of a Dispatchable Load Portfolio with

regard to its Market Schedule.

Inversely, a Downward Balancing Energy Offer refers to:

a) a decrease in the production level (MW) of a Generating Unit or a Dispatchable RES

Portfolio with regard to its Market Schedule,

b) an increase in the consumption level (MW) of a Dispatchable Load Portfolio with

regard to its Market Schedule.

BSPs representing Generating Units (Producers) are obliged to submit in the ISP:

a) an Upward Balancing Energy Offer per their BSE for each Dispatch Period of the

Dispatch Day, for a total upward Balancing Energy quantity equal to the Registered

Capacity of the BSE based on its Registered Operating Characteristics, and

b) a Downward Balancing Energy Offer per their BSE for each Dispatch Period of the

Dispatch Day, for a total downward Balancing Energy quantity equal to the Registered

Capacity of the BSE based on its Registered Operating Characteristics.

RES Producers and RES Aggregators are entitled to submit in the ISP:

A) an Upward Balancing Energy Offer per their BSE for each Dispatch Period of the

Dispatch Day, for a total upward Balancing Energy quantity, at maximum equal

to the Registered Capacity of the BSE based on its Registered Operating

Characteristics, and

B) a Downward Balancing Energy Offer per their BSE for each Dispatch Period of

the Dispatch Day, for a total downward Balancing Energy quantity, at maximum

equal to the Registered Capacity of the BSE based on its Registered Operating

Characteristics.

Self-Supplied Consumers and DR Aggregators representing Dispatchable Load

Portfolios are entitled to submit Upward and Downward Balancing Energy Offers, at


maximum for their whole technical capability to provide upward and downward Balancing

Energy.

The obligations described in the above paragraphs shall be suspended in the following

cases:

a) for the time in which the BSE is undergoing Scheduled Maintenance, in accordance

with the Independent Transmission System Operation Code, and

b) during the period of validity of the Total Non-Availability Declaration (where

applicable).

7.6.2 Format of the Balancing Energy Offers in the Integrated Scheduling Process

With regard to the format of the Balancing Energy Offers submitted in the ISP, the

following provisions apply:

1) The BSPs must submit half-hourly step-wise Balancing Energy Offers for each BSE

registered in their BSP Account in the ISP for both upward and downward direction.

Each step shall bear a non-negative upward / downward Balancing Energy quantity

in MW per half-hour, with accuracy of up to 3 decimal points, and an offer price in

€/MWh with accuracy of up to 2 decimal points.

2) According to the Figure 7-2, the upward Balancing Energy step-wise function shall

include up to ten steps, where Balancing Energy prices for successive steps must be

strictly non-decreasing. The total offered Balancing Energy quantity (sum of all steps)

shall respect the provisions of Section 7.6.1.

3) According to the Figure 7-3, the downward Balancing Energy step-wise function shall

include up to ten steps, where Balancing Energy prices for successive steps must be

strictly non-increasing. The total offered Balancing Energy quantity (sum of all steps)

shall respect the provisions of Section 7.6.1.

4) In general, the offered Balancing Energy prices for each step of the step-wise

Balancing Energy Offer must be greater than an Administratively Defined Balancing

Energy Offer Lower Limit (which can be negative) and less than or equal to an

Administratively Defined Balancing Energy Offer Cap, as such limits apply for the

Dispatch Period to which the Balancing Energy Offer corresponds.

5) The numerical values of the Administratively Defined Balancing Energy Offer Lower

Limit and the Administratively Defined Balancing Energy Offer Cap shall be

established by a decision of the Regulator. Such decision shall be taken at least two

months prior to the date of enforcement of the new values of the above limits.


Figure 7-2: Upward Balancing Energy step-wise function

Figure 7-3: Downward Balancing Energy step-wise function

6) Especially for the Upward Balancing Energy Offers submitted by the BSPs

(Producers) for the Generating Units they operate, these can be priced:

a) at minimum at the Unit’s Minimum Variable Cost, as computed using the data

contained in the respective Techno-Economic Declaration, and

b) at maximum at the Administratively Defined Balancing Energy Offer Cap.

7) Accordingly, the Downward Balancing Energy Offers submitted by the BSPs

(Producers) for the Generating Units they operate can be priced:

a) at minimum at the Administratively Defined Balancing Energy Offer Lower Limit,

and

b) at maximum at the Unit’s Minimum Variable Cost, as computed using the data

…

…

€ / MWh

Price10

Price1

Quantity1 Quantity10

MW

Technical capability to provide

upward Balancing Energy

…

€ / MWh

Price1

Price10

…Quantity1 Quantity10

MW

Technical capability to provide

Downward Balancing Energy


contained in the respective Techno-Economic Declaration.

8) There are no respective constraints on the submitted offer prices for upward and

downward Balancing Energy for Dispatchable RES Portfolios and Dispatchable Load

Portfolios. Nevertheless, it is considered rational that the respective BSPs

representing such BSEs shall submit higher prices for providing upward Balancing

Energy and lower prices for providing downward Balancing Energy, leading to the

activation of either upward or downward Balancing Energy from each BSE. However,

such rational bidding behaviour cannot be absolutely foreseen.

In case of irrational bidding behaviour by one or more BSPs (i.e., submitting a higher

price for downward Balancing Energy, as compared to the offer price for upward

Balancing Energy), the ISP problem should encompass a certain constraint for

choosing to activate only one (upward or downward) of the two services from each

BSE. Such constraint is presented in Section 7.10.13 (constraint (34)).

9) Together with their step-wise Balancing Energy Offers, the BSPs are entitled to submit

a minimum quantity of Balancing Energy in MW per each direction and each Dispatch

Period to be accepted either thoroughly or not accepted at all by the ISP (as a

minimum “acceptance ratio”), as further explained in Section 7.10.13 regarding

constraints (32) and (33).

10) Under Extreme Conditions (deficit in covering an increase in the system load, or

covering the reserve requirements), the TSO shall submit for each Dispatch Period

of each Dispatch Day a Balancing Energy Offer for each Contracted Unit. The Offer

Price (€/MWh) in such Balancing Energy Offers shall be determined in accordance

with the relevant Supplementary System Energy Contract.

7.6.3 Modification and acceptance of the Balancing Energy Offers in the Integrated Scheduling Process

As previously noted, the Balancing Energy Offers concerning a given Dispatch Day shall

be submitted before the ISP1 GCT corresponding to the specific Dispatch Day. Balancing

Energy Offers submitted after the ISP1 GCT shall not be accepted for the ISP executions.

Within the period of submission, the BSPs can submit their Balancing Energy Offers

multiple times and the final accepted Balancing Energy Offers shall be considered for the

ISP clearing.

The following provisions apply with regard to possible modifications of the submitted

Balancing Energy Offers during the period of submission in the ISP:

1) In case a Balancing Energy Offer is not valid, namely it does not fully comply with the

provisions of Sections 7.6.1 – 7.6.2, the whole Balancing Energy Offer (for all

Dispatch Periods of the Dispatch Day) shall be automatically rejected by the

Balancing Market System. In case of rejection, a justification of the reason for the


rejection shall immediately and automatically be sent to the BSP. In such case, the

BSP can resubmit his Balancing Energy Offer before the ISP1 GCT, until a valid

Balancing Energy Offer is finally accepted by the Balancing Market System. Only

validated Balancing Energy Offers are inserted in the ISP clearing engine.

2) After the ISP1 GCT, the Balancing Energy Offers that will be taken into account in the

ISP problem solution (in any of the subsequent ISPs regarding the Dispatch Day D)

shall not be changed.

7.6.4 Consequences of non-submission of Balancing Energy Offers

In case of non-submission of Balancing Energy Offers for a Dispatch Day by a BSP

obligated to such submission in the ISP (essentially a Producer), the TSO shall charge

such BSP for such Dispatch Day a penalty, which is described in Chapter 9.

In such case, the Balancing Market System shall automatically create Balancing Energy

Offers for each associated Generating Unit and any given Dispatch Period, by

establishing offer prices equal to the Minimum Variable Cost of the Generating Unit for

both upward and downward Balancing Energy. If the variable cost has not been declared,

then Balancing Energy Offers prices are equal to the respective prices in the last validated

Balancing Energy Offer of the BSE during the previous day(s).

7.7 Submission of Reserve Capacity Offers

The following provisions apply with regard to the submission of Reserve Capacity Offers

by the BSPs in the ISP:

7.7.1 General provisions

Producers are obligated to submit for the Generating Units registered in their BSP

Account Reserve Capacity Offers per each type of Reserve Capacity in the Integrated

Scheduling Process, provided that they have the technical capability to contribute to a

given type of Reserve Capacity based on their Declared Characteristics.

BSPs are entitled to submit on a voluntary basis for the Dispatchable Load Portfolios and

Dispatchable RES Portfolios registered in their BSP Account Reserve Capacity Offers for

each type of Reserve Capacity in the Integrated Scheduling Process, provided that they

have the technical capability to contribute to a given type of Reserve Capacity based on

their Declared Characteristics.

Participants are not entitled to submit Reserve Capacity Offers for Contracted Units.

The GCT for the submission of Reserve Capacity Offers in the ISP opens at 14:00 EET in

calendar day D-1 and closes at 16:00 EET in calendar day D-1, corresponding to the

Dispatch Day D. Within this period, the BSPs can submit Reserve Capacity Offers for each


BSE registered in their BSP Account as many times as they wish. The last validated

Reserve Capacity Offers shall be considered for the ISP problem solution.

The same Reserve Capacity Offers submitted before the execution of the ISP1 (as per the

previous paragraph) are taken into account for the execution of ISP2 and ISP3, as well as

any other ISP execution triggered by the TSO on demand.

The obligations of Producers under the previous paragraph shall be suspended in the

following cases:

a) for the time in which the Generating Unit is undergoing Scheduled Maintenance, in

accordance with the provisions in the Independent Transmission System Operation

Code, and

b) during the period of validity of the Total Non-Availability Declaration, where applicable.

7.7.2 Format of the Reserve Capacity Offers in the Integrated Scheduling Process

The Participants must submit half-hourly step-wise Reserve Capacity Offers in the ISP

for all types of Reserve Capacity their BSEs are technically capable to provide, according

to their Declared Characteristics.

The upward Reserve Capacity Offer step-wise function shall include up to ten steps,

where Reserve Capacity prices for successive steps must be strictly non-decreasing.

The downward Reserve Capacity Offer step-wise function shall include up to ten steps,

where Reserve Capacity prices for successive steps must be strictly non-increasing.

Together with their step-wise Reserve Capacity Offers, the Producers are entitled to

submit a minimum quantity of Reserve Capacity per each direction and each Dispatch

Period of the Dispatch Day, to be accepted under a fill-or-kill condition by the ISP.

Self-Supplied Consumers and DR Aggregators representing Dispatchable Load

Portfolios and RES Producers and RES Aggregators representing Dispatchable RES

Portfolios are entitled to submit a minimum quantity of Reserve Capacity per step, per

each direction and per Dispatch Period of the Dispatch Day, to be accepted under a fill-

or-kill condition by the ISP.

The Reserve Capacity Offers for each Dispatch Period of a Dispatch Day shall include up

to six (6) capacity prices, namely a separate price for upward and downward FCR, aFRR

and mFRR, with a numerical value higher than zero and less than or equal to the

Administratively Defined Reserve Capacity Offer Cap for each reserve type. Such

capacity prices shall be in €/MW per Dispatch Period, with an accuracy of up to two (2)

decimal points.


The numerical values of the Administratively Defined Reserve Capacity Offer Cap per

reserve type shall be established by a decision of the Regulator. Such decision shall be

taken at least two months prior to the date of enforcement of the new values of these

limits.

The reserve quantities shall be expressed in MW with an accuracy of up to one (1)

decimal point.

7.7.3 Modification and acceptance of the Reserve Capacity Offers in the Integrated Scheduling Process

As previously noted, the Reserve Capacity Offers concerning a given Dispatch Day shall

be submitted before the ISP1 GCT corresponding to the specific Dispatch Day. Reserve

Capacity Offers submitted after the ISP1 GCT shall not be accepted. Within the period of

submission, the BSPs can submit their Reserve Capacity Offers multiple times and the

final accepted Reserve Capacity Offers shall be considered for the ISP clearing.

The following provisions apply with regard to possible modifications of the submitted

Reserve Capacity Offers during the period of submission in the ISP:

1) In case a Reserve Capacity Offer is not valid, according to the provisions referred

above in this Section, the Reserve Capacity Offer shall be automatically rejected by

the Balancing Market System, and it shall not be taken into account in the ISP clearing.

2) In case of rejection, a justification of the reason for the rejection shall immediately

and automatically be sent to the BSP. In such case, the BSP can resubmit his Reserve

Capacity Offer before the ISP1 GCT, until a valid Reserve Capacity Offer is finally

accepted by the Balancing Market System.

3) After the ISP1 GCT, the Reserve Capacity Offers that will be taken into account in the

ISP problem solution (in any of the subsequent ISPs regarding the Dispatch Day D)

shall not be changed.

4) The Reserve Capacity Offers submitted in the ISP are economically binding, meaning

that in case a BSE is awarded FCR, aFRR and/or mFRR and provides such

availability in real time, the respective BSP shall be subject to a financial settlement

with the TSO (for the provision of such service); else, if the BSE is awarded FCR,

aFRR and/or mFRR, but does not provide such service in real time, the respective

BSP shall be subject to a Non-Compliance Charge, as described in Chapter 9.

7.7.4 Consequences of non-submission of Reserve Capacity Offers

In case of no-submission of Reserve Capacity Offers for a Dispatch Day by a BSP

obligated to such submission, the TSO shall charge such BSP a Non-Compliance

Charge, as described in Chapter 9.


In such case, the Balancing Market System shall automatically create a Reserve Capacity

Offer for each respective BSE and any given Dispatch Period, with reserve prices equal

to the respective prices included in the last validated Reserve Capacity Offer of the BSP

(during the previous days).

7.8 Integrated Scheduling Process Data

The TSO shall establish the results of a given ISP session based on the following

information for each Dispatch Period of the respective ISP scheduling period:

a) The Balancing Energy Offers’ price - quantity pairs corresponding to the steps of

the Balancing Energy Offers’ step-wise functions.

b) The Reserve Capacity Offers’ price-quantity pairs for upward and downward FCR,

aFRR and mFRR.

c) The Registered Operating Characteristics of the BSEs.

d) The Techno-Economic Declarations submitted by the BSPs for each BSE,

considering especially the interrelations of the multi-shaft combined cycle

Generating Units.

e) The Total Non-Availability Declarations and Partial Non-Availability Declarations

submitted by the BSPs for their BSEs.

f) The operational state of the BSEs at the start of the scheduling period, namely the

half-hours already in operation or out of operation and the scheduled injection or

consumption at the start of the ISP scheduling period.

g) The Market Schedules of all Entities, which are processed by the Transmission

System Operator.

h) Any updates in the scheduled operation of the Generating Units / RES Units in

Commissioning or Testing Operation, as submitted to the Transmission System

Operator by the respective Producers / RES Producers through the

Commissioning Schedules Declarations.

i) The mandatory generation schedules of hydro Generating Units, as submitted to

the Transmission System Operator by the respective Producers through the Hydro

Mandatory Injections Declarations.

j) The zonal Non-Dispatchable Load Imbalance, computed as the difference

between the zonal Non-Dispatchable Load Forecast and the latest Market

Schedules of all Non-Dispatchable Load Portfolios connected at the specific

Bidding Zone, as notified by the Market Operator.

k) The zonal Non-Dispatchable RES Portfolios Imbalance, computed as difference

between the zonal Non-Dispatchable RES Portfolios Forecast and the latest

Market Schedules of all Non-Dispatchable RES Portfolios connected at the specific


Bidding Zone, as notified by the Market Operator.

l) The zonal RES FiT Portfolio Imbalance, computed as difference between the zonal

RES FiT Portfolio Forecast and the latest Market Schedules of the RES FiT

Portfolio for a specific RES technology and Bidding Zone.

m) The available flows in the inter-zonal corridors.

n) The import / export schedule deviations at the interconnections imposed by the

Transmission System Operator;

o) The FCR, aFRR and mFRR requirements that are established by the Transmission

System Operator.

p) Events that are notified to the Transmission System Operator, in accordance with

the Independent Transmission System Operation Code.

q) Other information collected and/or notified to the Transmission System Operator

in accordance with the Independent Transmission System Operation Code, as well

as other technical and simulation data regarding the operation of the Transmission

System.

Based on the Market Schedules sent by the Market Operator, the Transmission System

Operator determines:

a) the Final Internal Schedules per Dispatch Period of the Dispatch Day, which

correspond to generation and load Entities within Greece, and are equal to the

Market Schedule sent by the Market Operator, and

b) the Final External Schedules per Dispatch Period of the Dispatch Day, which

correspond to the import / export schedules on the interconnections, and take into

account the latest Market Schedules and the import / export deviations included

the latest Physical Transmission Rights nominations of the Participants, caused:

(1) either by the difference between the imported quantity included in the Market

Schedule of a Participant and his nomination of long-term Physical

Transmission Rights for electricity imports through an interconnection at

which an obligation for physical delivery exists;

(2) or by the difference between the sold / bought energy quantities in the Greek

Day-Ahead Market corresponding to short-term Physical Transmission

Rights and the bought / sold energy quantities in neighboring countries Day-

Ahead Market(s) corresponding to the same short-term Physical

Transmission Rights.

The Final Internal Schedules and the Final External Schedules are used by the

Transmission System Operator as input for the solution of the Integrated Scheduling

Process, for the solution of the Real-Time Balancing Energy Market and for Settlement

purposes,


7.9 Integrated Scheduling Process Solution Methodology

The ISP problem is solved as a Mixed Integer Linear Programming model, according to

the detailed description of the following Section 7.10.

If the Balancing Energy prices of different Balancing Energy Offersfor the same Dispatch

Period arithmetically coincide and the respective Balancing Energy quantities of such

Balancing Energy Offers are not included in their entirety in the ISP results, the priority of

(partial or whole) inclusion of such Balancing Energy Offers in the ISP results shall be

established at random.

If the Reserve Capacity prices of different Reserve Capacity Offers for an Ancillary

Service and for the same Dispatch Period arithmetically coincide, and the respective

Reserve Capacity quantities of such Reserve Capacity Offers are not included in their

entirety in the ISP results, the specific Reserve Capacity Offers that are partially or wholly

included in the ISP results are selected at random.

Where the ISP performs a random selection in accordance with the provisions described

herein, the Balancing Market System shall register the exact time of such random

selection, as well as the rest of the information to which it is related.

In case the model parameters for the execution of the ISP problem are modified by the

TSO, such modification shall be notified to the Regulator and to the BSPs with a written

letter, followed by a justification for the performed modification.

In case for a Dispatch Period of the Dispatch Day it is impossible to cover the forecasted

imbalances and/or the reserve requirements, the TSO must consider the provisions

concerning Extreme Conditions, namely:

a) include Balancing Energy Offers for Contracted Units, according to the

provisions of Paragraph 7.6.2, and

b) re-run the ISP problem in order to attain feasible results.

In case after the re-run of the ISP infeasibilities still appear in the imbalance covering

constraints and/or the reserve requirements constraints, then the infeasibilities in the

respective constraints are relaxed, and the problem is solved in realtime under the

provisions of Emergency Situations, as defined in the Independent Transmission System

Operation Code.The relaxation order should be as follows:

a) First, the upward and/or downward mFRR requirements are relaxed;

b) Second, the upward and/or downward aFRR requirements are relaxed;

c) Third, the upward and/or downward FCR requirements are relaxed;


d) Fourth, the system imbalance constraint is relaxed.

7.10 Mathematical Formulation

7.10.1 Objective Function

The ISP model is formulated as a co-optimization problem of Balancing Energy and the

various types of Reserve Capacity, and constitutes a Mixed Integer Linear Programming

model, as follows:

(1) Min BalancingEnergyCost ReserveCapacityCost CommitmentCost PenaltyCost

The TSO total cost (1) to be minimized over the scheduling horizonis expressed in € and

consists of the:

BalancingEnergyCost :procurement (as-bid) cost of Balancing Energy,

ReserveCapacityCost : procurement (as-bid) cost of Reserve Capacity,

CommitmentCost : start-up cost,

PenaltyCost : non-physical cost due to constraint violation when no physical

solution exists.

The above costs are described in the following Paragraphs.

7.10.2 Balancing Energy Cost

The Balancing Energy cost is expressed in € and represents the procurement cost of the

priced Upward and Downward Balancing Energy Offers for the entire system and all

Dispatch Periods.

The Balancing Energy cost is expressed as follows:

(2)

BEup BEup BEdn BEdnitk itkitk itk

i t k

BalancingEnergyCost D Quant Price Quant PriceI T K

Note that the Dispatch Period duration D is set to ½ hour for the ISP, since the Dispatch

Period is half-hourly. As already discussed, the Balancing Energy Offer prices shall

be submitted by the BSPs in €/MWh, while the Balancing Energy Offer quantities

shall be submitted in MWh per hour; the respective volume in MWh to be allocated

to the BSPs, taking into account the particular duration of the Dispatch Period (half-


hourly), is calculated directly in the ISP problem formulation through the use of

parameter D .

Note also in (2), that in case of downward Balancing Energy procurement, the TSO

receives (rather than pays) a revenue from the BSPs, since the provision of downward

Balancing Energy implies that:

a) the Generating Units avoid variable generation costs (i.e., their production is reduced

as compared to their Market Schedule), whereas

b) the Dispatchable Load Portfolios are scheduled to consume more (i.e., withdraw more

energy than their Market Schedule, for which they have not previously paid (i.e., in

the Forward, Day-Ahead or Intraday Market).

7.10.3 Reserve Capacity Cost

The Reserve Capacity cost is expressed in € and represents the as-bid cost for the

various types of Reserve Capacity (FCR, aFRR and mFRR in both directions)22, for the

full system and all Dispatch Periods. As the Reserve Capacity is not reallocated in real

time, this cost is used only in the ISP, and it is expressed as follows:

(3)

FCRup FCRup FCRdn FCRdnit itit it

i t

aFRRup aFRRup aFRRdn aFRRdnit itit it

i t

ReserveCapacityCost=

D Quant Price Quant Price

+D Quant Price Quant Price

I T

I T

mFRRup mFRRup mFRRdn mFRRdnit itit it

i t

RRup RRupRRns RRdn RRdnit it itit it

i t

+D Quant Price Quant Price

+D Quant Quant Price Quant Price

I T

I T

Again, parameter D is equal to ½ in the ISP. The Reserve Capacity Offer prices shall be

submitted by the Participants so as to reflect their opportunity costs when contributing to

the respective Reserve Capacity quantities on a half-hourly basis, and the effect of the

particular duration of the Dispatch Period (half-hourly) is considered directly in the ISP

problem formulation through the use of parameter D .

22 RR is included in all equations in this section (even though it shall not be used in the Greek Balancing Market), just

for future reference.


7.10.4 Start-up Cost

No commitment costs shall be taken into account in the solution of the ISP.

(4) CommitmentCost 0

7.10.5 Penalty Cost

The penalty cost is expressed in € and represents the non-physical cost due to constraint

violation when no feasible solution exists, for the full system and all Dispatch Periods. To

handle problem infeasibility under certain circumstances, violation (surplus / deficit)

variables are considered in certain constraints, and respective terms for penalizing the

violation variables are added to the objective function.

Τhe penalty cost in the objective function of the ISP model is defined in (5). As can be

noted, a violation penalty coefficient (i.e., a price in €/MW) is associated with each of the

violation variables. With large values assigned as penalty prices, values of the respective

violation variables are zero in a feasible solution. Any non-zero violation variable at the

solution indicates that the ISP problem is infeasible. When infeasibility is detected for any

constraint, a corresponding violation notification shall be available to the TSO in the

respective results.

Different penalty prices may be applied to reflect relative priorities in the enforcement of

the various constraints, according to the TSO needs. The constraints with larger penalty

coefficients have higher priorities in being satisfied than those with lower penalty

coefficients.

The TSO shall be able to modify the penalty prices at the Balancing and Ancillary Services

Market Database on-demand, given the approval of RAE. The penalty prices can be set

initially at the respective values indicated in the Nomenclature Section.


ZonImb DeficitZonImbzt

z t

ZonImb SurplusZonImbzt

z t

ZonFCRup ZonFCRdnzt zt

PenaltyCost

Deficit Price

Surplus Price

Deficit Deficit P

Z T

Z T

TotDeficitFCR

z t

ZonaFRRup ZonaFRRdn TotDeficitaFRRzt zt

z t

ZonmFRRup ZonmFRRdn TotDeficitmFRRzt zt

rice

Deficit Deficit Price


Z T

Z T

z t

ZonRRup ZonRRdn TotDeficitRRzt zt

z t


Z T

Z T

SysFCRup SysFCRdn TotDeficitFCRt t

t

SysaFRRup SysaFRRdn TotDeficitaFRRt t

t

SysmFRRupt


5 Deficit Deficit Price

Deficit

T

T

SysmFRRdn TotDeficitmFRRt

t

SysRRup SysRRdn TotDeficitRRt t

t

Deficit Price


T

T

Cap DeficitCapit

i t

Cap SurplusCapit

i t

MaxEnergy SurplusMaxEnergyit

i t

Deficit Price

Surplus Price

Surplus Price

I T

I T

I T

RampUp SurplusRampUpit

i t

RampDn SurplusRampDnit

i t

RampUpRes RampDnRes SurplusRampResit it

i t

Surplus Price

Surplus Price

Surplus Surplus Price

I T

I T

T

FCRup FCRdn SurplusFCRitit

i t


I

I T


aFRRup aFRRdn SurplusaFRRitit

i t

mFRRup mFRRdn SurplusmFRRitit

i t

RRup RRditit



Surplus Surplus

I T

I T

n SurplusRR

i t

ns Deficitnsit

i t

ns Surplusnsit

i t

DeficitGenConGenCon Gt t

Price

Deficit Price

Surplus Price

Deficit Price +Surplus

I T

I T

I T

SurplusGenConenCon

gc GC t

Price T

7.10.6 Dispatch Scheduling and Reserve Capacity Allocation Concept

Figure 7-4 exhibits the fundamental logic of the ISP model with regard to the dispatch

scheduling of a Generating Unit (positive y-axis) and a Dispatchable Load (negative y-

axis). As already discussed, the Market Schedule is the net energy schedule (net position)

resulting from all BSE trades in the wholesale market (i.e., trades in the Forward, Day-

Ahead or Intraday Market) concluded prior to the given ISP execution. Such Market

Schedule is depicted with the red dotted line in Figure 7-4 (either in the positive direction

regarding the Generating Unit, or in the negative direction regarding the Dispatchable

Load), and shall be automatically transferred (prior to the given ISP execution) from the

Market Operator to the TSO in order to be inserted as input data in the ISP model, namely

to be used as the initial position of the Generating Unit and the Dispatchable Load for the

solution of the ISP problem.

Since the Market Schedule is based on different (hourly) resolution from the ISP time-

step (half-hourly resolution), the Market Schedule shall be appropriately converted into

respective half-hourly MW values prior to insertion in the ISP model; for example, an

hourly Entity schedule of 150 MW shall be converted into two subsequent half-hourly

schedules of 150 MW.

During execution, the ISP model “builds” on these initial Market Schedules with upward

and/or downward Balancing Energy (see blue and orange areas, respectively, in Figure

7-4, either for the Generating Unit or for the Dispatchable Load), (i.e., the upward

Balancing Energy refers to an increase in the production level of a Generating Unit, a


Dispatchable RES Portfolio, and a decrease in the consumption level of a Dispatchable

Load Portfolio, with regard to their Market Schedules, while the downward Balancing

Energy refers to a decrease in the production level of a Generating Unit, a Dispatchable

RES Portfolio, and an increase in the consumption level of a Dispatchable Load Portfolio,

with regard to their Market Schedules).

Figure 7-4: Dispatch Scheduling in the ISP model

Specifically for the Dispatchable Load(or a DR Portfolio), as can be noted in Figure 7-4,

the Market Schedule itMS and the Dispatch Schedule itP are rather on the negative side

of the y-axis (they are considered as negative numbers for the solution of the ISP); max iP

indicates the full loading level (e.g., -100 MW) while min iP indicates the minimum

loading level (e.g., 0 MW / “out of operation” case), according to the respective Declared

Characteristics of the Dispatchable Load.

itz = 1

Off

t1 t2 t4 t5 t6 t8 t9

ity 1

On

itu 1itu 0

synitu = 1

Syn DispSoak Desdispitu = 1

desitu = 1

Upward

Balancing Energy

BEupitu = 1 BEdn

itu = 1

Downward

Balancing Energy

… … … … … …t3

Balancing Energy

Off

BEitu = 0

max

iP

min

iP

syn

iP

it(MS )

itP

(MW)

(h)

t7

soakitu = 1

Off

itu 0

Dispatch Schedule it(P ) Market Schedule

min

iP

Upward

Balancing Energy Downward

Balancing Energy

On

itu 1

Generating Unit

Dispatchable Load Portfolio

0

BEupitu = 1

BEdnitu = 1

ity 1 itz = 1

Balancing Energy

Off

BEupitu = 0

t


Τhe Balancing Energy procured in the ISP is aimed:

a) to cover mainly (1) the Non-Dispatchable Load Imbalance, namely the difference

between the Non-Dispatchable Load Forecast at the time of the ISP execution and

the Non-Dispatchable Load already cleared in the wholesale market (Forward, Day-

Ahead and Intraday Market), (2) the Non-Dispatchable RES Portfolios Imbalance,

namely the difference between the Non-Dispatchable RES Portfolios Forecast at the

time of the ISP execution and the Non-Dispatchable RES Portfolios production

already cleared in the wholesale market (Forward, Day-Ahead and Intra-Day Market),

as well as (3) the RES FiT Portfolio Imbalance, namely the difference between the

RES FiT Portfolio Forecast at the time of the ISP execution and the RES FiT Portfolio

production already cleared in the wholesale market (Forward, Day-Ahead and

Intraday Market), as further explained in Paragraph 7.10.20 (imbalance covering

constraints);

Figure 7-5: Reserve Capacity allocation in the ISP model

itz = 1

Off

t1 t2 t4 t5 t6 t8 t9

ity 1

On

synitu = 1

Syn DispSoak Desdispitu = 1

desitu = 1

… … … … ……t3

max

iP

min

iP

syn

iP

it(MS )

itP

(MW)

(h)

t7

soakitu = 1

Off

Dispatch Schedule it(P ) Market Schedule

min

iP

On

itu 1

Generating Unit

0

ity 1 itz = 1

min,AGC

iP

max,AGC

iP

FCR Up aFRR Up

FCR Down aFRR Down

Dispatchable Load Portfolio

t


b) to produce a technically feasible Dispatch Schedule for the BSEs based on a half-

hourly time-step and taking into account all associated BSE technical constraints;

c) to procure the required reserves for each type of Reserve Capacity (upward /

downward FCR, aFRR, mFRR, and RR), “on top” of the attained Dispatch

Schedule of each eligible BSE, taking into account the BSE’s capability to provide

any given type of Reserve Capacity. Figure 7-5 (extension of Figure 7-4) provides

a relevant example of such reserve allocation over the Dispatch Schedules (black

lines) of the afore-mentioned Generating Unit and Dispatchable Load. Specifically

for the Dispatchable Load, it is considered in Figure 7-5 that it has the capability

to contribute only to upward and downward RR.

7.10.7 Balancing Services Provider Operating States

Generating BSEs

The Dispatch Schedule ( itP ) of a generating BSE consists of various operating states,

which are presented in detail in the previous Figure 7-5 (with regard to a Generating Unit).

The Generating Unit starts-up at Dispatch Period t1 ( ity 1 ), after being reserved for a

prior period of time ( itu 0 ), and remains committed ( itu 1 ) until it shuts-down at

Dispatch Period t8( itz 1). Once committed, the Generating Unit follows four consecutive

operating phases denoted by binary variables synitu ,

soakitu ,

dispitu ,

desitu , respectively, as

follows:

1) Syn (synchronization). The synchronization phase represents the time needed

from the Generating Unit to be synchronized with the system; during this time, the

Generating Unit injection into the system is zero.

2) Soak (soak). The soak phase consists of up to six (6) (indicative number) pre-

defined half-hourly steps of MW values from the synchronization load syn

iP to the

technical minimum power output min

iP of the Generating Unit. All steps can also

be fixed to a certain value during the soak time (e.g., to the synchronization load syn

iP ) to model a constant soak trajectory.

3) Disp (normal dispatch). During normal dispatch, the Generating Unit varies its

output from its minimum power output min

iP to its nominal power output max

iP

according to its ramp-rate limits, and can contribute to the various types of spinning

Reserve Capacity.

4) Des(desynchronization). It concerns a stepwise desynchronization process with a

linear decrease rate from the Generating Unit minimum power output min

iP to zero

production.


The first two states (Syn and Soak) comprise the Generating Unit start-up phase. Different

start-up types are modeled, namely hot, warm and cold (as described in the following

Paragraphs) each with distinct synchronization time, soak time, and pre-defined start-up

power output trajectory, depending on the Generating Unit prior reservation time.

It should be stressed that the remaining generating BSEs, namely the Dispatchable RES

Portfolios, do not strictly have a synchronization, soak or desynchronization phase, thus

the respective times (i.e., the synchronization, soak and desynchronization times) in their

Registered Operating Characteristics shall normally be equal to zero (so as the ISP model

“bypasses” such operating phases for the given types of BSPs). Nevertheless, RES

Producers and RES Aggregators should be able to declare positive values for such

timings, in case such declaration resembles the start-up and shut-down processes of their

assets in a more accurate manner.

Loading BSEs (Dispatchable Load Portfolios)

The Dispatchable Load Portfolios have only one operating state, the normal dispatch

state denoted by the binary variable dispitu . In Figure 7-5, the Dispatchable Load starts-up

at Dispatch Period t4 ( ity 1 ), after being reserved (out of operation) for a prior period of

time ( itu 0 ), and remains committed ( disp

it itu u 1 ) until it shuts-down at Dispatch

Period t9 ( itz 1). During normal dispatch the Dispatchable Load can:

a) vary its output from its minimum loading level (min iP )to its maximum loading

level (max iP ) according to its ramp-rate limits, and

b) contribute to the various types of spinning Reserve Capacity being capable to

provide.

In this context, the following Paragraphs provide the formulation of the various operating

constraints / phases of the BSEEs, clarifying each time (a) which constraints apply only

for the generating BSEs (Generating Units, Dispatchable RES Portfolios), (b) which

constraints apply only for the Dispatchable Load Portfolios, and (c) which constraints

apply for all BSEs irrelevant of their specific category.

7.10.8 Start-up Phase

Special care has been given to the modeling of the BSE start-up sequence. Such

modeling is included only in the ISP and consists of two phases:

1) the synchronization phase (Syn) and

2) the soak phase (Soak).

As noted before, the above phases are modeled only for the BSEs i which are generating

Entities, thus all constraints presented below in this Paragraph apply only for the

Generating Units and the Dispatchable RES Portfolios, namely i G R2 .


The following constraints model the start-up sequence:

Start-up type constraints

Constraints (6) - (8) select the correct start-up type of BSE i (namely, hot, warm or cold),

depending on the BSE’s prior reservation time and its declared times off-load before going

into longer standby conditions ( HotToWarmiT and HotToCold

iT ). The binary variables hotity ,

warmity and

coldity indicate when a BSE begins a start-up phase in hot, warm and cold

conditions, respectively.

(6) ,HotToWarm

i

thotit i

t T 1

y z i t

G R2 T

(7) ,

HotToWarmi

HotToColdi

t Twarmit i

t T 1

y z i t

G R2 T

(8) ,

HotToColdit T

coldit i

1

y z i t

G R2 T

(9) ,hot warm coldit it it ity y y y i t G R2 T

Constraint (9) ensures that only one start-up type (hot, warm or cold) per start-up is selected. It is noted that modeling-wise the specific constraint (9) also applies for the

Dispatchable Load Portfolios having by default warm coldit ity y 0 , namely hot

it ity y

, i tL1 L3 T ; thus, it is considered that any start-up of a Dispatchable Load

Portfolio takes place in “hot conditions”.

