Otsus

All Baltic CCR TSOs’ Common Capacity Calculation Methodology for Long-term Time Frames in Accordance with Article 10(1) of the Commission Regulation (EU) 2016/1719 of 26 September 2016 Establishing a Guideline on Forward Capacity Allocation

Among:

AS “Augstsprieguma tikls” Elering AS LITGRID AB PSE S.A. Svenska kraftnat Fingrid Oyj

December 23rd, 2024

Vilnius, Riga, Tallinn, Helsinki, Stockholm, Warsaw

2

TABLE OF CONTENTS

1 SUBJECT MATTER AND SCOPE .............................................................................................................................. 4

2 DEFINITIONS......................................................................................................................................................... 4

3 CAPACITY CALCULATION AND VALIDATION PROCESS ........................................................................................... 5

4 TRANSMISSION RELIABILITY MARGIN CALCULATION METHODOLOGY ................................................................. 6

5 OPERATIONAL SECURITY LIMITS, CRITICAL NETWORK ELEMENTS, CONTINGENCIES AND ALLOCATION CONSTRAINTS ............................................................................................................................................................... 7

6 GENERATION AND LOAD SHIFT KEYS (GLSK) ......................................................................................................... 8

7 REMEDIAL ACTIONS (RAS) .................................................................................................................................... 9

8 COMMON RULES CAPACITY CALCULATION METHODOLOGY FOR LONG-TERM TIME FRAMES .............................. 9

9 TTC CALCULATION METHODOLOGY ..................................................................................................................... 10

10 COORDINATED NTC CALCULATION PRINCIPLES FOR INTERNAL BALTIC AC INTERCONNECTORS .......................... 11

11 COORDINATED NTC CALCULATION PRINCIPLES FOR DC INTERCONNECTORS ....................................................... 12

12 TOTAL TRANSFER CAPACITY (TTC) CALCULATION FOR LITHUANIAN - POLAND AC CROSS-BORDERS INTERCONNECTOR ....................................................................................................................................................... 12

13 LONG-TERM CAPACITY CALCULATION RULES FOR YEAR-AHEAD TIMEFRAME ..................................................... 14

14 LONG-TERM CAPACITY CALCULATION RULES FOR MONTH-AHEAD TIMEFRAME ................................................. 14

15 LONG-TERM CAPACITY CALCULATION FOR OTHER TIMEFRAMES ........................................................................ 15

16 RULES FOR TAKING INTO ACCOUNT PREVIOUSLY ALLOCATED CROSS-ZONAL CAPACITY ..................................... 15

17 RULES FOR EFFICIENTLY SHARING POWER FLOW CAPABILITIES OF CRITICAL NETWORK ELEMENTS AMONG DIFFERENT BIDDING-ZONE BORDERS ........................................................................................................................... 15

18 RULES FOR SHARING THE POWER FLOW CAPABILITIES OF CRITICAL NETWORK ELEMENTS AMONG DIFFERENT CCRS 15

19 RULES ON THE ADJUSTMENT OF POWER FLOWS OF CROSS-ZONAL CAPACITY DUE TO RAS ................................ 16

20 CROSS-ZONAL CAPACITY VALIDATION METHODOLOGY ...................................................................................... 16

21 FALLBACK PROCEDURE ........................................................................................................................................ 16

22 PUBLICATION OF DATA ....................................................................................................................................... 16

23 REPORTING ......................................................................................................................................................... 16

24 IMPLEMENTATION OF THE LONG-TERM CCM ...................................................................................................... 17

25 LANGUAGE .......................................................................................................................................................... 17

ANNEX 1: JUSTIFICATION OF THE METHODOLOGY FOR CALCULATION OF ALLOCATION CONSTRAINTS (ARTICLE 5) AND ITS APPLICATION ......................................................................................................................................................... 18

3

All Baltic CCR TSOs, taking into account the following,

Whereas

(1) This document is developed by Baltic Capacity Calculation region (hereafter referred to as

“Baltic CCR”) Transmission System Operators (hereafter referred to as “TSOs”) as common

Capacity Calculation Methodology for Long-Term time frames (hereafter referred to as “Long-

term CCM”) in accordance with Article 10(1) of Commission Regulation (EU) 2016/1719

establishing a guideline on forward capacity allocation (hereafter referred to as the “FCA

Regulation”).

(2) The Long-term CCM shall be compatible with the capacity calculation methodology established

for the day-ahead and intraday time frames according to Article 10(3) of FCA Regulation.

(3) The goal of the FCA Regulation is the coordination and harmonisation of forecasted cross-zonal

capacity calculation and capacity allocation in the forward markets. Moreover, the requirements

are set for the TSOs to cooperate on the level of capacity calculation regions (hereinafter

referred to as “CCRs”), on a pan-European level and across bidding zone borders. The Article

10(2) of FCA Regulation also sets rules for establishing capacity calculation methodologies

based either on the coordinated net transmission capacity approach or on the flow-based

approach. This Methodology foresees to apply coordinated net transmission capacity (CNTC)

approach in Baltic CCR.

(4) The objective of providing Long-term CCM is two-fold. Firstly, market participants in the power market aim at forecasting future day-ahead pricing of the different bidding zones, acting as an input to the strategies for operation and investment decisions. The goal of Long-term CCM is to provide the market participants with the information of expected capacity between bidding zones, as this information has an impact on demand and supply of electricity and hence the day-ahead pricing. Secondly, the calculation of long-term capacity will act as input to the issuing of long-term transmission rights on bidding zone borders where long-term transmissions rights are implemented.

(5) Long-term CCM is ensuring and enhancing the transparency and reliability of information on

forward capacity allocation, as the Long-term CCM determines the main principles and main

processes for long-term capacity calculation timeframes. The Methodology enables TSOs in a

transparent way to provide information on forecasted cross-zonal capacities for long-term

transmission rights auctions where applicable on Baltic CCR borders.

(6) In this Long-term CCM, unless the context requires otherwise:

a) headings are inserted for convenience only and do not affect the interpretation of this Long- term CCM; and

b) any reference to legislation, regulations, directives, orders, instruments, codes or any other enactment shall include any modification, extension or re-enactment of it when in force.

c) references to an “Article” are, unless otherwise stated, references to an article of this Long- term CCM.

(7) This Methodology also takes into account and acts upon the fact that the Baltic States are

foreseen to be synchronized with the Continental Europe Synchronous Area by double circuit

line connecting Poland and Lithuania. The capacity of interconnection will have to be, in large

part, kept for reliability margins in a case of unexpected tripping of aforementioned double circuit

line (with simultaneous transfer of Baltic System into island operation) or outage (of load or

generation/infeed) in the Baltic System. TSOs will continue offering maximum capacity for

cross-border trading, compliant with operational security limits and considering possible

contingencies in the Polish and Lithuanian systems, including those resulting from

aforementioned unexpected events. The specific situation of this interconnection is hereby

4

taken into consideration for the calculation of the total capacity and contingencies pursuant to

Article 16(8) of Regulation (EU) 2019/943 and whereas (54) of Regulation (EU) 2024/1747 of

the European Parliament and of the Council of 13 June 2024 amending Regulations (EU)

2019/942 and (EU) 2019/943 as regards improving the Union’s electricity market design.

SUBMIT THE FOLLOWING LONG-TERM CCM TO ALL REGULATORY AUTHORITIES OF THE BALTIC CCR:

1 SUBJECT MATTER AND SCOPE

1.1. The common CCM for long-term timeframes as determined in this document shall be considered as the common Long-term Methodology of Baltic CCR TSOs in accordance with Article 10(1) and Article 21 of FCA Regulation.

1.2. Long-term CCM covers year ahead and month ahead long-term capacity calculation timeframes, which are foreseen by Article 9 of FCA Regulation, and any timeframe included in the regional design of long-term transmission rights pursuant to Article 31 of FCA Regulation.

1.3. No physical capacity allocation (both implicitly and explicitly) other than balancing capacity market allocations are made before day-ahead implicit allocation and no physical capacity is reserved (both implicitly and explicitly) for long-term capacity on the Baltic CCR borders.

2 DEFINITIONS

2.1. For the purposes of the Long-term CCM, terms used in this document shall have the meaning of the definitions included in Article 2 of the Commission Regulation (EU) 2015/1222 establishing a guideline on capacity allocation and congestion management (hereafter referred to as "CACM Regulation"), Article 2 of the FCA Regulation, Article 2 of Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity and Directive (EU) 2019/944 of the European Parliament and of the Council of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU.

BSPS – Baltic State Power Systems (Republic of Estonia, the Republic of Latvia and the Republic of Lithuania).

CCC – Coordinated capacity calculator established in accordance with Article 27 of CACM Regulation.

CEP – Clean Enegy Package.

Cross-Border Interconnection – is a physical transmission link (e.g. tie-lines) which connects two power systems.

CGMM – common grid model methodology in accordance with Articles 67(1) and 70(1) of Commission Regulation (EU) 2017/1485 of 02 August 2017 establishing a guideline on electricity transmission system operation.

CGM (Common Grid Model) – electrical system grid model agreed between TSOs describing the main characteristic of the power system (generation, loads and grid topology) and rules for changing these characteristics during the capacity calculation process in accordance with Article 17 of the CACM Regulation.

CGMES – Common grid model exchange standard.

Elering – Elering AS, electricity transmission system operator of the Republic of Estonia.

Fingrid – Fingrid Oyj, electricity transmission system operator of the Republic of Finland.

5

Litgrid – LITGRID AB, electricity transmission system operator of the Republic of Lithuania.

GLSK – generation and load shif keys further elaborated in Article 24 of CACM Regulation.

Market Coupling Operator (MCO)/Nominated electricity Market Operator (NEMO) - the operator/- s of day-ahead and Intraday Markets in Baltic CCR.

NTC – coordinated Net Transmission Capacity of the designated Cross-Border Interconnections is the maximum Trading Capacity, which is permitted in transmission Cross-Border Interconnections compatible with Operational Security standards and taking into account the technical uncertainties on planned network conditions for each TSO.

PSE – PSE S.A., electricity transmission system operator of the Republic of Poland.

Shift Key – means a method of translating a net position change of a given power system into estimated specific injection increases or decreases in the Common Grid Model. Shift Key is settled as generation, renewable generation and load.

SvK – Svenska kraftnat, electricity transmission system operator in Sweden.

SO GL – European Commission Regulation (EU) No 2017/1485 establishing a Guideline on electricity transmission system operation.

TRM – Transmission Reliability Margin which shall have meaning of "reliability margin" definition of CACM Regulation.

TTC - Total Transfer Capacity of the designated Cross-Border Interconnections is the maximum transmission of active power, which is permitted in transmission Cross-Border Interconnections compatible with Operational Security standards applicable for each TSO.

Trading Capacity – the maximum available cross-zonal Capacity for trade in Day-Ahead Market and Intraday Market.

