Otsus

OTSUS

27.11.2024 nr 7-26/2024-007

Balti koordineeritud võimsusarvutuse ala põhivõrguettevõtjate metoodika, vastavalt

Komisjoni määruse (EL) 2015/1222, millega kehtestatakse võimsuse jaotamise ja

ülekoormuse juhtimise suunised, artikkel 20 lõikele 2, kooskõlastamise kohta

1. Haldusmenetluse alustamine

Elektrituruseaduse (edaspidi ELTS) § 93 lõige 6 punkti 1 kohaselt kontrollib Konkurentsiamet

Euroopa Parlamendi ja nõukogu määruses (EL) 2019/943 ning selle alusel kehtestatud

komisjoni määrustes sätestatud tingimuste täitmist.

ELTS § 93 lõige 6 punkti 6 kohaselt Konkurentsiamet väljastab ELTS-is sätestatud juhul

kooskõlastamise otsuseid.

Euroopa Komisjoni Määrusega (EL) 2015/1222 kehtestati võimsuse jaotamise ja ülekoormuse

juhtimise suunised (edaspidi ka CACM või CACM määrus)1.

CACM artikkel 9 lõike 1 kohaselt töötavad põhivõrguettevõtjad ja määratud

elektriturukorraldajad välja CACM määrusega nõutud tingimused ja meetodid ning esitavad

need heakskiitmiseks koostööametile või pädevale reguleerivale asutusele vastavalt CACM

määruses sätestatud tähtaegadele. Erandlikel asjaoludel, eelkõige juhul, kui tähtajast ei ole

võimalik kinni pidada põhivõrguettevõtjatest või määratud elektriturukorraldajatest sõltumatute

asjaolude tõttu, võib tingimuste või meetodite tähtaegu pikenda lõike 6 kohaste menetluste

puhul koostööamet, lõike 7 kohaste menetluste puhul võivad seda teha kõik pädevad

reguleerivad asutused ühiselt ja lõike 8 kohaste menetluste puhul võib seda teha pädev

reguleeriv asutus.

Kui CACM määruse kohase tingimuste ja meetodite kehtestamise ettepaneku väljatöötamises

ja kokkuleppimises peab osalema rohkem kui üks põhivõrguettevõtja või määratud

elektriturukorraldaja, teevad osalevad põhivõrguettevõtjad ja määratud elektriturukorraldajad

tihedat koostööd. Põhivõrguettevõtjad peavad koostöös Euroopa elektri põhivõrguettevõtjate

võrgustiku (edaspidi ka ENTSO-E) ja kõigi määratud elektriturukorraldajatega korrapäraselt

teavitama pädevaid reguleerivaid asutusi ja koostööametit nimetatud tingimuste ja meetodite

väljatöötamise edenemisest.

CACM artikkel 9 lõike 5 kohaselt peab iga reguleeriv asutus või vajaduse korral koostööamet

heaks kiitma põhivõrguettevõtjate ja määratud elektriturukorraldajate poolt ühtse järgmise

päeva turu ja päevasisese turu mehhanismi arvutamiseks või rakendamiseks välja töötatud

tingimused ja meetodid. Nad vastutavad lõigetes 6, 7 ja 8 nimetatud tingimuste ja meetodite

heakskiitmise eest. Enne tingimuste ja meetodite heakskiitmist vaatavad koostööamet või

1 Kättesaadav: https://eur-lex.europa.eu/legal-content/ET/TXT/HTML/?uri=CELEX:02015R1222-20210315

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pädevad reguleerivad asutused pärast asjaomaste põhivõrguettevõtjate või määratud

elektriturukorraldajatega konsulteerimist vajaduse korral ettepanekud läbi, et tagada nende

kooskõla käesoleva määruse eesmärgiga ning aidata kaasa turgude lõimimisele,

mittediskrimineerimisele, tõhusale konkurentsile ja turu nõuetekohasele toimimisele.

CACM artikkel 9 lõige 7 punkti a) kohaselt peab ühine võimsusarvutusmeetod kooskõlas

artikkel 20 lõikega 2 saama kõigi asjaomase piirkonna reguleerivate asutuste heakskiidu.

CACM artikkel 9 lõike 10 kohaselt kui tingimuste või meetodite heakskiitmiseks vastavalt

lõikele 7 või nende muutmiseks vastavalt lõikele 12 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 korral koostööamet peavad lõigete 6, 7 ja 8 kohaselt esitatud tingimuste ja

meetodite kohta tegema otsused kuue kuu jooksul pärast seda, kui koostööamet või reguleeriv

asutus 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, viimasele asjaomasele reguleerivale asutusele vastavalt

lõikele 7 või vajaduse korral reguleerivale asutusele vastavalt lõikele 8.

CACM artikkel 9 lõike 11 kohaselt kui reguleerivad asutused ei ole jõudnud kokkuleppele

lõikes 10 osutatud ajavahemiku jooksul või nende ühise taotluse korral või koostööameti

taotlusel vastavalt määruse (EL) 2019/942 artikkel 5 lõike 3 kolmandale lõigule, võtab

koostööamet kuue kuu jooksul vastavalt määruse (EL) 2019/942 artikkel 5 lõikele 3 ja artikkel

6 lõike 10 teisele lõigule vastu otsuse tingimuste või meetodite ettepanekute kohta.