Synchronization phase constraints

Constraints (10) - (12) ensure that a BSE i enters the synchronization phase immediately

following start-up (see also the synchronization phase of the Generating Unit between

periods t1 and t2 in Figure 7-5). The duration of the synchronization phase ,syn hotiT , ,syn warm

iT

or ,syn coldiT depends on the start-up type (hot, warm or cold). Thus, in (10) - (12) the

synchronization phase binary variable ,syn hot

itu , ,syn warm

itu or ,syn cold

itu is turned on,

whenever there is a hot, warm, or cold start-up of the BSE in the prior ,syn hotiT , ,syn warm

iT or

,syn coldiT hours, respectively. The latter constraint (13) ensures that only one

synchronization type (hot, warm or cold) per start-up is selected.


It is noted again that the synchronization times of the Dispatchable RES Portfolios shall

normally bear a zero value in their Registered Operating Characteristics, thus forcing the

ISP model to “bypass” the above synchronization operating phase for said BSEs (as is

currently the case with the fast hydro units in the Dispatch Scheduling of the TSO).

However, in case a Dispatchable RES Portfolio declares a (positive) synchronization time,

then the following constraints shall still be valid for such Entity.

(10) ,

,,

syn hoti

tsyn hot hot

iitt T 1

u y i t

G R2 T

(11) ,

,,

syn warmi

tsyn warm warm

iitt T 1

u y i t

G R2 T

(12) ,

,,

syn coldi

tsyn cold cold

iitt T 1

u y i t

G R2 T

(13) , , ,

,syn syn hot syn warm syn coldit it it itu u u u i t G R2 T

Soak phase constraints

Constraints (14) - (16) impose that a BSE i should enter a soak phase following its

synchronization (see also the soak phase of the Generating Unit between periods t2 and

t3 in Figure 7-5). The duration of the soak phase ,soak hotiT , ,soak warm

iT or ,soak coldiT depends

on the start-up type (hot, warm, or cold). A binary variable ,soak hot

itu , ,soak warm

itu or ,soak cold

itu is turned on during a soak phase after a hot, warm, or cold start-up,

respectively. Constraint (17) ensures that only one soak type (hot, warm, cold) per start-

up is selected.

(14)

,

, ,

, ,

syn hoti

syn hot soak hoti i

t Tsoak hot hotit i

t T T 1

u y i t

G R2 T

(15)

,

, ,

, ,

syn warmi

syn warm soak warmi i

t Tsoak warm warmit i

t T T 1

u y i t

G R2 T


(16)

,

, ,

, ,

syn coldi

syn cold soak coldi i

t Tsoak cold coldit i

t T T 1

u y i t

G R2 T

(17) , , , ,soak soak hot soak warm soak cold

it it it itu u u u i t G R2 T

Moreover, as shown in Figure 7-4, the power output of the Generating Unit during the

soak phase follows a pre-defined sequence of MW values ,soak hot

isP , ,soak warm

isP or ,soak cold

isP (depending on the type of start-up), for a number of half-hourly steps

,, ... , soak hotiTs 1 , ,, ... , soak warm

iTs 1 or ,, ..., soak coldiTs 1 , respectively.

Constraint (18) models such power output during the soak phase, based on the pre-

defined steps for each type of start-up.

(18)

,

,

,

,

,

,

, ( )

,

, ( )

,

, ( )

,

soak hoti

syn hoti

soak warmi

syn warmi

syn coldi

Tsoak soak hot hot

it is i t T s 1s 1

Tsoak warm warm

is i t T s 1s 1

soak cold coldis i t T s 1

s 1

P P y

P y i t

P y

G R2 T

,soak coldiT

It is noted that the pre-defined steps (soak trajectory) of each BSE for each type of start-

up (i.e., the parameters ,soak hot

isP , ,soak warm

isP and ,soak cold

isP used in (18)) shall be

recorded along with the associated soak time ( ,soak hotiT , ,soak warm

iT and ,soak coldiT ) in the

BSE’s Registered Operating Characteristics, as also stated in Section 5.3 (Generating

Unit Registries).

The registered soak trajectory shall consist of up to six pre-defined half-hourly steps of

MW values from the synchronization load syn

iP to the minimum power output min

iP of the

BSE. All steps can also be fixed to a certain value during the soak time (for example to

the synchronization load syn

iP ) to model a constant soak trajectory.


Finally, as for the synchronization time, the soak time of the Dispatchable RES Portfolios

shall normally bear a zero value in their Registered Operating Characteristics, thus forcing

the ISP model to “bypass” the above soak operating phase for said BSE s (as is currently

the case with the fast hydro units in the Dispatch Scheduling of the TSO). However, in

case for a Dispatchable RES Portfolio the respective BSP declares a (positive) soak time

along with an associated soak trajectory in its Registered Operating Characteristics, then

the above constraints shall still be valid for such Entity.

7.10.9 De-synchronization Phase

The de-synchronization phase (Des) modeling is included only in the ISP, to describe the

operation of a generating BSE from its minimum power output min

iP to zero production.

Again, this phase is modeled only for the BSEs i which are generating Entities. Thus, the

following constraints (19), (20) apply only for the Generating Units and the Dispatchable

RES Portfolios, namely i G R2 .

Constraint (19) ensures that a BSE should operate in a desynchronization phase (

desitu 1) the last des

iT hours before its shut-down ( itz 1 ). In (20), the power output of

the BSE during the de-synchronization process decreases linearly from its minimum

power output min

iP to zero production (see also the de-synchronization phase of the

Generating Unit between periods t7 and t8 in Figure 7-4).

(19) ,

desit T 1

desit i

t 1

u z i t

G R2 T

(20) min

,

desit T 1

des iit i des

t i

PP z t i t

T

G R2 T

Finally, as for the synchronization and the soak time, the desynchronization time of the

Dispatchable RES Portfolios shall normally bear a zero value in their Registered

Operating Characteristics, thus forcing the ISP model to “bypass” the above

desynchronization operating phase for said BSEs. However, in case for a Dispatchable

RES Portfolio the respective BSP declares a (positive) desynchronization time along with

a positive minimum power output min

iP in its Registered Operating Characteristics, then

the above constraints shall still be valid for such Entity.

7.10.10 Logical Status of Commitment

Constraint (21) is imposed to the generating BSEs (Generating Units and Dispatchable

RES Portfolios) to ensure that these BSEs operate each time at one of the various


operating states (Syn, Soak, Disp, Des), i.e., only one at most of the respective binary

variables can take a unitary value (1) in a given Dispatch Period t.

The Dispatchable Load Portfolios operate only in the normal dispatch state, as previously

discussed. In this case, constraint (21) is degenerated into the respective (22), which is

applied only to the Dispatchable Load Portfolios.

Constraint (23) models the logic of the start-up and shut-down status change, while

constraint (24) requires that a BSE i may not be started-up and shut-down simultaneously

in a given Dispatch Period t.

(21) ,syn dispsoak des

it it itit itu u u u u i t G R2 T

(22) ,disp

it itu u i t L1 T

(23) , it it it i t 1y z u u i tI T

(24) , it ity z 1 i t I T

The above two constraints (23) and (24) are enforced for all BSEs i irrespective of their

specific category (namely i G R1 R2 L1 L3I ).

7.10.11 Minimum Up / Down Time Constraints

Inequalities (25) and (26) enforce the minimum up and down time constraints,

respectively, uniformly for all BSEs. A BSE i must remain committed (de-committed) at

Dispatch Period t if its start-up (shut-down) started during the previous iMUT 1 ( iMDT 1)

hours.

(25) ,

i

t

i itt MUT 1

y u i tI T

(26) ,

i

t

i itt MDT 1

z 1 u i tI T

As described in Paragraph 5.3 (Dispatchable Load Registries), the Dispatchable Load

Portfolios shall also declare their minimum up and down times in their Registered


Operating Characteristics (as in the case of the Generating Units). Apparently, such times

can be declared with zero values, in case a Dispatchable Load Portfolio is not truly subject

to a minimum up or down time constraint.

Regarding the minimum up and down times of the Dispatchable RES Portfolios, these

are expected to be declared with zero values in the Dispatchable RES Registry

(Paragraph 5.3), thus essentially deactivating constraints (25) and (26) for such Entities.

7.10.12 Power Output Constraint

Equation (27) determines the Dispatch Schedule itP of each BSE, essentially arising

from:

a) its Market Schedule ( itMS ) obtained by the Market Operator,

b) its upward Balancing Energy ( itBEup ) scheduled in the ISP, and

c) its downward Balancing Energy ( itBEdn ) scheduled in the ISP.

Thus, (27) inherits the initial Market Schedule itMS , and computes the Dispatch Schedule

itP by adding upward Balancing Energy or subtracting downward Balancing Energy:

(27) , it it it itP MS BEup BEdn i tI T

Note that (27) is enforced for all BSEs in a uniform manner irrespectively of their specific

category.

It should be stressed again that a non-negative MW Market Schedule per Dispatch Period

t ( itMS ) shall be inserted in the ISP model for the generating BSEs (Generating Units,

Dispatchable RES Portfolios), while a non-positive MW Market Schedule per Dispatch

Period t shall be inserted for the loading BSEs (Dispatchable Load Portfolios) (opposite

of the positive MW schedule recorded for such Entities), according to the description of

the relevant Figure 7-4 (see, for example, the corresponding positive and negative red

dotted lines in this Figure, regarding the Generating Unit and the Dispatchable Load,

respectively).

7.10.13 Balancing Energy Constraints

The Balancing Energy quantities itBEup and itBEdn noted in the previous equality (27)

result from the respective step-wise Balancing Energy Offers submitted by the BSPs

according to the provisions of Section 2.6.


Thus, in (28) and (29) a Balancing Energy award ( itBEup or itBEdn ) for a given BSE i

and Dispatch Period t is derived from the cleared quantities of all steps k of the associated

BSP Balancing Energy Offer (i.e., BEupitkQuant or

BEdnitkQuant ).

(28) ,

BEup

it itkk

BEup Quant i tK

I T

(29) ,

BEdn

it itkk

BEdn Quant i tK

I T

Apparently, constraints (28) and (29), as well as the remaining constraints of this

Paragraph, apply for all BSEs irrespective of their specific category.

Constraints (30) and (31) ensure that the cleared quantity of each step k of a Balancing

Energy Offer is limited to the offered size of the step (i.e., BEupitkMaxQuant or

BEdnitkMaxQuant , for the upward or downward offers, respectively).

(30) , , BEup BEup BEup

ititk itkQuant MaxQuant u i t kI T K

(31) , , BEdn BEdn BEdnitk itk itQuant MaxQuant u i t kI T K

A respective minimum quantity ( itMinBEup or itMinBEdn ) of the Balancing Energy

procured (if procured) by BSE i in a given direction (upwards / downwards) and Dispatch

Period t can also be ensured (as a minimum “acceptance ratio”) through the imposition

of the following constraints (32) and (33).

(32) , BEup

it it itBEup MinBEup u i tI T

(33) , BEdnit it itBEdn MinBEdn u i tI T

The minimum quantity constraints (32) and (33) may be useful to specific BSEs to

approximate internal operating limitations of their resources which are not taken explicitly

into account by the ISP model; e.g., a Dispatchable Load can provide upward Balancing

Energy by switching off part of its demand, but this can be implemented for at least a

minimum quantity of demand, or a Combined Cycle Gas Turbine unit can provide upward


Balancing Energy by transiting to a new configuration state (i.e., committing another Gas

Turbine in addition to its Market Schedule), but such Balancing Energy shall come up to

a least minimum generation level (i.e., minimum power output of the additional Gas

Turbine).

The imposition of (32) and (33) introduces two new binary variables indicating the provision (“activation”) of Balancing Energy either in the upward or in the downward

direction (i.e., BEupitu and

BEdnitu , respectively).

In the example of Figure 7-4, the Generating Unit is committed earlier (in comparison to

its Market Schedule), by activating upward Balancing Energy ( BEupitu 1) at Dispatch

Period t2 and providing Balancing Energy quantities ( BEupitu 1) which correspond to the

pre-defined soak values until Dispatch Period t3. Upward Balancing Energy is

continuously awarded ( BEupitu 1) until the respective deactivation at Dispatch Period t5

and the restoration of the initial Market Schedule ( BEitu 0 ). A corresponding concept

applies for the activation and deactivation of downward Balancing Energy at Dispatch Periods t6 and t9, respectively, the provision of which incurs the Generating Unit’s shut-down at the intermediate interval t8 (based on the aforementioned linear de-synchronization process). An analogous logic (regarding the activation and deactivation of Balancing Energy and the Balancing Energy binary variable) applies also for the Dispatchable Load in Figure 7-4, or any other type of BSE.

It is noted again that the above minimum quantities of Balancing Energy (i.e., the

parameters itMinBEup and itMinBEdn ) shall be submitted by the BSPs as part of their

BSEs’ Balancing Energy Offers for any given Dispatch Period t, according to the provision

of Section 7.6.

(34) , BEup BEdn

ititu u 1 i tI T

Finally, as noted in Section 7.6.2, the offer prices submitted by the BSPs (Producers) for

their Generating Units should not be below the Units’ Minimum Variable Cost with regard

to Upward Balancing Energy Offers, and not above the Units’ Minimum Variable Cost with

regard to Downward Balancing Energy Offers.

However, as discussed in Section 7.6.2, there are no respective constraints on the

submitted offer prices for upward and downward Balancing Energy for the Dispatchable

RES Portfolios and the Dispatchable Load Portfolios. It is considered rational that the

respective BSPs operating / representing such BSEs shall submit higher prices for

providing upward Balancing Energy and lower prices for providing downward Balancing

Energy, in which case the activation of Balancing Energy from said BSEs will


deterministically take place in only one direction (upwards or downwards) in any given

Dispatch Period t. However, such rational bidding behaviour cannot be absolutely

foreseen.

In the opposite case, namely if the BSPs submit lower prices for providing upward

Balancing Energy and higher prices for providing downward Balancing Energy, their

Balancing Energy may be activated in both directions in a given Dispatch Period t (since

such counteractive provision minimizes the TSO cost in equality (2)), in which case the

BSPs experience undue losses. To prohibit such counteractive provision in case of

irrational bidding behaviour by one or more BSPs, the ISP problem may encompass

constraint (34) for choosing to activate only one (upward or downward) of the two services

from a BSE i in a given Dispatch Period t.

7.10.14 Capacity Constraints

Generating BSEs

Constraints (35) - (39) coordinate the Dispatch Schedule itP of each generating BSE

(Generating Unit, Dispatchable RES Portfolio) with the BSE contribution in any given

type of spinning Reserve Capacity (i.e., FCRupitQuant ,

FCRdnitQuant ,

aFRRupitQuant ,

aFRRdnitQuant ,

mFRRupitQuant ,

mFRRdnitQuant ,

RRupitQuant ,

RRdnitQuant ), within the

respective minimum and maximum BSE technical limits in every operating state (Syn, Soak, Disp, Des).

More specifically, the first three terms of the right-hand side of (35) - (39) constrain the

Dispatch Schedule of the BSE during the synchronization, soak and desynchronization

phases. In these phases the minimum and maximum limits essentially take the same

value forcing the Dispatch Schedule to be fixed to that value. Thus, in the synchronization

phase (i.e., when synitu 1) the Dispatch Schedule will be equal to 0, while in the soak

and de-synchronization phases, the Dispatch Schedule will be equal to soak

itP and des

itP ,

as these variables have been defined in equalities (18) and (20), respectively.

Constraints (35), (36) describe the BSE minimum limits:

(35) min

,

FCRdn aFRRdn mFRRdn RRdn Capit it it it it it

syn soak des dispit it it it it

P Quant Quant Quant Quant Deficit

0 u P P P u i t

G R2 T


(36) min

min, ,

Cap syn dispaFRRdn soak des AGCit it it it it itit it it

AGC AGCi it

P Quant Deficit 0 u P P P u u

P u i t

G R2 T

Constraints (37) - (39) describe the BSE maximum limits:

(37) max min max

( )desi

FCRup aFRRup mFRRup RRup Capit it it it it it

syn dispsoak desit it it it itit it i t T

P Quant Quant Quant Quant Surplus

0 u P P P u P P z

, i t G R2 T

(38) max

,


syn soak des dispit it it it it


0 u P P P u i t

G R2 T

(39)

max max, ,

aFRRup Cap syn soak desit it itit it it

disp AGC AGC AGCit it i itit

P Quant Surplus 0 u P P

P u u P u i t

G R2 T

It is noted that constraints (36) and (39) enforce the particular BSE minimum (min, AGC

iP

) and maximum (max,AGC

iP ) limits when aFRR is procured and the BSE is scheduled to

operate under AGC in the corresponding Dispatch Period t ( AGCitu 1). An illustrative

example of such aFRR procurement within the Generating Unit’s AGC limits has been provided in the previous Figure 7-5. Finally, the last term in the right-hand side of (37)

ensures that a generating BSE will operate at its minimum power output (min

itP ) at the

Dispatch Period prior to entering the desynchronization phase, as also shown in the illustrative example of Figure 7-4 (see the Dispatch Schedule of the Generating Unit in period t6). This term must be omitted for the generating BSEs not having a desynchronization phase (e.g., Dispatchable RES Portfolios or fast Generating Units). Thus, (37) is enforced only for the generating BSEs which actually have a

desynchronization phase (i.e., if des

iT 1 ), while the respective (38) (in which the afore-

mentioned last term has been omitted) is enforced for all generating BSEs (i.e., if des

iT 0

).

It should be noted that the problem formulation ignores the detailed technical constraints

of multi-shaft units, for simplicity reasons. Nevertheless, in case such formulation is


deemed necessary by the TSO, it can be easily incorporated in the herein described

model.


As previously noted, the Dispatchable Load Portfolios may operate only in the normal

dispatch state, during which they may contribute to the various types of Reserve Capacity,

also including aFRR (i.e., they may be scheduled to operate under AGC in case they

acquire the relevant technical capability). In this context, the capacity constraints

presented above for the generating BSEs are degenerated into the following constraints

(40) - (43) for the Dispatchable Load Portfolios.

Constraints (40), (41) describe the maximum loading limits:

(40) max

,

FCRdn aFRRdn mFRRdn RRdn Capit it it it it it

dispit it

P Quant Quant Quant Quant Deficit

P u i t

L1 T

(41)

max

max, ,

Cap dispaFRRdn AGCit it it itit it

AGC AGCi it

P Quant Deficit P u u

P u i t

L1 T

Constraints (42), (43) describe the minimum loading limits:

(42) min

,


dispit it


P u i t

L1 T

(43) min min,

,

aFRRup Cap disp AGC AGC AGCit it it it it it i itP Quant Surplus P u u P u

i t

L1 T

Note that the formulation of the above constraints is consistent with the convention adopted in the previous Figure 7-4 for the Dispatchable Load. The Dispatchable Load

technical limitations max

itP (full loading level, e.g., 100 MW), min

itP (minimum loading level,

e.g., 0 MW / “out of operation” case), max,AGC

iP (full loading level when operating under


AGC, e.g., 80 MW) and min, AGC

iP (minimum loading level when operating under AGC,

e.g., 20 MW) are obtained as positive values from its Declared Characteristics. The

Dispatch Schedule itP is then delimited during the ISP execution (through the above

constraints) between min itP and

max itP , or min, AGC

iP and max, AGC

iP (in the case

of aFRR provision), taking also into account the contribution of the Dispatchable Load into the various types of Reserve Capacity. Under this convention, the Dispatch Schedule

itP of a Dispatchable Load or a DR Portfolio shall take only non-positive values in the ISP

results, while the upward Balancing Energy awards ( itBEup ) and the downward

Balancing Energy awards ( itBEdn ) take only non-negative values as for the generating

BSEs.

7.10.15 Hydro Mandatory Generation

Constraint (44) is imposed only to the hydro Generating Units (i.e., i H ) in order to

ensure that their Dispatch Schedules itP resulting from the ISP solution will be greater

than or equal to their mandatory injections for any given Dispatch Period t. The mandatory

generation itMand of a hydro Generating Unit shall be nominated to the TSO (through

the Hydro Mandatory Injections Declaration) on a half-hourly basis, in order to be properly

taken into account for the solution of the ISP.

(44) , it itP Mand i tH T

It should be noted that the mandatory injections of hydro units (according to the provisions

of the current Power Exchange Code) should have a special treatment in the Day-Ahead

Market Coupling process. In case they are not declared to cover forward or OTC contracts

by the respective Producers, they (upon the consent of the TSO on the declared

quantities) should be inserted in the Local Order Book of LAGIE and in the Market

Coupling input data as “price-taking” energy offers, in order to be cleared with priority in

the Market Coupling results (zonal market prices) and thus be included in the hydro units’

Market Schedules that will be initially inserted in the ISP model.

Such rule is not necessary in order to avoid gaming from the hydro Producer (e.g., a hydro

Producer deliberately provokes a zero Market Schedule for his hydro units, and the ISP

and RTBEM solutions activate upward Balancing Energy from these units to satisfy

constraint (44)), since in the Balancing Market these activated Balancing Energy Offers

shall be remunerated at the marginal Balancing Energy price and not pay-as-bid. Such

rule is rather necessary in order to avoid the distortion of the wholesale market, since in

case of zero Market Schedules from hydro units (being inserted at the ISP), the Day-

Ahead Market prices may probably be higher than the attained prices of the RTBEM (in


a fully competitive market structure), something which shall distort the market signals to

the BRPs (which may become unconcerned for their imbalances).

7.10.16 Maximum Daily Energy Constraint

The limit for the maximum daily energy production ( iMaxEnergy ) of the Generating Units

is imposed through (45) in the ISP. This constraint shall be enforced only for the

Generating Units, in case such Units have limits in their maximum daily generation. It is

noted however that these limits mainly concern the hydro injections.

Essentially, constraint (45) applies only when parameter iMaxEnergy is strictly positive.

Again, parameter D is equal to 1 hour.

(45)

MaxEnergyit i iit

t

P D Surplus MaxEnergy IniEnergy iT

G

Additionally, the maximum energy iMaxEnergy is decreased in each subsequent ISP

execution (i.e., ISP2, ISP3, ISP on-demand) by the amount of energy ( iIniEnergy ) already

(scheduled to be) produced during the previous Dispatch Periods (i.e., from the beginning

of the Dispatch Day until the start of the scheduling horizon in question).

Apparently, the parameter iIniEnergy takes a zero value for ISP1. For the rest ISPs, the

initial energy is computed through the expression (46):

(46)

CurrentPeriod 1 HorizonStart 1

i it itt 1 t CurrentPeriod

IniEnergy ActualMW PlannedMW i G

itActualMW is a parameter representing the actual instructed generation (in MW) for all

Dispatch Periods t until the previous of the CurrentPeriod (period of the ISP execution).

itPlannedMW is a parameter representing the generation planned for the Generating

Unit by the latest validated ISP run for all residual periods until before the start of the

scheduling horizon ( HorizonStart ).


Finally, it is noted that the sum of the Market Schedules itMS of a Generating Unit for all

Dispatch Periods t shall not overcome the value of the right-hand side of (45) for a given

ISP execution (BSE obligation to be imposed by regulatory means), namely the value

i iMaxEnergy IniEnergy , to avoid gaming behavior from the respective Participants.

7.10.17 Ramping Constraints

A BSE has limits on its ability to move from one level of MW to another within a specified

time period. The following constraints model such limitations separately for the generating

BSEs and the loading BSEs.

Generating BSEs (Generating Units, Dispatchable RES Portfolios)

Constraints (47) and (48) enforce the ramp rate limits on the power output between

consecutive Dispatch Periods for the generating BSEs (Generating Units, Dispatchable

RES Portfolios). Inequality (47) models the upward ramping constraint, while inequality

(48) models the downward ramping constraint.

Note that W is a large constant, so that these constraints are relaxed when a BSE is in

the synchronization, soak or desynchronization phase.

(47) RampUp disp syn soak

it i itit it iti t 1P P Surplus 60 RU u W u u

i , t

G R2 T

(48) RampDn disp des

it i it itit iti t 1P P Surplus 60 RD u W z u

i , t

G R2 T


Analogous ramping constraints are enforced for the Dispatchable Load Portfolios.

Inequality (49) models the upward ramping constraint (“load pickup rate”), while inequality

(50) models the downward ramping constraint (“load drop rate”) in this case.

(49) RampUp disp

it it i iti t 1P P Surplus 60 RU u i , t L1 T

(50) RampDn disp

it it i it iti t 1P P Surplus 60 RD u W z i , t L1 T


Note that the above constraints have been adjusted (as compared to the previous (47)

and (48)) so as to take into account the fact that the Dispatch Schedules itP of the

Dispatchable Load Portfolios take non-positive values. In this case:

a) the parameter iRU refers to the maximum increase in the loading level of a

Dispatchable Load or a DR Portfolio in MW/min, e.g., a Dispatchable Load with

niRU 1 MW/mi can move from -50 MW to -110 MW in 60-minutes time; while

b) the parameter iRD refers to the maximum decrease in the loading level of a


niRD 1 MW/mi can move from -80 MW to -20 MW in 60-minutes time.

The last term in the downward ramping constraint (50) associated with parameter W is

used to relax this constraint when the Dispatchable Load or DR Portfolio is

desynchronized in the current Dispatch Period t. In this case itP 0 and i t 1P 0 , thus

the left-hand side of (50) is positive while the first term of the right-hand side is zero (

dispitu 0 ); however, the last term with itz 1 relaxes the constraint to allow for the proper

de-synchronization of the Dispatchable Load or DR Portfolio in the current period t.

7.10.18 Reserve Capacity Ramping Constraints

Constraints (51) - (54) introduce the effect of the ramp rate limits on the aggregated BSE

contribution in aFRR, mFRR and RR (per each direction, respectively).


Specifically for the generating BSEs (Generating Units, Dispatchable RES Portfolios) the

maximum - ramp-limited - contribution in upward aFRR, mFRR and RR in each half-hourly

Dispatch Period t is given by inequality (51), while the respective maximum contribution

in downward aFRR, mFRR and RR is given by inequality (52):

(51) aFRRup mFRRup RRup RampUpResRRns

itit it it it

i

Quant Quant Quant Quant Surplus

60 RU i , t

G R2 T

(52)

RampDnResaFRRdn mFRRdn RRdnit it it it

i

Quant Quant Quant Surplus

60 RD i , t

G R2 T


Accordingly, for the Dispatchable Load Portfolios, the maximum - ramp-limited -

contribution in upward aFRR, mFRR and RR in each half-hourly Dispatch Period t is given


by inequality (53), while the respective maximum contribution in downward aFRR, mFRR

and RR is given by inequality (54):

(53) aFRRup mFRRup RRup RampUpResRRns

itit it it it

i

Quant Quant Quant Quant Surplus

60 RD i , t

L1 T

(54) RampDnResaFRRdn mFRRdn RRdn

it it it it

i

Quant Quant Quant Surplus

60 RU i , t

L1 T

Note, again that the parameter iRD in the case of a Dispatchable Load or a DR Portfolio

refers to the maximum decrease in the loading level, thus, it is associated with the

activation of upward reserves in (53), while the parameter iRU refers to the maximum

increase in the loading level, thus, it is associated with the activation of downward

reserves in (54).

7.10.19 Reserve Capacity Contribution Constraints

As already discussed, the Ancillary Services Market is only part of the ISP; no further

market-based procurement of the various types of Reserve Capacity (upward / downward

FCR, aFRR, mFRR, RR) shall take place in the RTBEM. Thus, the following constraints

(55) - (71) which model the BSE maximum contribution to each type of Reserve Capacity

are only included in the ISP model. These constraints are applicable to all BSE s

irrespective of their specific category.

It is noted that:

a) the maximum contribution of BSE i in a given type of Reserve Capacity (i.e., RCtypeiMaxQuant in the following constraints) is computed by the Energy

Balancing System according to the provisions of Section 7.7. For the BSEs that cannot contribute to any given type of Reserve Capacity, the respective maximum

contribution RCtypeiMaxQuant shall be set to zero (as per the Declared

Characteristics);

b) the contribution in spinning reserves takes place only in the dispatchable phase

of any given BSE (i.e., when dispitu 1 ). Νo reserve contribution is modeled during

the start-up phase (synchronization and soak phases) and the shut-down phase (de-synchronization phase), as also illustrated in the previous Figure 7-5.


FCR contribution

The BSE maximum contribution to upward and downward FCR is modeled in (55) and

(56), respectively:

(55) , FCRup FCRup FCRup dispit it i itQuant Surplus MaxQuant u i t I T

(56) , dispFCRdn FCRdn FCRdn

it it i itQuant Surplus MaxQuant u i t I T

Since the FCR aims at the relief of instant incidents occurring within the real-time Dispatch

Period (e.g., load variations or disturbances occurring within each 15-min interval of the

RTBEM), thus the FCR procured from each BSE at the ISP shall be maintained in the

RTBEM in order to be available after each real-time solution (namely, within the real-time

Dispatch Period). This is achieved in the RTBEM by inheriting the FCR awards obtained

by the ISP execution as fixed incremental / decremental quantities over the RTBEM

Dispatch Schedules of the eligible BSEs, as further explained in Chapter 3.

aFRR contribution

Constraints (57) - (59) model the respective contribution in aFRR.

More specifically, (57) states that a BSE may provide aFRR (operate under AGC /

AGCitu 1) only at the dispatchable phase (

dispitu 1 ). For the BSEs that cannot operate

under AGC, the AGC binary variably (AGCitu ) shall be fixed to a zero value in the ISP,

through an associated flag.

The BSE maximum contribution to upward and downward aFRR is then modeled in (58)

and (59), respectively:

(57) , dispAGC

it itu u i tI T

(58) , aFRRup aFRRup aFRRup AGC

itit it iQuant Surplus MaxQuant u i tI T

(59) , aFRRdn aFRRdn aFRRdn AGCit it i itQuant Surplus MaxQuant u i t I T

Since the aFRR (AGC operation) aims at the relief of the load and RES variability

occurring within the real-time Dispatch Period, thus the aFRR procured from each BSE

at the ISP shall be maintained in the RTBEM, in order to be available after each real-time


solution (namely, within the real-time Dispatch Period). Again, this is achieved in the

RTBEM by inheriting the aFRR awards obtained by the ISP execution as fixed

incremental / decremental quantities over the RTBEM Dispatch Schedules of the eligible

BSEs, as further explained in Chapter 8.

An additional constraint can also be added to the clearing to ensure that the BSEs’

contribution to aFRR cannot be less than a certain percentage of their NCAP (i.e., 0.7%),

as currently considered by the TSO. The minimum percentage shall be the same for all

BSEs and its value shall be configurable according to the TSO preference (given the

approval of the Regulator). However, the minimum percentage configured can be equal

to zero, in which case the additional constraint is disabled. This additional constraint can

be written as follows:

(60) , aFRRup aFRRdn AGC

it i ititQuant Quant Percent NCAP u i tI T

Fast aFRR contribution

Moreover, as currently implemented by the TSO, a sufficient amount of fast (upward or downward) aFRR with 1-min ramping capability can be secured by the BSEs selected for

(upward or downward) aFRR, by introducing an auxiliary variable FastaFRRupitQuant or

FastaFRRdnitQuant , and enforcing constraints (61) - (64) in combination with the respective

system reserve requirement constraints (86) and (87).

(61) , FastaFRRup aFRRupit itQuant Quant i tI T

(62) min , FastaFRRup AGC

iitQuant RR 1 i t I T

(63) , FastaFRRdn aFRRdnit itQuant Quant i t I T

(64) min , FastaFRRdn AGCit iQuant RR 1 i t I T

mFRR contribution

The BSE maximum contribution to upward and downward mFRR is modeled in (65) and

(66), respectively:

(65) , mFRRup mFRRup mFRRup dispit it i itQuant Surplus MaxQuant u i tI T


(66) , dispmFRRdn mFRRdn mFRRdn

it it i itQuant Surplus MaxQuant u i tI T

The mFRR procured by each BSE in the ISP shall be released in the RTBEM, namely it

shall be activated (if needed) as Balancing Energy by the RTBEM clearing engine, in

order to cover the load and RES movements at this slower (as compared to the FCR and

aFRR activation) timeframe (i.e., movements from each 15-min real-time Dispatch Period

to the following 15-min real-time Dispatch Period).

RR contribution

Accordingly, the BSE maximum contribution to upward and downward spinning RR (if

such product exists) is modeled in (67) and (68), respectively:

(67) , RRup RRup RRup dispit it i itQuant Surplus MaxQuant u i tI T

(68) , dispRRdn RRdn RRdn

it it i itQuant Surplus MaxQuant u i t I T

As in the case of mFRR, the RR procured by each BSE in the ISP shall be released in

the RTBEM, namely it shall be activated (if needed) as Balancing Energy, in order to

cover the load and RES movements at a slower timeframe (e.g. RR Dispatch Instructions

issued 30 minutes prior to the respective delivery period).

It should be noted that with regard to the loading BSEs (Dispatchable Load Portfolios), the provision of upward / downward mFRR and RR in the above constraints shall be associated with the provision of upward / downward Balancing Energy in the ISP, in order the loading BSE not to be awarded with mFRR or RR Reserve Capacity in Dispatch Periods in which it is not scheduled for a DR event (i.e., for the provision of Balancing

Energy). In this case, constraints (65) – (68) shall rather utilize the binary variables BEupitu

or BEdnitu appropriately, instead of the binary variable

dispitu , only for these BSEs.

Non-spinning RR contribution

Finally, some generating BSEs are able to provide upward RR even when off-line ( itu 0

and nsitu 1 ). This represents the non-spinning RR and currently concerns particularly

the fast start peaker and the hydro units. However, other generating BSEs (e.g., a

Dispatchable RES Portfolio) may also be able to provide non-spinning RR in the future,

by receiving direct Dispatch Instructions by the TSO to be committed (if needed) in real-

time operation. The non-spinning RR contribution is delimited between the BSE minimum

power output and maximum technical capability to provide non-spinning RR, as follows:


(69) , nsit itu 1 u i tI T

(70) min , RRns ns ns

it it it itQuant Deficit P u i tI T

(71) , RRns ns RRns nsit it i itQuant Surplus MaxQuant u i tI T

It is noted that the above constraints (69) - (71) are enforced for all BSEs. However, for

the BSEs that cannot provide non-spinning RR (e.g., Dispatchable Load Portfolios), the

maximum contribution to non-spinning RR RRnsiMaxQuant takes a zero value from their

Registered Operating Characteristics (Section 7.7); in this case, the non-spinning binary

variable (nsitu ) can also be fixed to a zero value prior to the ISP solution, through a

respective flag.


7.10.20 Zonal Imbalance covering Constraints (Inter-zonal Transfer Model)

As already discussed, the latest Market Schedules of all Entities referred in Paragraph

5.1 are sent by the Market Operator to the TSO (Balancing Market Management System)

for the purposes of the ISP execution. These Market Schedules respect in advance the

following power balance equation (on a zonal basis):

Non-dispatchable Entities: Forecast establishment by the TSO.

Dispatchable Entities (BSEs): Balancing Energy procurement to cover any

forecasted deviations of the non-dispatchable Entities from their Market Schedule.

where:

itGenUnitMS is the Market Schedule of the Generating Unit i for Dispatch Period

t,

itResPortMS is the Market Schedule of the Dispatchable RES Portfolio i for

Dispatch Period t,

ztResFiTPortMS is the sum of the Market Schedules of the RES FiT Portfolios for

all RES categories in Bidding Zone z for Dispatch Period t,

jtNonDispResUnitMS is the Market Schedule of the Non-Dispatchable RES

Portfolio j for Dispatch Period t,

,

z z

z z4

z z3

it iti i

zt jt jtj j

inter t itinter i

jtj

GenUnitMS ResPortMS

ResFiTPortMS NonDispResUnitMS + CommisMS +

ImpMS = DRPortMS

NonDispLoadMS

2G R

R C

INTER L

L , , ,

,

z z zinter t zz t z z t

inter z

t

ExpMS + Flow Flow +

ForecastedSystemLosses z t

2 INTER Z

Z T


jtCommisMS is the Market Schedule of the Generating Unit / RES Unit in

Commissioning or Testing Operation j for Dispatch Period t,

,inter tImpMS is the scheduled import at interconnection inter for Dispatch Period t,

itDRPortMS is the Market Schedule of the Dispatchable Load Portfolio i for

Dispatch Period t,

jtNonDispLoadMS is the Market Schedule of the Non-Dispatchable Load Portfolio

j for Dispatch Period t, and

,inter tExpMS is the scheduled export at the interconnection inter for Dispatch

Period t.

tForecastedSystemLosses is the difference between the forecasted losses in the

transmission system and the already cleared quantities in the Day-Ahead Market

and the Intra-Day Market for Dispatch Period t.