CESA – Continental Europe Synchronous Area.

MTU – Market time unit.

Internal Baltic AC interconnectors – Interconnectors between Baltic TSOs in Baltic area, covering Lithuania – Latvia and Latvia – Estonia cross-borders.

Baltic AC interconnectors – Interconnectors in Baltic area, covering Lithuania – Latvia, Lithuania – Poland, Latvia – Estonia cross-borders.

3 CAPACITY CALCULATION AND VALIDATION PROCESS

3.1. Capacity calculation and validation process involves TSOs and Coordinated Capacity Calculator (hereafter referred to as “CCC”) and consists of these main steps:

• Input data provision by TSOs for Capacity Calculator (further detailed in Paragraph 3.3).

• Capacity calculation (further detailed in Sections 8 - 15).

• Capacity validation and coordination procedure (further detailed in Section 20).

• Capacity publication to market operator (further detailed in Section 22).

Detailed data exchange processes rules describing input data provision, capacity calculation, coordination, validation and process step timings shall be described in agreements between TSOs and CCC.

6

3.2. TSOs of Baltic CCR shall set up CCC according to rules set out in Article 27.2 of the CACM Regulation and Article 37.1.a of CEP Regulation and establish rules governing their operations defined in agreements between TSOs and CCC.

3.3. TSOs of the Baltic CCR shall provide to the CCC and coordinate between the TSOs and the CCC the following inputs for TTC calculation according to Article 29.1 of the CACM Regulation:

• IGM - base case model, which includes power transmission equipment model of Control Area of TSO (according to CACM Article 17 and Section 8.4).

• Operational Security Limits (according to Section 5).

• Generation and Load Shift Keys (according to Section 6).

• Critical Network Elements (according to Section 5).

• Contingencies (according to Section 5).

• Remedial Actions (according to Section 7).

• TRM values or input data for TRM calculation (according to Section 4).

• Allocation constraints (according to Section 5.5).

3.4. If input data for capacity calculation process referred in 3.3 is used as static data and is constant in daily capacity calculation processes, such data shall be reviewed and shared between TSOs and CCC at least on a yearly basis or upon TSO or CCC request.

3.5. In accordance with Article 29 and 30 of the CACM Regulation, capacity calculation shall be performed by the CCC whereas the TSOs shall provide required input data and perform validation.

4 TRANSMISSION RELIABILITY MARGIN CALCULATION METHODOLOGY

4.1. The TRM is a capacity margin needed for secure operation of interconnected power systems considering the planning data inaccuracy (load and generation prognosis) , including the errors due to imperfect information during operational electrical system planning at the time the transfer capacities have been computed.

4.2. TRM calculation methodology is covering Baltic AC interconnectors of BSPS.

4.3. TRM value for DC interconnectors shall be equal to 0 MW.

4.4. For determining of the TRM values for each Cross-Border Interconnection, the statistical data of historically planned and actual power flows (historical physical flows) shall be used for each MTU. TRM shall be determined as the arithmetic average of the deviations between the expected power flows at the time of the capacity calculation and realised power flows in real time value plus standard deviation based on historical data. TRM shall be rounded to the nearest integer. TRM shall be calculated for each cross-border direction according to formula (1):

(1)

where:

Xi - data sets of the i-th element, defined as deviation of planned power flow from actual power flow

(actual flow subtracted from planned flow) over Cross-Border Interconnection;

7

̅ arithmetic average value of Xi equal to

n - number of elements in the data set.

4.5. TRM shall be recalculated every month using last 1 year or latest available historical period data. Historical data for TRM evaluation shall be acquired since Baltic TSOs synchronisation with CESA.

4.6. For initial operation period after Baltic TSOs synchronisation with CESA, fixed TRM values

shall be applied to AC interconnections of BSPS. These values shall be applied for 1 month period.

After this period, TRM shall be calculated according to principles set out in 4.4 and 4.5. Fixed values

provided in Table 1.

Table 1. Fixed TRM values for initial operation period

Border EE-LV LV-EE LT-LV LV-LT LT-PL PL-LT

TRM value 50 MW 50 MW 50 MW 50 MW 50 MW 50 MW

5 OPERATIONAL SECURITY LIMITS, CRITICAL NETWORK ELEMENTS, CONTINGENCIES AND ALLOCATION CONSTRAINTS

5.1. Each Baltic CCR TSO shall define list of critical network elements (CNEs) of its control area for capacity calculation process. Elements could be all Cross-Border Interconnectors, lines, transformers, HVDC elements.

5.2. CNEs for capacity calculation shall be defined considering impact computation principles defined in methodology according to art. 75 of SO GL annex 1 and factor determining impact for CNE shall be cross-zonal power flow exchange. Internal CNEs which power flow filtering influence factor according to art. 75 of SO GL annex 1 is less than percentage, defined by TSOs based on operational and planning expertise, shall be excluded from capacity calculation process. TSO shall update CNE list in case of significant change in grid topology when influence value for CNE element significantly changed from average value and CNE became relevant/irrelevant for capacity calculation process.

5.3. Contingency Analysis is performed at least for those contingencies which are agreed among Baltic TSOs in the Contingency Lists. Contingency Lists shall be agreed and provided among Baltic TSOs and provided to CCC for Capacity Calculation.

5.4. Each Baltic CCR TSO shall provide Contingency List to be used in capacity calculation process in accordance with art. 33 of SO GL. Contingency list shall include contingencies of TSO observability area. Contingency can be:

• Line, cable; • Transformer; • Generator; • Load; • Busbar; • Multiple elements combined; • HVDC;

5.5. A TSO may use allocation constraints as a constraint on the cross-border and/or on the global net position (the sum of all cross-border exchanges for a certain bidding zone - hereinafter referred

8

to as balancing constraints), thus limiting the net position of the respective bidding zone with regards to all CCRs which are part of long term calculation process. The global net position constraint is used to ensure a minimum level of operational reserve for balancing in case of a central dispatch model. The balancing constraints introduced are bi-directional, with independent values for directions of import and export, depending on the foreseen balancing situation. This balancing constraints on long- term level, may be used only as long as they serve to accommodate the existing day-ahead balancing constraints. The details, justifications for use, and the methodology for the calculation of this kind of allocation constraints are set forth in Annex 1.

5.6. The allocation constraint specified in Article 5.5 may be used for an interim period of 2 years following the implementation of this Methodology. If all of the Baltic CCR TSOs still want to use allocation constraints after this period, they shall deliver a proposal for amendments to this Methodology, describing the technical details for calculating the allocation constraints and the justification for the need for them latest two years after the implementation of this Methodology. The justification shall include, in the explanatory document, the impact of the allocation constraint on economic surplus and the distributional effects during the MTUs when the allocation constraint has been binding during the last 12 months and alternative solutions. In case such a proposal has been submitted, the interim period shall be extended until the decision on the proposal is taken by all national regulatory authorites (hereafter referred to as “NRAs”) of the Baltic CCR.

5.7. The TSOs applying the long-term allocation constraints as specified in Article 5.5 shall:

a) update the calculation of allocation constraints at least on a quarterly basis; and

b) provide to all CCR Baltic TSOs and NRAs the detailed calculation and its results upon each update of the allocation constraints’ values.

5.8. Each Baltic CCR TSO and CCC shall perform regular review of CNEs, Contingencies, Allocation constraints and other input data and evaluate their relevance and application in capacity calculation process. Reviews shall be performed on a yearly basis, in line with the requirements set forth in Article 27(4) of the CACM and Article 3(f) of the FCA Regulation. Where the review identifies a need to update any long-term capacity calculation inputs, the following steps shall be undertaken:

• The updated information shall be published no later than one month prior to it's implementation.

• The updates shall be communicated to NRAs of the Baltic CCR and market participants. The Baltic CCR TSOs shall communicate the impact of any change of parameters listed in Article 27(4)(d) of the CACM Regulation to market participants and all Baltic CCR NRAs.

• If the update results in a change to the methodology, the Baltic TSO's shall submit a proposal for amendment of the methodology in accordance with Article 4(12) of the FCA Regulation.

6 GENERATION AND LOAD SHIFT KEYS (GLSK)

6.1. GLSK shall represent the best forecast of the relation of a change in the net position of a bidding

zone to a specific change of generation or load in the CGM according to Article 24 of the CACM

Regulation. That forecast shall notably take into account the information from the generation and load

data provision methodology according to Article 16 of CACM Regulation. GLSK strategy per TSO

control area shall be the responsibility of each involved TSO, which has to be communicated with

other TSOs and Capacity Calculator before commencing TTC calculation process in case of deviation

from default GLSK strategy set out in paragraphs 6.3 and 6.4.

6.2. Default GLSK strategy shall be based on merit order principle and set up according to

paragraphs 6.3 and 6.4. To maintain Operational Security and data accuracy TSOs may determine

different GLSK strategy based on best available forecast for generation and load according to Article

9

24 of the CACM Regulation. If TSOs determine different GLSK strategy, implementation in calculation

algorithm shall be coordinated with Capacity Calculator.

6.3. TSOs shall define GLSK strategy to best represent latest specific changes of generation or load

in TSO control area according to Article 24 of the CACM Regulation. Following generation and/or load

groups merit order shall be used as default:

a. Internal specific area generation shift.

b. HVDCs setpoint change.

c. Neighbouring system generation shift (including HVDCs setpoint change, if HVDC’s flow

goes into synchronous area).

d. Load shifting in specific area.

6.4. GLSK principle depending upon a merit order generation/load shift key method shall be

performed according to following rules:

6.4.1. The chosen generation nodes scaled up or down according to the merit order list defined in the

GLSK input, provided by TSOs. GLSK data shall contain the generation nodes which performs the

total positive or negative shift are provided.

6.4.2. The merit order determines sequence how generation shift is applied to node. The order is

defined by the TSOs to best represent latest specific changes of generation or load in TSO control

area. If group of generators have the same merit order, then that group of generators will be shifted

proportionally.

6.5. GLSK strategy applied in Nordics is described in detail in Nordic CCR Capacity Calculation

Methodology.

7 REMEDIAL ACTIONS (RAS)

7.1. Relevant TSOs shall provide relevant CCC with information on available and applicable non-

costly and costly remedial actions that shall be used in capacity calculation process.

7.2. List of possible remedial actions in Baltic CCR, which can be used during capacity calculation process shall cover changes of network topology.

7.3. Non-costly remedial actions are such actions which don't result in additional costs to TSO in case of planned operational regime for which capacity calculation is performed. Costly remedial actions are such actions which result in additional costs to TSO even in case of planned operational regime for which capacity calculation is performed.

7.4. Countertrading and redispatching possibilities along with other remedial actions shall be fully

exploited before an internal Critical Network Element may affect cross zonal trade.

8 COMMON RULES CAPACITY CALCULATION METHODOLOGY FOR LONG- TERM TIME FRAMES

8.1. Long-term cross-zonal capacity shall be calculated for each timeframe which are foreseen by

Article 9 of FCA Regulation and any timeframe included in the regional design of long-term

transmission rights pursuant to Article 31 of FCA Regulation. Capacity calculation process shall be

performed as separate calculation for each long-term timeframe.

10

8.2. TSOs cannot start long-term capacity calculation process for any of the upcoming year's

timeframes before agreeing on preliminary transmission infrastructure outage plans, which taking into

account provisions of Article 97 of Commission Regulation (EU) 2017/1485 of 2 August 2017

establishing a guideline on electricity transmission system operation (SO GL) will be earliest on 1st of

November of each year.

8.3. Long-term cross-zonal capacity shall be calculated for all Baltic CCR borders after TSOs and

CCC have all information (needed for calculations – i.e. information mentioned in Articles 3 to 7 of

this methodology, CGM, as well as planned transmission infrastructure outage plans. Latest agreed

transmission infrastructure outage plan shall be used for each long-term capacity calculation period.

The long-term cross-zonal capacity for respective border and respective timeframe is calculated

according to Article 23(2) of FCA Regulation and applying requirements set out in Article 29 of CACM

Regulation.

8.4. The uncertainties in long-term cross-zonal capacity calculation will be taken into account by

applying a security analysis based on multiple scenarios in accordance with Article 3 of the CGMM

developed in accordance with Article 18 and 19 of the FCA Regulation. Unless and until these

scenarios have been developed, the default scenarios as defined in Article 3(1) of CGMM shall be

used. On those scenarios outage sets can be applied as stipulated in 8.2 to take into account all

available information for capacity calculation including transmission lines' outage plans, which can

change on daily basis for long-term capacity calculation process.

8.5. Long-term cross-zonal CCM for each Baltic CCR border is given below in Sections 10-11.

Long-term cross-zonal capacity calculation process shall be performed by CCC following

requirements of Section 4 of FCA Regulation.

8.6. Limits of transmission capacity on the Polish-Lithuanian border shall be determined pursuant

to Section 12, using the latest available CGM models in accordance with Article 3 of the CGMM

developed in accordance with Article 18 and 19 of the FCA Regulation or special models prepared by

TSOs for respective periods in which its closed 110 kV distribution grid is included as well as latest

forecast of a load, generation and topology.

9 TTC CALCULATION METHODOLOGY

9.1. The Cross-Border Interconnection TTC determination for AC interconnectors shall be done by

performing Contingency Analyses based on N-1 criterion on a CGM, while taking into account the

intra and intersystem Operational Security limits according to Section 5 of synchronous area and

Control Area of Baltic TSOs.

9.2. TTC is maximum power flow value on Cross-Border Interconnection between two bidding

zones resulted from modelling net position variation and performing contingency analysis. TTC value

is obtained by summing up power flow values of cross-border lines above 110 kV after Operational

Security or stability limits are reached for any CNE after modelling net position increase in exporting

area and decrease in importing area and performing N-1 contingency analysis.

9.3. TSOs and Capacity Calculator shall not limit cross-zonal exchanges due to Critical Network

Elements not significantly impacted by cross-zonal trade according to Article 29.3(b) of CACM

Regulation and Section 5 unless performed Contingency Analyses determines threat to Operational

Security or when operational security analyses show that boundaries of stability limits are exceeded

during operation of the transmission system.

9.4. While calculating TTC and performing Contingency Analyses after applying of N-1 criteria

11

following Operational Security limits shall be not exceeded:

• Permanently allowed thermal limits, that correspond to the relevant ambient temperature, of

network elements, i.e. the maximum amount of electric current that a given network element

can conduct without sustaining damage or being in violation of safety requirements;

• Voltage and load stability limits in network nodes, i.e. maximum and minimum voltage levels

permitted at given network node in order to prevent equipment damage or voltage collapse

respectively;

• Dynamic and or any other time dependent stability limit (including frequency, oscillatory and

rotor angle stability), based on TSOs internal stability assessment procedure.

9.5. TTC for each cross-border that consists solely of HVDC connections is limited by the sum of

ratings of HVDC interconnectors that connect the Bidding Zones. In order to define TTC limitation

related to adjacent AC networks, Contingency Analyses based on N-1 criterion (i.e. a loss of any

single element of power system) shall be performed using CGM, while taking into account the intra

and intersystem Operational Security limits according to principles set out in paragraph 9.4.

10 COORDINATED NTC CALCULATION PRINCIPLES FOR INTERNAL BALTIC AC INTERCONNECTORS

10.1. For the long-term capacity calculation timeframes, CNTC (Coordinated Net transmission

Capacity) approach is applied in the Baltic CCR.

10.2. Capacity Calculator shall calculate NTC value for Internal Baltic AC interconnections following

equation:

NTC = TTC – TRM (2)

where:

TTC - Total Transfer Capacity according to actual power system network status, identified during TTC

evaluation, defined in Section 9;

TRM - transmission reliability margin value calculated according to the methodology described in

Section 4 of this Methodology.

10.3. In case if during capacity validation process neighbouring TSOs determine different NTC values

for the same Cross-Border Interconnection the lowest value shall be used as a coordinated value.

10.4. Trading Capacity shall be defined for both interconnection directions according to formula (2).

In case if during capacity validation process different NTC values are calculated for the same Cross-

Border Interconnection direction the lowest value shall be used as a coordinated value.

NTCA-B; B-A= min (A NTCA-B; B NTCA-B); min (A NTCB-A; B NTCB-A) (3)

where:

NTCA-B; B-A – coordinated NTC values according to formula (2) for each interconnection direction

between area A and B;

A NTCA-B; A NTCB-A – as calculated by party A according to formula (2);

B NTCA-B; B NTCB-A – as calculated by party B according to formula (2) .

12

11 COORDINATED NTC CALCULATION PRINCIPLES FOR DC INTERCONNECTORS

11.1. CCC shall calculate NTC value for Baltic DC interconnectors using formula (2) considering input

data provided from TSOs.

11.2. (2)TTC calculation approach defined in Section 9 for DC interconnectors shall be applied by

Capacity Calculator assigned by Baltic CCR.

11.3. Coordinated capacity value shall be obtained by evaluating minimum value according to

principles defined in 10.4 and formula (3).

12 TOTAL TRANSFER CAPACITY (TTC) CALCULATION FOR LITHUANIAN - POLAND AC CROSS-BORDERS INTERCONNECTOR

12.1. While calculating TTC, list of considered CNE and contingencies should be determined according to Section 5.

12.2. While calculating TTC and performing contingency analyses after applying of N-1 criteria following operational security limits shall be not exceeded:

12.2.1. Permanently allowed thermal limits, that correspond to the relevant ambient temperature, of network elements, i.e. the maximum amount of electric current that a given network element can conduct without sustaining damage or being in violation of safety requirements.

12.2.2. Voltage and load stability limits in network nodes, i.e. maximum and minimum voltage levels permitted at given network node in order to prevent equipment damage or voltage collapse respectively.

12.2.3. Dynamic stability limits including:

i. transient stability.

ii. small signal stability (see further description in paragraph 12.3).

12.2.4. Frequency stability limit is assessed based on commonly agreed and coordinated availability of frequency support measures between Baltic TSOs. Measure 12.2.4.ii is agreed between relevant Baltic TSOs, Swedish TSO and Finnish TSO. The respective values in both directions are calculated by Lithuanian TSO taking into account the following commonly agreed and coordinated measures/parameters:

i. Forecasted inertia level in BSPS.

ii. Available fast frequency response settings on HVDC links in BSPS.

iii. Forecasted available fast frequency reserves amount provided by Battery Energy Storage Systems (BESS) in BSPS.

iv. Disconnection of AC interconnection with CESA shall not cause rate of change of frequency (ROCOF) greater than 1 Hz/s and activation of load shedding in BSPS.

12.3. TTC values for relevant direction calculated considering small signal operational security stability limits (according 12.2.3.ii) shall be defined by applying following approach:

TTCSS(PL>LT) = min (TTC1(PL>LT); TTC2(PL>LT)); TTCSS(LT>PL) = min (TTC1(LT>PL); TTC2(LT>PL)) (4)

Where:

TTCSS(PL>LT); TTCSS(LT>PL) – Total Transfer Capacity considering dynamic small signal stability limits.

TTC1(PL>LT); TTC1(LT>PL) – small signal stability limit with N-1 line outages evaluation in directions to

13

PL>LT and LT>PL.

TTC2(PL>LT); TTC2(LT>PL) – security limit based on small signal stability criteria without N-1 line outages evaluation shall be calculated considering security limits based on small signal stability criteria and possible loss of biggest infeed in Baltic PS in directions to PL>LT and LT>PL.

TTC2(PL>LT) = TTC0(PL>LT) – MaxInf; TTC2(LT>PL) = TTC0(LT>PL) – MaxDem (5)

Where:

TTC0(PL>LT); TTC0(LT>PL) – small signal stability limit without N-1 line outages for direction PL>LT and LT>PL.

MaxInf - biggest N-1 infeed disconnection in BSPS.

MaxDem - biggest N-1 demand disconnection in BSPS.

12.4. The hourly values of matched TTC according to Operational security limits defined in 12.2.1 - 12.2.3 in direction to Lithuania are calculated according to the following formula:

TTCPL>LT = min (PL TTCSS(PL>LT); LT TTCSS(PL>LT); TTC(PL>LT)(F)) (6)

where:

PL TTCSS(PL>LT) – TTC between LT and PL bidding areas in direction to Lithuania, determined by PL TSO, considering Operational security limits defined in 12.2.1 - 12.2.3 and 12.3.

LT TTCSS(PL>LT) – TTC between LT and PL bidding areas in direction to Lithuania, determined by LT TSO, considering Operational security limits defined in 12.2.1 - 12.2.3 and 12.3.

TTC(PL>LT)(F) – TTC of Lithuania-Poland Cross-Border Interconnection in direction to Lithuania calculated by Lithuanian TSO considering frequency stability limits as in 12.2.4.

12.5. The hourly values of matched TTC according to Operational security limits defined in 12.2.1 - 12.2.3 in directions to Poland are calculated according to the following formula:

TTCLT>PL = min (PL TTCSS(LT>PL); LT TTCSS(LT>PL); TTC(LT>PL)(F)) (7)

where:

PL TTCSS(LT>PL) – TTC between LT and PL bidding areas in direction to Poland, determined by PL TSO, considering Operational security limits defined in 12.2.1 - 12.2.3 and 12.3.

LT TTCSS(LT>PL) – TTC between LT and PL bidding areas in direction to Poland, determined by LT TSO, considering Operational security limits defined in 12.2.1 - 12.2.3 and 12.3.