This power balance is already respected since the above-mentioned Market Schedules

have been obtained by respective balanced Participant transactions in the wholesale

market.

Now, the scope of the ISP imbalance covering equation is to cover any TSO-forecasted

deviations of the non-dispatchable Entities from their Market Schedules, by procuring

appropriately Balancing Energy from the dispatchable Entities, namely from the BSEs.

Thus, the imbalance covering constraint is described by the following linear equation (72),

taking into account a decomposition of the system into different Bidding Zones z.

In (72), the net Balancing Energy procured from all dispatchable BSEs per each zone z

(i.e., the first term on the left-hand side) covers the forecasted zonal imbalances, which

consist of the following components:

Non-Dispatchable Load Portfolios Imbalance

The zonal Non-Dispatchable Load Portfolios Imbalance is the difference between:

a) the zonal Non-Dispatchable Load Forecast ztNonDispLoadFR ; this forecast shall

be established by the TSO as provisioned in Section 7.11, and

b) the zonal Non-Dispatchable Load Portfolios already cleared in the Forward

(including OTC contracts), Day-Ahead and Intraday Market


z

jtj

NonDispLoadMS

2L

; this sum is essentially an aggregation of the latest

Market Schedules of all Non-Dispatchable Load Portfolios, as obtained by the

Market Operator for the current ISP.

Important note:

The Load Representatives shall nominate their Forward Market, Day-Ahead Market

and Intra-Day Market traded (bought) quantities separately for each Dispatchable

Load Portfolio i and for the Non-Dispatchable Load Portfolio j represented by them,

in order the Marker Operator to be able to determine the individual Market

Schedules of each Dispatchable Load Portfolio i and of the Non-Dispatchable Load

Portfolio j per Load Representative.


z

z

it iti I

zt jtj

BEup BEdn

NonDispLoadFR NonDispLoadMS

72

2L

,

,

z4

z

zt zt

zt jtj

jt jt inter tj

z t

ResFiTPortFR ResFiTPortMS

NonDispResUnitFR NonDispResUnitMS

CommisDS CommisMS ImpDev ExpDe

R

C

Z T

,

, ,

z

z

inter tinter

ZonImb ZonImbzt zt zz t z z t t

z

v

Deficit Surplus Flow Flow ForecastedSystemLosses

INTER

Z

RES FiT Portfolio Imbalance

The zonal RES FiT Portfolio Imbalance is the difference between:

a) the zonal RES FiT Portfolio Forecast ztResFiTPortFR ; this forecast shall be

established by the TSO as provisioned in Paragraph 7.11, and

Non-Dispatchable Load Portfolios Imbalance


Commissioning Imbalance

Net Balancing Energy from BSEs

Flow deviations at the interconnections

Non-Dispatchable RES Portfolios Imbalance


b) the zonal RES FiT Portfolio production already cleared in the wholesale market

ztResFiTPortMS ; this is essentially the latest Market Schedule of the RES FiT

Portfolio in Bidding Zone z, as obtained by the Market Operator for the current

ISP.


The zonal Non-Dispatchable RES Portfolios Imbalance is the difference between:

a) the zonal Non-Dispatchable RES Portfolios Forecast ztNonDispRESUnitFR ; this

forecast shall be established by the TSO as provisioned in Paragraph 7.11, and

b) the zonal Non-Dispatchable RES Portfolios production already cleared in the

wholesale market

z4

jtj

NonDispRESUnitMSR

; this is essentially an aggregation

of the latest Market Schedules of all Non-Dispatchable RES Portfolios, as

obtained by the Market Operator for the current ISP.


With regard to the Generating Units / RES Units in Commissioning or Testing Operation,

the difference between a) and b) below essentially constitutes another zonal imbalance

(the zonal “Commissioning Imbalance”):

a) the Units’ MW schedules declared to the TSO prior to the given ISP execution

through the Commissioning Schedules Declarations ( jtCommisDS , j C ), and

b) the Units’ latest Market Schedules, submitted to the Market Operator at the Day-

Ahead Market and Intraday Market stage and inserted in the respective clearings

as “price-taking orders” ( jtCommisMS , j C ).

This imbalance shall also be covered by the activation of upward or downward Balancing

Energy in (72).


These include the following categories:

a) The difference between the imported quantity in the Market Schedule (sold in the

Forward, Day-Ahead and Intraday Markets) by a trader and his nomination of

long-term Physical Transmission Rights (PTRs) for electricity imports through an


interconnection (e.g. Bulgaria, Italy) for which an obligation for physical delivery

exists,

b) The difference between the sold / bought energy quantity in the Greek Day-Ahead

Market corresponding to short-term (daily) PTRs and the bought / sold energy

quantities in neighboring countries Day-Ahead Market(s) corresponding to the

same daily PTRs,

c) Adjusting schedules for flow inadvertent deviations at the interconnections,

d) emergency schedules,

e) return of emergency schedules,

f) guarantees of commercial schedules that relate to the cases when an

interconnection is out of operation for more days than a maximum threshold

(included in the respective Auction Rules), and the TSO is obliged to guarantee

the commercial schedules beyond that threshold,

g) return of guarantees of commercial schedules, or

h) deviations for any other future-established purpose.

All the above constitute zonal imbalances that shall be covered appropriately by the

activation of Balancing Energy in (72).

Respective imbalances of adjacent Bidding Zones

The respective imbalances (as per the above-mentioned ones) of adjacent Bidding Zones

of each zone z can be covered with the activation of Balancing Energy from the given

zone z, through the consideration of corresponding corridor flows on the right-hand side

of (72) (i.e., Balancing Energy corridor flows).

Constraint (73) enforces the flow limit of the corridor between adjacent Bidding Zones z

and z’:

(73) , , , ' , Max zzz t zz tFlow AvailableFlow z z tZ Z T

It is noted that the corridor flows resulting from the right-hand side of (72) and constrained

by (73) above represent the additional flows produced by the ISP due to the procurement


of Balancing Energy and the possible sharing of such Balancing Energy between

neighboring Bidding Zones. Essentially, these “Balancing Energy” flows are only

incremental flows over those already established in the wholesale market (i.e., prior to

the given ISP execution). In this context, the maximum limit ,Maxzz tAvailableFlow imposed

in (73) constitutes the residual transfer capacity in each corridor, after subtracting the

corridor flow already scheduled in the wholesale market (Forward, Day-Ahead and

Intraday Market).

7.10.21 Zonal Imbalance covering Constraints (Flow-Based Model)

The Flow-Based (FB) model allows a better representation of the physical power flow

constraints, as compared to the simple transportation model (e.g. ATC-based model).

Under the Flow-Based model the zonal net positions are translated into physical flows in

critical branches through the usage of (linear) Power Transfer Distribution Factors

(PTDFs), thus achieving a physically feasible solution of the market clearing problem.

The following constraints (74)-(77) are enforced in order to apply the Flow-Based model

in the zonal imbalance covering equation in the ISP:


z

z

it iti I

zt jtj

BEup BEdn


74

2L

,

,

z4

z

zt zt

zt jtj

jt jt inter tj

z t



CommisDS CommisMS ImpDev ExpDe

R

C

Z T

,

zinter t

inter

ZonImb ZonImbzt zt zt

v

Deficit Surplus NetInjection

INTER

(75) , , ,

z

zz t z z t ztz

Flow Flow =NetInjection z tZ

Z T

(76)

,, ,,

, ' ,

z ref z

zz t z tzz tz

Flow = PTDF NetInjection z z tZ Z T

(77) , , , ' ,Max zzz t zz tFlow AvailableFlow z z t Z Z T

7.10.22 Reserve Requirements Constraints

The following constraints (78) - (95) ensure that the total contribution of the BSEs in each

type of Reserve Capacity (upward / downward FCR, aFRR, mFRR, RR) meets the

associated zonal / system reserve requirements. These constraints are enforced only in

the ISP since there is no additional market-based procurement of reserves in the RTBEM.


FCR requirements constraints

The sum of the BSEs’ contribution in FCR must be greater than or equal to the zonal FCR

requirement in each direction (upwards / downwards), as imposed in (78) and (79),

respectively. Similar constraints (80) and (81) apply on a system basis:

(78) ,

z

FCRup ZonFCRup FCRupzt ztit

i

Quant Deficit Req z tI

Z T

(79) ,

FCRdn ZonFCRdn FCRdnit zt zt

i

Quant Deficit Req z tzI

Z T

(80)

FCRup SysFCRup FCRup

t titi

Quant Deficit Req tI

T

(81)

FCRdn SysFCRdn FCRdnit t t

i


T

aFRR requirements constraints

The sum of the BSEs’ contribution in aFRR must be greater than or equal to the zonal

aFRR requirement in each direction (upwards / downwards), as imposed in (82) and (83),


(82) ,

aFRRup ZonaFRRup aFRRup

zt ztiti


Z T

(83) ,

aFRRdn ZonaFRRdn aFRRdnit zt zt

i


Z T

(84)

aFRRup SysaFRRup aFRRup

t titi


T

(85)

aFRRdn SysaFRRdn aFRRdnit t t

i


T

With respect to the system requirements for fast aFRR with 1-min ramping capability,

these can be covered through constraints (86) and (87) for each direction (upwards /

downwards), respectively:


(86)

FastaFRRup FastaFRRup

titi

Quant Req tI

T

(87)

FastaFRRdn FastaFRRdnit t

i

Quant Req tI

T

mFRR requirements constraints

The sum of the BSEs’ contribution in mFRR must be greater than or equal to the zonal

mFRR requirement in each direction (upwards / downwards), as imposed in (88) and (89),


(88) ,

mFRRup ZonmFRRup mFRRup

zt ztiti


Z T

(89) ,

mFRRdn ZonmFRRdn mFRRdnit zt zt

i


Z T

(90)

mFRRup SysmFRRup mFRRup

t titi


T

(91)

mFRRdn SysmFRRdn mFRRdnit t t

i


T

RR requirements constraints

Finally, the sum of the BSEs’ contribution in RR must be greater than or equal to the zonal

RR requirement in each direction (upwards / downwards), as imposed in (92) and (93),

respectively. Again, similar constraints (94) and (95) apply on a system basis:

(92) ,

RRup RRns ZonRRup RRup

it zt ztiti

Quant Quant Deficit Req z tzI

Z T

(93) ,

RRdn ZonRRdn RRdnit zt zt

i


Z T

(94)

RRup RRns SysRRup RRup

it t titi

Quant Quant Deficit Req tI

T


(95)

RRdn SysRRdn RRdnit t t

i


T

7.10.23 Generic Constraints

The modeling of the generic constraints currently established by the TSO shall still be

valid in the ISP problem of the new market design.

Generic constraints provide a simple way for the user to program additional security type

constraints into the market clearing engine. They can be defined for the MW power output

itP (BSE generation / load) and/or the upward RR contribution RRupitQuant (allocation of

upward RR on the BSE). More specifically, the generic constraint feature shall be used

to:

a) define an additional RR requirement on a regional or blocks of units’ base,

b) model the minimum total energy injection into a Bidding Zone,

c) model manual constraints to fix the schedule of chosen BSEs for certain reasons

(i.e. voltage constraint, intra-zonal transmission constraint, etc.).

The generic constraints in the ISP are described mathematically in (96) - (98):

(96) , ,,

,

RRup RRupP GenConit it gc t gcit it gc

i i

GenCont gc

P Factor Quant Factor Surplus

Limit t gcT, GC

(97)

RRup RRupP GenConit it ,gc t ,gcit it ,gc

i i

GenCont ,gc

P Factor Quant Factor Deficit

Limit t gc T, GC

(98) , ,,

, ,

RRup RRupP GenConit it gc t gcit it gc

i i

GenCon GenCont gc t gc

P Factor Quant Factor Surplus

Deficit Limit t gc T, GC


It is noted that multiple generic constraints gc can be enforced for the same Dispatch

Period t.

7.10.24 Specific Operating Constraints for the Loading BSEs (Dispatchable Load Portfolios)

As already discussed, there are certain constraints regarding the provision of Balancing

Energy from loading BSEs (Dispatchable Load Portfolios), which shall be included in the

mathematical formulation, in order to help such BSEs to participate more effectively in the

market. These constraints are as follows:

Minimum delivery period constraints for the provision of Balancing Energy

Constraints (99) and (100) impose a minimum delivery period on the provision of

Balancing Energy (if activated) from a given BSE, in the upward or downward direction,

respectively. A BSE i must deliver Balancing Energy in the upward (downward) direction,

at Dispatch Period t, if the relevant activation of upward (downward) Balancing Energy

occurred during the previous BEup

iMinDP 1 ( BEdn

iMinDP 1 ) hours. The minimum delivery

periods BEupiMinDP and BEdn

iMinDP are technical characteristics which are submitted by the

respective operators in the Techno-Economic Declaration.

(99) ,BEup

i

tBEup BEupi it

t MinDP 1

y u i t

L1 T

(100) ,BEdn

i

tBEdn BEdni it

t MinDP 1

y u i t

L1 T

Maximum delivery period constraints for the provision of Balancing Energy

Constraints (101) and (102) impose a maximum delivery period on the provision of

Balancing Energy (if activated) from a given BSE, in the upward or downward direction,

respectively. A BSE i must not deliver Balancing Energy in the upward (downward)

direction, at Dispatch Period t, if a relevant de-activation of upward (downward) Balancing

Energy does not occur in the following BEupiMaxDP ( BEdn

iMaxDP ) hours. The maximum

delivery periods BEupiMaxDP and BEdn

iMaxDP are technical characteristics which are

submitted by the respective operators in the Techno-Economic Declaration.


(101) ,

BEupit MaxDP

BEup BEupi it

t 1

z u i t

L1 T

(102) ,

BEdnit MaxDP

BEdn BEdni it

t 1

z u i t

L1 T

Minimum baseload period constraints

Constraints (103) and (104) impose a minimum baseload period, namely a minimum

period between two successive activations of Balancing Energy from a given BSE, in the

upward or downward direction, respectively. A BSE i must not deliver Balancing Energy

in the upward (downward) direction, at Dispatch Period t, if a relevant de-activation of

upward (downward) Balancing Energy occurred during the previous iMinBP 1 hours. The

minimum baseload period iMinBP is a technical characteristic which is submitted by the

respective operators in the Techno-Economic Declaration.

(103) ,

i

tBEup BEupi it

t MinBP 1

z 1 u i t

L1 T

(104) ,

i

tBEdn BEdni it

t MinBP 1

z 1 u i t

L1 T

Maximum frequency of activations for the provision of Balancing Energy in

the course of a day

Constraints (105) and (106) impose a maximum frequency in the activations of Balancing

Energy from a given BSE in a certain Dispatch Day, in the upward or downward direction,

respectively. A BSE i shall not activate Balancing Energy in the upward (downward)

direction, in a given Dispatch Day, more than BEupiMaxFA (

BEdniMaxFA ) times. The

maximum frequency of activations BEupiMaxFA or

BEdniMaxFA is a technical

characteristic which is submitted by the respective operators in the Techno-Economic

Declaration.

It should also be noted that such characteristic shall be adjusted appropriately in

successive ISP executions in the course of a Dispatch Day (i.e. ISP2 – ISP3), in order to

take into account the already scheduled activations of Balancing Energy from a given

BSE in previous ISP executions.


(105) BEup BEupit i

t

y MaxFA i

T

L1

(106) BEdn BEdnit i

t

y MaxFA i

T

L1

Logical relationships of the Balancing Energy binary variables

Finally, similar logical relationships which govern the commitment binary variables, are

also applicable for the Balancing Energy binary variables, as follows:

(107)

,BEup BEup BEup BEupit it it i t 1

y z u u i t

L1 T

(108) ,BEdn BEdn BEdn BEdnit it it i t 1y z u u i t L1 T

(109) ,BEup BEupit ity z 1 ti L1 T

(110) ,BEdn BEdnit ity z 1 ti L1 T

7.11 Responsibilities of the Transmission System Operator

In the context of the Integrated Scheduling Process the TSO assumes the following

responsibilities:

1) The TSO shall establish the zonal Non-Dispatchable Load Forecast for each Dispatch

Period of the Dispatch Day used for the calculation of the zonal Non-Dispatchable

Load Imbalance in constraints (72) or (74) of the ISP model.

The Non-Dispatchable Load Forecast can be updated for each subsequent ISP

execution (i.e., ISP1, ISP2, ISP3, and any on-demand ISP) with regard to the

concerned Dispatch Periods.

For the establishment of the Non-Dispatchable Load Forecast, the TSO takes

account of the following information concerning the Dispatch Periods in question:

a) historical Non-Dispatchable Load data and statistics resulting from their

processing, such as load evolution per energy usage category,

b) weather condition forecasts, historical load data under similar weather conditions,

as well as comparable statistics, and especially load co-variation and weather

condition parameters,


c) events which the TSO knows in advance they will occur,

d) Transmission System / Distribution System operations that shall affect the

average half-hourly Non-Dispatchable Load at a certain Transmission Meter, of

which the TSO has been informed, and

e) other information collected and notified to the TSO.

2) The TSO shall establish the zonal RES FiT Portfolio Forecast for each Dispatch

Period of the Dispatch Day used for the calculation of the zonal RES Fit Portfolio

Imbalance in constraints (72) or (74) of the ISP model.

The RES FiT Portfolio Forecast can be updated for each subsequent ISP execution

(i.e., ISP1, ISP2, ISP3, and any on-demand ISP) with regard to the concerned

Dispatch Periods.

For the establishment of the RES FiT Portfolio Forecast, the TSO takes account of

the following information concerning the Dispatch Periods in question:

a) historical RES injection data (regarding the RES FiT Portfolios), and statistics

resulting from their processing,

b) weather condition forecasts (wind speed, solar radiation, etc.), historical RES

injection data (regarding the RES FiT Portfolio) under similar weather conditions,

as well as comparable statistics, and especially RES injection co-variation and

weather condition parameters,


d) other information collected and notified to the TSO.

3) The TSO shall establish the zonal Non-Dispatchable RES Portfolios Forecast for

each Dispatch Period of the Dispatch Day used for the calculation of the zonal Non-

Dispatchable RES Portfolios Imbalance in constraints (72) or (74) of the ISP model.

The Non-Dispatchable RES Portfolios Forecast can be updated for each subsequent

ISP execution (i.e., ISP1, ISP2, ISP3, and any on-demand ISP) with regard to the


For the establishment of the Non-Dispatchable RES Portfolios Forecast, the TSO

takes account of the following information concerning the Dispatch Periods in

question:

a) historical Non-Dispatchable RES Portfolios injection data, and statistics resulting

from their processing,

b) weather condition forecasts (wind speed, solar radiation, etc.), historical Non-

Dispatchable RES Portfolios injection data under similar weather conditions, as


well as comparable statistics, and especially the RES units’ injection co-variation

and weather condition parameters,


d) Especially the RES Producer representing the Non-Dispatchable RES Portfolio

must send an injection forecast to the TSO for each Dispatch Period of the

Dispatch Day, not later than 13:00 EET of day D-1, which may be taken into

account by the TSO for the establishment of the Non-Dispatchable RES Portfolios

Forecast.

e) other information collected and notified to the TSO.

4) The TSO shall establish the zonal / system reserve requirements of upward and

downward FCR, aFRR and mFRR for each Dispatch Period of the Dispatch Day, used

in the reserve requirements constraints (78) - (95) of the ISP model, by utilizing

reliable and suitable scientific methodologies, as analyzed in Annex Β.

The zonal / system reserve requirements can be updated for each subsequent ISP

execution (i.e., ISP1, ISP2, ISP3, and any on-demand ISP) with regard to the


During the zonal / system reserve requirements establishment, the TSO shall assess

the need to procure FCR, aFRR and mFRR, in order to ensure adequate system

response / regulation / replacement reserves within acceptable limits established in

the Hellenic Transmission System Operation Code, taking account of the

particularities of the System.

5) The TSO shall publish at its website seven (7) hours prior to the ISP Gate Closure

Time (namely not later than 09:00 EET in day D-1) the following information for each

Dispatch Period of the Dispatch Day:

a) the zonal Non-Dispatchable Load Forecast,

b) the RES FiT Portfolio Forecast,

c) the zonal Non-Dispatchable RES Portfolios Forecast

d) the system upward and downward FCR, aFRR and mFRR requirements.

The Non-Dispatchable Load Forecast, the RES FiT Portfolio Forecast, the zonal Non-

Dispatchable RES Portfolios Forecast, and the reserve requirements shall be

updated by the TSO and published at its website two (2) hours prior to the ISP1 GCT.

They shall also be updated for each subsequent programmed ISP execution

regarding the Dispatch Day in question, and published at the TSO website two (2)

hours prior to such execution.


6) The TSO receive and apply validation rules for the Balancing Energy Offers, Reserve

Capacity Offers, Non-Availability Declarations and Techno-Economic Declarations

from the BSPs.

7) The TSO shall decide on the validity of the Balancing Energy Offers and the Reserve

Capacity Offers submitted in the context of participation in the Balancing and Ancillary

Services Market.

8) The TSO shall acquire the operation schedules of the Generating Units / RES Units

in Commissioning or Testing Operation by the respective Producers, through the

Commissioning Schedules Declarations.

9) The TSO shall acquire the mandatory generation schedules of hydro Generating

Units by the respective Producers, through the Hydro Mandatory Injections

Declarations.

10) The TSO shall establish the cross-zonal transmission capacity among the internal

Bidding Zones for the solution of the ISP.

11) The TSO shall establish the import / export schedule deviations at the

interconnections for the solution of the ISP (constraint (72) or (74)).

12) The TSO shall operate the Balancing Market System, which shall exchange the

appropriate information with the Market Operator (acquire the latest Market

Schedules), in order to operate efficiently the Balancing Market, in accordance with

the provisions described in this document.

13) The TSO shall solve the ISP problem for each subsequent ISP session, according to

the timelines provided for in Section 7.1.

14) After each ISP solution, the TSO shall send to BSPs the part of the ISP results that

concern their BSEs, namely the results described in Section 7.12. The TSO shall also

prepare and publish such results in its website, in accordance with the timelines

provisioned in Section 7.1.

15) The TSO shall publish statistics and information relating to the monitoring of the

Balancing Market.

16) The TSO shallpublish in its website until 12:00 EET of each calendar day D+1 balance

information for each Real-Time Unit of the previous Dispatch Day D, regarding the

deviations of the Transmission System real operation from the Non-Dispatchable

Load Forecast, RES FiT Portfolio Forecast and Non-Dispatchable RES Portfolios

Forecast performed in day D-1 / D.

17) The TSO shall keep records with regard to the data and other parameters used for


the Non-Dispatchable Load Forecast, the RES FiT Portfolio Forecast, the Non-

Dispatchable RES Portfolios Forecast and the zonal / system reserve requirements,

as well as the results of these forecasts for each calendar year. The TSO shall publish

and notify to the Regulator statistics about the accuracy of the foregoing forecasts

within two (2) months from the end of each calendar year.

18) The TSO shall prepare a timetable of activities (an ISP timetable) governing the

actions required for the solution of the ISP, and this timetable shall be published on

the TSO website and shall be updated from time to time upon reasonable notice to

BSPs. The ISP Timetable shall include activities required for the Dispatch Day and

activities to be performed on the preceding day (the day ahead).

7.12 Integrated Scheduling Process Results

The ISP results of any given ISP execution contain the following:

a) a commitment schedule of the Balancing Service Entities;

b) the FCR, aFRR and mFRR awards per Balancing Service Entity and per Dispatch

Period of the Dispatch Day; and

c) an indicative production schedules of the Balancing Service Entities for each

Dispatch Period of the Dispatch Day, called ISP Schedule.

The Integrated Scheduling Process results are biding as follows:

a) the results of ISP1 are non-binding;

b) the results of ISP2 are binding only for the first twenty-four (24) Dispatch Periods

of Dispatch Day D, and

c) the results of ISP3 are binding for the last twenty-four (24) Dispatch Periods of the

Dispatch Day D.

Any preliminary acceptance (proactive procurement) of Balancing Energy Offers within

the ISP problem execution is not firm and not subject to any BSP-TSO settlement. The

ISP half-hourly production schedules do not constitute real Dispatch Instructions, but their

goal is to inform the respective Participants so that they take all necessary actions in order

to make to all extent possible the potential activation of their Balancing Energy Offers.

The provision of the Reserve Capacity awards resulted from the ISP by the Balancing

Service Entities is mandatory. In case of non-availability of such Reserve Capacity by a

BSE in real time, a non-compliance charge shall be imposed by the Transmission System

Operator to the respective Participant.


7.13 Integrated Scheduling Process Results Publication

One (1) hour after the ISP1 Gate Closure the Transmission System Operator shall

prepare and publish the results for the initial execution of the Integrated Scheduling

Process (ISP1).

Forty-five (45) minutes after each subsequent scheduled or unscheduled execution of the

Integrated Scheduling Process, the Transmission System Operator shall prepare and

publish the results for such execution.

Immediately after that, the Transmission System Operator shall notify all parties having

submitted accepted Balancing Energy Offers and Reserve Capacity Offers the part of the

Integrated Scheduling Process results concerning them. Such notification is not

considered a Dispatch Instruction, but its intent is to inform its recipient so that the latter

takes all necessary actions in order to proceed to the maximum extent possible with the

potential activation of the Balancing Energy Offer, and to provide the Reserve Capacity

awards during the Dispatch Day.

7.14 Integrated Scheduling Process Results Monitoring

Every calendar day D+1, not later than 11:00 EET, the TSO shall automatically transfer

all data, parameters and results of the subsequent ISPs solved for the Dispatch Day D in

editable format to the Regulator, in order the latter to monitor the normal operation of the

scheduling process and identify any potential sources of misconduct or strategic bidding

that may distort the ISP results and the scheduling of the BSEs.


8 Real-Time Balancing Energy Market

The 2nd phase of the Central Dispatch process is the Real-Time Balancing Energy Market

(RTBEM). This Chapter provides the detailed design specifications regarding the

operation of the RTBEM in the new market design in Greece. This includes the proposed

timeframe and Dispatch Period, the rigorous definition of the Balancing Services

products, the modification of Balancing Energy Offers by the BSPs during the RTBEM,

the required input data in RTBEM, the proposed RTBEM solution methodology and

mathematical formulation, the RTBEM results, the resulting Dispatch Instructions, etc.).

Such RTBEM shall be applicable until the transition into a common Balancing Market

solver in the future, since some changes / adjustments will need to be implemented

thereafter.

It is noted that two execution processes are described in this Chapter for the RTBEM; (a)

one that is more familiar with the current economic dispatch procedures in real-time

(single techno-economic clearing), and (b) one that is closer to the Target Model for the

Balancing Market and the incorporation to a common Balancing Market solver with other

European countries (including the conversion process for the consideration of the unit

technical limitations and derivation of a merit order and subsequent economic clearing).

The first execution approach shall be applied in the 1st implementation phase of the

Balancing and Ancillary Services Market in Greece, whereas the second execution

process shall be applied during the respective 2nd implementation phase.

8.1 General

The RTBEM is the market for procuring and activating Balancing Energy in real

time in order to balance supply and demand while considering all applicable real-

time system conditions. In that respect, the RTBEM refines the Market Schedules

of the BSEs at a more granular level than the half-hourly time resolution of the ISP,

to address continuous changes in the system / zonal load and renewable

production, as well as changes in resource availability and system conditions that

may occur in real time.

The mFRR process inherits the commitment decisions taken in the ISP and does

not re-evaluate these commitment decisions, nor does it make any additional

optimal BSP commitment. Thus, it is not a unit commitment application, but rather

an economic dispatch process, which respects and follows the ISP commitment

decisions, unless a relevant resource suffers a forced outage in which case it

becomes unavailable in the mFRR process or the load, or renewable production

and system conditions change considerably during the real-time process. In such

cases, a new run of the ISP (ISP on-demand) shall provide the necessary

commitment decisions to follow in real time. Also in such cases, instant actions


can be taken by the TSO (e.g commit a unit, set a unit under AGC) that have not

been foreseen by the latest ISP, through direct (not scheduled) instructions.

Moreover, within the spirit of the Network Code on Electricity Balancing and the Target

Model in general, the mFRR process does not procure any additional Ancillary Services.

Indeed:

a) The mFRR schedules determined in the ISP are effectively released by the eligible

BSEs at each Dispatch Period of the mFRR process, in order to be optimally activated

as Balancing Energy for the relief of the very short-term forecasted imbalances.

b) The FCR and aFRR schedules determined in the ISP remain in effect at each

Dispatch Period of the mFRR process (i.e., they are being secured by the eligible

BSEs having been awarded such reserves in the ISP); they are then released closer

to real time, namely within the real-time Dispatch Period (e.g., through the operation

of AGC for aFRR) to manage the load and renewable production variability and any

unforeseen events taking place at a more instant timeframe. This applies unless the

eligible resource becomes unavailable due to an outage, in which case a new run of

the ISP shall provide the new FCR and aFRR awards to be available, as already

discussed.

8.2 Dispatch Period

The following provisions apply with regard to the Dispatch Period in the RTBEM:

1) A 15-min Dispatch Period shall be engaged in the RTBEM clearing engine.

2) Accordingly, all Balancing Energy Offers in the RTBEM have 15-min validity period or

longer.

3) There are 96 Dispatch Periods in each Dispatch Day, except from Dispatch Days

when daylight saving time changes occur where the number of Dispatch Periods

changes accordingly. Dispatch Periods commence at 00:00 on the Dispatch Day.

8.3 Balancing Services Products – Dispatch Process

8.3.1 Balancing Services Products

The following types of Balancing Energy products shall be applicable in real-time

operation23:

23 RAE Decision 67/2017, Guidelines and instructions to the competent market operators for the establishment of market codes according to par. 2 of article 6 of l. 4425/2016. Available online:


a) Upward and downward mFRR Balancing Energy activated through the mFRR

clearing engine in each 15-minute Real Time Unit. Essentially, the mFRR that was

secured by the BSEs as Reserve Capacity in the ISP shall be effectively released

in the mFRR process and activated (if needed) as mFRR Balancing Energy for

the relief of the very short-term forecasted imbalances. The Available Capacity of

the Balancing Service Providers that was not secured as Reserve Capacity in the

ISP is also available for activation of mFRR Balancing Energy Offers in the mFRR

process.

b) Upward and downward aFRR Balancing Energy activated through the AGC

operation. BSPs shall submit energy offers associated to the activation of aFRR

(i.e., aFRR Balancing Energy Offers), which shall be considered for the derivation

of the Economic Participation Factors. The Economic Participation Factors will be

input – along with other factors, like ramp-rates – in the AGC function to distribute

the Area Control Error (ACE) to the resources operating under AGC. An

appropriate pricing mechanism shall then provide the prices for the compensation

of the activated aFRR Balancing Energy (maximum price between the marginal

price resulting from the mFRR clearing and the aFRR energy bid of the BSP), as

detailed in Chapter 9.

The detailed methodology for the derivation of the Economic Participation Factors

and the aFRR Balancing Energy pricing mechanism shall be further analyzed

during the implementation phase of the RTBEM; in this Chapter, we focus only on

the functionality of the mFRR clearing engine (case (a) above).

8.3.2 mFRR Process (two executions methods)

1st implementation phase - Single techno-economic clearing

At the 1st implementation phase, the execution method is more familiar with the current

(2017) economic dispatch procedure of ADMIE; the main difference is that a 15-min

interval shall be applied, instead of a 5-min time-step.

As can be seen in Figure 8-1 (upper part, regarding 1st implementation phase), the TSO

executes the mFRR clearing algorithm for each subsequent 15-min interval (rolling basis).

As further discussed in Section 8.8, the single mFRR optimization problem is a techno-

economic problem, including both the main technical/operational constraints of the

resources (e.g. ramp-rates) and the economic clearance of the market for the optimal

activation of Balancing Energy.

The mFRR process is executed at -3΄ (from the start of the 15-minute period, namely for

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0΄ – 15΄), and results in the upward and downward mFRR Balancing Energy (in MWh)

that must be provided by each BSP. The resulted mFRR Balancing Energy is then

expressed in MW production that the BSP must reach at the end of the 15-minute period

(0΄ – 15΄), generating as follows:

a) the Balancing Service Entity must start ramping up or ramping down from the

beginning of the Real Time Unit (minute 0΄) until reaching the Dispatch Instruction

level (in MW) and then stay at this level until the end of the Real Time Unit (minute

15΄).

b) The shape of the production/withdrawal level during the Real Time Unit (0΄ – 15΄)

is such that the provided mFRR upward or downward Balancing Energy is equal

to the respective mFRR Balancing Energy resulted from the solution of the mFRR

process.

This process is executed every 15 minutes, providing new Dispatch Instructions to BSPs

for each Real Time Unit (15-minute period).

2nd implementation phase – Conversion process for merit order /

subsequent economic clearing

At the 2nd implementation phase, the mFRR process execution shall be closer to the

Target Model for the Balancing Market and the incorporation to a common Balancing

Market solver with other European countries. As in the 1st implementation phase, the TSO

shall execute the mFRR clearing algorithm for each subsequent 15-minute interval (on a

rolling basis), with each execution taking place 15 minutes (indicative time) prior to the

15-min Dispatch Period in question (see second diagram of Figure 8-1 regarding the 2nd

implementation phase).

However, each execution is now divided into two main steps:

a) a conversion process for the derivation of an appropriate merit order of the BSPs’

mFRR Balancing Energy Offers; and

b) the mFRR economic clearing execution.


Figure 8-1: mFRR clearing process (two implementation phases)


With regard to the second step mentioned above (mFRR clearing), this step

minimizes the total activation cost of mFRR Balancing Energy in order to cover the

very short term forecasted imbalances for the Dispatch Period in question. In order

to comply with the Target Model provisions, the mFRR clearing in this case shall

constitute a pure economic activation problem for mFRR which (a) excludes the

BSE technical / operating constraints, while also (b) it does not take into account

other types of Balancing Capacity (FCR, aFRR) having been awarded to the BSEs

(in the ISP) for the Dispatch Period in question.

Thus, in order (a) to attain feasible results in the mFRR clearing, and (b) to secure

the Balancing Capacity (FCR, aFRR allocated in the ISP) for possible activation

after the mFRR clearing and closer to real time (e.g., instant events, AGC

operation), while retaining the pure economic structure of the mFRR clearing

(Target Model provisions), a set of respective constraints is taken into account in

a separate pre-process, the “conversion process” (see respective building block

in Figure 8-1). The conversion process is solved prior to each mFRR clearing

referring to the same 15-min dispatch interval, and aims:

a) to adjust (limit) the maximum quantity of mFRR Balancing Energy offered by the

BSEs, subject to the BSE technical / operating constraints, and taking into account

the already allocated Balancing Capacity (FCR, aFRR) in the ISP;

b) to provide a corresponding merit order of the converted BSEs’ Balancing Energy

Offers, which shall be available for the execution of the subsequent mFRR clearing.

It is noted that no particular action is required by the BSPs during or prior to the above-

mentioned processes, other than submitting (in the ISP) and optionally updating (until the

respective RTBEM GCT) their Balancing Energy Offers. The various processes shall be

automatically executed by the TSO according to analytical specifications provided in the

following Sections of this Chapter.

When ADMIE enters the common Balancing Market solver with other European

countries for the exchange of mFRR through the interconnections, it is expected

that some changes will have to be implemented (if any) in the mFRR solver in this

second implementation phase. Essentially, ADMIE will have to cancel the mFRR

economic clearing process (second step described above), since this will be

undertaken by the common Europe-wide solver. The conversion process shall still

be applicable prior to sending the Balancing Energy Offers to the common clearing

engine for possible activation, so as to ensure the feasibility of the results.

In the above context and with reference to the third diagram of Figure 8-1, the solution of

the mFRR clearing (e.g., at time 45’) shall activate an mFRR Balancing Energy Offer (for

the quarterly Dispatch Period 60’ - 75’), in which case the activated offer will have a 12.5-

min Full Activation Time (47.5’ - 60’) and a 15-min Full Delivery Period (60’ - 75’). For this


offer, the respective Dispatch Instruction is issued at time 47.5’ (see corresponding

orange circle in Figure 8-1), or the sooner possible after the results of the mFRR clearing

have been obtained. Note that there must be some time period between clearing and

sending of Dispatch Instructions. The required time for the clearing, sending of the

Dispatch Instructions, acknowledging the receipt of Dispatch Instructions, etc. shall be

considered during the implementation phase.