TTC(LT>PL)(F) – TTC of Lithuania-Poland Cross-Border Interconnection in direction to Poland calculated by Lithuanian TSO considering frequency stability limits as in 12.2.4.

NTC CALCULATION RULES BETWEEN LITHUANIAN AND POLISH POWER SYSTEMS

12.6. NTC values for Lithuania-Poland Cross-Border Interconnection in direction to Lithuania shall be calculated by using following formula:

NTC(PL>LT) = TTC(PL>LT) - TRM(PL>LT) (8)

where:

TTC(PL>LT) – TTC of Lithuania-Poland Cross-Border Interconnection in direction to Lithuania calculated by Polish and Lithuanian TSO’s according to formula (6) as in 12.4.

14

TRM(PL>LT) – transmission reliability margin due to unintentional deviations in the Lithuania-Poland Cross- Border Interconnection. For initial operation period after Baltic TSOs synchronisation with CESA, TRM

shall be calculated and applied according to paragraph 4.6, but not higher, than 30% of TTC(PL>LT).

12.7. NTC values for Lithuania-Poland Cross-Border Interconnection in direction to Poland shall be calculated by using following formula:

NTC(LT>PL) = TTC(LT>PL) – TRM(LT>PL) (9)

where:

TTC(LT>PL) – TTC of Lithuania-Poland Cross-Border Interconnection in direction to Poland calculated by Polish and Lithuanian TSO’s according to formula (7) as in 12.5.

TRM(LT>PL) – transmission reliability margin due to unintentional deviations in the Lithuania-Poland Cross- Border Interconnection. For initial operation period after Baltic TSOs synchronisation with CESA, TRM

shall be calculated and applied according to 4.6, but not higher, than 30% of TTC(LT>PL).

13 LONG-TERM CAPACITY CALCULATION RULES FOR YEAR-AHEAD TIMEFRAME

13.1. For LV-LT, LT-PL, LT-SE4 Year-Ahead timeframe long-term capacity calculation process shall publish results to market participants and transparency platform by 15th of December as the latest.

13.2. For EE-LV and EE-FI Year-Ahead timeframe long-term capacity calculation process shall publish results to market participants and transparency platform by 8th of November as the latest.

13.3. Capacity calculation for Year-Ahead timeframe shall be performed on a yearly CGM. Scenarios and timestamps for yearly CGM shall be set according to CGMM methodology.

13.4. Capacity calculation for Year-Ahead timeframe shall be performed at least for each month of the year using latest available CGM scenario and yearly coordinated outages plan applied. Capacities shall also be calculated for each cross-zonal capacity impacting planned outages or outages combination period also including new infrastructure plans and generation/load patterns.

13.5. TTC and NTC values shall be calculated considering system security and net position variation in accordance with Section 9.

14 LONG-TERM CAPACITY CALCULATION RULES FOR MONTH-AHEAD TIMEFRAME

14.1. For Month-Ahead timeframe long-term capacity calculation process shall provide results 6 days before analysed month the latest.

14.2. Capacity calculation for Month-Ahead timeframe shall be performed on a latest available CGM or yearly CGM. Data for CGM shall be updated accordingly.

14.3. Capacity calculation for Month-Ahead timeframe shall be performed at least for each day of the month using latest available CGM scenario and yearly or latest available coordinated outages plan applied. Capacities shall also be calculated for each cross-zonal capacity impacting planned outages or outages combination period also including new infrastructure plans and generation/load patterns.

14.4. TTC and NTC values shall be calculated considering system security and net position variation in accordance with sections Section 9.

15

15 LONG-TERM CAPACITY CALCULATION FOR OTHER TIMEFRAMES

15.1. If any of Baltic CCR TSO needs to offer or publish capacities for any additional timeframes, the results from the previous capacity calculation (M-1, Y-1) that cover the additional timeframe will be used as default.

15.2. If, for the case mentioned in point15.1, there are any changes to outages defined respectively in yearly or monthly outage plan, NTC’s used for processed timeframe shall be re-calculated for relevant cross-borders to ensure transparency of the capacities for the market.

15.3. The results of recalculation process shall be published as mentioned in point 22.1 and 22.2.

15.4. Capacity calculation for any other timeframe shall be performed using the latest available CGM as described in paragraph 8.4 and 8.6 and outage plan to calculate capacities.

15.5. TTC and NTC values shall be calculated considering system security and net position variation in accordance with sections in Section 8.

16 RULES FOR TAKING INTO ACCOUNT PREVIOUSLY ALLOCATED CROSS- ZONAL CAPACITY

When determining cross-zonal capacities for any long-term timeframe defined in this methodology, previously allocated capacities shall be considered. Cross-zonal capacities shall be reduced, where appropriate, by the amount of previously allocated capacities for long-term transmission rights (if present).

17 RULES FOR EFFICIENTLY SHARING POWER FLOW CAPABILITIES OF CRITICAL NETWORK ELEMENTS AMONG DIFFERENT BIDDING-ZONE BORDERS

17.1. When defining appropriate network areas in and between which congestion management is to apply, TSOs shall be guided by the principles of cost-effectiveness and minimisation of negative impacts on the internal market in electricity. Specifically, TSOs shall not limit interconnection capacity in order to solve congestion inside their own control area, save for the abovementioned reasons and reasons of operational security. To ensure that potential congestions inside a control area do not affect the interconnection capacity the TSO shall exploit all available remedial actions such that cross- zonal capacities is at least as high as prescribed in Article 16(8) of the Electricity Market Regulation 2019/943. 17.2. Baltic TSOs network is radial which results in direct flows between areas without any loop flows and there is no such CNEs in Baltic CCR that would clearly and in majority cases influence power flow capabilities of several borders at once, therefore rules for efficiently sharing the power flow capabilities of CNEs among different bidding zone borders in Baltic CCR are not applied.

18 RULES FOR SHARING THE POWER FLOW CAPABILITIES OF CRITICAL NETWORK ELEMENTS AMONG DIFFERENT CCRS

In the Baltic CCR, no critical network elements (CNEs) that are important for more than one region were identified. Therefore, all CNEs are handled the same way (equaly) during the capacity calculation process. This ensures that the power-flow capacity is shared fairly and evenly among the different regions. It prevents any region from being favoured over others, promoting transparency and fairness. By using the network effectively, this method ensures that all regions can share resources without risking system reliability or safety.

16

19 RULES ON THE ADJUSTMENT OF POWER FLOWS OF CROSS-ZONAL CAPACITY DUE TO RAS

CCC shall take into account in the capacity calculation RAs as defined in Section 7 to increase the cross-zonal capacity for the long-term time frame. If RAs are agreed during capacity calculation for any long-term timeframe process, TSOs shall ensure availability of agreed RAs or provide alternative RAs to maintain operational security.

20 CROSS-ZONAL CAPACITY VALIDATION METHODOLOGY

20.1. Each TSO shall perform the validation of cross-zonal capacities on its bidding zone border(s) to ensure that the results of regional calculation of cross-zonal capacity will ensure operational security. When performing the validation, the TSOs shall consider operational security, taking into account new and relevant information obtained during or after the most recent capacity calculation.

20.2. According to Article 24 of FCA Regulation and Article 26 of CACM Regulation, each TSO shall validate and have the right to correct long-term cross-zonal capacity relevant to the TSO's bidding zone borders provided by the CCC. If during the initial or after capacity calculation/coordination process a TSO identifies an issue with the capacity calculation results or determines that it needs to make adjustments (e.g., due to updated data, operational constraints, or errors), it has the authority to correct or recalculate these capacities. Once the TSO recalculates or corrects the capacities, it must send the updated values back to the CCC. The CCC then coordinates with relevant parties to ensure these corrected capacities are used appropriately. The TSO must document the reasons for any correction or rejection of the original capacity values (e.g., technical issues, unexpected grid conditions, or operational security concerns). These reasons are shared with the CCC to maintain transparency and support the coordination process.

21 FALLBACK PROCEDURE

If long-term cross-zonal capacities cannot be calculated by CCC, the CCC informs relevant TSOs on inability to calculate capacities. Then relevant TSOs calculate, coordinate capacities and publish for respective Cross-Border Interconnection among themselves as set in accordance with Section 10 and provide coordinated capacities to CCC.

22 PUBLICATION OF DATA

22.1. Calculated long-term capacities shall be published in ENTSO-E Transparency platform as soon as available after calculations for all Baltic CCR borders by TSOs or CCC of Baltic CCR but not later than foreseen according to Article 11 of Regulation 543/2013.

22.2. Long-term capacities calculated according to this methodology and published at ENTSO-E Transparency Platform can be updated at any time before, during and/or after long term transmission rights auctions in case of changes of input data used in calculations (update of calculation input preliminary data e.g. transmission infrastructure outage plans).

23 REPORTING

23.1. According to CACM article 26(5) CCC shall, every three months, report all reductions made during the validation of cross-zonal capacity to all NRAs of the capacity calculation region. This report shall include the location and amount of any reduction in cross-zonal capacity and shall give reasons for the reductions.

23.2. Following article of 24(5) of the FCA regulation, each TSO shall, upon request, provide to their NRAs a report detailing how the value of long-term cross-zonal capacity for a specific time frame has

17

been obtained. Following the objectives of forward capacity allocation, in particular Article 3(f) of the FCA regulation, to complete the objective of “ensuring and enhancing the transparency and reliability of information on forward capacity allocation”, CCC, together with the TSOs will ensure the publication of all relevant data items per calculated scenario used in the capacity calculation.

23.3. Relevant data items shall be counted as the data items outlined in the "list of relevant information to be communicated by ENTSO for Electricity to the Agency,” as stipulated in Article 63(3) of the FCA Regulation. This list, established within six months of the Regulation's entry into force, is created in cooperation with the Agency for the Cooperation of Energy Regulators (hereafter referred to as “Agency”) and may be subject to updates to ensure ongoing relevance and compliance. ENTSO for Electricity must maintain a comprehensive, standardized format and a digital archive for the data required by the Agency.

In alignment with Article 63(3), TSOs are obligated to provide ENTSO-E with the necessary data to

support its tasks. These tasks include ensuring the consistency and accuracy of data for relevant

timeframes such as month-ahead, year-ahead, or additional timelines. The data provided must align

with the requirements of the capacity calculation approach applied in the Baltic region.

24 IMPLEMENTATION OF THE LONG-TERM CCM

24.1. The TSOs shall implement this Long-term CCM latest in 6 months after NRAs approval of the Long-term CCM within the Baltic CCR or a decision has been taken by the Agency in accordance with Article 4(4) and/or Article 4(10) and/or Article 4(11) of the FCA Regulation. 24.2. The Methodology shall be published on web pages of Baltic CCR TSO within 7 days after NRA approval of the Methodology within the Baltic CCR or a decision has been taken by the Agency in accordance with Article 4(13) of the FCA regulation.

24.3. The TSOs shall within 24 months after the implementation of this Methodology perform an evaluation of this Methodology and submit it to the NRAs in the Baltic CCR. If needed, the TSOs shall propose a revised version of the Methodology to the NRAs in the Baltic CCR.

25 LANGUAGE

The reference language for this Long-term CCM shall be English. For the avoidance of doubt, where TSOs need to translate this Long-term CCM into their national language(s), in the event of inconsistencies between the English version published by TSOs in accordance with Article 4(13) of the FCA Regulation and any version in another language, the relevant TSOs shall, in accordance with national legislation, provide the relevant NRAs with an updated translation of the Long-term CCM.

18

ANNEX 1: JUSTIFICATION OF THE METHODOLOGY FOR CALCULATION OF ALLOCATION CONSTRAINTS (ARTICLE 5.5) AND ITS APPLICATION

The following section depicts in detail the justification of usage and methodology currently used by PSE to design and implement allocation constraints, if applicable.

PSE may use an allocation constraint to limit the import and export of the Polish bidding zone.

Rationale behind implementation of allocation constraints on PSE side

Implementation of allocation constraints as applied by PSE side is related to the fact that under the conditions of the integrated scheduling based market model applied in Poland (also called central dispatching model) the responsibility of the Polish TSO on system balance is significantly extended comparing to such standard responsibility of TSOs in so-called self-dispatch market models. Central dispatching is one of the two dispatching models authorized by EB Regulation. In self-dispatch markets BRPs are themselves supposed to take care about their generating reserves and load following, while TSO ensures them just for dealing with contingencies in the time frame of up to one hour ahead. In a central dispatching model, it is the TSO that dispatches generating units taking into account their: operational constraints, transmission constraints and reserve capacity requirements with the aim to balance national generation, demand and cross-border exchanges while ensuring secure operation of the transmission system.

In central dispatching model, the above process is realized in an integrated scheduling process run as a single optimization problem called security constrained unit commitment (SCUC – where generation units are being dispatch on and off) and security constrained economic dispatch (SCED – where generation output for all dispatched generation units is determined).

According to the national legislation, PSE is legally obliged to ensure availability of sufficient level of generating reserves for the whole Polish power system in order to safeguard its secure operation in case of contingency, as well as in case of insufficient and ineffective balancing activities performed by market participants in Poland. However, if balancing service providers (generating units) would already have sold too much energy in the day-ahead market in form of high exports, they may not be able to provide sufficient upward reserve capacity within the integrated scheduling process as required by national legislation. This conclusion equally applies for the case when market participants import significant amount of energy, as it could result in balancing service providers being unable to provide downward regulation capabilities due to not securing enough generation levels in the day- ahead market. The strength of the imbalance settlement pricing is also important in this process, together with the maturity and the ability of the market participants to maintain balanced portfolios under objectively high RES and demand uncertainties and underdeveloped intraday markets.

This leads to implementation of allocation constraints, being the necessary means to ensure operational security of Polish power system in terms of securing generating capacities for upward or downward regulation, as well as in order to cover the national imbalances in the direction of shortage (i.e. cover the residual demand) and surplus (i.e. manage and regulate down the surplus of power during periods of oversupply). Excluding such a solution and depriving TSOs under central dispatching model from the usage of allocation constraints to set appropriate limits to how much electricity can be imported or exported by the system as a whole may lead to insufficient balancing capacity reserves, making the provisions of EB Regulation void, and making it impossible or at least much more difficult to comply with SO Regulation.

It needs to be highlighted that despite implementation of explicit balancing capacity procurement in Poland as per 14 June 2024, and despite maintaining the use of allocation constraints, PSE still has to apply remedial measures at large scale in order to ensure equilibrium between demand and supply in the Polish power system. These measures are mostly the non-market-based curtailment of RES (in case of energy surplus) and emergency exchanges with neighbouring TSOs (in case of energy

19

surplus or shortage). Both aforementioned measures have severe negative consequences, such as difficulties for TSO and DSO dispatching teams to manage hundreds of operational commands issued to dispersed RES facilities in very short time, difficulties of RES facility owners to respond to dispatching commands issued with short notice, as well as depletion of operational reserves of neighbouring TSOs when asked for emergency exchanges, reducing overall European power system resilience. In many instances of time, neighbouring TSOs are unable to provide the requested support.

Balancing market reform executed on 14 June 2024 has significantly improved market price signals, so that balancing responsible parties are better reacting to dynamically changing power system situation. Nonetheless, the observed levels of balancing energy that needs to be activated by PSE under integrated scheduling process is still very high, often exceeding the procured balancing capacity. This implies that the new improved balancing market prices are still unable to convey sufficient incentives for market participants to improve generation and demand planning as BRPs still do not balance their portfolios earlier on more attractive day-ahead and intraday markets. Moreover, new balancing capacity reserves procurement process is still immature and suffers from lack of liquidity, low supply and low competition. Both aforementioned items are a subject of intensive analysis on PSE side with the aim to prepare improvements and increase effectiveness of price signals.

PSE role in system balancing

PSE directly dispatches all major generating units in Poland taking into account their operational characteristics and transmission constraints in order to cover the load forecasted by PSE, having in mind adequate reserve requirements. To fulfil this task PSE runs the process of operational planning, which begins three years ahead with relevant overhaul (maintenance) coordination and is continued via yearly, monthly and weekly updates to day-ahead SCUC and SCED. The results of this day-ahead market are then updated continuously in intraday time frame up to real time operation.

In a yearly time frame PSE tries to distribute the maintenance overhauls requested by generators along the year in such a way that the minimum year ahead generation reserve margin1 over forecasted demand including already allocated capacities on interconnections is kept on average in each month. The monthly and weekly updates aim to keep a certain reserve margin on each day2, if possible. This process includes also network maintenance planning, so any constraints coming from the network operation are duly taken into account.

Determination of allocation constraints in Poland

When determining the allocation constraints, the Polish TSO takes into account the most recent information on the aforementioned technical characteristics of generation units, forecasted power system load as well as minimum reserve margins required in the whole Polish power system to ensure secure operation and forward import/export contracts that need to be respected from previous capacity allocation time frames.

Allocation constraints are bidirectional, with independent values for each MTU, and separately for directions of import to Poland and export from Poland.

For each hour, the constraints are calculated according to the below equation:

1 The generation reserve margin is regulated by the Polish grid code and currently set at 18% (point 10.2.11(3)). It is subject to change depending on the results of the development of operational planning processes.

2 The generation reserve margin for monthly and weekly coordination is also regulated by the Polish grid code (point 10.2.11(2) and (3)).

20

EXPORT = P − (P + P) + P − (P + P) (1)

IMPORT = P − P − P − P (2)

Where:

P Sum of available generating capacities of centrally dispatched units as declared by generators3

P Sum of technical minima of centrally dispatched generating units in operation

P Sum of schedules of generating units that are not centrally dispatched, as provided by generators (for weather-dependent intermittent renewable generation: forecasted by PSE)

P Generation not available due to grid constraints (both planned outage and/or anticipated congestions).

P Generation unavailability’s adjustment resulting from issues not declared by generators, forecasted by PSE due to exceptional circumstances (e.g. cooling conditions or prolonged overhauls)

P Demand forecasted by PSE

P Minimum reserve for up regulation

P Minimum reserve for down regulation

For illustrative purposes, the process of practical determination of allocation constraints in the framework of day-ahead transfer capacity calculation is illustrated below: figures 1 and 2. The figures illustrate how a forecast of the Polish power balance for each hour of the next day is developed by the Polish TSO day ahead in the morning in order to determine reserves in generating capacities available for potential exports and imports, respectively, for day ahead market. For the intraday market, the same method applies mutatis mutandis.

Allocation constraint in export direction is applicable if Export is lower than the sum of transfer capacities on all Polish interconnections in export direction. Allocation constraint in import direction is applicable if Import is lower than the sum of transfer capacities on all Polish interconnections in import direction.

3 Note that generating units which are kept out of the market on the basis of strategic reserve contracts with the TSO are not taken into account in this calculation.

21

1. Sum of available generating capacities of

centrally dispatched units as declared by

generators, reduced by:

1.1 Generation not available due to grid

constraints

1.2 Generation unavailability’s adjustment

resulting from issues not declared by

generators, forecasted by PSE due to

exceptional circumstances (e.g.

cooling conditions or prolonged

overhauls)

2. Sum of schedules of generating units that

are not centrally dispatched, as provided

by generators (for weather-dependent

intermittent renewable generation:

forecasted by PSE)

3. Demand forecasted by PSE

4. Minimum necessary reserve for up

regulation

Figure 1: Determination of allocation constraints in export direction (generating capacities available for potential exports) in the framework of day-ahead transfer capacity calculation.

1 Sum of technical minima of centrally

dispatched generating units in operation

2 Sum of schedules of generating units

that are not centrally dispatched, as

provided by generators (for weather-

dependent intermittent renewable

generation: forecasted by PSE)

3 Demand forecasted by PSE, reduced by:

3.1 Minimum necessary reserve for down

regulation

Figure 2: Determination of allocation constraints in import direction (reserves in generating capacities available for potential imports) in the framework of day-ahead transfer capacity calculation.

Frequency of review

22

Allocation constraints are determined in a continuous process based on the most recent information, for each capacity allocation time frame.

Tatari 39 / 10134 Tallinn / 667 2400 / [email protected] / Registrikood 70000303

OTSUS

25.06.2025 nr 7-26/2025-001

Balti koordineeritud võimsusarvutuse ala põhivõrguettevõtjate metoodika, vastavalt

Komisjoni määruse (EL) 2016/1719, millega kehtestatakse võimsuse jaotamise

forvardturu eeskiri, artikli 10 lõikele 1, kooskõlastamise kohta

1. Haldusmenetluse alustamine

Euroopa Komisjoni määrusega (EL) 2016/1719 kehtestati võimsuse jaotamise forvardturu

eeskiri (edaspidi ka FCA või FCA määrus)1.

FCA artikli 4 lõike 1 alusel töötavad põhivõrguettevõtjad välja FCA määrusega nõutud

tingimused ja meetodid ning esitavad need heakskiitmiseks koostööametile2 või pädevatele

reguleerivatele asutustele vastavalt FCA määruses sätestatud tähtaegadele. Erandlikel

asjaoludel, eelkõige juhul, kui tähtajast ei ole võimalik kinni pidada põhivõrguettevõtjatest

sõltumatute asjaolude tõttu, võib lõike 6 kohaste menetluste puhul tingimuste või meetodite

tähtaegu pikenda koostööamet ning lõike 7 kohaste menetluste puhul võivad seda teha kõik

pädevad reguleerivad asutused ühiselt. Kui käesoleva määruse kohase tingimuste või meetodite

kehtestamise ettepaneku väljatöötamises ja kokkuleppimises peab osalema rohkem kui üks

põhivõrguettevõtja, peavad osalevad põhivõrguettevõtjad tegema tihedat koostööd.