Note also, that the Full Activation Time (ramp) is not explicitly modeled within the clearing

engine, but is rather the “blank” time between the issuance of the Dispatch Instruction

and the respective initialization of the Full Delivery Period.

Finally, the settlement period for the BSPs (fourth diagram in Figure 8-1) coincides with

the Full Delivery Period of each mFRR Balancing Energy Offer activated by the clearing

engine.

8.4 Modification of Balancing Energy Offers by the Balancing Services Providers

In Central Dispatch systems the scheduling and dispatch process starts in day D-

1 (ISP) and continues up till real time. Substantial changes of offers during the real-

time dispatching process might lead to sub-optimal dispatch and could expose the

TSO and energy consumers as well as other Participants to very high costs. As

BSPs know in advance some results of the dispatch process (for example, the

decision about start-up and shut-down of Generating Units) they may use this

knowledge to abuse market power, for example by substantially changing the

incremental / decremental Balancing Energy Offer prices after obtaining

information that their resource will be operating in any given hours of the following

Dispatch Day D. For this reason, the opportunity for BSPs in Central-Dispatch

systems to subsequently modify their offers may be limited in the terms and

conditions (something which is also recognized in the Network Code on Electricity

Balancing of ENTSO-E). The above observations are especially valid for immature

or rapidly evolving markets.

The overall process requires therefore rules for the update / modification (during the

RTBEM) of the offers submitted in the ISP by the BSPs for their eligible BSEs. The

following provisions apply with regard to such possible modifications of the Balancing

Energy Offers after their original submission (i.e., submission prior to the ISP GCT):

1) As already stated in Section 7.6, all Balancing Energy Offers of the ISP corresponding

to the Dispatch Day D are submitted prior to the ISP1 GCT (16:00 EET in calendar

day D-1). The BSPs submit half-hourly step-wise (up to ten steps) Balancing Energy

Offers in the ISP, where Balancing Energy prices for successive steps must be strictly

non-decreasing for upward offers and non-increasing for downward offers. Each step

bears a positive upward / downward Balancing Energy quantity in MW, with accuracy


of up to 3 decimal points, and an offer price in €/MWh with accuracy of up to 2 decimal

points.

2) At the ISP1 GCT and in order the half-hourly ISP Balancing Energy Offers to be

properly taken into account in the 15-min process of the RTBEM, the ISP Balancing

Energy Offers shall be automatically converted (in the Balancing Market Management

System) into respective 15-min offers for the RTBEM. Essentially, each half-hourly

ISP Balancing Energy Offer shall cascade into two (2) equivalent 15-min RTBEM

Balancing Energy Offers for both mFRR and aFRR processes, with the same format

and for the same MW quantities and prices as the initial offer. The only feature that

changes is the validity period. Thus, the Balancing Energy Offers in the RTBEM are

15-min step-wise (up to ten steps) offers, where Balancing Energy prices for

successive steps must be strictly non-decreasing for upward offers and non-

increasing for downward offers. Each step bears a positive upward / downward

Balancing Energy quantity in MW, with accuracy of up to 3 decimal points, and an

offer price in €/MWh with accuracy of up to 2 decimal points.

3) The 15-min Balancing Energy Offers for mFRR and aFRR automatically obtained by

the Balancing Market System at the ISP1 GCT as per the above specification can

be voluntarily updated by the BSPs for their BSEs no later than fifteen (15) minutes

prior to each mFRR process execution, as can be seen in Figure 8-2.

Figure 8-2: Real-Time Balancing Energy Market (RTBEM) Gate Closure Times

With respect to the updated prices:


a) The price submitted at each step of the updated Balancing Energy Offer for

either mFRR or aFRR for a given 15-min Dispatch Period of the RTBEM shall

be “better” than the price submitted at each corresponding step of the

associated half-hourly Balancing Energy Offer in the ISP; by the term

“better” we refer to a lower price for upward offers and a higher price for

downward offers.

b) All the provisions regarding the maximum and minimum Balancing Energy

Offer Price limits (i.e., Administratively Defined Balancing Energy Offer

Lower Limit, Administratively Defined Balancing Energy Offer Cap, specific

limits for the Generating Units based on their Minimum Variable Cost, etc.)

apply also for the Balancing Energy Offers submitted in the RTBEM.

With respect to the updated quantities:

a) For the Generating Units:

1) The sum of the quantities (sum of all steps) offered for upward Balancing

Energy for a given 15-min Dispatch Period of the RTBEM shall cover the

difference between the Available Capacity (based on the Declared

Characteristics) and the latest Market Schedule of the (i.e., the most

updated Market Schedule shall be obtained by the Market Operator prior to

the respective RTBEM GCT), Generating Units.

2) The sum of the quantities over all steps offered for downward Balancing

Energy for a given 15-min Dispatch Period of the RTBEM shall cover the

latest Market Schedule of the Generating Unit.

b) For the Dispatchable RES Portfolios:

1) The sum of the quantities over all steps offered for upward Balancing

Energy for a given 15-min Real Time Unit of the RTBEM shall be at

maximum equal to the difference between the Registered Capacity (based

on the Registered Operating Characteristics) and the latest Market

Schedule of the Dispatchable RES Portfolio.


Energy for a given 15-min Real Time Unit of the RTBEM shall cover the

latest Market Schedule of the Dispatchable RES Portfolio.

c) For the Dispatchable Load Portfolios:

1) The sum of the quantities over all steps offered for upward Balancing


maximum equal to the technical capability of the Dispatchable Load

Portfolio to provide upward Balancing Energy.



maximum equal to the technical capability of the Dispatchable Load


Portfolio to provide downward Balancing Energy.

It should be noted that in case the Market Schedule of a BSE changes after the ISP

GCT for a given 15-min Dispatch Period and the respective BSP does not update the

BSE’s Balancing Energy Offer referring to said 15-min Real-Time Unit until the

relevant RTBEM GCT, then the Balancing Market System shallautomatically

implement the required quantity updates at the expiration of said RTBEM GCT.

Namely, the prices of the updated offers shall be the same with the prices of the

original offers, while the total quantity of the updated offer shall be subject to the

provisions hereinabove; thus, in case of a decreased total quantity as compared to

the original offer, the corresponding last (less competitive) steps of the offer shall be

omitted, while in case of an increased total quantity as compared to the original offer,

the last step of the original offer shall be extended so as to cover the respective

increase.

8.5 Obligations of BSPs in the context of the Real-Time Balancing Energy Market

Participation in the RTBEM shall mean in particular:

a) the submission of updated upward and downward Balancing Energy Offers by BSPs

for their BSEs regarding mFRR and aFRR processes and

b) the submission of Total or Partial Non-Availability Declarations by Producers and RES

Porducers for their Generating Units or RES Units, respectively, , in case their

Available Capacity has changed from the latest ISP GCT.

Participation in the mFRR process of Real-Time Balancing Energy Market is obligatory

for all Balancing Service Entities other than Dispatchable Load Portfolios with all their

available capacity to provide upward and downward Balancing Energy, independently of

the fact that they were or were not awarded mFRR in the relevant procurement processes.

Participation in aFRR is obligatory for all Producers with Generating Units that are

obliged, according to the Independent Power Transmission Operator Code to provide this

ancillary service (e.g. conventional units with nominal capacity higher than a certain limit

capacity).

In the context of the RTBEM, BSPs are required to:

a) submit Partial and Total Non-Availability Declarations as soon as reasonably possible

after the occurrence of an event, which results in the change of the Available Capacity

of the Generating Units or RES Units registered in their Participant Account;

b) take all necessary measures for their BSEs to be available for operation in

accordance with their Declared Characteristics; and


c) comply with the Commitment Instructions and Dispatch Instructions issued by the

TSO.

8.6 Real-Time Balancing Energy Market Input Data

The TSO shall establish the results of a given 15-min RTBEM execution based on the

following information:

1) The latest Market Schedules of all Balance Responsible Entities (e.g. Generating

Units, Dispatchable RES Portfolios, Non-Dispatchable RES Portfolios, Dispatchable

Load Portfolios, Non-Dispatchable Load Portfolios, etc.), as received from the

Nomination Platform of the Market Operator.

2) The operation schedules of the Generating Units / RES Units in Commissioning or

Testing Operation by the respective Producers, through the Commissioning

Schedules Declarations.

3) The mandatory generation schedules of hydro Generating Units submitted by the

respective Producers, through the Hydro Mandatory Injections Declarations.

4) The import / export schedule deviations at the interconnections used for the solution

of the ISP, along with actual tripping on interconnections (if any).

5) The already established flows in the inter-zonal corridors among Bidding Zones that

stem from the Market Schedules of all Entities, in order to establish the residual

available flows in the inter-zonal corridors for the solution of the RTBEM.

6) The information for the BSEs taken by the Energy Management System (EMS) of the

Transmission System Operator (e.g. unit in operation or not, real time measurements

of units production)

7) The AGC status for the BSΕs providing aFRR, obtained by the Balancing Market

System of the TSO.

8) The Reserve Capacity awards of the BSEs for upward / downward FCR, aFRR, and

mFRR obtained by the latest ISP execution.

9) The validated Balancing Energy Offers submitted in the ISP, and optionally updated

until the respective RTBEM GCT;

10) The Available Capacity of all BSEs, based on the latest submitted Non-Availability

Declaration.

11) The current operating plan of BSEs with an active maximum daily energy constraint.

12) The Declared Characteristics of the BSEs.


13) The initial production / demand level of the BSEs prior and as much as possible closer

to the start of the Dispacth Period of the given RTBEM execution.

14) The zonal Non-Dispatchable Load Imbalance, the computation of which is explained

in Paragraph 8.8.10.

15) The zonal RES FiT Portfolio Imbalance, the computation of which is explained in

Paragraph 8.8.10.

16) The zonal Non-Dispatchable RES Portfolios Imbalance, the computation of which is

explained in Paragraph 8.8.10.

8.7 Real-Time Balancing Energy Market Solution Methodology

The 15-min mFRR clearing problem is solved as a Mixed Integer Linear Programming

model, according to the detailed description of the following Section 8.8 and the two

execution methods provided.

If the Balancing Energy prices of different Balancing Energy Offers for the same

Dispatch Period arithmetically coincide and the respective Balancing Energy

quantities of such Balancing Energy Offers are not included in their entirety in the

mFRR clearing results, the priority of (partial or whole) inclusion of such Balancing

Energy Offers in the mFRR clearing results shall be given to DR providers then to

RES units and then established at random.

Where the mFRR clearing performs a random selection in accordance with the provisions

described herein, the Energy Balancing System (EBS) shall register the exact time of

such random selection, as well as the rest of the information to which it is related.

In case the model parameters for the execution of the mFRR clearing problem are

modified by the TSO, such modification shall be notified to the Regulator and to the BSPs

with a written letter, followed by a justification for the performed modification.

In case for a 15-min Dispatch Period of the Dispatch Day, it is impossible to cover

the very short-term forecasted imbalances, the TSO must consider the provisions

concerning Extreme Conditions, namely:

a) include Balancing Energy Offers for Contracted Units, and

b) re-execute the mFRR clearing problem in order to attain feasible results.

In case after the re-run of the mFRR clearing infeasibilities still appear in the

imbalance covering constraints, then the infeasibilities in the respective

constraints are relaxed, and the problem is solved in real time under the provisions

of Emergency Situations, as defined in the Independent Transmission System


Operation Code.

8.8 mFRR Process Mathematical Formulation – 1st execution method (Single Techno-economic Clearing)

In this Section, we provide the mathematical formulation of the 15-min mFRR clearing

problem under the 1st execution method (single techno-economic clearing), considering

the participation of all BSEs (Generating Units, Dispatchable Load Portfolios and

Dispatchable RES Portfolios). A set of BSE technical / operating constraints is taken into

account within the formulation of the single optimization problem, in order (a) to attain

feasible results for all BSEs and (b) to secure (maintain) the FCR and aFRR awards

having been allocated to the BSEs (in the ISP) for possible activation after the 15-min

mFRRclearing and closer to real time (e.g., through AGC operation within the 15-min

interval, for aFRR).


The mFRR clearingproblem is formulated as an optimization problem of Balancing

Energy, and constitutes a Mixed Integer Linear Programming model, as follows:

(1) Min BalancingEnergyCost PenaltyCost

The objective is to minimize the TSO cost of activation of mFRR Balancing Energy (

BalancingEnergyCost ) from the BSEs, as this cost is mathematically described in the

following Paragraph (equation (2)).

It is noted that the BSEs i that shall be considered in each 15-min mFRR clearing

execution are the BSEs which were scheduled to operate in the dispatchable phase (

dispitu 1 ) by the latest ISP solution (namely the BSEs which were scheduled to operate

between their minimum min

itP and maximummax

itP technical limits), or the BSEs which

were scheduled to provide non-spinning RR ( nsitu 1 ), or the loading BSEs which were

scheduled to provide Balancing Energy (/

BEup dnitu 1 ) in said 15-min Dispatch Period by

the latest ISP solution. The rest BSEs (i.e., generating BSEs scheduled to operate in the

synchronization, soak or desynchronization phase, or off-line BSEs) are considered as

“out of the market” and their offers are not included in the mFRR clearing.

The PenaltyCost included in the objective function (1) represents the non-physical cost

due to constraint violation when no physical solution exists, and is further explained in

Paragraph 8.8.3.



The Balancing Energy cost is expressed in € and represents the activation cost of the

priced Upward and Downward Balancing Energy Offers for the entire system and all

Dispatch Periods.

Note that each mFRR clearing execution may “look-ahead” in more than one 15-

min Dispatch Periods in the future (e.g., four Dispatch Periods), thus resulting in a

rolling 15-min economic dispatch scheme with each single execution having a

dispatch horizon of more than one 15-min intervals in the future. In this way, the

TSO can make the most efficient dispatch in the current 15-min Dispatch Period,

taking also into account evolving (estimated) system conditions in later 15-min

intervals. Nevertheless, in each mFRR clearing execution, the Balancing Energy

activation and the respective dispatch decisions of only the current (first) 15-min

Dispatch Period shall be binding for the BSPs and the TSO, while any dispatch

decisions concerning later intervals (i.e. from the second 15-min interval until the

end of the given mFRR clearing dispatch horizon) shall be released to the Market

Participants for information purposes only. These advisory dispatch schedules will

be re-assessed by the subsequent mFRR clearing executions.


In this context, the Balancing Energy cost is expressed as follows:

(2)


i t k

BalancingEnergyCost

+ D Quant Price Quant PriceI T K

Note that the Dispatch Period duration D is set to 1/4 for the mFRR clearing, since the

Dispatch Period has a 15-min length. Note also in (2), that in case of downward Balancing

Energy procurement, the TSO receives (rather than pays) a revenue from the BSPs, since

the provision of downward Balancing Energy implies that:

a) the Generating Units avoid variable generation costs (i.e., their production is

reduced as compared to their Market Schedule), whereas

b) the Dispatchable Load Portfolios are scheduled to consume more (i.e., withdraw

more energy than their Market Schedule, for which they have not previously paid

(i.e., in the Forward, Day-Ahead or Intra-Day Market).

8.8.3 Penalty Cost

To handle problem infeasibilities, violation (surplus / deficit) variables will be

introduced for various constraints. The penalty cost (3) is expressed in € and

represents the non-physical cost due to constraint violation when no feasible

solution exists, for the full system and all Dispatch Periods. The introduction of

penalty functions to deal with infeasibilities has been deployed as a standard

practice in recent years with substantial success. The form and strength of the

penalty functions provides a flexible methodology for including various policy

considerations in the market clearing solution approach.

When infeasibility is detected for a constraint, a corresponding violation notification with

the attained value of the surplus / deficit variable shall be available to the TSO in the

respective results. The TSO shall be able to modify the penalty prices at the Balancing

and Ancillary Services Market Database on-demand, given the approval of RAE. The

penalty prices can be set initially at the respective values indicated in the Nomenclature

Section.


8.8.4 Power Output Constraint

Equation (4) determines the Dispatch Schedule itP of each BSE i for each 15-min

Dispatch Period t, essentially arising from:

a) the BSE latest Market Schedule ( itMS ) obtained by the Market Operator,

b) the BSE upward Balancing Energy ( itBEup ) determined in the mFRR clearing

clearing, or

c) the BSE downward Balancing Energy ( itBEdn ) determined in the mFRR clearing.

Thus, (4) inherits the latest Market Schedule itMS prior to the current mFRR clearing

execution (for all Dispatch Periods t of the scheduling horizon), and computes the

Dispatch Schedule itP by using the upward Balancing Energy and downward Balancing

Energy, and by computing a dispatch level (in MW) that provides the Balancing Energy

(in MWh) that is optimally cleared to cover the system imbalance. The function f is derived

as follows:

a) The Transmission System Operator shall send to each Balancing Service Entity a

dispatch (production/withdrawal) level, in MW, which must be produced/ consumed

by the Balancing Service Entity at the end of the following Real Time Unit.


z t


z t

Cap DeficitCapit

i t

PenaltyCost

Deficit Price

Surplus Price

Deficit Price

Z T

Z T

T

Cap SurplusCapit

i t

RampUp SurplusRampUpit

i t


i t

(3) Surplus Price

Surplus Price

Surplus Price

I

I T

I T

I T


i t

Surplus Price

I T


b) Each Balancing Service Entity must start ramping up or ramping down from the

beginning of the Real Time Unit until reaching the Dispatch Instruction level (in

MW) and then stay at this level until the end of the Real Time Unit.

c) The shape of the production/withdrawal level during the Real Time Unit is such

that the provided mFRR upward or downward Balancing Energy is equal to the

respective mFRR Balancing Energy resulted from the solution of the mFRR

process, as detailed in the Balancing Market Manual.

(4) , , ,it it it itP f MS BEup BEdn i t I T

Note that (4) is enforced for all BSEs in a uniform manner, irrespectively of their specific

category. According to the relevant description of the ISP (Figure 7-4), it should be

stressed again that:

a) a non-negative MW Market Schedule per Dispatch Period t ( itMS ) shall be inserted

in the mFRR clearing model for the generating BSEs (Generating Units,

Dispatchable RES Portfolios), while,

b) a non-positive MW Market Schedule per Dispatch Period t shall be inserted for the

loading BSEs (Dispatchable Load Portfolios) (opposite of the positive MW schedule

recorded for such Entities).


The Balancing Energy quantities itBEup and itBEdn noted in the previous equality (4)

result from the most updated 15-min step-wise Balancing Energy Offers submitted by the

BSPs for their BSEs according to the provisions of Section 3.4. Thus, in (5) and (6), a

Balancing Energy award ( itBEup or itBEdn ) for a given BSE i and 15-min Dispatch Period

t is derived from the cleared quantities of all steps k of the associated BSE Balancing

Energy Offer (i.e., BEupitkQuant or

BEdnitkQuant ). Apparently, constraints (5) and (6), as well

as the remaining constraints of this Paragraph, apply for all BSEs irrespective of their

specific category.

(5) ,

BEup

it itkk

BEup Quant i tK

I T


(6) ,

BEdn

it itkk

BEdn Quant i tK

I T



BEdnitkMaxQuant , for the upward or downward offers, respectively).


ititk itk0 Quant MaxQuant u i t kI T K

(8) , , BEdn BEdn BEdnitk itk it0 Quant MaxQuant u i t kI T K


activated (if activated) by BSE i in a given direction (upwards / downwards) and Dispatch

Period t can also be ensured (as a minimum “acceptance ratio”) through the imposition

of constraints (9) and (10). It is noted again that the minimum quantities of Balancing

Energy (i.e., the parameters itMinBEup and itMinBEdn ) shall be submitted by the

Participants during the ISP period of submission, as part of their BSEs’ Balancing Energy

Offers for any given half-hourly Dispatch Period t. The submitted minimum quantities in

the ISP shall also be considered in the mFRR clearing (namely, in constraints (9) and

(10)), but now with a 15-min time resolution.

(9) , BEup

it it itBEup MinBEup u i tI T

(10) , BEdnit it itBEdn MinBEdn u i tI T

The imposition of constraints (9) and (10) introduces two binary variables, indicating the

activation of Balancing Energy either in the upward or in the downward direction (i.e.,BEupitu and

BEdnitu , respectively). Regarding the loading BSEs (Dispatchable Load

Portfolios), it should be noted that these binary variables BEupitu and

BEdnitu (i.e. the

activation status for upward and downward Balancing Energy) have already been

determined by the latest ISP execution (so as to take into account specific intertemporal

constraints, like the minimum baseload constraint), so they shall rather be fixed

accordingly in the mFRR clearing process.


Finally, constraint (11) is included in the mFRR clearing problem for the same reason

used also in the ISP model. A floor for Downward Balancing Energy Offers and a cap for

Upward Balancing Energy Offers may be decided by the NRA. However, there are no

respective constraints on the submitted offer prices for upward and downward Balancing

Energy for the Dispatchable RES Portfolios and the Dispatchable Load Portfolios. To

prohibit any counteractive provision of upward and downward Balancing Energy, the

clearing problem may encompass constraint (11) for choosing to activate only one

(upward or downward) of the two services from a BSE i in a given 15-min Dispatch Period

t.

(11) , BEup BEdn

ititu u 1 i t I T


The following constraints (12) – (19) are intended to coordinate the final Dispatch

Schedule itP (of each BSE i for each 15-min Dispatch Period t), along with the respective

firm BSE Reserve Capacity awards for FCR and aFRR (obtained by the relevant ISP),

within the BSE technical minimum and maximum limits. Note again that the Reserve

Capacity awards for FCR and aFRR that have been allocated (based on half-hourly time

resolution) to the various eligible BSEs during the ISP shall remain in effect during the

corresponding 15-min Dispatch Periods in the mFRR clearing (FCR and aFRR Reserve

Capacity is not re-optimized during the mFRR clearing). Thus, the mFRR clearing

algorithm shall inherit such ISP Reserve Capacity awards as “fixed” quantities for the

eligible BSEs and for the 15-min Dispatch Periods concerned.

Constraints (12) – (15) concern the generating BSEs (Generating Units and Dispatchable

RES Portfolios), while constraints (16) – (19) concern the loading BSEs (Dispatchable

Load Portfolios).


Constraints (12a) and (12b) describe the generating BSE minimum limits, while also

taking into account the downward FCR and aFRR reserves having been awarded by the

latest ISP execution to said BSE. Accordingly, constraint (13) describes the BSE

maximum limit, while also taking into account the upward FCR and aFRR reserves having

been awarded by the latest ISP execution to said BSE.


(12a) min,

FCRdn aFRRdn Capit it it itit Quant Quant Deficit P i tP G R2 T

(12b) minmax , , CapFCRdn

it it it ititP Quant Deficit P Mand i tH T

(13) max

,

FCRup aFRRup Capit itit it itP Quant Quant Surplus P

i t

G R2 T

The following explanatory comments should be noted:

a) All input parameters used in this Chapter which are assigned with the final (attained)

values of respective variables of another (preceding) process are noted with an upper

dash. Thus, constraints (12a), (12b) and (13) above consider the 15-min input

parameters FCRdnitQuant , aFRRdn

itQuant and FCRupitQuant , aFRRup

itQuant which have

been assigned with the attained values of the corresponding half-hourly variablesFCRdnitQuant ,

aFRRdnitQuant and

FCRupitQuant ,

aFRRupitQuant of the ISP, after proper

adjustment of the time resolution (e.g., a half-hourly upward aFRR award of 10 MW in

the ISP shall be converted into two respective 15-min upward aFRR awards of 10 MW

before insertion in the mFRR clearing process).

b) The quantities of FCR and aFRR allocated in the ISP are taken into account in the

mFRR clearing, so as to limit (if needed) the respective activation of upward /

downward Balancing Energy by the corresponding BSEs. This is because the already

allocated FCR and aFRR shall not be “overlapped” by the activation of Balancing

Energy in the mFRR clearing, but rather remain available for possible activation within

the 15-min Dispatch Period (e.g., at the AGC process for the allocated aFRR, or at

any occurrence of instant events for the allocated FCR).

c) In the case of hydro Generating Units (or Dispatchable CHP Units) with a nominated

mandatory generation itMand , the minimum limit considered in constraint (12b) is

rather the mandatory generation itMand , if the latter is greater than the technical

minimum min

itP of the Unit (without considering the awarded downward aFRR in this

case). As already discussed in Paragraph 7.10.15, the Market Schedule itMS in this

case already contains the mandatory generation itMand . For the rest BSEs the

parameter itMand takes a zero value in this constraint.


Constraints (14) and (15) enforce the respective technical minimum (min, AGC

itP ) and

maximum (max,AGC

itP ) limits when the generating BSE is operating under AGC in the

corresponding Dispatch Period t ( AGCitunder 1).

(14) min min,

,

CapaFRRdn AGC AGC AGCit it it it it ititP Quant Deficit P 1 under P under

i t

G R2 T

(15) max max,

,

aFRRup Cap AGC AGC AGCit it it it itit itP Quant Surplus P 1 under P under

i t

G R2 T


The capacity constraints presented above for the generating BSEs are transformed into

the following constraints (16) - (19) for the loading BSEs.

Constraint (16) describes the BSE maximum loading limit, while constraint (17) describes

the BSE minimum loading limit:

(16) max,

FCRdn aFRRdn Capit it it itit Quant Quant Deficit P i tP L1 T

(17) min,

FCRup aFRRup Capit it it itit Quant Quant Surplus P i tP L1 T

Similarly, constraint (18) describes the BSE maximum loading limit, while constraint (19)

describes the BSE minimum loading limit, when the Dispatchable Load or the DR Portfolio

is operating under AGC:


(18)

max

max, ,

CapaFRRdn AGCit it it itit

AGC AGCit it

P Quant +Deficit P 1 under +

P under i t

L1 T

(19)

min

min, ,

aFRRup Cap AGCit it itit it

AGC AGCit it

P Quant -Surplus P 1 under +

+ P under i t

L1 T



time period. For a given 15-min Dispatch Period, the initial MW level of each committed

BSE i (noted with the parameter iInitialMW ) is equal to the actual (metered) MW level of

the BSE (non-negative for the generating BSEs / non-positive for the loading BSEs)

during the associated mFRR clearingexecution (taking place, e.g. 15 minutes prior to said

Dispatch Period).


In this context, constraints (20) and (21) enforce the ramp rate limits for the Generating

Units and Dispatchable RES Portfolios, for the binding (first) Dispatch Period of the

dispatch horizon ( t 1). Inequality (20) models the upward ramping constraint, while

inequality (21) models the downward ramping constraint. Accordingly, constraints (22)

and (23) model the upward and downward ramping limitations for the rest Dispatch

Periods of the dispatch horizon ( t 2 ), if a look-ahead functionality applies in the mFRR

clearing.

(20) itRampUp

i iitP InitialMW Surplus 15 RU i , t G R2 1

(21) itRampDn

i iitP 1InitialMW Surplus 15 RD i , t G R2

(22) ( )it i t 1RampUp

iitP P Surplus 15 RU i , t G R2 2

(23) ( )i t 1 itRampDn

iitP P 2Surplus 15 RD i , t G R2



Analogous ramping constraints are enforced for the Dispatchable Load Portfolios.

Inequality (24) models the upward ramping constraint (“load pickup rate”), while inequality

(25) models the downward ramping constraint (“load drop rate”) for the binding (first)

Dispatch Period of the dispatch horizon ( t 1). Accordingly, constraints (26) and (27)

model the upward and downward ramping limitations for the rest Dispatch Periods of the

dispatch horizon ( t 2 ).

(24) RampUp

i it iitIn MW P Surplus 15 RU i , t 1itial L1

(25) ,RampDn

it i iitP In MW Surplus 15 RD i t 1itial L1

(26) ( )RampUp

i t 1 it iitP P Surplus 15 RU i , t 2 L1

(27) ( ) ,RampDn

it i t 1 iitP P Surplus 15 RD i t 2 L1

Note again, that the above constraints have been adjusted (as compared to the previous

(20) - (23)) so as to take into account the fact that the Dispatch Schedules itP of the

Dispatchable Load Portfolios take non-positive values. In this case:

a) the parameter iRU refers to the maximum increase in the loading level of a


niRU 1 MW/mi can move from -50 MW to -65 MW in 15-minutes time; while,

b) the parameter iRD refers to the maximum decrease in the loading level of a


niRD 1 MW/mi can move from -50 MW to -35 MW in 15-minutes time.


In the mFRR clearing, the Dispatch Schedule itP of a Generating Unit is also limited by the

Unit current operating plan itP (ISP Dispatch Schedule), which in turn has been

constrained by a maximum daily energy limit (in the ISP). The final Dispatch Instruction

itP shall not exceed this limit:

(28) , MaxEnergy

ititit Surplus P i tP G T


The TSO shall also be able to de-activate this daily energy limit through an instruction

(activation of a respective flag per BSE) prior to the mFRR clearing. In such case, the

previous constraint shall not be applied.

8.8.9 Mandatory Activation Process prior to the mFRR Clearing

There exist certain conditions under which a mandatory activation of Balancing

Energy from given BSEs is required by the TSO prior to each mFRR clearing. Such

mandatory activation concerns BSEs which are considered as “out of the market”

in any of the 15-min Dispatch Periods of the dispatch horizon of a given mFRR

clearing execution (i.e., BSΕs which were either scheduled to operate in the

synchronization, soak or de-synchronization phase, or scheduled to be offline, and

thus do not participate in the mFRR clearing procedure).

The TSO is responsible to determine the MW level of such BSΕs together with the

Dispatch Instructions that will be issued for the rest BSΕs based on the results of the

mFRR clearing. The MW level will be either a zero MW level (in case the BSΕ was

scheduled to be offline), or the appropriate MW level based on the registered

synchronization, soak or de-synchronization trajectory of the BSΕ. However, the MW level

of “out of the market” resources in this case shall be computed prior to a given mFRR

clearing, so as the TSO to be able to determine the exact amount and direction of

Balancing Energy that has been manually activated (over the resource Market Schedule)

for the Dispatch Periods in question, and thus subtract this amount from the imbalances

to be covered during mFRR clearing.

If, for example, the MW level for a given BSE i in the soak phase is 25 MW at a certain Dispatch Period t, while his Market Schedule for said period is 80 MW, that means that an amount of (80 – 25) = 55 MW of downward Balancing Energy has been manually

activated by the TSO, thus BEdnitMand 55 MW . If the MW level for a BSE in the

desynchronization phase is 40 MW when the Market Schedule is zero at the same Dispatch Period t, that means that an amount of (40 – 0) = 40 MW of upward Balancing

Energy has been manually activated, thus BEupitMand 40 MW . As a last example, if the

MW level for a BSΕ is zero (off-line BSP) when the Market Schedule is 50 MW at the given Dispatch Period t, that means that an amount of (50 – 0) = 50 MW of downward Balancing Energy has been mandatorily activated over the BSΕ Market Schedule, thus

BEdnitMand 50 MW . These quantities

BEupitMand and

BEdnitMand are then considered in

the imbalance covering equation (29) in Paragraph 8.8.10 (or (31) in Paragraph 8.8.11), so as the mFRR clearing to cover only the residual imbalances of the given Dispatch Period t.

It should finally be noted that all upward or downward Balancing Energy quantities

mandatorily activated by the TSO shall define the Balancing Energy Price if greater


than the marginal price of mFRR clearing and shall be compensated based on this

price.


Following the respective methodology adopted in the ISP model, the scope of the

imbalance covering equation in mFRR clearing is to cover any actual or TSO-forecasted

deviations (short-term forecasted deviations) of the non-dispatchable Entities from their

Market Schedules, by procuring appropriately Balancing Energy from the dispatchable

Entities, namely from the BSEs. Thus, the imbalance covering constraint is described by

the following linear equation (29), taking into account a decomposition of the system into

different Bidding Zones z.

In equation (29), the net Balancing Energy activated from all “in the market” BSEs per

each zone z (i.e., the first term on the left-hand side) plus the already (manually) activated

Balancing Energy by the TSO (Mandatory Activation Process) from all “out of the market”

BSEs per each zone z (i.e., the second term on the left-hand side) covers the forecasted

zonal imbalances, which consist of the following components:

( )

z z

z

z4

BEup BEdnit it itit

i I i I

zt jtj

zt zt

zt jtj

BEup BEdn Mand Mand


29 ResFiTPortFR ResFiTPortMS


2L

R

, ,

, ,

,

z z

z

jt jt inter t inter tj inter

ZonImb ZonImbzt zt zz t z z t t

z

CommisDS CommisMS ImpDev ExpDev

Deficit Surplus = Flow Flow + ForecastedSystemLosses

z t

C INTER

Z

Z T

Non-Dispatchable Load Imbalance

The zonal Non-Dispatchable Load Imbalance is the difference between:


a) the very short-term zonal Non-Dispatchable Load Forecast ztNonDispLoadFR ; this

forecast shall be established by the TSO prior to the given mFRR clearing, as

provisioned in Paragraph 8.13.2, and

b) the zonal Non-Dispatchable Load already cleared in the Forward (including OTC

contracts), Day-Ahead and Intra-Day Market

z

jtj

NonDispLoadMS

2L

; this sum is

essentially an aggregation of the latest Market Schedules of all Non-Dispatchable

Load Portfolios, as obtained by the Market Operator for the current mFRR clearing

execution.


The zonal RES FiT Portfolio Imbalance is the difference between:

a) the very short-term zonal RES FiT Portfolio Forecast ztResFiTPortFR ; this forecast

shall be established by the TSO prior to the given mFRR clearing execution as

provisioned in Paragraph 8.13.3 (and shall refer only to the RES FiT Portfolio per

Bidding Zone z), and

b) the zonal RES FiT Portfolio production already cleared in the wholesale market

ztResFiTPortMS ; this is essentially the latest Market Schedule of the RES FiT

Portfolio per Bidding Zone z, as obtained by the Market Operatorfor the current

mFRR clearing execution.


The zonal Non-Dispatchable RES Portfolios Imbalance is the difference between:

a) the zonal Non-Dispatchable RES Portfolios Forecast ztNonDispRESUnitFR ; this

forecast shall be established by the TSO as provisioned in Paragraph 8.13.4, and

b) the zonal Non-Dispatchable RES Portfolios production already cleared in the

wholesale market

z4

jtj

NonDispRESUnitMSR

; this is essentially an aggregation of

the latest Market Schedules of all Non-Dispatchable RES Portfolios, as obtained

by the Market Operatorfor the current ISP.


With regard to the Generating Units / RES Units in Commissioning or Testing Operation,

the difference between a) and b) below essentially constitutes another zonal imbalance

(the zonal “Commissioning Imbalance”):

a) the Units’ MW schedules declared to the TSO through the latest Commissioning

Schedules Declarations ( jtCommisDS , j C ), and


b) the Units’ latest Market Schedules, submitted to the Market Operator at the Day-

Ahead and Intra-Day Market stage and inserted in the respective clearings as

“price-taking orders” ( jtCommisMS , j C ).

This imbalance shall also be covered by the activation of upward or downward Balancing

Energy in (29).


These include the following categories:

a) the difference between the imported quantity in the Market Schedule (sold in the

Forward, Day-Ahead and Intra-Day Markets) by a trader and his nomination of

long-term Physical Transmission Rights (PTRs) for electricity imports through an

interconnection (e.g. Bulgaria, Italy) for which an obligation for physical delivery

exists,

b) the difference between the sold / bought energy quantity in the Greek Day-Ahead

Market corresponding to short-term (daily) PTRs and the bought / sold energy

quantities in neighboring countries Day-Ahead Market(s) corresponding to the

same daily PTRs,

c) adjusting schedules for flow inadvertent deviations at the interconnections,

d) emergency schedules,

e) return of emergency schedules,

f) guarantees of commercial schedules that relate to the cases when an

interconnection is out of operation for more days than a maximum threshold

(included in the respective Auction Rules), and the TSO is obliged to guarantee

the commercial schedules beyond that threshold,

g) return of guarantees of commercial schedules, or

h) deviations for any other future-established purpose.

All the above constitute zonal imbalances that shall be covered appropriately by the

activation of Balancing Energy in equation (29).

Respective imbalances of adjacent Bidding Zones

The zonal imbalances of adjacent Bidding Zones of each zone z can be covered with the

activation of Balancing Energy from the given zone z, through the consideration of

corresponding corridor flows on the right-hand side of equation (29) (i.e., Balancing

Energy corridor flows).