Põhivõrguettevõtjad peavad koostöös Euroopa elektri põhivõrguettevõtjate võrgustikuga

korrapäraselt teavitama pädevaid reguleerivaid asutusi ja koostööametit nimetatud tingimuste

või meetodite väljatöötamise edenemisest.

FCA artikli 4 lõike 5 järgi vastutab iga reguleeriv asutus või vajaduse korral koostööamet artikli

4 lõigetes 6 ja 7 osutatud tingimuste või meetodite heakskiitmise eest. Enne tingimuste ja

meetodite heakskiitmist vaatavad koostööamet või pädevad reguleerivad asutused pärast

asjaomaste põhivõrguettevõtjatega konsulteerimist vajaduse korral ettepanekud läbi, et tagada

nende kooskõla käesoleva määruse eesmärgiga ning aidata kaasa turgude lõimimisele,

mittediskrimineerimisele, tõhusale konkurentsile ja turu nõuetekohasele toimimisele.

FCA artikli 4 lõike 7 punkti a alusel peab võimsuse arvutamise metoodika kooskõlas FCA

artikliga 10 saama kõigi asjaomase piirkonna reguleerivate asutuste heakskiidu.

FCA artikli 4 lõike 9 järgi, kui tingimuste või meetodite heakskiitmiseks vastavalt lõikele 7 või

nende muutmiseks vastavalt lõikele 11 on vaja rohkem kui ühe reguleeriva asutuse otsust,

peavad pädevad reguleerivad asutused kokkuleppele jõudmiseks omavahel konsulteerima,

tegema tihedat koostööd ja kooskõlastama oma tegevuse. Vajaduse korral võtavad pädevad

reguleerivad asutused arvesse koostööameti arvamust. Reguleerivad asutused või vajaduse

1 Kättesaadav: https://eur-lex.europa.eu/legal-content/ET/TXT/?uri=CELEX%3A02016R1719-20210315 2 Energeetikasektorit Reguleerivate Asutuste Koostöö Amet (ingl Agency for the Cooperation of Energy

Regulators ehk ACER)

2 (5)

korral koostööamet teevad lõigete 6 ja 7 kohaselt esitatud tingimuste ja meetodite kohta otsuse

kuue kuu jooksul alates sellest, kui koostööamet või asjakohasel juhul viimane asjaomane

reguleeriv asutus on tingimused või meetodid kätte saanud. Ajavahemik algab järgmisel päeval

pärast seda, kui ettepanek esitati koostööametile vastavalt lõikele 6 või viimasele asjaomasele

reguleerivale asutusele vastavalt lõikele 7.

FCA artikli 4 lõike 11 alusel, kui koostööamet või kõik pädevad reguleerivad asutused ühiselt

nõuavad lõigete 6 ja 7 kohaselt esitatud tingimuste või meetodite muutmist enne nende

heakskiitmist, peavad asjaomased põhivõrguettevõtjad esitama muudetud tingimuste või

meetodite ettepaneku heakskiitmiseks kahe kuu jooksul alates koostööameti või reguleerivate

asutuste sellekohase taotluse esitamisest. Koostööamet või pädevad reguleerivad asutused

teevad muudetud tingimuste või meetodite kohta otsuse kahe kuu jooksul pärast nende

esitamist. Kui pädevad reguleerivad asutused ei ole jõudnud kokkuleppele lõikes 7 osutatud

tingimuste või meetodite osas kahe kuu pikkuse tähtaja jooksul või nende ühise taotluse korral

või koostööameti taotlusel vastavalt määruse (EL) 2019/942 artikli 5 lõike 3 kolmandale

lõigule, võtab koostööamet kuue kuu jooksul vastavalt määruse (EL) 2019/942 artikli 5 lõikele

3 ja artikli 6 lõike 10 teisele lõigule vastu otsuse muudetud tingimuste või meetodite kohta. Kui

asjaomased põhivõrguettevõtjad ei esita tingimuste või meetodite muutmise ettepanekut,

kohaldatakse lõikes 4 kirjeldatud menetlust.

FCA artikli 4 lõike 13 alusel FCA määruse kohaste tingimuste ja meetodite väljatöötamise eest

vastutavad põhivõrguettevõtjad avaldavad need tingimused ja meetodid internetis pärast nende

heakskiitmist ameti või pädevate reguleerivate asutuste poolt, või kui heakskiitu ei ole vaja, siis

pärast nende tingimuste ja meetodite väljatöötamist, välja arvatud juhul, kui selline teave on

artikli 7 kohaselt konfidentsiaalne.

FCA artikli 10 lõike 1 järgi peavad hiljemalt kuus kuud pärast ühise kooskõlastatud võimsuse

arvutamise metoodika heakskiitmist, määruse (EL) 2015/1222 (edaspidi ka CACM või CACM

määrus)3 artikli 9 lõike 7 kohaselt, iga võimsusarvutuse ala kõik põhivõrguettevõtjad esitama

ühise võimsuse arvutamise metoodika ettepaneku pikkade ajavahemike jaoks asjaomases alas.

Ettepaneku üle tuleb pidada konsultatsioone kooskõlas artikliga 6.

FCA artikli 10 lõike 2 järgi tuleb võimsuse ühise arvutamise meetodina kasutada kas

koordineeritud netoülekandevõimsusel põhinevat meetodit või voopõhist meetodit.

FCA artikli 10 lõike 3 järgi peab võimsuse arvutamise meetod olema kooskõlas võimsuse

arvutamise meetodiga, mis on kehtestatud järgmise päeva turu ja päevasisese turu ajavahemike

jaoks CACM artikli 21 lõike 1 kohaselt.

FCA artikli 10 lõike 4 alusel tuleb võimsuse arvutamisel pikkade ajavahemike jaoks arvestada

määramatust järgmiselt:

a) seoses mitme stsenaariumi põhjal tehtava talitluskindluse analüüsiga, milles

kasutatakse võimsusarvutuse sisendandmeid, võimsusarvutusmeetodit, millele on

osutatud artikli 21 lõike 1 punktis b ning piirkonnaülese võimsuse valideerimismeetodit,

millele on osutatud CACM artikli 21 lõike 1 punktis c; või

b) seoses statistilise käsitlusega, mis põhineb varasemal piirkonnaülesel võimsusel

järgmise päeva turu või päevasisese turu ajavahemikes, kui on võimalik tõendada, et

selle käsitlusega võib:

i) tõhustada võimsuse arvutamise metoodikat;

3 Kättesaadav: https://eur-lex.europa.eu/legal-content/ET/TXT/?uri=CELEX%3A02015R1222-20210315

3 (5)

ii) paremini arvesse võtta määramatust piirkonnaülese võimsuse arvutamisel pikkade

ajavahemike jaoks kui talitluskindluse analüüsiga vastavalt lõike 4 punktile a;

iii) suurendada majanduslikku tasuvust, säilitades sama talitluskindluse.

FCA artikli 10 lõike 7 järgi tuleb võimsuse arvutamise metoodika väljatöötamisel võtta arvesse

varumeetmete nõudeid ja CACM artikli 21 lõikes 3 sätestatud nõuet.

Haldusmenetluse seaduse (HMS) § 14 lõike 1 järgi esitatakse haldusmenetluse algatamiseks

haldusorganile vabas vormis avaldus (taotlus).

2. Menetlusosaline

Elering AS, äriregistri kood 11022625, asukoht Kadaka tee 42, Tallinn, 12915, e-post:

[email protected].

3. Asjaolud ja menetluse käik

16.05.2024 esitas Elering AS (edaspidi Elering) Konkurentsiametile kooskõlastamiseks Balti

koordineeritud võimsusarvutuse ala4 põhivõrguettevõtjate (edaspidi ka põhivõrguettevõtjad)

ühise võimsuse arvutamise metoodika ettepaneku pikkade ajavahemike jaoks Balti

koordineeritud võimsusarvutuse alas, kooskõlas FCA artikli 10 lõikega 1 (metoodika). Viimane

asjaomane riiklik reguleeriv asutus sai metoodika ettepaneku kätte 21.05.2024.

Põhivõrguettevõtjad on kooskõlas FCA artikliga 6 metoodika ettepanekut koos selgitava

dokumendiga avalikult konsulteerinud Euroopa põhivõrguettevõtjate koostööorganisatsiooni

(ENTSO-E) konsultatsioonikeskkonnas perioodil 05.03.2024 kuni 05.04.2024.5

20.11.2024 jõudsid kõik asjaomased riiklikud reguleerivad asutused kokkuleppele taotleda

metoodika ettepaneku muutmist FCA artikli 4 lõike 11 alusel. Kooskõlas FCA artikli 4 lõikega

9 konsulteerisid asjaomased riiklikud reguleerivad asutused omavahel, tegid tihedat koostööd

ja kooskõlastasid oma tegevust, et jõuda Metoodika kooskõlastamise asjus kokkuleppele.

20.11.2024 edastas Konkurentsiamet Eleringile kirja muudatusnõuete kohta.

17.01.2025 esitasid põhivõrguettevõtjad ühiselt asjaomastele riiklikele reguleerivatele

asutustele muudetud metoodika ettepaneku, mis oli ühiselt heakskiidetud kõikide Balti

koordineeritud võimsusarvutuse ala põhivõrguettevõtjate poolt.

22.01.2025 esitas Elering Konkurentsiametile ka eraldi taotluse eelnimetatud muudetud

metoodika ettepaneku kooskõlastamiseks. Viimane asjaomane riiklik reguleeriv asutus sai

metoodika ettepaneku kätte 22.01.2025.

Balti koordineeritud võimsusarvutuse ala riiklikud reguleerivad asutused jõudsid ühisele

seisukohale, et muudetud metoodikas esineb endiselt lahendamata küsimusi ning otsustati

ühiselt taotleda ACERilt 3-kuulist pikendust metoodika kooskõlastamistähtajale Euroopa

Parlamendi ja nõukogu määruse (EL) 2019/942 (ACERi määrus) artikli 6 lõike 10 alusel.

4 Balti koordineeritud võimsusarvutuse alasse kuuluvad Eesti, Läti, Leedu, Poola, Soome ja Rootsi. 5 Kättesaadav: https://consultations.entsoe.eu/markets/baltic-ltcc-methodology/

4 (5)

ACERi 23.06.2025 otsusega nr 04/20256, pikendati kooskõlastamisperioodi 3 kuu võrra, mille

järgi peavad asjaomased riiklikud reguleerivad asutused jõudma kokkuleppele metoodika

kooskõlastamise asjus hiljemalt 24.06.2025.

12.06.2025 toimus kohtumine Balti koordineeritud võimsusarvutuse ala riiklike reguleerivate

asutuste ja põhivõrguettevõtjate vahel, et konsulteerida asjaomaste põhivõrguettevõtjatega Balti

riiklike reguleerivate asutuste poolt tehtavaid muudatusi metoodika ettepanekus. Eelnimetatud

muudatused käsitlevad mh tugimeetmetega seonduva täpsustamist, jaotamispiirangute

tingimusi, Balti piirkondliku koordineerimiskeskuse ülesannetega seonduvat ning läbipaistvuse

parandamist turuosalistele avaldatava teabe osas. Detailsem muudatuste sisu on välja toodud

Balti koordineeritud võimsusarvutuse ala riiklike reguleerivate asutuste ühise seisukoha punktis

3 (Lisa 2).

17.06.2025 konsulteerisid Balti koordineeritud võimsusarvutuse ala riiklikud reguleerivad

asutused asjaomaste põhivõrguettevõtjatega e-kirja vahendusel muudetud kujul metoodika

ettepanekut.

23.06.2025 kiitsid asjaomased riiklikud reguleerivad asutused ühiselt Balti koordineeritud

võimsusarvutuse ala põhivõrguettevõtjate metoodika ettepaneku muudetud kujul heaks (Lisa

2).

4. Asjaomaste reguleerivate asutuste ühine seisukoht

Balti koordineeritud võimsusarvutuse ala riiklikud reguleerivad asutused on hinnanud

põhivõrguettevõtjate esitatud metoodika ettepanekut ning otsustasid enne metoodika

ettepaneku kooskõlastamist muuta metoodikat, FCA artikli 4 lõike 5 ja ACERi määruse artikli

5 lõike 6 alusel, et tagada metoodika ettepaneku kooskõla FCA ning CACM määrustega. Balti

koordineeritud võimsusarvutuse ala riiklike reguleerivate asutuste tehtud muudatused

metoodika ettepanekus puudutavad mh tugimeetmetega seonduva täpsustamist,

jaotamispiirangute tingimusi, Balti piirkondliku koordineerimiskeskuse ülesannetega

seonduvat ning läbipaistvuse parandamist turuosalistele avaldatava teabe osas. Detailsemalt on

muudatuste sisu välja toodud Balti koordineeritud võimsusarvutuse ala riiklike reguleerivate

asutuste ühise seisukoha punktis 3 (Lisa 2).

Kokkuvõte

Konkurentsiamet töötas läbi 22.01.2025 Eleringi poolt ametile kooskõlastamiseks esitatud Balti

koordineeritud võimsusarvutuse ala põhivõrguettevõtjate ühise võimsuse arvutamise

metoodika ettepaneku pikkade ajavahemike jaoks Balti koordineeritud võimsusarvutuse alas,

kooskõlas FCA artikli 10 lõikega 1, ning asub seisukohale, et pärast Balti koordineeritud

võimsusarvutuse ala riiklike reguleerivate asutuste ühiselt sisse viidud muudatusi, arvestab

nimetatud dokument kehtivast seadusandlusest tulenevate alusetega ning ei ole vastuolus

FCAst tuleneva regulatsiooniga.

FCA artikli 4 lõike 13 alusel FCA määruse kohaste tingimuste ja meetodite väljatöötamise eest

vastutavad põhivõrguettevõtjad avaldavad need tingimused ja meetodid internetis pärast nende

heakskiitmist ameti või pädevate reguleerivate asutuste poolt, või kui heakskiitu ei ole vaja, siis

6 Kättesaadav: https://www.acer.europa.eu/sites/default/files/documents/Individual%20Decisions/ACER-

Decision-04-2025-Baltic-NRAs-extension-request.pdf

5 (5)

pärast nende tingimuste ja meetodite väljatöötamist, välja arvatud juhul, kui selline teave on

artikli 7 kohaselt konfidentsiaalne.

Arvestades eeltoodut ja tuginedes FCA artikli 4 lõikele 7 punktile a)

otsustan:

kooskõlastada Balti koordineeritud võimsusarvutuse ala põhivõrguettevõtjate ühine võimsuse

arvutamise metoodika ettepanek pikkade ajavahemike jaoks Balti koordineeritud

võimsusarvutuse alas, kooskõlas Komisjoni määruse (EL) 2016/1719, 26. september 2016,

millega kehtestatakse võimsuse jaotamise forvardturu eeskiri, artikli 10 lõikega 1.

Käesoleva otsusega mittenõustumise korral on õigus esitada kaebus otsuse tühistamiseks

Tallinna Halduskohtule. Kaebuse halduskohtule võib esitada 30 päeva jooksul arvates

käesoleva otsuse teatavaks tegemisest.

(allkirjastatud digitaalselt)

Evelin Pärn-Lee

peadirektor

Lisad:

1. All Baltic CCR TSOs’ Common Capacity Calculation Methodology for Long-term

Time Frames in Accordance with Article 10(1) of the Commission Regulation (EU)

2016/1719 of 26 September 2016 Establishing a Guideline on Forward Capacity

Allocation

2. POSITION PAPER BY ALL BALTIC CAPACITY CALCULATION REGION

NATIONAL REGULATORY AUTHORITIES on All Baltic CCR TSOs’ Common

Capacity Calculation Methodology for Long-term Time Frames in Accordance with

Article 10(1) of the Commission Regulation (EU) 2016/1719 of 26 September 2016

Establishing a Guideline on Forward Capacity Allocation

Armin Ilisson

[email protected]

POSITION PAPER BY ALL BALTIC CAPACITY

CALCULATION REGION NATIONAL REGULATORY

AUTHORITIES

on

All Baltic CCR TSOs’ Common Capacity Calculation

Methodology for Long-term Time Frames in Accordance

with Article 10(1) of the Commission Regulation (EU)

2016/1719 of 26 September 2016 Establishing a

Guideline on Forward Capacity Allocation

23 June 2025

2

1. INTRODUCTION AND LEGAL CONTEXT

This document elaborates an agreement of all Baltic Capacity Calculation Region (hereinafter ‘CCR) National

Regulatory Authorities (hereinafter: “Baltic NRAs”), agreed on 23 June 2025, on all Baltic CCR Transmission

System Operators’ (hereinafter: “Baltic TSOs”) proposal on Common Capacity Calculation Methodology for

Long-term Time Frames in Accordance with Article 10(1) of the Commission Regulation (EU) 2016/1719 of 26

September 2016 Establishing a Guideline on Forward Capacity Allocation (hereinafter: “FCA Regulation”).

All Baltic TSOs submitted Common Capacity Calculation Methodology for Long-term Time Frames (hereinafter

also ‘Methodology’), in accordance with Article 10(1) of the FCA Regulation and the last concerned NRA

received the proposal on 21 May 2024.

Article 4(9) of the FCA Regulation requires Baltic NRAs to consult and closely cooperate and coordinate with

each other in order to reach an agreement and take a decision within six months following receipt of submission

of the proposal to the last Baltic NRA..

This agreement of the Baltic NRAs shall provide evidence that Common Capacity Calculation Methodology for

Long-term Time Frames, does not, at this stage, need to be adopted by the Agency for the Cooperation of

Energy Regulators (hereinafter ACER/ the Agency) pursuant to Article 4(10) of the FCA Regulation. It is

intended to constitute the basis on which the Baltic NRAs will each subsequently issue a national decision to

approve the Common Capacity Calculation Methodology for Long-term Time Frames, pursuant to Article 4(9)

of the FCA Regulation.

The legal provisions that lie at the basis of the Common Capacity Calculation Methodology for Long-term Time

Frames, and this Baltic NRAs’ agreement on the methodology can be found in Articles 3,4 and 10 of the FCA

Regulation, and in Article 5 of the Regulation (EU) 2019/942 of the European Parliament and of the Council of

5 June 2019 establishing a European Union Agency for the Cooperation of Energy Regulators (hereinafter:

‘ACER Regulation’). These articles are set out below for reference.

1.1 FCA Regulation

Article 3

Objectives of forward capacity allocation

This Regulation aims at:

(a) promoting effective long-term cross-zonal trade with long-term cross-zonal hedging opportunities for

market participants;

(b) optimising the calculation and allocation of long-term cross-zonal capacity;

(c) providing non-discriminatory access to long-term cross-zonal capacity;

(d) ensuring fair and non-discriminatory treatment of TSOs, the Agency, regulatory authorities and market

participants;

(e) respecting the need for a fair and orderly forward capacity allocation and orderly price formation;

(f) ensuring and enhancing the transparency and reliability of information on forward capacity allocation;

(g) contributing to the efficient long-term operation and development of the electricity transmission system and

electricity sector in the Union.

Article 4

Adoption of terms and conditions or methodologies (…)

3

1. TSOs shall develop the terms and conditions or methodologies required by this Regulation and submit them for approval to the Agency or the competent regulatory authorities within the respective deadlines set out in this Regulation. In exceptional circumstances, notably in cases where a deadline cannot be met due to circumstances external to the sphere of TSOs, the deadlines for terms and conditions or methodologies may be prolonged by the Agency in procedures pursuant to paragraph 6, and jointly by all competent regulatory authorities in procedures pursuant to paragraph 7. Where a proposal for terms and conditions or methodologies pursuant to this Regulation needs to be developed and agreed by more than one TSO, the participating TSOs shall closely cooperate. TSOs, with the assistance of the ENTSO for Electricity, shall regularly inform the competent regulatory authorities and the Agency about the progress of the development of those terms and conditions or methodologies.

2. (…)

3. (…)

4. (…)

5. Each regulatory authority or where applicable the Agency, as the case may be, shall be responsible for approving the terms and conditions or methodologies referred to in paragraphs 6 and 7. Before approving the terms and conditions or methodologies, the Agency or the competent regulatory authorities shall revise the proposals where necessary, after consulting the respective TSOs, in order to ensure that they are in line with the purpose of this Regulation and contribute to market integration, non-discrimination, effective competition and the proper functioning of the market.

6. (…)

7. The proposals for the following terms and conditions or methodologies and any amendments thereof shall be subject to approval by all regulatory authorities of the concerned region:

a) the capacity calculation methodology pursuant to Article 10; (b) (…)

(c) (…)

(d) (…)

(e) (…)

8. (…)

.

9. Where the approval of the terms and conditions or methodologies in accordance with paragraph 7 or the amendment in accordance with paragraph 11 requires a decision by more than one regulatory authority, the competent regulatory authorities shall consult and closely cooperate and coordinate with each other in order to reach an agreement. Where applicable, the competent regulatory authorities shall take into account the opinion of the Agency. Regulatory authorities or, where competent, the Agency shall take decisions concerning the submitted terms and conditions or methodologies in accordance with paragraphs 6 and 7, within 6 months following the receipt of the terms and conditions or methodologies by the Agency or, where applicable, by the last regulatory authority concerned. The period shall begin on the day following that on which the proposal was submitted to the Agency in accordance with paragraph 6 or to the last regulatory authority concerned in accordance with paragraph 7.