Constraint (30) enforces the flow limit of the corridor between adjacent Bidding Zones z

and z’:

(30) , , ,, ' Maxzz t zz t

zFlow AvailableFlow tz z TZ Z

It is noted that the corridor flows resulting from the right-hand side of the imbalance covering equation (29) and constrained by inequality (30) above represent the additional flows produced by the mFRR clearing due to the activation of Balancing Energy and the possible sharing of such Balancing Energy between neighboring Bidding Zones. Essentially, these “Balancing Energy” flows are only incremental flows over those already established in the wholesale market (i.e., prior to the given mFRR clearing execution). In

this context, the maximum limit ,Maxzz tAvailableFlow imposed in constraint (30) constitutes

the residual transfer capacity in each corridor, after subtracting the corridor flow already scheduled in the wholesale market (Forward, Day-Ahead and Intra-Day Market).


As already discussed, the Flow-Based (FB) model allows a better representation of the

physical power flow constraints, as compared to the simple transportation model (ATC-

based model), through the usage of (linear) Power Transfer Distribution Factors (PTDFs).

In accordance with the description provided in the previous Paragraph, the following

constraints (31) - (34) are enforced in order to apply the FB model in the zonal imbalance

covering equation of the mFRR clearing problem:

( )

z z

z

z4

BEup BEdnit it itit

i I i I

zt jtj

zt zt

zt jtj

BEup BEdn Mand Mand


31 ResFiTPortFR ResFiTPortMS


2L

R

, ,

, ,

,

z z

z


ZonImb ZonImbzt zt zz t z z t

z

t


Deficit Surplus = Flow Flow +

+ ForecastedSystemLosses z t

C INTER

Z

Z T


(32) , , ,

z

zz t z z t ztz


Z T

(33) ,, ,,

, ' ,

z ref z

zz t z tzz tz

Flow = PTDF NetInjection z z t Z Z T

(34)

, , , ' , Max zzz t zz tFlow AvailableFlow z z tZ Z T

8.9 Mathematical Formulation of the 2nd implementation phase of the mFRR process (Conversion Process / Economic Clearing)

As noted earlier, the execution at the 2nd implementation phase is closer to the Target

Model for the Balancing Market and the incorporation to a common Balancing Market

solver with other European countries. Again, the TSO executes the mFRR clearing

algorithm for each subsequent 15-min interval, with each execution taking place 15

minutes (indicative time) prior to the dispatch interval in question (see second diagram of

Figure 8-1). However, each execution is now divided into two main steps:

a) a conversion process for the derivation of an appropriate merit order list of the BSPs’

Balancing Energy Offers, and

b) the mFRR economic clearing execution which considers the produced merit order list.

With regard to the second step above (mFRR clearing), this minimizes the total activation

cost of mFRR Balancing Energy in order to cover the very short term forecasted

imbalances. In order to comply with the Target Model provisions, the mFRR clearing in

this case constitutes a pure economic activation problem for mFRR which (a) excludes

the BSE technical / operating constraints, while also (b) it does not take into account other

types of Balancing Capacity (FCR, aFRR) having been awarded to the BSEs (in the ISP)

for the Dispatch Period in question.


Thus, in order (a) to attain feasible results in the mFRR clearing, and (b) to secure the

Balancing Capacity (FCR, aFRR allocated in the ISP) for possible activation after the

mFRR clearing and closer to real time (e.g., instant events, AGC operation), while

retaining the pure economic structure of the mFRR clearing, a set of respective

constraints is taken into account in a separate pre-process, the “conversion process” (see

respective building block in Figure 8-1).

8.9.1 Conversion Process

The conversion process is solved prior to each mFRR clearing and aims:

a) to adjust (limit) the maximum quantity of mFRR Balancing Energy initially offered by

the BSEs, subject to system constraints, the BSE technical / operating constraints,

and taking into account the already allocated Balancing Capacity (FCR, aFRR) in the

ISP;

b) to provide the merit order list of the converted Balancing Energy Offers, which shall

then be available for the execution of the subsequent mFRR clearing.

The following Paragraphs provide the mathematical formulation of the mFRR conversion

process, which is again formulated as an optimization problem.


The conversion process is formulated as an optimization problem and constitutes a Linear

Programming model. The objective is to maximize the quantity of mFRR Balancing

Energy offered by the BSEs both in the upward and downward direction which shall be

considered in the subsequent mFRR clearing:

(35)

it it

i t

Max BEup BEdn PenaltyCostI T

It is noted that:

a) the conversion process (and the subsequent clearing) shall be solved once each

quarter for the following Dispatch Period t (single period optimization); in this sense,

the set t can be omitted from all symbols presented in the herein formulation, however

it has been retained for homogeneity purposes;

b) the BSEs i that shall be considered in the conversion process (and the subsequent

clearing) are again the BSEs which were scheduled to operate in the dispatchable

phase ( dispitu 1 ), or the BSEs which were scheduled to provide non-spinning RR (


nsitu 1 ), or the loading BSEs which were scheduled to provide Balancing Energy (

/

BEup dnitu 1 ) in said 15-min Dispatch Period by the latest ISP solution. The remaining

BSEs (i.e., generating BSEs scheduled to operate in the synchronization, soak or

desynchronization phase, or off-line BSEs) are considered as “out of the market” and

their offers are not included in the mFRR clearing.

The PenaltyCost referred in the objective function is a non-physical “cost” due constraint

violation in the conversion process, and is further explained in Paragraph 9.9.6.


The following constraints are intended to limit the mFRR Balancing Energy offered by

each BSE either in the upward or in the downward direction, so as the final Dispatch

Instructions (i.e., Dispatch Instructions that shall be issued after the mFRR clearing) not

to violate the BSE technical minimum and maximum limits.

Constraints (36) – (39) concern the generating BSEs, while constraints (40) – (43)

concern the loading BSEs.

Generating BSEs

In constraint (36), the maximum downward Balancing Energy itBEdn offered by BSE i in

Dispatch Period t is delimited between the BSE Market Schedule itMS and the BSE

technical minimum min

itP , while also taking into account the downward FCR and aFRR

reserves having been awarded by the latest ISP execution to said BSE.

Accordingly, in constraint (37), the maximum upward Balancing Energy itBEup offered

by BSE i in Dispatch Period t is delimited between the BSE Market Schedule itMS and

the BSE technical maximum max

itP , while also taking into account the upward FCR and

aFRR reserves having been awarded by the latest ISP execution to said BSE.

(36a) min

,

CapFCRdn aFRRdnit it it it ititMS BEdn Quant Quant Deficit P

i t

G R2 T

(36b) minmax ,

,

CapFCRdnit it it it ititMS BEdn Quant Deficit P Mand

i tH T


(37) max

,

FCRup aFRRup Capit it itit it itMS BEup Quant Quant Surplus P

i t

G R2 T

Again, in the case of hydro Generating Units (or Dispatchable CHP Units) with a

nominated mandatory generation itMand , the minimum limit considered in constraint

(36b) is rather the mandatory generation itMand (without considering the awarded

downward aFRR in this case), if the latter is greater than the technical minimum min

itP of

the unit. For the rest BSEs the parameter itMand takes a zero value in this constraint.

Constraints (38) and (39) enforce the respective technical minimum (min, AGC

itP ) and

maximum (max,AGC

itP ) limits when the BSE is operating under AGC in the corresponding

Dispatch Period t ( AGCitunder 1).

(38)

min min, ,

CapaFRRdnit it it it

AGC AGC AGCit it it it

MS BEdn Quant Deficit

P 1 under P under i t

G R2 T

(39)

max max, ,

aFRRup Capit it it it


MS BEup Quant Surplus


G R2 T

Loading BSEs

Τhe capacity constraints presented above for the generating BSEs are transformed into

the following constraints (40) - (43) for the loading BSEs.

Constraint (40) describes the maximum loading limit, while constraint (41) describes the

minimum loading limit:

(40) max

,

CapFCRdn aFRRdnit it it it ititMS BEdn Quant Quant Deficit P

i t

L1 T


(41) min

,

FCRup aFRRup Capit it itit it itMS BEup Quant Quant Surplus P

i t

L1 T

Similarly, constraint (42) describes the maximum loading limit, while constraint (43)

describes the minimum loading limit, when the loading BSE is operating under AGC:

(42)

max max, ,

CapaFRRdnit it it it


MS BEdn Quant Deficit


L1 T

(43)

min min, ,

aFRRup Capit it it it


MS BEup Quant Surplus


L1 T



time period. For a given 15-min Dispatch Period, the initial MW level of each committed

BSE i (noted with the parameter iInitialMW ) is equal to the actual (metered) MW level of

the BSE (non-negative for the generating BSEs / non-positive for the loading BSEs)

during the associated mFRR execution (taking place, e.g. 15 minutes prior to said

Dispatch Period).

Generating BSEs

In this context, constraint (44) maximizes the upward Balancing Energy itBEup offered

by generating BSE i in the given Dispatch Period t, so as the BSE not to ramp-up above

his iInitialMW plus his 15-min upward ramping capability. Similarly, constraint (45)

maximizes the downward Balancing Energy itBEdn offered, based on the 15-min

downward ramping capability of the BSE.

(44) RampUp

it it i iitMS BEup InitialMW Surplus 15 RU

i ,t

G R2 T


(45) RampDn

i it it iitInitialMW MS BEdn Surplus 15 RD

i , t

G R2 T

Loading BSEs

Analogous ramping constraints are enforced for the loading BSEs.

Inequality (46) models the upward ramping constraint (maximum increase in the loading

level), while inequality (47) models the downward ramping constraint (maximum decrease

in the loading level).

(46) RampUp

i it it iitInitialMW MS BEdn Surplus 15 RU

i ,t

L1 T

(47)

,

RampDnit it i iitMS BEup InitialMW Surplus 15 RD

i t

L1 T


The maximum upward Balancing Energy itBEup offered by a Generating Unit is also

limited by the Unit current operating plan itP (ISP Dispatch Schedule), which in turn has

been constrained by a maximum daily energy limit (in the ISP). The final Dispatch

Instruction shall not exceed this limit:

(48) , MaxEnergy

it it ititMS BEup Surplus P i tG T

The operator shall also be able to de-activate this daily energy limit through an instruction

(activation of a respective flag per BSE) prior to the conversion process. In such case,

the previous constraint shall not be applied.

8.9.6 Penalty Cost

To handle problem infeasibilities, violation (surplus / deficit) variables have been

considered in the respective constraints, and the following penalty cost (49) has been

included in (subtracted from) the objective function.


Cap DeficitCapit

i t

Cap SurplusCapit

i t

Ramit

PenaltyCost

Deficit Price

Surplus Price

Surplus

I T

I T

pUp SurplusRampUp

i t


i t


i t

Price

(49) Surplus Price

Surplus Price

I T

I T

I T

It is noted again, that since the objective of the conversion process is to maximize the

mFRR Balancing Energy offered by the BSEs, the above penalty cost has no real cost

interpretation (the shadow costs of the respective constraints are not taken into account

at all). It is only considered in the objective in order to penalize the violation of the various

constraints with relative priorities (different penalty prices).

However, when infeasibility is detected for any constraint, a corresponding violation

notification with the attained value of the surplus / deficit variable shall be available to the

TSO in the respective results.




8.9.7 Conversion of the Balancing Energy Offers prior to mFRR Clearing and Creation of the Final Merit Order

The solution of the above optimization problem for a given quarterly Dispatch Period

provides the maximum quantity of upward / downward Balancing Energy that shall be

offered by each BSE i in the given Dispatch Period t during the subsequent clearing:

Maximum upward Balancing Energy: , MaxitBEup i tI T .

Maximum downward Balancing Energy: , MaxitBEdn i tI T .

The obtained maximum quantities MaxitBEup and Max

itBEdn are then used to limit

(convert) the latest (most updated) Upward / Downward Balancing Energy Offers

submitted by the BSPs, prior to their insertion in the mFRR economic clearing problem.

Figure 8-3 illustrates the above description.


With regard to the upper diagram of Figure 8-3, the residual Upward Balancing Energy

Offer (white area) of each BSE i for the given Dispatch Period t (i.e., remaining price -

quantity pairs BEup BEupitk itkMaxQuant Price after the conversion) is then considered as a

respective Upward Balancing Energy Offer. Accordingly, with regard to the lower diagram

of Figure 8-3, the residual Downward Balancing Energy Offer (white area) of each BSE

for the given Dispatch Period t (i.e., remaining price - quantity pairs

BEdn BEdnitk itkMaxQuant Price after the conversion) is then considered as a respective

Downward Balancing Energy Offer.

The converted Balancing Energy Offers form two merit order lists, one for the upward and

one for the downward direction, which are then inserted in the subsequent economic

clearing problem for activation purposes.

Note

The provisions of Paragraph 8.8.9 regarding the mandatory activation of Balancing

Energy from given “out of the market” BSEs apply also in this case. Any mandatory

activation of Balancing Energy shall take place prior to the subsequent economic clearing.


Figure 8-3: Conversion of the Balancing Energy Offers prior to their insertion in the mFRR clearing

8.9.8 mFRR Clearing – Mathematical Formulation

Every 15 minutes, and after the completion of the conversion process and the formation

of the final merit order lists, the mFRR clearing problem is solved for the following (single)

Dispatch Period t.

…

…

€ / MWh

MW

BEupit1

MaxQuant BEupit10

MaxQuant

BEupit1

Price

BEupit10

Price

Maxit

BEup

…

€ / MWh

…

MWBEdnit10

Price

BEdnit1

Price

BEdnit1

MaxQuant BEdnit10

MaxQuantMaxit

BEdn


The following Paragraphs describe the mathematical formulation of the mFRR clearing

problem.


The mFRR clearing problem is formulated as an optimization problem of mFRR Balancing

Energy, and constitutes a Mixed Integer Linear Programming model, as follows:

(50) Min BalancingEnergyCost PenaltyCost

The objective is to minimize the TSO cost of activation of Balancing Energy (

BalancingEnergyCost ) from the BSEs, as this cost is mathematically described in the

following Paragraph (equation (51)).

It is noted again that the BSEs that shall be considered in the mFRR clearing (as for the

conversion process) are the BSEs which were scheduled to operate in the dispatchable

phase ( dispitu 1 ), or the BSEs which were scheduled to provide non-spinning RR (

nsitu 1 ), or the loading BSEs which were scheduled to provide Balancing Energy (

/

BEup dnitu 1 ) in said 15-min Dispatch Period by the latest ISP solution. The remaining

BSEs (i.e., generating BSEs scheduled to operate in the synchronization, soak or

desynchronization phase, or off-line BSEs) are considered as “out of the market” and their

offers are not included in the mFRR clearing.

The PenaltyCost included in the objective function represents the non-physical cost due

to constraint violation when no physical solution exists, and is further explained in

Paragraph 8.10.3.


The Balancing Energy cost is expressed in € and represents the activation cost of the

priced Upward and Downward Balancing Energy Offers for the entire system and the

given Dispatch Period t. The Balancing Energy cost is expressed as follows:

(51)


i t k

BalancingEnergyCost

+ D Quant Price Quant PriceI T K


Note that the Dispatch Period duration D is set to ¼ for the mFRR clearing (and generally

for the RTBEM), since the Dispatch Period is quarterly.

8.9.11 Penalty Cost

The penalty cost (52) is expressed in € and represents the non-physical cost due to

constraint violation when no feasible solution exists, for the full system and the given

Dispatch Period. To handle such problem infeasibility, violation (surplus / deficit) variables

have been considered in the imbalance covering constraint (58) (or (60)).

(52)


z t


z t

PenaltyCost

Deficit Price

Surplus Price

Z T

Z T

When infeasibility is detected for this constrain (imbalance covering constraint) a

corresponding violation notification with the attained value of the surplus / deficit variable

shall be available to the TSO in the respective results.







BEdnitkMaxQuant , for the upward or downward offers, respectively). It is noted again that

the Balancing Energy Offers considered in the economic clearing are the ones included in the final upward and downward merit order lists (converted offers).


ititk itk0 Quant MaxQuant u i t kI T K

(54) , , BEdn BEdn BEdnitk itk it0 Quant MaxQuant u i t kI T K


activated (if activated) by BSE i in a given direction (upwards / downwards) can also be

ensured (as a minimum “acceptance ratio”) through the imposition of the following

constraints (55) and (56).


(55) ,

BEup BEup

it ititkk

Quant MinBEup u i tK

I T

(56) ,

BEdn BEdnitk it it

k

Quant MinBEdn u i tK

I T

The imposition of constraints (55) and (56) introduces two binary variables, indicating the activation of Balancing Energy either in the upward or in the downward direction (i.e.,

BEupitu and

BEdnitu , respectively).

Finally, constraint (57) is included in the mFRR clearing problem for the same reason

used also in the ISP model (to prohibit any counteractive activation of upward and

downward Balancing Energy from a certain BSE in the given Dispatch Period t).

(57) , BEup BEdn

ititu u 1 i t I T


The scope of the imbalance covering equation in mFRR clearing is again to cover any

TSO-forecasted deviations (very short-term forecasted deviations) of the non-

dispatchable Entities from their Market Schedules. This is achieved through the

appropriate activation of Balancing Energy from the dispatchable Entities, namely from

the BSEs.

Thus, the imbalance covering constraint is described by the following linear equation (58),

taking into account a decomposition of the system into different Bidding Zones z.

In equation (58), the net Balancing Energy activated from all “in the market” BSEs per

each zone z (i.e., the first term on the left-hand side) plus the already (manually) activated

Balancing Energy by the TSO (Mandatory Activation Process) from all “out of the market”

BSEs per each zone z (i.e., the second term on the left-hand side) covers the forecasted

zonal imbalances, which consist of the same components as per the respective

description in Paragraph 8.8.10 (1st execution method for the mFRR).


(58)

z z

z

BEup BEupBEdn BEdnitk itititk

ki I i I

zt jtj

zt zt

zt

Quant Quant Mand Mand




2

K

L

, ,

, ,

,

z4

z z

z

jtj



z

t




R

C INTER

Z

Z T

Finally, constraint (59) enforces the flow limit of the corridor between adjacent Bidding

Zones z and z’:

(59) , , , ' , zMaxzz t zz t z zFlow AvailableFlow tZ Z T

It is noted again that the corridor flows resulting from the right-hand side of the imbalance covering equation (58) and constrained by inequality (59) above represent the additional flows produced by the mFRR clearing due to the activation of Balancing Energy and the possible sharing of such Balancing Energy between neighboring Bidding Zones. Essentially, these “Balancing Energy” flows are only incremental flows over those already established in the wholesale market (i.e., prior to the given mFRR clearing execution). In

this context, the maximum limit ,Maxzz tAvailableFlow imposed in constraint (59) constitutes

the residual transfer capacity in each corridor, after subtracting the corridor flow already scheduled in the wholesale market (Forward, Day-Ahead and Intra-Day Market).


As already discussed, the Flow-Based (FB) model allows a better representation of the

physical power flow constraints, as compared to the simple transportation model (ATC-

based model), through the usage of (linear) Power Transfer Distribution Factors (PTDFs).

In accordance with the description provided in the previous Paragraph, the following

constraints (60) - (63) are enforced in order to apply the FB model in the zonal imbalance

covering equation of the mFRR clearing problem:


(60)

z z

z

BEup BEupBEdn BEdnitk itititk

ki I i I

zt jtj

zt zt

zt

Quant Quant Mand Mand




2

K

L

, ,

, ,

,

z4

z z

z

jtj



z

t




R

C INTER

Z

Z T

(61) , , ,

z

zz t z z t ztz


Z T

(62) ,, ,,

, ' ,

z ref z

zz t z tzz tz

Flow = PTDF NetInjection z z t Z Z T

(63)

, , , ' , Max zzz t zz tFlow AvailableFlow z z tZ Z T


8.10 mFRR Clearing Results

The results of each subsequent mFRR clearing execution (it refers to both execution

methods for the mFRR clearing) comprise the 15-min-based activation of Upward and

Downward Balancing Energy Offers of all BSPs:

a) ,

BEup

it itkk

BEup Quant i t K

I T ,

b) ,

BEdn

it itkk

BEdn Quant i t K

I T

The above activated offers shall be used for the computation of the Dispatch Instructions

of all BSEs after the given mFRR clearing (e.g. executed at hh:00) regarding the (binding

/ first) Dispatch Period in question (hh:15 - hh:30), in order to attain system balancing.

The following Section contains analytical details on the issuance of the Dispatch

Instructions by the TSO.


8.11 Dispatch Instructions stemming from the mFRR Problem Solution

After the results of the mFRR problem solution have been obtained, the TSO shall issue

the respective Dispatch Instructions to the BSEs. The following provisions apply:

General Provisions

1) The TSO shall issue Dispatch Instructions which differ from the ISP results depending

on the degree of deviation of the operating conditions of the system, the possibly

updated Balancing Energy Offers of the BSEs, and the Available Capacity of the

BSEs during the mFRR process, from those that have been taken into account when

implementing the ISP.

2) A Dispatch Instruction (in MW) shall be issued by the TSO to each BSE the sooner

possible after the results of the given mFRR clearing have been obtained for 15-min

Dispatch Period in question. Essentially, the Dispatch Instruction that shall be issued

to each “in the market” BSE is the itP derived from the solution of the mFRR process.

(35) this equation is intentionally left blank

3) In case the TSO issues Dispatch Instructions which differ from the above stated ones

(i.e., from the Dispatch Instructions resulting from the outcome of the mFRR), then

the TSO shall submit a report to the Regulator justifying the choice of BSEs to cover

the system imbalance, in case such report is requested by the Regulator

4) The Dispatch Instructions differ from the AGC Instructions, which are provided by the

Automatic Generation Control system, and they also differ from the commitment

instructions that are issued based on the ISP results.

5) The BSEs selected for activation of Balancing Energy are obliged to follow the

Dispatch Instructions issued by the TSO for the relevant volumes and time period

they have been selected for.

Sending of Dispatch Instructions

1) Dispatch Instructions shall be sent by the TSO to the BSPs using the Dispatch

Information Administration System.

2) In case of Dispatch Information Administration System outage which renders

impossible the sending of a Dispatch Instruction, alternative means of

communications shall be used.


Obligation of Balancing Services Providers to comply with instructions

1) BSPs ensure the way of operation of their BSEs as this is established in the Dispatch

Instructions and change the operation of their BSE only following a Dispatch

Instruction.

2) Where compliance with a Dispatch Instruction is impossible due to constraints to the

operation of a Generating Unit, Dispatchable RES Portfolio, Dispatchable Load

Portfolio, which constraints are included in the Declared Characteristics of the BSE,

the respective Participant shall immediately inform the TSO. In that case, the TSO

may revoke the initial Dispatch Instruction and issue a new one.

3) Where compliance with a Dispatch Instruction has become impossible due to an

unforeseen impediment due exclusively to reasons regarding the safety of the

personnel or the installations of a Generating Unit, Dispatchable RES Portfolio,

Dispatchable Load Portfolio, the respective BSP is required to immediately inform the

TSO. In such case, the TSO may issue a new Dispatch Instruction in accordance with

the new Declared Characteristics of the respective BSE.

4) BSPs shall comply with the Commitment Instructions that concern the

synchronization or desynchronization of their BSE, if they execute them with a ten

(10) minute deviation from the time established in such instructions.

5) BSPs shall comply with Dispatch Instructions that refer to Active Power generation /

offtake by their BSEs, if they execute such Dispatch Instructions with a maximum

non-systematic deviation of ±5 MW (threshold defined by the TSO) from the Active

Power value and within the period established in such Dispatch Instructions.

6) In case of non-compliance on the part of a BSP with a Dispatch Instruction, the TSO

shall point out such non-compliance to such BSP indicating the relevant BSE, the

Dispatch Instruction and the time of its issue. Under no circumstances shall such

obligation of the TSO release such BSP from its obligations deriving from the

Dispatch Instruction and the consequences that may be incurred by it due to non-

compliance with such Dispatch Instruction.

Records and reporting regarding the dispatch procedure

1) The TSO is required to keep a complete data base regarding the dispatch procedure,

including:

a) a ISP Schedule record;

b) a Dispatch Instruction record;

c) a record of the proof of receipt of Dispatch Instructions.


2) The information contained in the above records shall be kept by the TSO for at least

five (5) years from their entry.

3) BSPs are entitled to access to the above information in any case for their BSEs, as

well as for other BSEs only in the context of settling disputes in accordance with the

procedure established in the Independent Transmission System Operation Code.

4) The TSO shall also provide all necessary information in accordance with the EU

Regulation for Energy Markets Integrity and Transparency (REMIT) and submission

and publication of data on Transparency platform of ENTSO-E.

Dispatch procedure statistics

1) The TSO is required to publish at the end of each calendar month information about

the dispatch procedure which shall include at least the following:

a) the total Energy and the maximum total system load per Dispatch Day;

b) the zonal total imbalances per Real-Time Unit;

c) the zonal marginal Balancing Energy prices per Real-Time Unit, corresponding

to the activated Balancing Energy;

d) any system events;

e) cumulative information regarding breaches of Dispatch Instructions by BSEs, as

well as information concerning the relevant actions of the TSO.

8.12 Direct Activation of mFRR

The Direct Activation (DA) of mFRR refers to the 2nd implementation phase of the

Balancing Market in Greece, where cross-border balancing shall be initiated.

Direct Activation of mFRR means an activation of mFRR Balancing Energy without

performing the described periodic mFRR process with 15 minutes cycles.

The Transmission System Operator is entitled to activate mFRR Balancing Energy

directly and send Dispatch Instructions to the Balancing Service Entities, in order to

balance the system in case of incidents, at any time between the scheduled runs of the

mFRR process, that necessitate immediate action to balance the system.

For this purpose, the Transmission System Operator creates indicatively can run the

mFRR process within the 15 minutes cycle time and/or create two merit order lists based

on the submitted Balancing Energy Offer prices, one in the upward direction and one in

the downward direction, including the Balancing Service Entities that can provide mFRR

Balancing Energy in each direction. The mFRR Balancing Energy quantity that can be


provided by each Balancing Service Entity is calculated based on their Balancing Energy

Offer quantity and their technical characteristics.

In such cases, the Transmission System Operator is entitled to select and activate mFRR

Balancing Energy sequentially from the merit order list in the appropriate direction.

The activation of Balancing Energy from a direct activation of mFRR starts immediately

after the receipt of the relevant dispatch instruction and ends at the end of the Real Time

Unit in which the dispatch instruction was issued.

The Balancing Energy Offers related to the direct activation of mFRR are taken into

account when calculating the Balancing Energy Price for the specific Balancing Energy

Settlement Time Unit.

8.13 Activation of aFRR

aFRR Balancing Energy is activated using the Automatic Generation Control (AGC)

function of the Transmission System Operator for frequency control as defined in

COMMISSION REGULATION (EU) 2017/1485 of 2 August 2017 establishing a guideline

on electricity transmission system operation.

All Balancing Service Entities with aFRR awards in the latest ISP are activated almost

simultaneously by the Transmission System Operator for the provision of aFRR Balancing

Energy. The criteria for the activation of aFRR Balancing Energy include the aFRR

Balancing Energy Offer prices and the ramp-rates of the Balancing Service Entities.

More details on the activation of aFRR Balancing Energy is included in the Balancing

Market Manual.

8.14 Responsibilities of the Transmission System Operator

In the context of the RTBEM the TSO shall:

1) collect the real-time telemetered power generation / offtake of the BSEs;

2) perform very short-term zonal Non-Dispatchable Load Forecasts for each 15-min

Dispatch Period of each execution of the mFRR process ;

3) perform very short-term zonal RES FiT Portfolio Forecasts for each 15-min Dispatch

Period of each execution of the mFRR process ;

4) perform very short-term zonal Non-Dispatchable RES Portfolios Forecasts for each

15-min Dispatch Period of each execution of the mFRR process ;

5) acquire and validate the updated Balancing Energy Offers and Non-Availability


Declarations from the BSPs;

6) operate the TSO Nomination Platform;

7) compute the respective zonal imbalances that should be covered by the activation of

Balancing Energy Offers;

8) compute the residual available flows in the inter-zonal corridors (corridors among

neighboring Bidding Zones) for the solution of the mFRR process;

9) attain the mFRR process results and the aFRR process results per BSE;

10) issue Dispatch Instructions and send them to BSEs;;

11) issue AGC Instructions and and send them to BSEs

12) monitor the compliance of BSEs to the Dispatch Instructions;

13) manage and use the Dispatch Information Administration System;

14) send the Balancing Market results to the Settlement for proper respective

calculations;

15) send the Settlement calculations to the Clearing House for invoicing, cash transfers

and Risk Management purposes;

16) publish statistics and information with regard to the results of the RTBEM and the

associated Dispatch Instructions; and

17) submit information to the ENTSO-E Transparency Platform and ACER.


9 Settlements

9.1 General Provisions

This Chapter presents:

a) the settlement of Balancing Energy and Balancing Capacity between the TSO and

the eligible BSΕs (through their respective BSPs), and

b) the Imbalance Settlement between the TSO and the Balance Responsible Entities

(BREs) (through their respective BRPs).

9.1.1 Balancing Market Settlements

The Settlements regarding the Balancing Market mainly consist of the following

procedures:

a) the Balancing Energy and Imbalance Settlement computations;

b) pay-as-bid reimbursement for offers activated for purposes other than balancing;

c) Contracted Units Settlement;

d) the Balancing Capacity Settlement;

e) other Ancillary Services Settlement;

f) the Uplift Account with respect to the System Losses, Balancing Capacity, Ancillary

Services, Contracted Units and Emergency Imports and Exports;

g) the Non-Compliance Charges computations; and

h) the Balancing Market Fee

i) the Transmission Use of System charges (system tariffs)

j) Calculation of the amount for financial neutrality of the TSO.

The Imbalance Settlement Period for the calculations of the Balancing Market settlements

is fifteen (15) minutes.

Financial neutrality of the TSO is achieved by a relevant amendment in the system tariffs

for next years. Specifically, net sums remaining after the Balancing Energy and Imbalance

Settlement for each Imbalance Settlement Period including interconnection deviations

and TSO interconnection schedules are credited/debited to a special reserve account of

the TSO, and are considered when calculating the system tariffs for next years. The TSO

may include a provision of the above net sum for next year Y+1 in order to be included in

the system tariffs of the year Y+1.

9.1.2 Responsibilities of the Transmission System Operator

In the context of the Settlements the Transmission System Operator is responsible to:


a) develop, maintain and operate the Balancing Market Settlement System;

b) calculate the debits and credits of each BSE / BRE concerning the settlement of

Balancing Energy and Reserve Capacity the Imbalance Settlement and other

Market Settlements;

c) issue the Initial Balancing Settlement Statement and the Reconciliation Balancing

Settlement Statements to the respective Participants, and

d) send to the Clearing House the final debits and credits per Participant.

The Transmission System Operator keeps a separate Balancing Market Account per type

of charge of the Balancing Market settlements, and a separate Participant Market Account

per Participant.

9.1.3 Obligations of the Distribution System Operator in the context of the Settlemnt Procedure

The Distribution System Operator shall calculate and provide to the Transmission System

Operator per Imbalance Settlement Period and Load Representative the following

regarding the Offtake of consumers connected at the Low Voltage of the Interconnected

System:

a) the ex-ante representation percentages per Load Representative and per Profile

Class, until the 20th calendar day of month M-1 for the Offtake of month M;

b) the total Offtake at the Low Voltage Profiled Offtake Meters for each Profile Class

for each Imbalance Settlement Period of month M, expressed at the Transmission-

Distribution Boundary, until the 18th calendar day of month M+1 for month M.

The Distribution System Operator shall provide to the Transmission System Operator the

aggregated metering data per Imbalance Settlement Period and Load Representative for

the Offtake of consumers connected at the Medium Voltage of the Interconnected System

expressed at the Transmission-Distribution Boundary, until the 14th calendar day of

month M+1 for month M.

The Distribution System Operator shall provide to the Transmission System Operator the

aggregated metering data per Imbalance Settlement Period for the production of RES

units connected at the Low Voltage of the Interconnected System expressed at the

Transmission-Distribution Boundary, until the 14th calendar day of month M+1 for month

M.

For every calendar month M, the Distribution System Operator will perform a

reconciliation calculation for (i) the offtake of each Profiled Meter, (ii) metering data of

consumers connected at the Medium Voltage Network and (iii) production of RES units

connected at the Low Voltage Network and send relevant data to the Transmission

System Operator the latest at the last day of month M+6, at the last day of month M+12


and at the last day of month M+24. No reconciliation for Profiled Meters is possible after

the above deadline.

9.1.4 Balancing Market Accounts

The Transmission System Operator shall establish and maintain the following Balancing

Market Accounts:

a) Balancing Energy Account;

b) Non-Balancing Energy Account;

c) Imbalance Energy Account;

d) Balancing Capacity Account;

e) Ancillary Services Account;

f) Contracted Units Account;

g) Uplift Account;

h) Non-Compliance Charges Account;

i) Balancing Market Fees;

j) Reserve Account for Financial Neutrality;

k) Transmission Use of System Account

The Transmission System Operator keeps a separate Participant Market Account per

Participant, in order to register the debits and credits stemming from the Balancing Market

settlements. A Participant Account shall be deactivated following removal of the relevant

Participant from the BSP Registry or the BRP Registry after all their overdue debts have

been paid, and after the finalization of all relevant settlements.

9.1.5 Settlement Scope

The Balancing Market Settlement S includes the following calculations for each Dispatch

Day:

a) mFRR Balancing Energy calculations for each BSE of a BSP and each Balancing

Energy Settlement Period in the Dispatch Day;

b) aFRR Balancing Energy calculations for each BSE of a BSP and each Balancing

Energy Settlement Period in the Dispatch Day;

c) energy provided by BSEs for purposes other than balancing for each BSE of a BSP

and each Balancing Energy Settlement Period in the Dispatch Day;

d) Imbalance quantity calculations for each BRE of a BRP and each Imbalance

Settlement Period in the Dispatch Day;


e) Imbalance Adjustment quantity calculations for each BSE of a BSP and each

Imbalance Settlement Period in the Dispatch Day;

f) Payment and charge calculations for the activated Balancing Energy of BSEs from

for each Imbalance Settlement Period in the Dispatch Day;

g) Payment and charge calculations for the activated Energy of BSEs for purposes other

than balancing for each Imbalance Settlement Period in the Dispatch Day;

h) Payment and charge calculations for the Imbalance of BREs for each Imbalance

Settlement Period in the Dispatch Day;

i) payment and charge calculations for Contracted Units;

j) payment and charge calculations for other Ancillary Services;

k) Cost of losses for each Imbalance Settlement Period in the Dispatch Day;

l) Calculation of non-compliance charges;

m) Calculation of the relevant Uplift Account costs;

n) Calculation of Balancing Market Fees; and

o) Calculation of amount to ensure financial neutrality of the Transmission System

Operator.

p) Calculation of Transmission Use of System charges

9.1.6 Settlement Input Data

The Settlement input data mainly consists of:

a) the Market Schedules of each BRE stemming from Day-Ahead Market and Intraday

Market accepted quantities;


b) the activated mFRR Balancing Energy Offers (quantity and price) per Real-Time Unit,

taken by the mFRR process;

c) the activated aFRR Balancing Energy Offers (quantity and price) per Real-Time Unit,

taken by the aFRR process;

d) The actual dispatch instructions sent to the BSPs

e) the SCADA measurements for Balancing Service Entities operating under AGC;

f) the Balancing Energy Offers of the Balancing Service Entities;

g) the Day-Ahead Market clearing prices per Delivery Period;

h) flags for activation of Balancing Energy Offers for non-balancing purposes;

i) the Certified Metered Energy quantities of all – production and demand – Entities and

interconnections;

j) the aggregated metered energy quantities for medium Voltage consumers by the

DSO;

k) the energy profiles for non-telemetered entities by the DSOs;

l) the aggregated RES units injections in the Low Voltage by the DSOs;

m) the Declared Characteristics of the Balancing Service Entities;

n) the latest valid Total or Partial Non-Availability Declarations of the Balancing Service

Entities;

o) the ISP results for awarded Reserve Capacity quantities to the BSEs, namely upward

and downward FCR, aFRR and mFRR, in MW;

p) the Reserve Capacity Offers of the Balancing Service Entities; and

q) the real-time availability of the BSEs to provide each type of Reserve Capacity, as

declared or ascertained in real time.


9.2 Balancing Energy and Imbalance Settlement

9.2.1 Balancing Energy and Imbalance Definitions

The Activated Balancing Energy is calculated for each Imbalance Settlement Period

separately for mFRR and aFRR. The Activated Balancing Energy is calculated based on

the results of the mFRR and aFRR processes, the actual availability of BSEs, the state

of the BSE and other special characteristics of the BSEs

a) Upward Activated Balancing Energy ( upABE ) is the additional energy

corresponding to the final Dispatch Instruction for additional balancing energy

production from generating BSEs (Generating Units, Dispatchable RES Portfolios)

with respect to their relevant Market Schedule, or equivalently less energy

consumption from Dispatchable Load Portfolios with respect to their relevant

Market Schedule; and

b) Downward Activated Balancing Energy ( dnABE ) is the reduction in energy

corresponding to the final Dispatch Instruction for less balancing energy production

from generating BSEs (Generating Units, Dispatchable RES Portfolios) with

respect to their relevant Market Schedule, or equivalently for additional energy

consumption from Dispatchable Load Portfolios with respect to their relevant

Market Schedule.

The Activated Energy for reasons other than balancing (Activated Other Energy) is

calculated for each Imbalance Settlement Period.

a) Upward Activated Other Energy (AOEup) is the additional energy corresponding

to the final Dispatch Instruction for additional energy production for reasons other

than balancing from generating BSEs (Generating Units, Dispatchable RES

Portfolios) with respect to their relevant Market Schedule, or equivalently less

energy consumption from Dispatchable Load Portfolios with respect to their

relevant Market Schedule; and

b) Downward Activated Balancing Energy (AOEdn) is the reduction in energy

corresponding to the final Dispatch Instruction for less energy production for

reasons other than balancing from generating BSEs (Generating Units,

Dispatchable RES Portfolios) with respect to their relevant Market Schedule, or

equivalently for additional energy consumption from Dispatchable Load Portfolios

with respect to their relevant Market Schedule.

The Total Activated Energy is calculated for each Imbalance Settlement Period as the

sum of all activated Balancing Energy Offers

TAEup=ABEup+AOEup


TAEdn=ABEdn+AOEdn.

The Instructed Energy of a Balancing Service Entity e for an Imbalance Settlement Period

t is equal to the Market Schedule plus the Upward mFRR Activated Balancing Energy

minus the Downward mFRR Activated Balancing Energy plus the Upward Activated Other

Energy minus the Downward Activated Other Energy, as follows. A tolerance per BSE

category may apply in the calculation below:

𝐼𝑁𝑆𝑇𝑒,𝑡 = 𝑀𝑆𝑒,𝑡 + 𝐴𝐵𝐸𝑒,𝑡𝑚𝐹𝑅𝑅,𝑢𝑝 − 𝐴𝐵𝐸𝑒,𝑡

𝑚𝐹𝑅𝑅,𝑑𝑛 + 𝐴𝑜𝐸𝑒,𝑡𝑢𝑝 − 𝐴𝑜𝐸𝑒,𝑡

𝑑𝑛

A tolerance per BRE category may be included in the calculation of the Instructed Energy

above.

The integral of the SCADA measurements of a Balance Responsible Entity e within an

Imbalance Settlement Period t which are higher than the Instructed Energy, ,e tINST , is

defined as the SCADA Upward Quantity, ,upe tSQ .

The integral of the SCADA measurements of a Balance Responsible Entity e within an

Imbalance Settlement Period t which are lower than the Instructed Energy, ,e tINST , is

defined as the SCADA Downward Quantity, ,dne tSQ .

The Imbalance of a Balance Responsible Entity e for an Imbalance Settlement Period t

is equal to the difference between the Entity’s Metered Quantity and the Entity’s Market

Schedule, as follows:

, , ,e t e t e tIMB MQ MS

A tolerance per BRE category may be included in the calculation above.

The Imbalance Adjustment of a Balance Responsible Entity e for an Imbalance

Settlement Period t is equal to the difference between the Entity’s Market Schedule and

the Entity’s Instructed Energy, as follows:

𝐼𝑀𝐵𝐴𝐷𝐽𝑒,𝑡 = 𝑚𝑖𝑛{[𝑀𝑆𝑒,𝑡 −𝑚𝑖𝑛(𝑀𝑄𝑒𝑡, 𝐼𝑁𝑆𝑇𝑒𝑡)], 0}, for upward balancing energy provision,

𝐼𝑀𝐵𝐴𝐷𝐽𝑒,𝑡 = 𝑚𝑎𝑥{[𝑀𝑆𝑒,𝑡 −𝑚𝑎𝑥(𝑀𝑄𝑒𝑡, 𝐼𝑁𝑆𝑇𝑒𝑡)], 0}, for downward balancing energy

provision

A tolerance per BRE category may be included in the calculation above. Moreover a

different tolerance may be applied for BRE in Commisioning Operation.

The Final Imbalance of a Balancing Service Entity e not operating under AGC for an

Imbalance Settlement Period t is equal to the Imbalance plus the Imbalance Adjustment,

as follows:

, , ,e t e t e tFIMB IMB IMBADJ


The Final Imbalance of a Balancing Service Entity e operating under AGC for an

Imbalance Settlement Period t is equal to zero (same with the current provisions of Annex

III of the Dispatch Manual of ADMIE).

The Final Imbalance of a Balance Responsible Entity e for an Imbalance Settlement

Period t is equal to the Imbalance as follows:

, , , ,e t e t e t e tFIMB IMB MQ MS

The Provided Upward mFRR Balancing Energy of a Balancing Service Entity e for an

Imbalance Settlement Period t is calculated as follows:

A) in case the BSE is not under AGC operation, ,upe tmFRR_PBE is computed as follows:

, , , ,max min , ,0upe t e t e t e tmFRR_PBE MQ INST MS

B) in case the BSE is under AGC operation, ,upe tmFRR_PBE is computed as follows:

, , ,max ,0upe t e t e tmFRR_PBE INST MS

The Provided Downward mFRR Balancing Energy of a Balancing Service Entity e for an

Imbalance Settlement Period t is calculated as follows:

A) in case the BSE is not under AGC operation, ,dne tmFRR_PBE is computed as follows:

, , , ,min max , ,0dne t e t e t e tmFRR_PBE MQ INST MS

B) in case the BSE is under AGC operation, ,dne tmFRR_PBE is computed as follows:

, , ,min ,0dne t e t e tmFRR_PBE INST MS

In case a Balancing Service Entity e is operating under AGC in an Imbalance Settlement

Period t , then the Provided Upward aFRR Balancing Energy is calculated as follows:

, , ,up upe t e t e taFRR_PBE SQ INST

and the Provided Downward aFRR Balancing Energy is calculated as follows:

, , ,dn dne t e t e taFRR_PBE SQ INST

According to the convention:

A) positive Final Imbalance means higher metered production from generating

BSEs (Generating Units and Dispatchable RES Portfolios) in real time as

compared to the relevant Dispatch Instruction, or equivalently less metered

consumption from Dispatchable Load Portfolios in real time as compared to the

relevant Dispatch Instruction; and


B) negative Final Imbalance means lower metered production from generating

BSEs (Generating Units and Dispatchable RES Portfolios) in real time as

compared to the relevant average Dispatch Instruction, or equivalently higher

metered consumption from Dispatchable Load Portfolios in real time as

compared to the relevant Dispatch Instruction.

In case the Market Schedule of a BRE e is smaller than the Technical Minimum of the

entity then:

(a) If in the ISP the energy is zero the quantity from Market Schedule to zero

is considered to be an imbalance

(b) If in the ISP the energy is larger than or equal to the Technical Minimum

the quantity from Market Schedule to the Technical Minimum is considered

to be an imbalance.

9.2.2 mFRR Balancing Energy Price

In case there is no congestion between the Bidding Zones, the mFRR Upward Balancing

Energy Price (in €/MWh) for each Imbalance Settlement Period for upward activation of

Balancing Energy is the price of the most expensive bid of mFRR which has been

activated to cover the System Imbalance. In case there is congestion between the Bidding

Zones, the Upward Balancing Energy Price for each Imbalance Settlement Period for

upward activation of Balancing Energy for each Bidding Zone is the price of the most

expensive bid of mFRR which has been activated to cover the Zonal Imbalance of the

specific Bidding Zone.

In case there is no congestion between the Bidding Zones, the mFRR Downward

Balancing Energy Price for each Imbalance Settlement Period for downward activation of

Balancing Energy is the price of the least expensive bid of mFRR which has been

activated to cover the System Imbalance. If there is congestion between the Bidding

Zones, the Downward Balancing Energy Price for each Imbalance Settlement Period for

downward activation of Balancing Energy for each Bidding Zone is the price of the least

expensive bid of mFRR, which has been activated to cover the Zonal Imbalance of the

specific bidding zone.

Upward and downward Balancing Energy Offers that are activated for reasons other than

Balancing Energy shall be tagged and excluded during the Balancing Energy Price

calculation. Other than balancing reasons will be proposed by the TSO and be approved

by the Regulator. Indicatively they can include system constraints management,

redispatching and for reconstitution of reserves.

Under Extreme Conditions when Supplementary System Energy Provision is activated

the Marginal Settlement Price (MSP) per Imbalance Settlement Period is set at the

Administratively Defined Balancing Energy Offer Cap. Contracted Units offering


Supplementary System Energy Provision are paid in accordance with the terms and

conditions of a Supplementary System Energy Contract.

9.2.3 Remuneration of Provided Balancing Energy

The remuneration / charge for the BSEs per Imbalance Settlement Period for the Provided

Balancing Energy shall be calculated as follows:

a) the Provided Upward Balancing Energy for each Imbalance Settlement Period

multiplied with the relevant Price; and

b) the Provided Downward mFRR Balancing Energy for each Imbalance Settlement

Period multiplied with the relevant Price.

The relevant credit/debit of the activated volume of Balancing Energy shall be defined for

each direction as defined in the next table:

positive relevant Price

negative relevant Price

Upward Balancing Energy Payment from TSO to

BSP Payment from BSP to

TSO

Downward Balancing Energy

Payment from BSP to TSO

Payment from TSO to BSP

.

9.2.4 Remuneration of Provided mFRR Balancing Energy

The remuneration / charge for the BSEs per Imbalance Settlement Period for the Provided

mFRR Balancing Energy shall be calculated as follows:

c) the Provided Upward mFRR Balancing Energy for each Imbalance Settlement

Period multiplied with the zonal mFRR upward Balancing Energy Price; and

d) the Provided Downward mFRR Balancing Energy for each Imbalance Settlement

Period multiplied with the zonal mFRR downward Balancing Energy Price.

The Balancing Energy Price, be it positive, zero or negative, of the activated volume of

Balancing Energy shall be defined for each direction as defined in the next table:

.


9.2.5 Remuneration Balancing Energy Offers activated for reasons other balancing

The Balancing Service Entities for which the Transmission System Operator activates

upward and downward Balancing Energy Offers for reasons other than Balancing Energy

shall be flagged. For such Entities, the respective BSP shall be credited based on the

pay-as-bid principle, namely based on the Balancing Energy Offer prices of these BSEs.

9.2.6 Remuneration of Provided aFRR Balancing Energy

The remuneration / charge for each BSE per Imbalance Settlement Period for the

Provided Upward aFRR Balancing Energy shall be calculated as the product of:

a) the Provided Upward aFRR Balancing Energy of the BSE during the Imbalance


b) the maximum of the mFRR Balancing Energy Price and the relevant aFRR


The charge / remuneration for each BSE per Imbalance Settlement Period for the

Provided Downward aFRR Balancing Energy shall be calculated as the product of:

a) the Provided Downward aFRR Balancing Energy of the BSE during the Imbalance


b) the minimum of the mFRR Balancing Energy Price and the relevant aFRR


9.2.7 Derivation of the Imbalance Settlement Price

The Imbalance Settlement Price (in €/MWh) per Imbalance Settlement Period shall be

calculated as follows:The zonal Upward Imbalance Price upztIP is computed for an

Imbalance Settlement Period t, in which the respective Bidding Zone z was short, as the

weighted average price of all activated upward Balancing Energy quantities (aFRR and

mFRR).The zonal Downward Imbalance Price dnztIP is computed for an Imbalance

Settlement Period t, in which the respective Bidding Zone z was long, as the weighted

average price of all activated downward Balancing Energy quantities (aFRR and mFRR).

The Reference Price ztRP shall be used in an Imbalance Settlement Period t:

for all settlements with the BRPs, if the respective Bidding Zone z is neutral (neither short

nor long), or for the settlement of any BRP Imbalance, if this Imbalance is in the opposite

direction as compared to the direction of the zonal imbalance, namely if the BRP

Imbalance passively contributed to restore the zonal balance (“passive balancing”).


The Reference Price ztRP shall be equal to the Day-Ahead Market clearing price for the

corresponding Market Time Unit, namely the Market Time Unit within which the given

Imbalance Settlement Period lies.

The Imbalance pricing regime is presented in the following Table.

Zonal imbalance

Negative (Short) Zero Positive (Long)

BR

E

Imb

ala

nc

e

Negative (Short) + upztIP + ztRP + max{ up

ztIP , ztRP }

Zero - - -

Positive (Long) -min{ upztIP , ztRP } - ztRP - dn

ztIP

An Administratively Defined Imbalance Energy Price Cap may be defined after a proposal

by the Transmission System Operator and a decision by the Regulator. The

Administratively Defined Imbalance Energy Price Cap will be used in case the zonal

imbalance is very low and the zonal Upward or Downward Imbalance Price computed as

the weighted average price of all activated Balancing Energy quantities is abnormally

high.

9.2.8 Imbalance Settlement

The Imbalance Settlement allocates the balancing costs incurred by the Transmission

System Operator, when activating Balancing Energy in the RTBEM to the Participants

that caused the imbalances. The Imbalance Settlement is performed initially per BRE and

afterwards aggregated per BRP, calculating the algebraic sum of Imbalance Amounts of

all BREs registered in the respective BRP Account.

The Imbalance Amount of a Balance Responsible Entity e providing mFRR and/or aFRR

Balancing Energy for an Imbalance Settlement Period t is calculated as follows:

The Imbalance Amount of a Balance Responsible Entity e for an Imbalance Settlement

Period t is calculated as the Final Imbalance ,e tFIMB multiplied by the Imbalance

Settlement Price.

In case the Imbalance Amount is positive, the BRE is debited with the calculated amount.

In case the Imbalance Amount is negative, the BRE is credited with the calculated amount

Under a recommendation of the Transmission System Operator and approval of the

Regulator, specific tolerances may be defined in the calculation of the Imbalance

Amounts of the RES Portfolios.


9.3 Balancing Capacity Settlement

9.3.1 Balancing Capacity Settlement Period

Balancing Capacity shall be settled with a 15-minutes time step corresponding to the

Imbalance Settlement Period. For this purpose the half-hourly Balancing Capacity results

of the ISP shall be converted into 15-minutes results. The Balancing Capacity results shall

be the same for the two 15- minutes intervals corresponding to each half-hourly interval

of the ISP.

9.3.2 Remuneration Calculation

The upward and downward FCR, aFRR and mFRR awards are taken from the solution

of the last updated Integrated Scheduling Process, for each BSE and for each AS

Imbalance Settlement Period of each Dispatch Day. The remuneration of Balancing

Service Entity e for the provision of FCR, aFRR and mFRR is calculated as described in

the following Paragraphs.

The upward and downward FCR that were available for provision in real-time by

Balancing Service Entity e for AS Imbalance Settlement Period t are calculated as follows:

,, , ,

up up FCR upe t e t e tPFCR FCR T , ,

, , ,dn dn FCR dne t e t e tPFCR FCR T

where:

,upe tFCR the provided upward FCR capacity by Balancing Service Entity e in real-time

(upward FCR Award from the Integrated Scheduling Process) for Imbalance

Settlement Period t ;

,,FCR up

e tT the percentage of time-period within a Imbalance Settlement Period t that a

Balancing Service Entity e was available for providing upward FCR in real-time;

,dne tFCR the provided downward FCR capacity by Balancing Service Entity e in real-time

(downward FCR Award from the Integrated Scheduling Process) for Imbalance

Settlement Period t ;

,,FCR dn


Balancing Service Entity e was available for providing downward FCR in real-

time;

The upward and downward aFRR that was available for provision in real-time by

Balancing Service Entity e for Imbalance Settlement Period t are calculated as follows:

,, , ,

up up aFRR upe t e t e tPaFRR aFRR T , ,

, , ,dn dn aFRR dne t e t e tPaFRR aFRR T

where:


,upe taFRR the provided upward aFRR capacity of Balancing Service Entity e in real-time

(part of or the whole upward aFRR Award from the Integrated Scheduling

Process) for Imbalance Settlement Period t ;

,dne taFRR the provided downward aFRR capacity of Balancing Service Entity e in real-time

(part of or the whole downward aFRR Award from the Integrated Scheduling

Process) for Imbalance Settlement Period t ;

,,aFRR up


Balancing Service Entity e was available for providing upward aFRR in real-

time;

,,aFRR dn


Balancing Service Entity e was available for providing downward aFRR in real-

time;

The upward and downward mFRR that was available for provision in real-time by

Balancing Service Entity e for Imbalance Settlement Period t is calculated as follows:

,, , ,

up up mFRR upe t e t e tPmFRR mFRR T , ,

, , ,dn dn mFRR dne t e t e tPmFRR mFRR T

where:

,upe tmFRR the provided upward mFRR of Balancing Service Entity e in real-time (part of or

the whole upward mFRR Award from the Integrated Scheduling Process) for

Imbalance Settlement Period t;

,,mFRR up


Balancing Service Entity e was available for providing upward mFRR in real-

time;

,dne tmFRR

the provided downward mFRR of Balancing Service Entity e in real-time (part of

or the whole downward mFRR Award from the Integrated Scheduling Process)

for Imbalance Settlement Period t; and

,,mFRR dn


Balancing Service Entity e was available for providing downward mFRR in real-

time.

The credits of Balancing Service Entity e for the provided upward and downward FCR,

aFRR and mFRR in Imbalance Settlement Period t, respectively, are calculated as

follows:

, ,, , , , ,

up FCR up dn FCR dne t e t e t e t e tCFCR PFCR OP PFCR OP

, ,

, , , , ,up aFRR up dn aFRR dn

e t e t e t e t e tCaFRR PaFRR OP PaFRR OP


, ,, , , , ,

up mFRR up dn mFRR dne t e t e t e t e tCmFRR PmFRR OP PmFRR OP

where:

,,FCR up

e tOP the Reserve Capacity Offer price of BSE e for providing upward FCR in the

Integrated Scheduling Process for Imbalance Settlement Period t;

,,FCR dn

e tOP the Reserve Capacity Offer price of BSE e for providing downward FCR in the


,,aFRR up

e tOP the Reserve Capacity Offer price of BSE e for providing upward aFRR in the


,,aFRR dn

e tOP the Reserve Capacity Offer price of BSE e for providing downward aFRR in the


,,mFRR up

e tOP the Reserve Capacity Offer price of BSE e for providing upward mFRR in the

Integrated Scheduling Process for Imbalance Settlement Period t; and

,,mFRR dn

e tOP the Reserve Capacity Offer price of BSE e for providing downward mFRR in the

Integrated Scheduling Process for Imbalance Settlement Period t.

9.4 Uplift Accounts

9.4.1 Uplift Accounts kept by the Transmission System Operator

The Uplift Account A-E includes the following sub-accounts:

a) UA-1: System Losses Uplift Account. This is the account for the allocation of the

cost of the system losses procured by the TSO.

b) UA-2: Balancing Capacity Uplift Account. This is the account for the allocation of

the cost Balancing Capacity.

c) UA-3: Ancillary Services Uplift Account. This is the account for the allocation for

the cost of Ancillary Services Account.

d) UA-4: Contracted Units Uplift Account. This is the account for the allocation for the

extra cost of contracted units.

e) UA-5: Emergency Imports and Exports Uplift Account. This is the account for the

allocation for the extra amounts related to Emergency Imports and Exports.

9.4.2 System Losses Uplift Account UA-1

The Transmission System Operator performs a forecast of the transmission system

losses and buys the respective energy to cover these losses by submitting Priority Price-

Taking Orders in the Day-Ahead Market and in the Intra-Day Market, as described in the

Day-Ahead Market Code and in the Intra-Day Market Code, respectively.


The Transmission System Operator calculates the actual transmission system losses,

and calculates the credit / debit of the Imbalance Settlement of these losses.

The System Losses Uplift Account UA-1 is used to cover the cost of transmission system

losses, which is calculated as the sum of the Day-Ahead Market and the Intra-Day Market

settlements, plus the credit / debit of the respective Imbalance Settlement.

The transmission system losses cost is allocated to BRPs in proportion to their metered

customer offtake in the Interconnected System in each Imbalance Settlement Period t ,

as follows:

,

,

,

1p t

p t t

p t

p

MQUPLIFT LOSSES

MQ

where:

tLOSSES the total cost of Transmission System Losses for Imbalance Settlement Period

t , in MWh

,p tMQ the Offtake (calculated at the Transmission-Distribution Boundary)

corresponding to consumers in the Interconnected System per BRP p for

Imbalance Settlement Period t , in MWh

9.4.3 Balancing Capacity Uplift Account UA-2

The Balancing Capacity Uplift Account UA-2 recovers the payments of Balancing

Capacity to the BSPs.

The cost for the provision of Balancing Capacity in each Imbalance Settlement Period t

,BALCAPt, is allocated to BRPs and BSPs in proportion to their total absolute Imbalance,

as follows:

,2

imbpt

p t t imbpt

p

PUPLIFT BALCAP

P

where:

tBALCAP cost for the provision of Balancing Capacity in each Imbalance Settlement

Period t , in €

imbetP the total Imbalance for the BRP or BSP for Imbalance Settlement Period t . The

total Imbalance is calculated as the algebraic sum of the imbalances of all

Entities of BRPs or BSP.


9.4.4 Ancillary Services Uplift Account UA-3

The Ancillary Services Uplift Account UA-3 recovers the cost of Ancillary Services.

The Ancillary Services cost is allocated to each BRP p in proportion to their metered

customer offtake in the Interconnected System in each month m , as follows:

,

,

,

3

p t

t mp m m

p t

p t m

MQ

UPLIFT ANCCMQ

where

mANCC the monthly Ancillary Services cost, including the cost of the Ancillary Services,

in €; and


corresponding to consumers in the Interconnected System per BRP p for each

Imbalance Settlement Period t .

9.4.5 Contracted Units Uplift Account UA-4

The Contracted Units Uplift Account UA-4 recovers the extra cost of Contracted Units.

The Contracted Units extra cost is allocated to each BRP p in proportion to their metered

customer offtake in the Interconnected System in each month m , as follows:

,

,

,

4

p t

t mp m m

p t

p t m

MQ

UPLIFT CONTRMQ

where

mCONTR the monthly Contracted Units extra cost; and




9.4.6 Emergency Imports and Exports Uplift Account UA-5

The Emergency Imports and Exports Uplift Account UA-5 recovers the extra cost of

Contracted Units.


The Emergency Imports and Exports extra cost is allocated to each BRP p in proportion

to their metered customer offtake in the Interconnected System in each month m , as

follows:

𝑈𝑃𝐿𝐼𝐹𝑇5𝑝,𝑡 = 𝐸𝑀𝐸𝑅𝐺𝑡𝑀𝑄𝑝,𝑡

∑ 𝑀𝑄𝑝,𝑡𝑝

where

mEMERG the Emergency Imports and Exports extra cost for each Imbalance Settlement

Period t ; and




9.5 Non-compliance Charges Settlement

9.5.1 Non-Compliance with Ancillary Services Dispatch Instructions by Balancing Service Providers

The Transmission System Operator shall calculate for each Imbalance Settlement Period

t of month m and for each Balancing Service Entity e the quantity of mFRR which the

Balancing Service Entity has been unable to provide despite the relevant Dispatch

Instructions and charge the respective Balancing Service Provider for such Imbalance Settlement Period the sum of ,e tNCAS , which is given by the following formula:

, , ,1x mFRR

e t AS e e t e tNCAS A NAS F CmFRR

where:

ASA a charge increase factor for non-compliance charges to Balancing Service

Entities for failing to follow Dispatch Instructions corresponding to activation of

mFRR awards;

eNAS a running counter of the Dispatch Days in the current calendar month when a

Balancing Service Entity e failed to follow Dispatch Instructions corresponding

to activation of mFRR awards at least for one Imbalance Settlement period t of

the corresponding Dispatch Day, which is bounded from above to the value

maxNAS ;

maxNAS the maximum value of the running counter eNAS

x an exponent between 0 and 1; and


,mFRR

e tF the part of the mFRR award that was not provided in real-time by the Balancing

Service Entity e during Imbalance Settlement Period t ; and

,e tCmFRR the remuneration of Balancing Service Entity e for the provided mFRR in


The numerical value of the charge increase factor ASA , NASmax and the exponent x shall

be established by proposal of the Transmission System Operator and a respective

decision of the Regulator. Such decision shall be taken at least two months prior to the

enforcement of the new values of the above parameters.

9.5.2 Consequences of non-lawful submission of Non-Availability Declarations

The Transmission System Operator shall verify whether Non-Availability Declarations

submitted are true and accurate and meet the requirements of this Code.

The Transmission System Operator may by a justified decision issued to the Participant

cancel a Total or Partial Non-Availability Declaration. In case of a decision to cancel a

Non-Availability Declaration or finding such a declaration unacceptable, the Transmission System Operator shall charge the Participant p for Dispatch Day d the sum of ,p dNCAV ,

calculated as follows:

, 1x

p d AV p u

u p

NCAV UNCAV A NAV NCAP

where:

UNCAV the unit charge for non-compliance charges to Participants for failing to submit

valid Non-Availability Declarations for their generation resources;

AVA the charge increase factor for non-compliance charges to Participants for failing

to submit valid Non-Availability Declarations for their generation resources;

pNAV the running counter of the Dispatch Days in the current calendar year when a

Participant failed to submit valid Non-Availability Declarations for its

generation resources, which starts to count after the first Dispatch Day with Non-Compliance of the year and is bounded from above to the value maxNAV .

maxNAV the maximum value of the running counter pNAV


uNCAP the Registered Capacity of generation resource u , in accordance with its

Registered Operating Characteristics, for which Participant p has submitted an

unacceptable Total or Partial Non-Availability Declaration for Trading Day d .

p


The numerical values of UNCAV unit charge, maxNAV , the exponent x and the AVA charge

increase factor shall be established by proposal of the Transmission System Operator

and a respective decision of the Regulator. Such decision shall be taken at least two

months prior to the enforcement of the new values of the above parameters.

9.5.3 Consequences of non-lawful Techno-Economic Declaration

In case of a decision on an unacceptable Techno-Economic Declaration for a Balancing Service Entity, the Transmission System Operator shall charge the Participant p for

Trading Day d the sum of ,p dNCTD , which is given by the following formula:

, 1x

p d TD p e

e p

NCTD UNCTD A NTD NCAP

where:

UNCTD the unit charge for non-compliance charges to Participants for failing to submit

valid Techno-Economic Declarations for their Balancing Service Entities;

TDA the charge increase factor for non-compliance charges to Participants for failing

to submit valid Techno-Economic Declarations for their Balancing Service

Entities;

pNTD a running counter of the Dispatch Days in the current calendar month when a

Participant failed to submit valid Techno-Economic Declarations for its

Balancing Service Entities, which starts to count after the first Dispatch Day

with Non-Compliance of the month and is bounded from above to the value

maxNTD ;

maxNTD the maximum value of the running counter pNTD


eNCAP the Registered Capacity of Balancing Service Entity e, in accordance with its

Registered Operating Characteristics, for which Participant p has submitted an

unacceptable Techno-Economic Declaration for Trading Day d .

The numerical values of UNCTD unit charge, maxNTD , the exponent x and the TDA charge




9.5.4 Consequences of non-submission of Balancing Energy Offers

In case of non-submission of Balancing Energy Offers for a Trading Day for a Balancing

Service Entity for which the respective Balancing Service Provider is obligated to such

p


submission, the Transmission System Operator shall charge such Balancing Service Provider for such Trading Day d the sum of ,e dNCBEO , calculated as follows:

, , ,1x up dn

e d EO e e t e t

t d

NCBEO UNCBEO A NBEO BEOO BEOO

where:

UNCBEO the unit charge for non-compliance charges to Balancing Service Providers for

failing to submit valid Balancing Energy Offers for their BSEs by the ISP1 Gate

Closure Time;

EOA the charge increase factor for non-compliance charges to Balancing Service

Providers for failing to submit valid Balancing Energy Offers for their BSEs by

the ISP1 Gate Closure;

eNBEO a running counter of the Dispatch Days in the current calendar month when a

Balancing Service Provider failed to submit valid Balancing Energy Offers for

its Balancing Service Entity e by the ISP1 Gate Closure, which starts to count

after the first Dispatch Day with Non-Compliance of the month and is bounded from above to the value maxNBEO ;

maxNBEO the maximum value of the running counter eNBEO

x an exponent between 0 and 1;

,upe tBEOO the part of the obligation of a Balancing Service Provider to provide an upward

Balancing Energy Offer for his Balancing Service Entity e for Trading Period t

by the ISP1 Gate Closure, for which such offer has not been submitted; and

,dne tBEOO the part of the obligation of a Balancing Service Provider to provide a downward

Balancing Energy Offer for his Balancing Service Entity e for Trading Period t

by the ISP1 Gate Closure, for which such offer has not been submitted.

The numerical values of UNCBEO unit charge, maxNBEO , the exponent x and the EOA

charge increase factor shall be established by proposal of the Transmission System

Operator and a respective decision of the Regulator. Such decision shall be taken at least

two months prior to the enforcement of the new values of the above parameters.

9.5.5 Consequences of non-submission of Reserve Capacity Offers

In case of non-submission of FCR, aFRR and mFRR Offers for a Trading Day d by a

Balancing Service Provider p obligated to such submission for its Balancing Service

Provider e, the Transmission System Operator shall charge such Balancing Service Provider for such Trading Day the sum of ,p dNCRO , calculated as follows:

, 1x

p d RO p e e e

e p

NCRO UNCRO A NRO DFCR DaFRR DmFRR


where:

UNCRO the unit charge for non-compliance charges to Balancing Service Providers for

failing to submit valid Reserve Capacity Offers (for FCR, aFRR and mFRR) for

their Balancing Service Entities by the ISP1 Gate Closure;

ROA the charge increase factor for non-compliance charges to Balancing Service

Providers for failing to submit valid Reserve Capacity Offers (for FCR, aFRR

and mFRR) for their Balancing Service Entities by the ISP1 Gate Closure;

pNRO a running counter of the Dispatch Days in the current calendar month when a

Balancing Service Provider failed to submit valid Reserve Capacity Offers

(for FCR, aFRR and mFRR) for its Balancing Service Entity e by the ISP1 Gate

Closure, which starts to count after the first Dispatch Day with Non-Compliance of the month and is bounded from above to the value maxNRO ;

maxNRO the maximum value of the running counter pNRO

x an exponent between 0 and 1;

eDFCR the BSE e FCR capability, in accordance with its Declared Characteristics, for

which a FCR Offer has not been submitted;

eDaFRR the BSE e aFRR capability, in accordance with its Declared Characteristics, for

which an aFRR Offer has not been submitted; and

eDmFRR the BSE e mFRR capability, in accordance with its Declared Characteristics,

for which an mFRR Offer has not been submitted.

The numerical values of UNCRO unit charge, maxNRO , the exponent x and the ROA charge




9.5.6 Consequences of significant non-performance of activated upward and downward Balancing Energy by a Balancing Service Entity

In case a significant non-performance of activated upward and downward Balancing

Energy by a Balancing Service Entity, namely in case the Balancing Service Entity’s metered generation/demand deviates significantly (above a specified tolerance limit beTOL

) from the Dispatch Instruction, then the Transmission System Operator shall charge the

respective Balancing Service Provider e for the Imbalance Settlement Period t the sum

p


,tote tNCNPBE , calculated using the following formula giving a tolerance of beSPTOL Imbalance

Settlement periods per month and per Balancing Service Provider e:

,

1 max 0, 1 ,

1 max 0, 1 ,

up upNPBE et be pt et et pt et

upe t

up upNPBE pt et be et et pt et

UNCNPBE A MQ TOL MS ABE if MQ MS ABENCNPBE

UNCNPBE A MS ABE TOL MQ if MQ MS ABE

,

1 max 0, 1 ,

1 max 0, 1 ,

dn dnNPBE et be pt et et pt et

dne t

dn dnNPBE pt et be et et pt et

UNCNPBE A MQ TOL MS ABE if MQ MS ABENCNPBE

UNCNPBE A MS ABE TOL MQ if MQ MS ABE

, , ,tot up dne t e t e tNCNPBE NCNPBE NCNPBE

where:

UNCNPBE the unit charge for non-compliance charges to Balancing Service Providers for

non-performance of their BSEs with respect to the activated upward and

downward Balancing Energy, in €/MWh;

NPBEA the charge increase factor for non-compliance charges to Balancing Service

Providers for non-performance of their BSEs with respect to the activated

upward and downward Balancing Energy;

etMQ the metered energy of Balancing Service Entity e for Imbalance Settlement

Period t properly adjusted for Transmission Losses and Distribution Losses, in

MWh;

beTOL the tolerance limit for the imposition of penalties to Balancing Service Providers

for significant non-performance of their BSEs with respect to the activated

upward and downward Balancing Energy, in %;

ptMS the Market Schedule of Balancing Service Entity e for Imbalance Settlement

Period t , in MWh;

upetABE the activated upward Balancing Energy of Balancing Service Entity e for

Imbalance Settlement Period t , in MWh; and

dnetABE the activated downward Balancing Energy of Balancing Service Entity e for

Imbalance Settlement Period t , in MWh.

The numerical values of UNCNPBE unit charge, the NPBEA charge increase factor, the

beSPTOL and the tolerance limit beTOL shall be established by proposal of the Transmission

System Operator and a respective decision of the Regulator. Such decision shall be taken

at least two months prior to the enforcement of the new values of the above parameters.


9.5.7 Consequences of significant systematic deviations in the demand purchased by Load Representatives

In case of systematic, within a month, significant deviations are ascertained between the energy quantity measured at all meters represented by a Load Representative p in an

Imbalance Settlement Period and the respective Market Schedule of the same Load

Representative, the Transmission System Operator shall charge such Load Representative the amount ,p mNCBAL , calculated based on the total absolute deviations

within the month m and the root-mean-square (RMS) value of the deviations within the

month m.

Significant deviation shall mean the case where the normalized absolute deviation for the month m exceeds the tolerance limit ,ld ADEVTOL or the normalized root-mean-square (RMS)

value of the deviations for the month m exceeds the tolerance limit ,ld RMSDEVTOL .

The deviation for every Imbalance Settlement Period t , ,p t

DEV , the monthly absolute

deviation for the month m, ,p mADEV , the normalized absolute deviation for the month m,

,p mNADEV , the monthly RMS deviation,

,p mRMSDEV , and the normalized RMS for the month

m, ,p mNRMSDEV , for Load Representative p are defined as follows:

,up dn

p t pt et et pte p

DEV MS ABE ABE MQ

, ,p m p tt m

ADEV DEV

,

,

, , ,

p m

p m

up dnp t e t e t

t m e p

ADEVNADEV

MS SBE SBE

2, ,p m p t

t m

RMSDEV DEV

,

,

p m

p m

up dnpt et et

t m e p

RMSDEVNRMSDEV

MS ABE ABE

where:

,p tDEV the deviation from the Market Schedule, adjusted for any activated upward

and/or downward Balancing Energy of the Dispatchable Load Portfolios represented by the Load Representative p for the Imbalance Settlement

Period t ;

ptMS the Market Schedule of Load Representative for Imbalance Settlement

Period .

p

t


,up dn

et etABE ABE the activated upward/downward Balancing Energy of the Dispatchable

Load Portfolios represented by the Load Representative p for the

Imbalance Settlement Period t; and

ptMQ the Offtake (calculated at the Generating Unit Meter Point) of Load

Representative p for Imbalance Settlement Period t properly adjusted

for Transmission Losses and Distribution Losses.