10.(...)

11.(...)

12. The Agency or the regulatory authorities jointly, where they are responsible for the adoption of terms and conditions or methodologies in accordance with paragraphs 6 and 7, may respectively request proposals for amendments of those terms and conditions or methodologies and determine a deadline for the submission of those proposals. TSOs responsible for developing a proposal for terms and conditions or methodologies may propose amendments to regulatory authorities and the Agency.

The proposals for amendment to the terms and conditions or methodologies shall be submitted to consultation in accordance with the procedure set out in Article 6 and approved in accordance with the procedure set out in this Article.

13.(...) TSOs responsible for establishing the terms and conditions or methodologies in accordance with this Regulation shall publish them on the internet after approval by the Agency or the competent regulatory

4

authorities or, if no such approval is required, after their establishment, except where such information is considered as confidential in accordance with Article 7.

Article 10

Capacity calculation methodology

1. No later than six months after the approval of the common coordinated capacity calculation methodology

referred to in Article 9(7) of Regulation (EU) 2015/1222, all TSOs in each capacity calculation region shall

submit a proposal for a common capacity calculation methodology for long-term time frames within the

respective region. The proposal shall be subject to consultation in accordance with Article 6.

2. The approach used in the common capacity calculation methodology shall be either a coordinated net

transmission capacity approach or a flow-based approach.

3. The capacity calculation methodology shall be compatible with the capacity calculation methodology

established for the day-ahead and intraday time frames pursuant to Article 21(1) of Regulation (EU) 2015/1222.

4. The uncertainty associated with long-term capacity calculation time frames shall be taken into account when

applying:

a). a security analysis based on multiple scenarios and using the capacity calculation inputs, the capacity

calculation approach referred to in Article 21(1)(b) and the validation of cross-zonal capacity referred to in

Article 21(1)(c) of Regulation (EU) 2015/1222; or

b). a statistical approach based on historical cross-zonal capacity for day-ahead or intraday time frames if it

can be demonstrated that this approach may:

(i) increase the efficiency of the capacity calculation methodology;

(ii) better take into account the uncertainties in long-term cross-zonal capacity calculation than the security

analysis in accordance with paragraph 4(a);

(iii)increase economic efficiency with the same level of system security.

5. All TSOs in each capacity calculation region may jointly apply the flow-based approach for long-term

capacity calculation time frames on the following conditions:

(a) the flow-based approach leads to an increase of economic efficiency in the capacity calculation region with

the same level of system security;

(b) the transparency and accuracy of the flow-based results have been confirmed in the capacity calculation

region;

(c) the TSOs provide market participants with six months to adapt their processes.

6. Where a security analysis based on multiple scenarios is applied for developing the capacity calculation

methodology in a capacity calculation region, the requirements for the capacity calculation inputs, the capacity

calculation approach and the validation of cross-zonal capacity as provided for in Article 21(1) of Regulation

(EU) 2015/1222, except Article 21(1)(a)(iv) where relevant, shall apply.

7. When developing the capacity calculation methodology, the requirements for the fallback procedures and

the requirement provided for in Article 21(3) of Regulation (EU) 2015/1222 shall be taken into account.

1.2 ACER Regulation

Article 5

Tasks of ACER as regards the development and implementation of network codes and guidelines

(…)

3. Where one of the following legal acts provides for the development of proposals for terms and conditions

or methodologies for the implementation of network codes and guidelines which require the approval of all the

5

regulatory authorities of the region concerned, those regulatory authorities shall agree unanimously on the

common terms and conditions or methodologies to be approved by each of those regulatory authorities:

(a) a legislative act of the Union adopted under the ordinary legislative procedure;

(b) network codes and guidelines that were adopted before 4 July 2019 and subsequent revisions of those

network codes and guidelines; or

(c) network codes and guidelines adopted as implementing acts pursuant to Article 5 of Regulation (EU) No

182/2011.

(…)

6. Before approving the terms and conditions or methodologies referred to in paragraphs 2 and 3, the

regulatory authorities, or, where competent, ACER, shall revise them where necessary, after consulting the

ENTSO for Electricity, the ENTSO for Gas or the EU DSO entity, in order to ensure that they are in line with

the purpose of the network code or guideline and contribute to market integration, non-discrimination, effective

competition and the proper functioning of the market. ACER shall take a decision on the approval within the

period specified in the relevant network codes and guidelines. That period shall begin on the day following that

on which the proposal was referred to ACER.

2. The Baltic TSOs’ proposal

Previous Methodology proposal was rejected by ACER Decision No 27/20201 where ACER request the Baltic

TSOs to resubmit a new one at the latest 24 months after its decision. The main reason for this rejection was

that ACER was not able to revise the Baltic TSOs' proposal to make it compliant with the FCA Regulation given

the number and complexity of issues related to the upcoming synchronization of the Baltic synchronous area

with the Continental synchronous area.

Before the final submission of the documents for Baltic NRAs approval, Baltic TSOs consulted the Common

Capacity Calculation Methodology for Long-term Time Frames from 5 March 2024 to 5 April 20242, fulfilling

the obligation set out in Article 13(1) of the FCA Regulation that the consultation shall last for a period of no

less than one month

The proposal by the Baltic TSOs for a Common Capacity Calculation Methodology for Long-term Time Frames

together with explanatory document were received by the last Baltic NRA on 21 May 2024. The Baltic NRAs

unanimously agreed to issue a request for amendment (RfA). On 22 January 2025 the last Baltic NRA received

the amended Methodology from their respective TSO(s). Accordingly, the two-month deadline for approval

was 23 March 2025.

As the Baltic NRAs were of the position that some important issues remained unresolved in the amended

Methodology, they therefore unanimously agreed to jointly request the Agency to grant a 3-month extension

according to Article 6(10) of ACER Regulation.

1 https://www.acer.europa.eu/sites/default/files/documents/Individual%20Decisions/ACER%20Decision%2027- 2020%20on%20Baltic%20LT%20CCM_0.pdf 2 https://consultations.entsoe.eu/markets/baltic-ltcc-methodology/

6

The Agency issued decision extending the period by 3 months. Therefore, the Baltic NRAs should reach an

agreement on the Common Capacity Calculation Methodology for Long-term Time Frames, before 24 June

2025.

3. The Baltic NRAs’ position

The Baltic NRAs have analysed the Common Capacity Calculation Methodology for Long-term Time Frames

and concluded that some elements of the methodology require further changes and development or were not

sufficiently clear. The main proposed changes to the Common Capacity Calculation Methodology for Long-

term Time Frames are listed below:

• The provisions for using the allocation constraints in Article 5 of the Methodology have been

changed, and the use of allocation constraints has been made dependent on the need for their

use within the Capacity Calculation Methodology established for the day-ahead and intraday

time frames pursuant to Article 21(1) of Regulation (EU) 2015/1222. In addition, if the Baltic

TSOs want to continue to use the allocation constraint after two years, they have to submit a

proposal for amendment and fulfil the provisions tied to it.

• The Baltic NRAs included provisions in Article 5(8) of this Methodology pursuant to Article

27(4) of Regulation (EU) 2015/122 and Article 3(f) of the FCA Regulation.

• The Baltic NRAs have incorporated costly remedial actions in Article 7 of the Methodology to

align it with Article 25(6) of the CACM Regulation. This article stipulates that each TSO must

ensure that the remedial actions considered in capacity calculation are consistent across all

capacity calculation timeframes and the Common Capacity Calculation Methodology for day-

ahead and intraday timeframes foresees the use of both costly and not costly remedial actions.

• The Baltic TSOs agreed to add in explanatory document justifications why in Articles 13.1 and

13.2 of the Methodology Baltic TSOs will publish results to market participants and

transparency platform in different dates depending on the borders and why in Article 14.2. of

the Methodology the yearly Common Grid Model (CGM) is used for capacity calculation for

the month-ahead timeframe. Due to this, there was no need to adapt the Methodology.

• The Baltic NRAs have deleted a provision in Article 17.1 of the Methodology that outlined next

steps in case the Baltic TSOs failed to fulfil the obligation specified in Article 16(8) of

Regulation 2019/943. This deletion was made as it was considered to be not in line with the

content of the Article 16(8) Regulation 2019/943.

• The Baltic NRAs amended Article 24.3 in order to make it aligned with the CACM Regulation.

In addition, the Baltic NRAs included a point which states that the Baltic TSOs shall within 24

months after the implementation of the Common Capacity Calculation Methodology for Long-

term Time Frames perform an evaluation of the Methodology and submit it to the Baltic NRAs.

• The Baltic NRAs updated the Annex 1 (“Justification of the Methodology for Calculation of

Allocation Constraints (Article 5) and Its Application”) to address reserve procurement in the

context of Poland’s balancing-market reform.

• The Baltic NRAs also agreed on some minor wording and clarification edits.

The Baltic NRAs decided to introduce those changes themselves in accordance with Article 5(6) of ACER

Regulation and Article 4(5) of the FCA regulation. The way forward was discussed during several dedicated

meetings among the Baltic NRAs including one with the Baltic TSOs on 12 June 2025. The draft version of the

revised Common Capacity Calculation Methodology for Long-term Time frames, was consulted with the Baltic

TSOs’ representatives starting on 17 June 2025. The Baltic TSOs confirmed the draft consolidated version

and the improvements made by the Baltic NRAs on 20 June 2025.

7

The Baltic TSOs confirmed the draft consolidated version and the improvements made by the Baltic NRAs on

20 June 2025 however they indicated that they do not agree with the addition to Article. 7.1 of the Methodology

costly remedial actions and additional provisions on allocation constrains stated in Article 5.6 of the

Methodology. The Baltic TSOs also informed that no additional comments will be provided to NRAs, therefore

consultation could be considered as finished. The Baltic NRAs decided not to take into the account the

comments of the Baltic TSOs at this stage and stated that they are open to discussion on the above issues in

the future.

4. Conclusions

The Baltic NRAs have consulted, closely cooperated and coordinated to jointly agree that they shall revise the

proposal of the Baltic Common Capacity Calculation Methodology for Long-term Time Frames with the

modifications as presented in the document attached to this position paper before approving it. The legal basis

for the direct amendments by Baltic NRAs lies in Article 5(6) of the ACER Regulation and in Article 4(5) of the

FCA Regulation.

Baltic NRAs will issue their national decisions to approve the revised the Baltic Common Capacity Calculation

Methodology for Long-term Time Frames, on the basis of this agreement.

5. Annex

All Baltic CCR TSOs’ Common Capacity Calculation Methodology for Long-term Time Frames in Accordance

with Article 10(1) of the Commission Regulation (EU) 2016/1719 of 26 September 2016 Establishing a

Guideline on Forward Capacity Allocation (clean and with track changes).