The monthly charge to Load Representative p for month m shall be calculated as the

maximum of the penalties derived from the monthly absolute and RMS deviations:

,, , ,

max ,, , , ,

0

UNCBAL ADEV NADEV TOLADEV p m p m ld ADEV

NCBAL UNCBAL RMSDEV NRMSDEV TOLp m RMSDEV p m p m ld RMSDEV

where:

ADEVUNCBAL the unit charge corresponding to non-compliance charges to Load

Representatives for the monthly normalized absolute deviation;

RMSDEVUNCBAL the unit charge corresponding to non-compliance charges to Load

Representatives for the monthly normalized RMS deviation;

,ld ADEVTOL the tolerance limit for the imposition of penalties to Load Representatives

for the monthly normalized absolute deviation; and

,ld RMSDEVTOL the tolerance limit for the imposition of penalties to Load Representatives

for the monthly normalized RMS deviation.

The numerical values of ADEVUNCBAL and RMSDEVUNCBAL unit charges, and the tolerance

limits ,ld ADEVTOL and ,ld RMSDEVTOL shall be established by proposal of the Transmission

System Operator and a respective decision of the Regulator. Such decision shall be taken

at least two months prior to the enforcement of the new values of the above parameters.

9.5.8 Consequences of significant systematic deviations in the actual generation of a Non-Dispatchable RES Portfolio

In case a significant deviation is ascertained between the energy quantity generated by

a Non-Dispatchable RES Portfolio in an Imbalance Settlement Period and the respective

Market Schedule of this Balance Responsible Entity e, the Transmission System Operator

shall charge the respective Participant for this Balance Responsible Entity the amount

,e mNCBALR calculated based on the total absolute deviations within the month m and the

root-mean-square (RMS) value of the deviations within the month m.


Significant deviation shall mean the case where the normalized absolute deviation for the month m exceeds the tolerance limit ,r ADEVTOL or the normalized root-mean-square (RMS)

value of the deviations for the month m exceeds the tolerance limit ,r RMSDEVTOL .

The deviation for every Imbalance Settlement Period t , ,e t

DEV , the monthly absolute

deviation for the month m, ,e m

ADEV , the normalized absolute deviation for the month m,

,e mNADEV , the monthly RMS deviation,

,e mRMSDEV , and the normalized RMS for the month

m, ,e m

NRMSDEV , for Balance Responsible Entity e are defined as follows:

,e t et etDEV MS MQ

,

,

e m

e m

ett m

ADEVNADEV

MS

2, ,e m e t

t m

RMSDEV DEV

2

,

,

et

t m

e m

e mMS

RMSDEVNRMSDEV

where:

,e tDEV the deviation from the Market Schedule of Balance Responsible Entity e for the

Imbalance Settlement Period t ;

etMS the Market Schedule Balance Responsible Entity e for Imbalance Settlement

Period t ; and

etMQ the generated energy of Balance Responsible Entity e for Imbalance

Settlement Period t , properly adjusted for Transmission Losses and

Distribution Losses.

The monthly charge corresponding to the Balance Responsible Entity e for month m shall

be calculated as the maximum of the penalties derived from the monthly absolute and

RMS deviations:

,, , ,

max ,, , , ,

0

UNCBALR ADEV NADEV TOLADEV e m e m r ADEV

NCBAL UNCBALR RMSDEV NRMSDEV TOLe m RMSDEV e m e m r RMSDEV

where:

, ,e m e tt m

ADEV DEV


ADEVUNCBALR the unit charge corresponding to Non-Compliance Charges to RES Units

for the monthly normalized absolute deviation;

RMSDEVUNCBALR the unit charge corresponding to Non-Compliance Charges to RES Units

for the monthly normalized RMS deviation;

,r ADEVTOL the tolerance limit for the imposition of penalties to RES Units for the

monthly normalized absolute deviation; and

,r RMSDEVTOL the tolerance limit for the imposition of penalties to RES Units for the

monthly normalized RMS deviation.

The numerical values of ADEVUNCBALR and RMSDEVUNCBALR unit charges, and the

tolerance limits ,r ADEVTOL and ,r RMSDEVTOL shall be established by proposal of the

Transmission System Operator and a respective decision of the Regulator. Such decision

shall be taken at least two months prior to the enforcement of the new values of the above

parameters.

9.5.9 Non-Compliance Charge for import/export deviations

In case there is a difference between the imported/exported quantity in the Market

Schedule of a Participant and his nomination of long-term Physical Transmission Rights

for electricity imports/exports through an interconnection for which an obligation for

physical delivery exists, then the Transmission System Operator shall compute the Non-

Compliance Charge of the relevant Participant for each Imbalance Settlement Period,

which shall be equal to the above deviation multiplied by the Administrative Defined

Trading Deviation Price UNCIR for imports and UNCER for exports, providing a tolerance

of one (1) Dispatch Day, per month and per participant, with at least one Imbalance

Settlement period with the above mentioned difference.

The numerical values of the Administrative Defined Trading Deviation Price, UNCIR and

UNCER, shall be established by proposal of the Transmission System Operator and a

respective decision of the Regulator.. Such decision shall be taken at least two months

prior to the enforcement of the new values of the above parameters.

9.5.10 Consequences of non-performance by a Contracted Unit

On any occasion for which a Contracted Unit has failed to synchronize following a lawful

commitment instruction by the Transmission System Operator or the Contracted Unit has

failed to be dispatched according to a lawful Dispatch Instruction, such failure related to

the inability of the Contracted Unit to reach the instructed generation level, the

Transmission System Operator shall notify the respective Participant for such non-

compliance.

On the first occurrence on a single of such non-compliance, the Transmission System Operator shall charge the respective Contracted Unit the sum ,1u tNCCU , calculated as

follows:


, ,1 ( )xu t NCCU u u tNCCU A nNCCU CRPM

where:

NCCUA the charge increase factor for non-compliance charges related to the inability

of the Contracted Unit to reach the instructed generation level;

nNCCU the number of Imbalance Settlement Periods in a calendar month for which

the non-compliance has occurred, while non-compliance during part of an

Imbalance Settlement Period is considered as non-compliance for the whole period, which is bounded from above to the value maxnNCCU ;

maxnNCCU the maximum value of nNCCU


,u tCRPM the capacity payment of the contracted Unit u that corresponds to one

Imbalance Settlement period t.

The numerical values of maxnNCCU , the exponent x and the NCCUA charge increase factor

shall be established by proposal of the Transmission System Operator and a respective

decision of the Regulator. Such decision shall be taken at least two months prior to the

enforcement of the new values of the above parameters.

The imposition of the non-compliance charge shall not release the Participant from the

obligations arising from the respective contract. On the occurrence of an additional

violation, the Transmission System Operator shall notify the Regulator which may impose

further sanctions.

9.5.11 Handling of the Non-Compliance amount

The total amount of the Non-Compliance Charges accumulated in the Non-Compliance

Charges Account A-D shall be credited on annual basis to TSO. The total annual amount

will be taken into consideration when calculating the system tariffs for the next years.

9.6 Balancing Market Settlement Process

The Balancing Market settlement shall be performed on a monthly basis. Settlement

months correspond to calendar months. For each Settlement Month, M, four settlement

runs are provisioned according to the timetable below:

Initial Settlement Run Last day of month M+1

1st Reconciliation Settlement Run Last day of month M+7

2nd Reconciliation Settlement Run Last day of month M+13

Final Reconciliation Settlement Run Last day of month M+25


Any corrections in the Settlement data and results can only occur on the specified dates

of the timetable above. After the ‘Final Reconciliation Settlement Run’ Date there can be

no corrections in the Settlement data and results. Exceptions to the above rule may apply

only after a relevant application by the affected Participant(s) and a decision by the

Regulator.

In carrying out any Reconciliation Settlement Run, the TSO shall:

A) make any adjustment or revision to any metering data;

B) make any adjustment or revision to any data following the resolution of any

Dispute;

C) use any adjusted or revised data submitted by the Market Operator or the DSOs;

D) use any revised Balancing Services data.

The Balancing Market Settlement for the Initial Settlement Run or any of the

Reconciliation Settlement Runs will be performed as follows:

A) The Transmission System Operator performs the necessary calculation of

quantities and amounts in €. The results of the Settlement calculations and any

relevant data are provided to the Participants by electronic means according to

the timetable;

B) no later than two (2) Working Days after the notification of the Settlement Results,

the Participants are entitled to lodge documented objections to the Transmission

System Operator;

C) no later than four (4) Working Days after the notification of the Settlement Results,

the Transmission System Operator shall decide on any objections, and proceed

with necessary corrections, if possible;

D) no later than five (5) Working Days after the notification of the Settlement Results,

the Transmission System Operator shall send the necessary data to the Clearing

House.

The Settlement data to be notified to the BSPs for Initial Settlement Run or any of the

Reconciliation Settlement Runs shall include at least the following information:

A) the Participant name and ID;

B) the Market Schedule of each BSE;

C) the Dispatch Instruction of the BSE per Real Time Unit;

D) the metered Energy quantities of the BSE per Imbalance Settlement Period;

E) the activated aFRR and mFRR Balancing Energy of the BSE per Imbalance

Settlement Period;

F) the Balancing Capacity provided by the BSE per Imbalance Settlement Period

per type of Reserve;


G) The Imbalance and Imbalance Adjustment quantities for the BSE per Imbalance

Settlement Period

H) the credit/debit for Balancing Energy and Balancing Capacity for the BSE per

Imbalance Settlement Period;

I) the credit/debit for Imbalances for the BSE per Imbalance Settlement Period;

J) the debit for the Non-Compliance Charges imposed to the Participant per penalty

type and Imbalance Settlement Period;

K) the Balancing Fee;

The Settlement data to be notified to the BSPs for Initial Settlement Run or any of the

Reconciliation Settlement Runs shall include at least the following information:

A) the BRP name and ID;

B) the Market Schedule of each Balance Responsible Entity represented by the

Participant per Imbalance Settlement Period;

C) the aggregated metered energy quantities of all the Balance Responsible Entities

represented by the BRP per Imbalance Settlement Period;

D) the Imbalance quantity of all the Balance Responsible Entities represented by

the BRP per Imbalance Settlement Period; and

E) the credit/debit to the BRP per Imbalance Settlement Period.


10 Annex A: Nomenclature

The following Table 10-1 provides a list of all sets (superscripts and subscripts) and

symbols used in the formulae and other algebraic expressions contained in this report. Its

purpose is to identify the variables and the parameters used in each process of the

Balancing and Ancillary Services Market. Thus:

a) the first (1st) part of this Table describes the sets and symbols used in the

Integrated Scheduling Process presented in Chapter 7 of this report,

b) the second (2nd) part of this Table describes the sets and symbols used in the Real-

Time Balancing Energy Market presented in Chapter 8 of this report; only the

additional / differentiated sets / symbols as compared to the Integrated Scheduling

Process list are presented in the Real-Time Balancing Energy Market list, while

c) the third (3rd) part of this Table describes the sets and symbols regarding the

settlement procedures described in Chapter 9 of this report.

All quantities and prices shall be used for the computations with 15 decimals (double

precision numbers). All quantities shall be reported / displayed using numbers rounded

up to three (3) decimals, whereas all prices shall be reported / displayed using numbers

rounded up to two (2) decimals.

1. Integrated Scheduling Process (Chapter 7)

Sets

Set Name and Context

t T Set of half-hourly Dispatch Periods of the scheduling horizon.

k K Set of steps of the step-wise Balancing Energy Offer.

z Z

Set of Bidding Zones.

When z is used as a superscript of another set (e.g. zI , z

3R , z2L ,

zC ), it specifies that the considered elements of the latter set

belong into the given Bidding Zone z.


i I

Set of the Balancing Services Entities (BSEs) participating in the

Balancing and Ancillary Services Market; I G R2 L1 where:

G I is the set of Generating Units,

H G I is the set of hydro Generating Units,

2R I is the set of Dispatchable RES Portfolios,

1L I is the set of Dispatchable Load Portfolios

j J

Set of the Balance Responsible Entities (BREs) in the context of

the Balancing and Ancillary Services Market;

IJ R3 R4 L2 C where:

I J is the set of BSPs,

3R J is the set of the RES FiT Portfolio (comprises one

element),

4R J is the set of Non-Dispatchable RES Portfolios,

2L J is the set of Non-Dispatchable Load Portfolios,

C J is the set of Generating Units / RES Units in

Commissioning or Testing Operation.

inter INTER Set of interconnections.

gc GC Set of generic constraints.

1. Integrated Scheduling Process (Chapter 7)

Symbols

Symbol Name and Context Source

BEupitkQuant

Non-negative variable representing the quantity

of upward Balancing Energy cleared for BSE i,

Dispatch Period t and step k of the respective

Balancing Energy Offer, in MW.

ISP model

BEdnitkQuant


of downward Balancing Energy cleared for BSE

i, Dispatch Period t and step k of the respective


ISP model

FCRupitQuant

Non-negative variable representing the

contribution of BSE i in upward FCR at Dispatch

Period t, in MW.

ISP model


FCRdnit Quant


contribution of BSE i in downward FCR at

Dispatch Period t, in MW.

ISP model

aFRRupitQuant


contribution of BSE i in upward aFRR at


ISP model

aFRRdnitQuant


contribution of BSE i in downward aFRR at


ISP model

mFRRupitQuant


contribution of BSE i in upward mFRR at


ISP model

mFRRdnitQuant


contribution of BSE i in downward mFRR at


ISP model

RRupitQuant


contribution of BSE i in upward spinning RR at


ISP model

RRnsitQuant


contribution of BSE i in non-spinning RR at


ISP model

RRdnitQuant


contribution of BSE i in downward RR at


ISP model

BEupitkPrice

Parameter representing the price of the upward

Balancing Energy Offer of BSE i, for Dispatch

Period t and step k, in €/MWh.

Upward

Balancing

Energy Offer

BEdnitkPrice

Parameter representing the price of the

downward Balancing Energy Offer of BSE i, for

Dispatch Period t and step k, in €/MWh.

Downward

Balancing

Energy Offer

FCRupitPrice

Parameter representing the price of the offer for

upward FCR of BSE i, for Dispatch Period t, in

€/MW.

FCR Offer

FCRdnitPrice


downward FCR of BSE i, for Dispatch Period t,

in €/MW.

FCR Offer

aFRRupitPrice Parameter representing the price of the offer for

upward aFRR of BSE i, for Dispatch Period t, in aFRR Offer


€/MW.

aFRRdnitPrice


downward aFRR of BSE i, for Dispatch Period t,

in €/MW.

aFRR Offer

mFRRupitPrice


upward mFRR of BSE i, for Dispatch Period t, in

€/MW.

mFRR Offer

mFRRdnitPrice


downward mFRR of BSE i, for Dispatch Period t,

in €/MW.

mFRR Offer

RRupitPrice


upward RR of BSE i, for Dispatch Period t, in

€/MW.

RR Offer

RRdnitPrice


downward RR of BSE i, for Dispatch Period t, in

€/MW.

RR Offer

D Parameter representing the Dispatch Period

duration, expressed in hours. For the ISP, this

parameter is set to 1.

ISP model

hotiSUC Parameter representing the start-up cost from

hot standby for BSE i, in €.

Techno-

Economic

Declaration

(Table C)

warmiSUC Parameter representing the start-up cost from

warm standby for BSE i, in €.

Techno-

Economic

Declaration

(Table C)

coldiSUC Parameter representing the start-up cost from

cold standby for BSE i, in €.

Techno-

Economic

Declaration

(Table C)

ity Binary variable indicating if BSE i is started-up

at Dispatch Period t (equal to 1 if started-up,

being 0 otherwise).

ISP model

hotity

Binary variable representing a start-up decision

from hot standby, for BSE i, at Dispatch Period t

(equal to 1 if BSE i is started-up during t after

hot standby, being 0 otherwise).

ISP model


warmity


from warm standby, for BSE i, at Dispatch

Period t (equal to 1 if BSE i is started-up during t

after warm standby, being 0 otherwise).

ISP model

coldity


from cold standby, for BSE i, at Dispatch Period

t (equal to 1 if BSE i is started-up during t after

cold standby, being 0 otherwise).

ISP model

HotToWarmiT

Parameter representing the time off-load before

BSE i is going into longer stand-by conditions

(i.e., from hot to warm conditions), in hours.

Registered

Operating

Characteristics

HotToColdiT

Parameter representing the time off-load before

BSE i is going into longer stand-by conditions

(i.e., from hot to cold conditions), in hours.

Registered

Operating

Characteristics

synitu Binary variable indicating if BSE i is in the

synchronization phase at Dispatch Period t. ISP model

,syn hotitu

Binary variable indicating if BSE i is in the

synchronization phase at Dispatch Period t, after

a hot start-up.

ISP model

,syn warmitu



a warm start-up.

ISP model

,syn colditu



a cold start-up.

ISP model

,syn hotiT Parameter representing the synchronization

time of BSE i under hot start-up, in hours.

Registered

Operating

Characteristics

,syn warmiT Parameter representing the synchronization

time of BSE i under warm start-up, in hours.

Registered

Operating

Characteristics

,syn coldiT Parameter representing the synchronization

time of BSE i under cold start-up, in hours.

Registered

Operating

Characteristics

soakitu Binary variable indicating if BSE i is in the soak

phase at Dispatch Period t. ISP model

,soak hotitu Binary variable indicating if BSE i is in the soak

phase at Dispatch Period t, after a hot start-up. ISP model


,soak warmitu

Binary variable indicating if BSE i is in the soak

phase at Dispatch Period t, after a warm start-

up.

ISP model

,soak colditu Binary variable indicating if BSE i is in the soak

phase at Dispatch Period t, after a cold start-up. ISP model

,soak hotiT Parameter representing the soak time of BSE i

after a hot start-up, in hours.

Registered

Operating

Characteristics

,soak warmiT Parameter representing the soak time of BSE i

after a warm start-up, in hours.

Registered

Operating

Characteristics

,soak coldiT Parameter representing the soak time of BSE i

after a cold start-up, in hours.

Registered

Operating

Characteristics

soakitP

Non-negative variable representing the power

output of (generating) BSE i during the soak

phase in Dispatch Period t, in MW.

ISP model

,soak hotisP

Parameter representing the power output of

(generating) BSE i corresponding to the sth step

of the soak phase after a hot start-up, in MW.

Registered

Operating

Characteristics

,soak warmisP



of the soak phase after a warm start-up, in MW.

Registered

Operating

Characteristics

,soak coldisP



of the soak phase after a cold start-up, in MW.

Registered

Operating

Characteristics

dispitu Binary variable indicating if BSE i is in the

dispatchable phase at Dispatch Period t. ISP model

desitu Binary variable indicating if BSE i is in the

desynchronization phase at Dispatch Period t. ISP model

desiT Parameter representing the desynchronization

time of (generating) BSE i, in hours.

Registered

Operating

Characteristics

desitP

Non-negative variable representing the power

output of (generating) BSE i during the

desynchronization phase in Dispatch Period t, in

MW.

ISP model

itz Binary variable representing a shut-down

decision for BSE i, at Dispatch Period t (equal to ISP model


1 if BSE i is shut-down during t, being 0

otherwise).

itu Binary variable indicating if BSE i is committed

(on-line) during Dispatch Period t. ISP model

iMUT Parameter representing the minimum up time of

BSE i, in hours.

Registered

Operating

Characteristics

iMDT Parameter representing the minimum down time

of BSE i, in hours.

Registered

Operating

Characteristics

minitP

Non-negative parameter representing the

technical minimum power output of BSE i in

Dispatch Period t, in MW (e.g. 150 MW of

minimum generation for a Generating Unit, or 10

MW of minimum loading for a Dispatchable

Load).

The technical minimum is included in the

Registered Operating Characteristics of the

BSEs, but when the maximum Availability of the

BSE (submitted through the Non-Availability

Declarations) equals zero, then the technical

minimum is overwritten to zero, and it is

transferred as zero in the ISP model.

Registered

Operating

Characteristics

maxitP


technical maximum power output of BSE i in

Dispatch Period t, in MW (e.g. 477 MW of

maximum generation for a Generating Unit, or

100 MW of full loading for a Dispatchable Load).

The combination of the technical maximum

included in the Registered Operating

Characteristics and in Non-Availability

Declarations (actually the minimum quantity per

Dispatch Period) is transferred as input in the

ISP model.

Registered

Operating

Characteristics

& Non-

Availability

Declarations

min, AGCiP


technical minimum power output in AGC mode

for BSE i, in MW (e.g. 182 MW of minimum

generation for a Generating Unit, or 20 MW of

minimum loading for a Dispatchable Load).

The technical minimum under AGC is included

Techno-

Economic

Declaration

(Table A2)


in the Techno-Economic Declarations of the




minimum under AGC is overwritten to zero, and

it is transferred as zero in the ISP model.

max,AGCiP

Parameter representing the technical maximum

power output in AGC mode for BSE i, in MW

(e.g. 417 MW of maximum generation for a

Generating Unit, or 80 MW of maximum loading

for a Dispatchable Load).

The technical maximum under AGC is included

in the Techno-Economic Declarations of the




maximum under AGC is overwritten to zero, and

it is transferred as zero in the ISP model.

Techno-

Economic

Declaration

(Table A2)

AGCitu Binary variable indicating a BSE i operating in

AGC mode. ISP model

itP

Real variable representing the power output of

BSE i during Dispatch Period t, in MW; it takes

non-negative values for Generating Units,

Dispatchable RES Portfolios, and non-positive

values for Dispatchable Load Portfolios.

ISP model

itMS

Parameter representing the Market Schedule of

BSE i during Dispatch Period t; it bears a non-

negative value for Generating Units,

Dispatchable RES Portfolios, and a non-positive

value for Dispatchable Load Portfolios.

Market

Operator

itBEup Non-negative variable representing the upward

Balancing Energy award for BSE i, at Dispatch

Period t, in MW.

ISP model

itBEdn Non-negative variable representing the

downward Balancing Energy award for BSE i, at


ISP model

BEupitkMaxQuant

Non-negative parameter representing the size of

step k of the Upward Balancing Energy Offer of

BSE i for Dispatch Period t, in MW.

Upward

Balancing

Energy Offer


BEdnitkMaxQuant


step k of the Downward Balancing Energy Offer

of BSE i for Dispatch Period t, in MW.

Downward

Balancing

Energy Offer

itMinBEup


minimum quantity of the upward Balancing

Energy award of BSE i for Dispatch Period t, in

MW.

Upward

Balancing

Energy Offer

itMinBEdn


minimum quantity of the downward Balancing

Energy award of BSE i for Dispatch Period t, in

MW.

Downward

Balancing

Energy Offer

BEupitu

Binary variable indicating if upward Balancing

Energy is provided by BSE i during Dispatch

Period t.

ISP model

BEdnitu

Binary variable indicating if downward Balancing

Energy is provided by BSE i during Dispatch

Period t.

ISP model

itMand Mandatory injection of hydro Generating Unit i

for Dispatch Period t, in MW.

Hydro

Mandatory

Injections

Declaration

iMaxEnergy Parameter representing the maximum daily

energy of generating BSE i, in MWh.

Techno-

Economic

Declaration

(Table A3)

iIniEnergy

Parameter representing the energy already

(scheduled to be) produced by a Generating

Unit i for all Dispatch Periods from the beginning

of the Dispatch Day until the start of the

scheduling horizon of a given ISP run, in MWh.

Metering

System / ISP

model

iRU

Non-negative parameter representing the ramp-

up rate of BSE i, in MW/min; it refers to the

maximum increase (over 1 minute) (a) in the

generating level of a generating BSE, or (b) in

the loading level of a loading BSE.

Registered

Operating

Characteristics

iRD

Non-negative parameter representing the ramp-

down rate of BSE i, in MW/min; it refers to the

maximum decrease (over 1 minute) (a) in the

generating level of a generating BSE, or (b) in

the loading level of a loading BSE.

Registered

Operating

Characteristics


AGCiRR Non-negative parameter representing the ramp

rate of BSE i in AGC mode, in MW/min.

Techno-

Economic

Declaration

(Table A2)

W Large constant. ISP model

FCRupiMaxQuant


maximum contribution of BSE i in upward FCR,

in MW.

Techno-

Economic

Declaration

(Table A2)

FCRdniMaxQuant


maximum contribution of BSE i in downward

FCR, in MW.

Techno-

Economic

Declaration

(Table A2)

aFRRupiMaxQuant


maximum contribution of BSE i in upward aFRR,

in MW.

Computed based

on the Techno-

Economic

Declaration

aFRRdniMaxQuant



aFRR, in MW.

Computed based

on the Techno-

Economic

Declaration

Percent Percentage of NCAP for BSEs’ contribution to

aFRR.

Energy

Balancing

System

Database

iNCAP Parameter representing the BSE i net capacity,

in MW.

Registered

Operating

Characteristics

FastaFRRupitQuant


contribution in fast upward aFRR (1-min

ramping capability) for BSE i in Dispatch Period

t, in MW.

ISP model

FastaFRRdnitQuant


contribution in fast downward aFRR (1-min

ramping capability) for BSE i in Dispatch Period

t, in MW.

ISP model

mFRRupiRegMaxQuant Non-negative parameter representing the

maximum technical capability of BSE i to

Registered

Operating


provide upward mFRR, in MW. Characteristics

mFRRdniRegMaxQuant



provide downward mFRR, in MW.

Registered

Operating

Characteristics

RRupiRegMaxQuant



provide upward RR, in MW.

Registered

Operating

Characteristics

RRdniRegMaxQuant



provide downward RR, in MW.

Registered

Operating

Characteristics

RRnsiRegMaxQuant



provide non-spinning RR, in MW.

Registered

Operating

Characteristics

mFRRupiMaxQuant


maximum contribution of BSE i in upward

mFRR, in MW. It is computed as described in

Paragraph 7.7.

Computed based

on the

Registered

Operating

Characteristics

mFRRdniMaxQuant



mFRR, in MW.

Computed based

on the

Registered

Operating

Characteristics

RRupiMaxQuant


maximum contribution of BSE i in upward RR, in

MW.

Computed based

on the

Registered

Operating

Characteristics

RRdniMaxQuant



RR, in MW.

Computed based

on the

Registered

Operating

Characteristics

RRnsiMaxQuant


maximum contribution of BSE i in non-spinning

RR, in MW.

Computed based

on the

Registered

Operating

Characteristics

nsitu Binary variable indicating if BSE i is contributing

to non-spinning RR during Dispatch Period t. ISP model


ztNonDispLoadFR

Non-negative parameter representing the Non-

Dispatchable Load Forecast of the TSO for zone

z and Dispatch Period t, in MW. Load Forecast

jtNonDispLoadMS Non-negative parameter representing the

Market Schedule of Non-Dispatchable Load j (

2j L ) for Dispatch Period t, in MW.

Market

Operator

ztResFiTPortFR Non-negative parameter representing the RES

FiT Portfolio Forecast of the TSO for zone z and


RES Injections

Forecast

ztResFiTPortMS Non-negative parameter representing the

Market Schedule of the RES FiT Portfolio for

zone z and Dispatch Period t, in MW.

Market

Operator

ztNonDispResUnitFR Non-negative parameter representing the Non-

Dispatchable RES Portfolios Forecast of the

TSO for zone z and Dispatch Period t, in MW.

RES Injections

Forecast

jtNonDispResUnitMS Non-negative parameter representing the

Market Schedule of Non-Dispatchable RES

Portfolio j ( 4j R ) for Dispatch Period t, in MW.

Market

Operator

jtCommisDS


schedule of the Generating Unit / RES Unit in

Commissioning or Testing Operation j ( j C ),

declared to the TSO prior to the ISP execution,

for Dispatch Period t, in MW.

Commissioning

Schedules

Declaration

jtCommisMS


Market Schedule of the Generating Unit / RES

Unit in Commissioning or Testing Operation j (

j C ), submitted to the Market Operator at the

Day-Ahead Market and Intraday Market stage

(and inserted in the respective clearings as

“price-taking orders”), for Dispatch Period t, in

MW.

Market

Operator

,inter tImpDev

Non-negative parameter representing the import

deviation at the interconnection inter at Dispatch

Period t, due to one or more causes described

in Paragraph 7.10.20, in MW.

LT PTR

Nominations &

Day-Ahead

Market results,

ADMIE

Scheduling

System


,inter tExpDev

Non-negative parameter representing the export

deviation at the interconnection inter at Dispatch

Period t, due to one or more causes described

in Paragraph 7.10.20, in MW.

LT PTR

Nominations &

Day-Ahead

Market results,

ADMIE

Scheduling

System

,zz tFlow Non-negative variable representing the flow

from Bidding Zone z to Bidding Zone z’, at


ISP model

,Maxzz tAvailableFlow


maximum residual flow from Bidding Zone z to

Bidding Zone z’ that is available at the Balancing

Market stage (considering the already

established flows at the wholesale market) at


Corridor limits

computation

process

ztNetInjection

Real variable representing the net position

(activated upward Balancing Energy minus

activated downward Balancing Energy) of

Bidding Zone z at Dispatch Period t, in MW.

ISP model

,,

z refzz t

PTDF

Parameter representing the Power Transfer

Distribution Factor at the corridor from Bidding

Zone z to Bidding Zone z’ at Dispatch Period t,

when an injection at zone z’’and a withdrawal at

the reference zone takes place.

Zonal data

computation

process

FCRupztReq

Parameter representing the upward FCR

requirement for Bidding Zone z during Dispatch

Period t, in MW.

Reserve

Requirements

Forecast

FCRuptReq

Parameter representing the upward FCR

requirement for the entire system during


Reserve

Requirements

Forecast

FCRdnztReq

Parameter representing the downward FCR


Period t, in MW.

Reserve

Requirements

Forecast

FCRdntReq

Parameter representing the downward FCR



Reserve

Requirements

Forecast

aFRRupztReq

Parameter representing the upward aFRR


Period t, in MW.

Reserve

Requirements

Forecast


aFRRuptReq

Parameter representing the upward aFRR



Reserve

Requirements

Forecast

aFRRdnztReq

Parameter representing the downward aFRR


Period t, in MW.

Reserve

Requirements

Forecast

aFRRdntReq

Parameter representing the downward aFRR



Reserve

Requirements

Forecast

FastaFRRuptReq

Parameter representing the fast upward aFRR

requirement (1-min ramping capability) for the

entire system during Dispatch Period t, in MW.

Reserve

Requirements

Forecast

FastaFRRdntReq

Parameter representing the fast downward

aFRR requirement (1-min ramping capability) for

the entire system during Dispatch Period t, in

MW.

Reserve

Requirements

Forecast

mFRRupztReq

Parameter representing the upward mFRR


Period t, in MW.

Reserve

Requirements

Forecast

mFRRuptReq

Parameter representing the upward mFRR



Reserve

Requirements

Forecast

mFRRdnztReq

Parameter representing the downward mFRR


Period t, in MW.

Reserve

Requirements

Forecast

mFRRdntReq

Parameter representing the downward mFRR



Reserve

Requirements

Forecast

RRupztReq

Parameter representing the upward RR


Period t, in MW.

Reserve

Requirements

Forecast

RRuptReq

Parameter representing the upward RR



Reserve

Requirements

Forecast

RRdnztReq

Parameter representing the downward RR


Period t, in MW.

Reserve

Requirements

Forecast

RRdntReq Parameter representing the downward RR


Reserve

Requirements


Dispatch Period t, in MW. Forecast

,GenCont gcLimit Parameter representing the generic constraint

gc right-hand side limit for Dispatch Period t.

Generic

Constraints

Declaration

,P

it gcFactor Parameter representing the factor of the generic

constraint gc, associated with the power output

of BSE i for Dispatch Period t; , ,Pit gcFactor 0 1

Generic

Constraints

Declaration

,RRup

it gcFactor

Parameter representing the factor of the generic

constraint gc, associated with the upward RR

contribution of BSE i for Dispatch Period t;

, ,RRup

it gcFactor 0 1

Generic

Constraints

Declaration

BEupity


Energy is activated by BSE i during Dispatch

Period t.

ISP model

BEdnity



Period t.

ISP model

BEupitz


Energy is de-activated by BSE i during Dispatch

Period t.

ISP model

BEdnitz


Energy is de-activated by BSE i during Dispatch

Period t.

ISP model

BEupiMinDP

Parameter representing the minimum delivery

period (duration) of Balancing Energy provision

in the upward direction, submitted by loading

BSE i, in hours.

Declared

Characteristics

BEdniMinDP

Parameter representing the minimum delivery


in the downward direction, submitted by loading

BSE i, in hours.

Declared

Characteristics

BEupiMaxDP

Parameter representing the maximum delivery


in the upward direction, submitted by loading

BSE i, in hours.

Declared

Characteristics

BEdniMaxDP Parameter representing the maximum delivery

period (duration) of Balancing Energy provision Declared


in the downward direction, submitted by loading

BSE i, in hours.

Characteristics

iMinBP

Parameter representing the minimum baseload

period (i.e., minimum period between two

successive activations of Balancing Energy),

submitted by loading BSE i, in hours.

Declared

Characteristics

BEupiMaxFA

Parameter representing the maximum frequency

of activations of Balancing Energy in the upward

direction, from loading BSE i in the course of a

Dispatch Day.

Declared

Characteristics

BEdniMaxFA

Parameter representing the maximum frequency

of activations of Balancing Energy in the

downward direction, from loading BSE i in the

course of a Dispatch Day.

Declared

Characteristics

DeficitZonImbPrice Deficit price for the violation of the zonal

imbalance covering constraint. Default value:

25.000 €/MW.

Energy

Balancing

System

Database

SurplusZonImbPrice Surplus price for the violation of the zonal


25.000 €/MW.

Energy

Balancing

System

Database

TotDeficitFCRPrice Deficit price for the violation of the zonal /

system upward and downward FCR requirement

constraints. Default value: 20.000 €/MW.

Energy

Balancing

System

Database

TotDeficitaFRRPrice

Deficit price for the violation of the zonal /

system upward and downward aFRR

requirement constraints. Default value: 15.000

€/MW.

Energy

Balancing

System

Database

TotDeficitmFRRPrice

Deficit price for the violation of the zonal /

system upward and downward mFRR

requirement constraints. Default value: 12.000

€/MW.

Energy

Balancing

System

Database


TotDeficitRRPrice Deficit price for the violation of the zonal /

system upward and downward RR requirement


Energy

Balancing

System

Database

DeficitCapPrice Deficit price for the violation of the BSE

minimum capacity constraints. Default value:

45.000 €/MW.

Energy

Balancing

System

Database

SurplusCapPrice Surplus price for the violation of the BSE

maximum capacity constraints. Default value:

45.000 €/MW.

Energy

Balancing

System

Database

SurplusMaxEnergyitPrice

Surplus price for the violation of the BSE

maximum daily energy constraint. Default value:

8.000 €/MWh.

Energy

Balancing

System

Database

SurplusRampUpPrice Surplus price for the violation of the BSE upward

ramping constraint. Default value: 40.000 €/MW.

Energy

Balancing

System

Database

SurplusRampDnPrice Surplus price for the violation of the BSE

downward ramping constraint. Default value:

40.000 €/MW.

Energy

Balancing

System

Database

SurplusRampResPrice Surplus price for the violation of the BSE upward

and downward Reserve Capacity ramping


Energy

Balancing

System

Database

SurplusFCRPrice Surplus price for the violation of the BSE upward

and downward FCR contribution constraints.

Default value: 20.000 €/MW.

Energy

Balancing

System

Database


SurplusaFRRPrice Surplus price for the violation of the BSE upward

and downward aFRR contribution constraints.


Energy

Balancing

System

Database

SurplusmFRRPrice Surplus price for the violation of the BSE upward

and downward mFRR contribution constraints.


Energy

Balancing

System

Database

SurplusRRPrice Surplus price for the violation of the BSE upward

and downward RR contribution constraints.


Energy

Balancing

System

Database

DeficitnsPrice Deficit price for the violation of the BSE

minimum non-spinning RR contribution

constraint. Default value: 35.000 €/MW.

Energy

Balancing

System

Database

SurplusnsPrice Surplus price for the violation of the BSE

maximum non-spinning RR contribution

constraint. Default value: 35.000 €/MW.

Energy

Balancing

System

Database

DeficitGenConPrice

Deficit price for the violation of the generic


Alternatively, it can be defined each time by the

TSO, through the Generic Constraints

Declaration.

Energy

Balancing

System

Database

SurplusGenConPrice

Surplus price for the violation of the generic


Alternatively, it can be defined each time by the

TSO, through the Generic Constraints

Declaration.

Energy

Balancing

System

Database

ZonImbztDeficit Deficit variable for the violation of the zonal

imbalance covering constraint, in MW. ISP model

ZonImbztSurplus Surplus variable for the violation of the zonal ISP model


imbalance covering constraint, in MW.

ZonFCRupztDeficitZonFCRdnztDeficit

Deficit variables for the violation of the zonal

upward and downward FCR requirement

constraints, in MW.

ISP model

ZonaFRRupztDeficitZonaFRRdnztDeficit


upward and downward aFRR requirement

constraints, in MW.

ISP model

ZonmFRRupztDeficit

ZonmFRRdnztDeficit


upward and downward mFRR requirement

constraints, in MW.

ISP model

ZonRRupztDeficitZonRRdnztDeficit


upward and downward RR requirement

constraints, in MW. ISP model

CapitDeficit Deficit variable for the violation of the BSE

minimum capacity constraint, in MW. ISP model

CapitSurplus Surplus variable for the violation of the BSE

maximum capacity constraint, in MW. ISP model

MaxEnergyitSurplus Surplus variable for the violation of the BSE

maximum daily energy constraint, in MWh. ISP model

RampUpitSurplus Surplus variable for the violation of the BSE

upward ramping constraint, in MW. ISP model

RampDnitSurplus Surplus variable for the violation of the BSE

downward ramping constraint, in MW. ISP model

RampUpResitSurplus

RampDnResitSurplus

Surplus variables for the violation of the BSE

upward and downward Reserve Capacity

ramping constraints, in MW.

ISP model

FCRupitSurplusFCRdnitSurplus


upward and downward FCR contribution

constraints, in MW.

ISP model

aFRRupitSurplusaFRRdnitSurplus


upward and downward aFRR contribution

constraints, in MW.

ISP model

mFRRupitSurplus


upward and downward mFRR contribution ISP model


mFRRdnitSurplus constraints, in MW.

RRupitSurplusRRdnitSurplus


upward and downward RR contribution

constraints, in MW.

ISP model

nsitDeficit

Deficit variable for the violation of the BSE

minimum non-spinning RR contribution

constraint, in MW.

ISP model

nsitSurplus

Surplus variable for the violation of the BSE

maximum non-spinning RR contribution

constraint, in MW.

ISP model

,GenCont gcDeficit Deficit variable for the violation of the generic

constraint gc, in MW. ISP model

,GenCont gcSurplus Surplus variable for the violation of the generic

constraint gc, in MW. ISP model

2. Real-Time Balancing Energy Market (Chapter 8)

Sets


t T Set of 15-min Dispatch Periods of the scheduling horizon.

2. Real-Time Balancing Energy Market (Chapter 8)

Symbols


itP

Real variable representing the power output of

BSE i during Dispatch Period t, in MW; it takes

non-negative values for Generating Units,

Dispatchable RES Portfolios, and non-positive

values for Dispatchable Load Portfolios.

RTBEMRTBEM

model

itMS

Parameter representing the latest Market

Schedule of BSE i during Dispatch Period t; it

bears a non-negative value for Generating

Units, Dispatchable RES Portfolios, and a non-

Market

Operator


positive value for Dispatchable Load Portfolios.

itBEup Non-negative variable representing the upward

Balancing Energy award for BSE i, at Dispatch

Period t, in MW.

RTBEMRTBEM

model

itBEdn Non-negative variable representing the

downward Balancing Energy award for BSE i, at


RTBEMRTBEM

model

FCRupitQuant


upward FCR award of BSE i in the ISP, at


ISP Results

FCRdnitQuant


downward FCR award of BSE i in the ISP, at


ISP Results

aFRRupitQuant


upward aFRR award of BSE i in the ISP, at


ISP Results

aFRRdnitQuant


downward aFRR award of BSE i in the ISP, at


ISP Results

AGCitunder Status parameter indicating a BSE i operating in

AGC mode at Dispatch Period t.

Energy

Balancing

System

iInitialMW

Parameter representing the initial power output

of BSE i for a given RTBEMRTBEM execution,

in MW; it bears a non-negative value for

Generating Units, Dispatchable RES Portfolios,

and a non-positive value for Dispatchable Load

Portfolios.

SCADA

itP Parameter representing the ISP schedule from

the latest ISP execution for the Generating Unit i

and Dispatch Period t.

ISP Results

BEupitMand

Parameter representing the quantity of upward

Balancing Energy activated manually

(mandatorily) by the TSO, for BSE i and


Mandatory

Activation

Process

BEdnitMand

Parameter representing the quantity of

downward Balancing Energy activated manually

(mandatorily) by the TSO, for BSE i and

Mandatory

Activation


Dispatch Period t, in MW. Process

D Parameter representing the Dispatch Period

duration, expressed in hours. For the

RTBEMRTBEM, this parameter is set to 1/4.

RTBEMRTBEM

model

BEupitkQuant


of upward Balancing Energy cleared for BSE i,

Dispatch Period t and step k of the respective


RTBEM model

BEupitkPrice

Parameter representing the price of the upward

Balancing Energy Offer of BSE i, for Dispatch

Period t and step k, in €/MWh.

Upward

Balancing

Energy Offer

BEdnitkQuant


of downward Balancing Energy cleared for BSE

i, Dispatch Period t and step k of the respective


RTBEM model

BEdnitkPrice

Parameter representing the price of the

downward Balancing Energy Offer of BSP i, for

Dispatch Period t and step k, in €/MWh.

Downward

Balancing

Energy Offer

BEupitkMaxQuant


step k of the Upward Balancing Energy Offer of

BSP i for Dispatch Period t, in MW.

Upward

Balancing

Energy Offer

BEdnitkMaxQuant


step k of the Downward Balancing Energy Offer

of BSP i for Dispatch Period t, in MW.

Downward

Balancing

Energy Offer

BEupitu



Period t.

RTBEM model

BEdnitu



Period t.

RTBEM model

DeficitCapPrice Deficit price for the violation of the BSE

minimum capacity constraints. Default value:

45.000 €/MW.

Energy

Balancing

System

Database


SurplusCapPrice Surplus price for the violation of the BSE

maximum capacity constraints. Default value:

45.000 €/MW.

Energy

Balancing

System

Database

SurplusRampUpPrice Surplus price for the violation of the BSE upward

ramping constraint. Default value: 40.000 €/MW.

Energy

Balancing

System

Database

SurplusRampDnPrice Surplus price for the violation of the BSE

downward ramping constraint. Default value:

40.000 €/MW.

Energy

Balancing

System

Database

SurplusMaxEnergyPrice Surplus price for the violation of the BSE

maximum daily energy constraint. Default value:

8.000 €/MW.

Energy

Balancing

System

Database

DeficitZonImbPrice Deficit price for the violation of the zonal


25.000 €/MW.

Energy

Balancing

System

Database

SurplusZonImbPrice Surplus price for the violation of the zonal


25.000 €/MW.

Energy

Balancing

System

Database

CapitDeficit Deficit variable for the violation of the BSE

minimum capacity constraints, in MW. RTBEM model

CapitSurplus Surplus variable for the violation of the BSE

maximum capacity constraint, in MW. RTBEM model

RampUpitSurplus Surplus variable for the violation of the BSE

upward ramping constraint, in MW. RTBEM model

RampDnitSurplus Surplus variable for the violation of the BSE

downward ramping constraint, in MW. RTBEM model

MaxEnergyitSurplus Surplus variable for the violation of the BSE

maximum daily energy constraint, in MW. RTBEM model


ZonImbztDeficit Deficit variable for the violation of the zonal

imbalance covering constraint, in MW. RTBEM model

ZonImbztSurplus Surplus variable for the violation of the zonal

imbalance covering constraint, in MW. RTBEM model

3. Settlements (Chapter 9)

Sets


t T Set of Settlement Periods (length: 15-min for the Balancing Energy

Settlement / 15-min for the Imbalance Settlement).

p P Set of BSPs or Balance Responsible Parties (BRPs).

3. Balancing Energy and Imbalance Settlement (Chapter 9)

Symbols


jtMS

Parameter representing the Market Schedule of

BRE j during Settlement Period t, in MW.

Market

Operator

itBEup

Parameter representing the procured upward

Balancing Energy of BSE i for Settlement

Period t, in MW.

RTBEM

itBEdn

Parameter representing the procured

downward Balancing Energy of BSE i for

Settlement Period t, in MW.

RTBEM

BEupztMP

Parameter representing the Marginal Upward

Balancing Energy Price of Bidding Zone z for

Settlement Period t, derived by the shadow

price (Lagrange multiplier) of the zonal

imbalance covering constraint of the RTBEM

clearing, in case the Bidding Zone is short in

the given Settlement Period, in €/MWh.

RTBEM

BEdnztMP

Parameter representing the Marginal

Downward Balancing Energy Price of Bidding

Zone z for Settlement Period t, derived by the

shadow price (Lagrange multiplier) of the zonal

imbalance covering constraint of the RTBEM

RTBEM


clearing, in case the Bidding Zone is long in the

given Settlement Period, in €/MWh.

BEupztLP

Parameter representing the (maximum) price of

the last activated Upward Balancing Energy

Offer of Bidding Zone z for Settlement Period t,

in case the Bidding Zone is long in the given

Settlement Period, in €/MWh.

RTBEM

BEdnztLP

Parameter representing the (minimum) price of

the last activated Downward Balancing Energy

Offer of Bidding Zone z for Settlement Period t,

in case the Bidding Zone is short in the given


RTBEM

BEupitOP

Parameter representing the offer price of

upward Balancing Energy of BSE i for

Settlement Period t, in €/MWh.

Balancing

Market

Manageme

nt System

BEdnitOP

Parameter representing the offer price of

downward Balancing Energy of BSE i for

Settlement Period t, in €/MWh.

Balancing

Market

Manageme

nt System

D

Parameter representing the Settlement Period

duration, expressed in hours. For the Balancing

Energy settlement this parameter is set equal to

1/4; for the Imbalance Settlement this

parameter is set equal to 1/4.

Balancing

Market

Settlement

System

BEitSettlement

Parameter representing the resulting cash

amount to be settled between BSE i (through

the respective Participant) and the TSO

(payment to the BSE when positive, collection

from the BSE when negative), for the BSE

Balancing Energy procured in the upward or

downward direction during Settlement Period t,

in €.

Balancing

Market

Settlement

System

BEitAddRemun

Parameter representing the additional

remuneration for BSE i and Settlement Period t,

through the bid-recovery mechanism, for its

mandatorily activated Balancing Energy

quantities (Mandatory Activation Process), in €.

Balancing

Market

Settlement

System

AvitP

Parameter representing the Dispatch Instruction

for a given 15-min Imbalance Settlement

Period, for BSE i and Imbalance Settlement

Balancing

Market

Settlement


Period t. System

AdjitP

Parameter representing the Dispatch

Instruction Adjustment of BSE ifor Settlement

Periodt, in MW.

Balancing

Market

Settlement

System

TOL Parameter representing the Imbalance

tolerance limit, in MW.

Balancing

Market

Settlement

System

jtMQ Parameter representing the Certified Metered

Energy of BRE jfor Settlement Periodt, in MW.

Metering

System

ImbjtP

Parameter representing the Imbalance of BRE

jfor Settlement Periodt, in MW.

Balancing

Market

Settlement

System

upztIP

Parameter representing the Upward Imbalance

Price for Bidding Zone z and Settlement Period

t, which is calculated in case the Bidding Zone

is short in the given Settlement Period, in

€/MWh.

Balancing

Market

Settlement

System

dnztIP

Parameter representing the Downward

Imbalance Price for Bidding Zone z and

Settlement Period t, which is calculated in case

the Bidding Zone is long in the given


Balancing

Market

Settlement

System

ztRP

Parameter representing the Reference Price for

Bidding Zone z and Settlement Period t, in

€/MWh; the Reference Price shall be equal to

the Day-Ahead Market clearing price for the

corresponding hour.

Balancing

Market

Settlement

System

(Day-Ahead

Market

results)

PEN

Parameter representing the additive component

in the Imbalance Price, when the absolute

value of the zonal imbalance is above a certain

threshold in a given Settlement Period.

Balancing

Market

Settlement

System

ImbjtSettlement

Parameter representing the resulting cash

amount to be settled between BRE j (through

the respective BRP) and the TSO (payment to

the BRE when positive, collection from the BRE

when negative), for the BRE Imbalance during

Balancing

Market

Settlement

System


Settlement Period t, in €.

3. Ancillary Services Settlement (Chapter 9)

Symbols


RCtypeitProvQuant

Parameter representing the reserve quantity of

type “RCtype” (i.e., FCRup , FCRdn , aFRRup ,

aFRRdn , mFRRup , mFRRdn , RRup , RRdn ) of

BSE i for Settlement Period t, that was available

for provision in real time, in MW.

Balancing

Market

Settlement

System

RCtypeitT

Parameter representing the percentage of time-

period within a Settlement Period t that a BSE i

provided Reserve Capacity of type “RCtype”

(i.e., FCRup , FCRdn , aFRRup , aFRRdn ,

mFRRup , mFRRdn , RRup , RRdn ) in real time,

in %.

Balancing

Market

Settlement

System

iNR

Parameter representing the nominal ramp-rate

of BSE i' of the same BSE category when

operating under Automatic Generation Control,

in MW/min.

Decision of

Regulator

RCtypeztMRCP

Parameter representing the Marginal Reserve

Capacity Price in Bidding Zone z for Settlement

Period t,obtained by the ISP for each type of

Reserve Capacity “RCtype” (i.e., FCRup ,

FCRdn , aFRRup , aFRRdn , mFRRup , mFRRdn ,

RRup , RRdn ), in €/MW.

ISP results

RCtypeitSettlement

Parameter representing the remuneration

amount of BSE i for the provided reserve

quantity of type “RCtype” (i.e., FCRup , FCRdn ,

aFRRup , aFRRdn , mFRRup , mFRRdn , RRup ,

RRdn ) in Settlement Period t, in €.

Balancing

Market

Settlement

System

3. Penalties Settlement (Chapter 9)

Symbols


NonCompBEDailyChargei

Parameter representing the non-compliance Balancing


charge imposed to a BSE i for failing to submit

valid Balancing Energy Offers by the ISP Gate

Closure Time, in €.

Market

Settlement

System

UNCBEO

Parameter representing the unit charge for non-

compliance charges imposed to BSEs, for

failing to submit valid Balancing Energy Offers

by the ISP Gate Closure Time, in €/MWh.

Balancing

Market

Settlement

System

BEOA

Parameter representing the charge increase

factor for non-compliance charges imposed to

BSEs, for failing to submit valid Balancing

Energy Offers by the ISP Gate Closure Time.

Balancing

Market

Settlement

System

iNBEO

Parameter representing the running counter of

the Dispatch Days in the current calendar year

when a BSE i failed to submit valid Balancing

Energy Offers by the ISP Gate Closure Time.

Balancing

Market

Manageme

nt System

upitBEOO

Parameter representing the obligation of BSE i

to provide an upward Balancing Energy Offer

for Dispatch Period t by the ISP Gate Closure

Time, in MWh.

Balancing

Market

Manageme

nt System

dnitBEOO

Parameter representing the obligation of BSE i

to provide a downward Balancing Energy Offer

for Dispatch Period t by the ISP Gate Closure

Time, in MWh.

Balancing

Market

Manageme

nt System

NonCompRCiDailyCharge

Parameter representing the non-compliance

charge imposed to a BSE i for failing to submit

valid Reserve Capacity Offers by the ISP Gate

Closure Time, in €.

Balancing

Market

Settlement

System

UNCRO

Parameter representing the unit charge for non-

compliance charges imposed to BSEs for

failing to submit valid Reserve Capacity Offers

by the ISP Gate Closure Time, in €/MW.

Balancing

Market

Settlement

System

ROA

Parameter representing the charge increase

factor for non-compliance charges imposed to

BSEs for failing to submit valid Reserve

Capacity Offers by the ISP Gate Closure Time.

Balancing

Market

Settlement

System

iNRO

Parameter representing the running counter of

the Dispatch Days in the current calendar year

when a BSE i failed to submit valid Reserve

Capacity Offers by the ISP Gate Closure Time.

Balancing

Market

Manageme

nt System


Table 10-1: Nomenclature


11 Annex Β: Computation of Reserve Requirements

This Annex presents the methodology to be performed by the TSO in order to compute

the reserve requirements per reserve type, which will be procured through the ISP

process.

11.1 Frequency Containment Reserve

According to Article 142 of the draft Regulation establishing a guideline on electricity

transmission system operation:

“The control target of Frequency Containment Process shall be the stabilization of

the system frequency by activation of FCR. The overall characteristic for FCR

activation in a synchronous area shall reflect a monotonic decrease of the FCR

activation as a function of the frequency deviation.”

According to Article 153 of the above-mentioned draft Regulation,

“All TSOs of each synchronous area shall specify dimensioning rules in the

synchronous area operational agreement in accordance with the following criteria:

(a) the reserve capacity for FCR required for the synchronous area shall cover at

least the reference incident and, for the CE24 and Nordic synchronous areas, the

results of the probabilistic dimensioning approach for FCR carried out pursuant to

point (c);

(b) the size of the reference incident shall be determined in accordance with the

following conditions:

(i) for the CE synchronous area, the reference incident shall be 3000 MW in

positive direction and 3000 MW in negative direction;

……

(c) for the CE and Nordic synchronous areas, all TSOs of the synchronous area shall

have the right to define a probabilistic dimensioning approach for FCR taking into

account the pattern of load, generation and inertia, including synthetic inertia as

well as the available means to deploy minimum inertia in real-time in accordance with

the methodology referred to in Article 39, with the aim of reducing the probability of

insufficient FCR to below or equal to once in 20 years; and

(d) the shares of the reserve capacity on FCR required for each TSO as initial FCR

obligation shall be based on the sum of the net generation and consumption of

24Continental Europe


its control area divided by the sum of net generation and consumption of the

synchronous area over a period of one year.”

The above process results in a half-hourly FCR requirement equal to 43MW for the

Greek interconnected control area. This constitutes the minimum FCR requirement

that should be procured on half-hourly basis by the Greek TSO; this means that the

TSO may decide to procure a higher FCR requirement, in case it is deemed

necessary to ensure the system operational security. This requirement is not

modified during a year (it is the same for all scheduling intervals), since it does not

depend on interval duration, lead time and corresponding day time.

11.2 Automatic Frequency Restoration Reserve

According to Article 143 of the draft Regulation establishing a guideline on electricity

transmission system operation:

“The control target of the Frequency Restoration Process shall be to:

(a) regulate the FRCE towards zero within the time to restore frequency;

(b) for the CE and Nordic synchronous areas, to progressively replace the activated

FCR by activation of FRR in accordance with Article 145.”


“The FRR dimensioning rules shall include at least the following:

(a) all TSOs of a LFC block in the CE and Nordic synchronous areas shall determine

the required reserve capacity of FRR of the LFC block based on consecutive

historical records comprising at least the historical LFC block imbalance

values. The sampling of those historical records shall cover at least the time to

restore frequency. The time period considered for those records shall be

representative and include at least one full year period ending not earlier than 6

months before the calculation date;

(b) all TSOs of a LFC block in the CE and Nordic synchronous areas shall determine

the reserve capacity on FRR of the LFC block sufficient to respect the current FRCE

target parameters in Article 128 for the time period referred to in point (a) based at

least on a probabilistic methodology. In using that probabilistic methodology, the

TSOs shall take into account the restrictions defined in the agreements for the sharing

or exchange of reserves due to possible violations of operational security and the

FRR availability requirements. All TSOs of a LFC block shall take into account any

expected significant changes to the distribution of LFC block imbalances or take into

account other relevant influencing factors relative to the time period considered;

(c) all TSOs of a LFC block shall determine the ratio of automatic FRR, manual

FRR, the automatic FRR full activation time and manual FRR full activation time


in order to comply with the requirement of paragraph (b). For that purpose, the

automatic FRR full activation time of a LFC block and the manual FRR full activation

time of the LFC block shall not be more than the time to restore frequency;

(d) the TSOs of a LFC block shall determine the size of the dimensioning incident

which shall be the largest imbalance that may result from an instantaneous

change of active power of a single power generating module, single demand facility,

or single HVDC interconnector or from a tripping of an AC line within the LFC block;

(e) all TSOs of a LFC block shall determine the positive reserve capacity on FRR,

which shall not be less than the positive dimensioning incident of the LFC

block;

(f) all TSOs of a LFC block shall determine the negative reserve capacity on FRR,

which shall not be less than the negative dimensioning incident of the LFC

block;

(g) all TSOs of a LFC block shall determine the reserve capacity on FRR of a LFC

block, any possible geographical limitations for its distribution within the LFC block

and any possible geographical limitations for any exchange of reserves or sharing of

reserves with other LFC blocks to comply with the operational security limits;

(h) all TSOs of a LFC block shall ensure that the positive reserve capacity on FRR

or a combination of reserve capacity on FRR and RR is sufficient to cover the

positive LFC block imbalances for at least 99 % of the time, based on the

historical records referred to in point (a);

(i) all TSOs of a LFC block shall ensure that the negative reserve capacity on FRR

or a combination of reserve capacity on FRR and RR is sufficient to cover the

negative LFC block imbalances for at least 99 % of the time, based on the

historical record referred to in point (a);

(j) all TSOs of a LFC block may reduce the positive reserve capacity on FRR of

the LFC block resulting from the FRR dimensioning process by developing a

FRR sharing agreement with other LFC blocks in accordance with provisions in

Title 8. The following requirements shall apply to that sharing agreement:

(i) for the CE and Nordic synchronous areas, the reduction of the positive reserve

capacity on FRR of a LFC block shall be limited to the difference, if positive, between

the size of the positive dimensioning incident and the reserve capacity on FRR

required to cover the positive LFC block imbalances during 99 % of the time, based

on the historical records referred to in point (a). The reduction of the positive

reserve capacity shall not exceed 30 % of the size of the positive dimensioning

incident;

………………..

(k) all TSOs of a LFC block may reduce the negative reserve capacity on FRR of

the LFC block, resulting from the FRR dimensioning process by developing a


FRR sharing agreement with other LFC blocks in accordance with the provisions

of Title 8. The following requirements shall apply to that sharing agreement:

(i) for the CE and Nordic synchronous areas, the reduction of the negative reserve

capacity on FRR of a LFC block shall be limited to the difference, if positive, between

the size of the negative dimensioning incident and the reserve capacity on FRR

required to cover the negative LFC block imbalances during 99 % of the time, based

on the historical records referred to in point (a);”

Based on the above, we can summarize that FRR has a double aim: the first is to restore

the frequency to its nominal value after a major disturbance and the second is to match

for the minute to minute net load variability. Consequently its quantification depends on

the first two factors (contingency events and net load variability).

A Control Area is responsible to nullify the Area Control Error (ACE) in case a

sudden generation loss takes place in its area. As a result the contingency part of

the FRR is calculated equal to largest generator/interconnector outage.

The variability part of the FRR is affected by the net load variability inside the

RTBEM interval, which is 15 minutes. For the calculation, the TSO shall use the

standard deviation of the historical differences between the net load minute values

from the net load 15-min average values, over a period of one year25. In this

analysis, the positive and negative differences are treated separately.

The net load minute to fifteen minute variability is not constant inside the day for

all 96 fifteen minute time intervals of the day; it is higher in the morning and

afternoon hours due to the morning and afternoon load ramps. The variability part

of the FRR is calculated for each 15-min interval as three standard deviations26.

The total value of upward/downward FRR is finally calculated as the algebraic sum of the

worst contingency event and the variability part of the FRR, as shown in the equations

below, where ,c upR , ,c dnR are the worst upward/downward contingency events,

respectively, var,net,

1 15

, var,net,

1 15

are the mean values of the positive/negative differences,

respectively, and var,net,

1 15

, var,net,

1 15

are the standard deviations of the minute net load value

to fifteen minute net load average positive/negative differences, respectively.

, var,net, var,net,

1 15 1 153

up c upFRR R , var,net,

1 15 0

, var,net

1 15 0 (for positive differences)

, var,net, var,net,

1 15 1 153

dn c dnFRR R , var,net,

1 15 0

, var,net

1 15 0 (for negative differences)

25This is the “probabilistic methodology” defined in Article 157(b) of the draft Regulation establishing a guideline on electricity transmission system operation.

26Actually, in order to cover 99% of the positive/negative LFC block imbalances, according to Article 157 of the draft Regulation, a FRR requirement equal to only 2.58 times the standard deviation is needed. However, in order to enhance system operational security, the TSO may decide on a higher FRR requirement.


11.3 Manual Frequency Restoration Reserve and Replacement Reserve

Tertiary control is a broader definition incorporating manual Frequency

Restoration Reserve and Replacement Reserve.

Separate provisions for the manual Frequency Restoration Reserve are not included in

the draft Regulation establishing a guideline on electricity transmission system operation.

For the Greek power system, the calculation above in Section 11.2 is regarded to concern

exclusively the automatic FRR. In the Greek power system the manual FRR is supposed

to handle the forecast errors of Non-Dispatchable Load Portfolios, Non-Dispatchable RES

Portfolios, etc., namely the difference between the forecasted production/demand of

these entities and the actual metered production/demand in each RTBEM time-step (15-

minute interval), plus what is specifically defined in the draft Regulation for the RR.

Concerning the Replacement Reserve, according to Article 144 of the draft Regulation

establishing a guideline on electricity transmission system operation:

“The control target of the RRP shall be to fulfil at least one of the following goals by

activation of RR:

(a) progressively restore the activated FRR;

(b) support FRR activation;”


“The RR dimensioning rules shall comprise at least the following requirements:

(a) for the Nordic and CE synchronous areas there shall be sufficient positive

reserve capacity on RR to restore the required amount of positive FRR. For the

GB and IE/NI synchronous areas there shall be sufficient positive reserve capacity

on RR to restore the required amount of positive FCR and positive FRR;

(b) for the Nordic and CE synchronous areas, there shall be sufficient negative

reserve capacity on RR to restore the required amount of negative FRR. For the

GB and IE/NI synchronous areas, there shall be sufficient negative reserve capacity

on RR to restore the required amount of negative FCR and negative FRR;

(c) there shall be sufficient reserve capacity on RR, where this is taken into account

to dimension the reserve capacity on FRR in order to respect the FRCE quality target

for the period of time concerned; and

(d) compliance with the operational security within a LFC block to determine the

reserve capacity on RR.

4. All TSOs of an LFC block may reduce the positive reserve capacity on RR of

the LFC block, resulting from the RR dimensioning process, by developing a


RR sharing agreement for that positive reserve capacity on RR with other LFC

blocks in accordance with the provisions of Title 8 of Part IV. The control capability

receiving TSO shall limit the reduction of its positive reserve capacity on RR in order

to:

(a) guarantee that it can still meet its FRCE target parameters set out in Article 128;

(b) ensure that operational security is not endangered; and

(c) ensure that the reduction of the positive reserve capacity on RR does not exceed

the remaining positive reserve capacity on RR of the LFC block.

5. All TSOs of a LFC block may reduce the negative reserve capacity on RR of

the LFC block, resulting from the RR dimensioning process, by developing a

RR sharing agreement for that negative reserve capacity on RR with other LFC

blocks in accordance with the provisions of Chapter 9 of Part IV. The control

capability receiving TSO shall limit the reduction of its negative reserve capacity on

RR in order to:

(a) guarantee that it can still meet its FRCE target parameters set out in Article 128;

(b) ensure that operational security is not endangered; and

(c) ensure that the reduction of the negative reserve capacity on RR does not exceed

the remaining negative reserve capacity on RR of the LFC block.”

Again, based on the probabilistic methodology, an analysis can be performed based on

the above-mentioned differences between the forecasted production/demand of these

entities and the actual metered production/demand in each RTBEM time-step (15-minute

interval) over a period of one year. In this analysis, the positive and negative differences

shall be treated separately.

The total value of upward/downward manual FRR shall be finally calculated as the

algebraic sum of the worst contingency event and the uncertainty part of the FRR, as

shown in the equations below, where ,c upR , ,c dnR are the worst upward/downward

contingency events, respectively, ,net,

1 15

unc , ,net,

1 15

unc are the mean values of the

positive/negative differences, respectively, and ,net,

1 15

unc , ,net,

1 15

unc are the standard

deviations of the positive/negative differences, respectively.

, ,net, ,net,

1 15 1 153

up c up unc uncmFRR R , var,net,

1 15 0

, var,net

1 15 0 (for positive differences)

, ,net, ,net,

1 15 1 153

dn c dn unc uncmFRR R , var,net,

1 15 0

, var,net

1 15 0 (for negative differences)


12 Annex C: RES Units Categorization under Greek Law 4414/2016

In most European countries there is a differentiation in the market participation rules of

old and new RES units, and there is also a differentiation between small and larger new

RES units. Similar differentiations exist also in the recent Greek Law 4414/201627,

concerning the new remuneration scheme of RES units in Greece. Specifically, the

following categorization of RES units has been adopted:

1st category: Old RES units with a Power Purchase Agreement (PPA) with LAGIE

until 31/12/2015, for which the purchase contract (e.g. lasting 20 or 25 years,

depending on technology) has not been terminated yet, independently of their

installed capacity.

According to the Law 4414/2016, the RES units with an installed capacity below 5

MWp shall continue to be remunerated with their Feed-in-Tariff (FiT), until the

termination of their contract with LAGIE, as stated in Article 3, par. 11 of Law

4414/2016.

On the contrary, the RES units with an installed capacity above 5 MWp (threshold

defined by a Ministerial Decision) have two options:

a) either to continue to be remunerated with their FiT, until the termination of their

contract with LAGIE, as stated in Article 3, par. 11 of Law 4414/2016,

b) or to sign a Contract for Difference (CfD) with LAGIE, in which case they shall

be remunerated with:

• the wholesale market prices, depending on the market they sell their

production, and

• an additional fee derived by the sliding Feed-in-Premium (FiP) mechanism,

and considering their existing FiT price, as stated in Article 3, par. 13 of Law

4414/2016.

In case of RES units with an installed capacity below 5 MWp, and in case (a) above,

the TSO (ADMIE) shall be responsible for the injection forecasting (in all individual

markets) for such RES units, LAGIE shall be responsible for the submission of the

respective price-taking energy offers in the markets (Day-Ahead Market and

possibly Intra-Day Market), and the TSO shall bear their balance responsibility,

namely the relevant imbalance cost shall be transferred to an uplift account (as it is


currently the case in Greece), which shall be fully covered by the Load

Representatives (pro-rata to their represented load).

In case (b) above, the respective RES operator (RES Producer, RES Aggregator,

or Last Resort Aggregator) shall be responsible for the RES units’ forecasting and

bidding in the markets, and shall bear their balance responsibility (according to the

Imbalance Settlement mechanism applying in categories 4 and 5 below, regarding

larger new RES units).

2nd category: Old RES units with a Power Purchase Agreement (PPA) with LAGIE

until 31/12/2015, for which the purchase contract (e.g. lasting 20 or 25 years,

depending on technology) has terminated, independently of their installed capacity.

The market participation of such units has not been decided yet by the Ministry of

Energy; such decision is expected to be taken in the following months.

One option for these RES units is to be remunerated with the wholesale market

prices, depending on where they sell their production (namely, to be remunerated

with the Day-Ahead Market price for the sold energy in the Day-Ahead Market, and

with the Intra-Day Market price for the sold energy in the Intra-Day Market). These

RES units shall not have any rights for remuneration through a sliding FiP.

If such option is implemented, such RES units shall fully enter in the wholesale

market, namely the respective RES operators (RES Producers, RES Aggregators,

or the Last Resort Aggregator) shall be responsible for their injection forecasting

and bidding in the markets, and shall bear their full balance responsibility.

3rdcategory: New RES units, that have the right to enter to a contract agreement

with LAGIE (refers to projects that conclude this process after the 1st January 2016),

with the aid granted either through an auctioning process or not, but with an

installed capacity up to 3 MWp for wind plants and up to 500 kWp for all other RES

categories (hereinafter called “small new RES units”)

These RES units have currently only the following option:

a) to sign a Fixed Price Power Purchase Agreement with LAGIE (in accordance

with the provisions of Article 3 par. 5 of Law 4414/2016), thus hereinafter called

“small new RES units under FiT”, in which case they will be remunerated with:

• either the Reference Price of Article 4 of Law 4414/2016,

• or the auction offer price in case the aid is granted through an auctioning

process, according to Article 7 par. 4 of Law 4414/2016.

At a later stage and upon the operation of the new electricity market model these

RES units could also have the following option:

b) to sign a CfD with LAGIE (most probably through a RES Aggregator), thus

hereinafter called “small new RES units under FiP”, in which case they shall be

remunerated with:


• the wholesale market prices, depending on the market they sell their

production, and

• an additional fee derived by the sliding FiP mechanism, while considering the

Reference Price stated in Article 4 of Law 4414/2016.

For RES units of case (a) (“small new RES units under FiT”), the TSO (ADMIE)

shall be responsible for their injection forecasting (in all individual markets), LAGIE

shall be responsible for the submission of the respective price-taking energy offers

in the markets (Day-Ahead Market and possibly Intra-Day Market), and the TSO

shall bear their balance responsibility (through an uplift account, as discussed

above).

For RES units of case (b) (“small new RES units under FiP”), whenever this

becomes active, the RES Operator (RES Producer, RES Aggregator, or Last

Resort Aggregator) shall be responsible for their forecasting and bidding in the

markets, and shall bear their balance responsibility (according to the Imbalance

Settlement mechanism applying in categories 4 and 5 below, regarding larger new

RES units).

4th category: New RES units, with a Contract for Difference (CfD) with LAGIE within

year 2016 (or, in any case, before the commencement of the auctioning processes

for the granting of new aid, as discussed in the 5th category), but with an installed

capacity above 3 MWp for wind plants and above 500 kWp for all other RES

categories (hereinafter called “larger new RES units”).

These RES units, having signed a CfD with LAGIE, shall be remunerated:

a) with the wholesale market prices, depending on the market they sell their

production, and

b) with an additional fee derived by the sliding FiP mechanism, while considering

the Reference Price stated in Article 4 of Law 4414/2016.

The Participants responsible for these RES units (RES operators) are either the

RES Producers, or the RES Aggregators (contracted appropriately with the RES

Producers), or the Last Resort Aggregator (according to the Law 4414/2016).

Concerning the balance responsibility for these RES units (“larger new RES units”),

a Transitory Mechanism for the Optimal Forecasting Accuracy (hereinafter

“TMOFA”) shall be activated. According to TMOFA, the respective RES operators

shall be penalized (at the monthly Imbalance Settlement process) in case of high

deviations of the forecasted injections (offered energy quantity at the Day-Ahead

Market) and the actual injections. The accuracy of the forecasted injections also

affects (increases) the “management fee” to be given to these RES operators during

the validity period of the TMOFA.

The TMOFA shall be active until the implementation of a liquid Intra-Day Market in

Greece, under the provisions of the Target Model. Then, the TMOFA shall be


terminated (along with the “management fee” given to the RES operators) and the

RES operators shall have full balance responsibilities (same as the balancing rules

for the conventional units) for the RES units they represent, according to the

provisions of the Imbalance Settlement process.

5th category: New RES units, which have been granted aid through an auction,

having signed a Sliding FiP Contract for Differences (CfD) with LAGIE, and with an

installed capacity above 3 MWp for wind plants and above 500 kWp for all other

RES categories (included in the group called “larger new RES units”).

These RES units, having signed a Sliding FiP Contract for Differences (CfD) with

LAGIE, shall be remunerated:

a) with the wholesale market prices, depending on the market they sell their

production, and

b) with an additional fee derived by the sliding FiP mechanism, while considering

their offered price in the auctioning process (according to Article 7 par. 4 of Law

4414/2016).

The Participants responsible for these RES units (RES operators) are either the

RES Producers, or the RES Aggregators (contracted appropriately with the RES

Producers), or the Last Resort Aggregator (according to the Law 4414/2016).

Concerning their balance responsibility, the same rules with the 4th category of RES

units applies. However, no “management fee” is provided to such RES operators.

It should be noted that the above categories refer exclusively to RES units connected at

the Greek interconnected power system. The respective status and categories for non-

interconnected islands are different, since special rules are valid for such RES units under

the Greek Law 4414/2016.

In this context, a 6th category can also be included in the above analysis,

concerning new RES units that shall be connected at a non-interconnected island,

which shall be afterwards connected with the Greek interconnected power system.

Upon such interconnection, the same remuneration scheme and market rules (as they

are valid in the interconnected system) shall apply for these RES units.