CACM artikkel 9 lõike 12 kohaselt kui koostööamet või kõik pädevad reguleerivad asutused

ühiselt või pädev reguleeriv asutus nõuab vastavalt lõigete 6, 7 ja 8 kohaselt esitatud tingimuste

või meetodite muutmist enne nende heakskiitmist, peavad asjaomased põhivõrguettevõtjad või

määratud elektriturukorraldajad esitama muudetud tingimuste või meetodite ettepaneku

heakskiitmiseks kahe kuu jooksul alates koostööameti või pädevate reguleerivate asutuste või

pädeva reguleeriva asutuse taotluse saamisest. Amet või pädevad reguleerivad asutused või

pädev reguleeriv asutus teevad muudetud tingimuste või meetodite kohta otsuse kahe kuu

jooksul alates nende esitamisest. 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

artikkel 5 lõike 3 kolmandale lõigule, võtab koostööamet kuue kuu jooksul vastavalt määruse

(EL) 2019/942 artikkel 5 lõikele 3 ja artikkel 6 lõike 10 teisele lõigule vastu otsuse muudetud

tingimuste või meetodite kohta. Kui asjaomased põhivõrguettevõtjad või määratud

elektriturukorraldajad ei esita tingimuste ja meetodite muutmise ettepanekut, kohaldatakse

artikkel 9 lõikes 4 kirjeldatud menetlust.

CACM artikkel 9 lõike 14 kohaselt CACM määruse kohaste tingimuste ja meetodite

väljatöötamise eest vastutavad põhivõrguettevõtjad ja määratud elektriturukorraldajad peavad

avaldama 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 13 kohaselt

konfidentsiaalne.

CACM artikkel 20 lõike 2 kohaselt peavad kõik koordineeritud võimsusarvutuse ala

põhivõrguettevõtjad esitama ühise koordineeritud võimsusarvutuse meetodi ettepaneku

võimsusarvutuse ala jaoks.

CACM artikkel 21 lõike 1 kohaselt peab iga kooskõlas artikkel 20 lõikega 2 määratud

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koordineeritud võimsusarvutuse ala kohta esitatav ühise võimsusarvutuse metoodika

kasutuselevõtmise ettepanek sisaldama vähemalt järgmist teavet iga võimsusarvutuse

ajavahemiku kohta:

a) meetodid selliste võimsusarvutuse sisendandmete arvutamiseks, mis peavad hõlmama

järgmiseid näitajaid:

i) talitluskindluse varu väljaselgitamise metoodika kooskõlas artikliga 22;

ii) võrgu talitluskindluse piirangute, võimsusarvutusega seotud erandolukordade ja

võimalike jaotamispiirangute väljaselgitamise metoodika kooskõlas artikliga 23;

iii) tootmise muutmise võtmete väljaselgitamise metoodika kooskõlas artikliga 24;

iv) võimsusarvutuses arvesse võetavate talitluskindluse tugimeetmete väljaselgitamise

meetod kooskõlas artikliga 25;

b) võimsusarvutusmeetodi üksikasjalik kirjeldus, mis peab hõlmama järgmist:

i) rakendatava võimsusarvutusmeetodi matemaatiline kirjeldus koos mitmesuguste

võimsusarvutuse sisendandmetega;

ii) eeskirjad piirkonnasiseste ja piirkonnaüleste vahetuste õigustamatu

diskrimineerimise vältimiseks kooskõlas määruse (EÜ) nr 714/2009 I lisa punktiga 1.7;

iii) võimaliku ettejaotatud piirkonnaülese võimsuse arvessevõtmise eeskirjad;

iv) eeskirjad kriitiliste võrguelementide võimsusvoogude reguleerimiseks või

piirkonnaülese võimsuse reguleerimiseks seoses talitluskindluse tugimeetmetega ja

kooskõlas artikliga 25;

v) voopõhise meetodi puhul võimsuse ülekandmise jaotustegurite arvutamise ning

kriitiliste võrguelementide ohutusvarude arvutamise matemaatiline kirjeldus;

vi) koordineeritud netoülekandevõimsuse põhise meetodi puhul piirkonnaülese

võimsuse arvutamise eeskirjad, muu hulgas eeskirjad kriitiliste võrguelementide

läbilaskevõime tõhusaks jaotamiseks erinevate pakkumispiirkondade piiride vahel;

vii) kui kriitiliste võrguelementide võimsusvooge mõjutavad erinevate koordineeritud

võimsusarvutuse alade piirkonnaülesed tehinguvõimsused, siis ka eeskirjad kriitiliste

võrguelementide läbilaskevõime jaotamiseks erinevate koordineeritud võimsusarvutuse

alade vahel selliste voogude võimaldamiseks;

c) piirkonnaülese võimsuse valideerimise metoodika kooskõlas artikliga 26.

CACM artikkel 21 lõike 2 kohaselt tuleb päevasisese võimsusarvutuse ajavahemiku puhul

võimsusarvutuse metoodikasse kaasata ka võimsuse ümberhindamise sagedus kooskõlas artikli

14 lõikega 4 ning sageduse valimise põhjendus.

CACM artikkel 21 lõike 3 kohaselt peab võimsuse arvutamise metoodika hõlmama

varuprotseduuri juhuks, kui esialgne võimsusarvutus ei anna oodatud tulemusi.

2. Menetlusosaline

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

[email protected].

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3. Asjaolud ja menetluse käik

19.01.2024 esitas Elering AS (edaspidi Elering) Konkurentsiametile kooskõlastamiseks Balti

koordineeritud võimsusarvutuse ala2 põhivõrguettevõtjate (edaspidi ka Põhivõrguettevõtjad)

ühise võimsusarvutusmeetodi päev-ette ja päevasisese perioodi jaoks, vastavalt CACM artikkel

20 lõike 2 sisule (edaspidi Metoodika). Viimane asjaomane riiklik reguleeriv asutus sai

Metoodika ettepaneku kätte 24.01.2024.

Põhivõrguettevõtjad on vastavalt CACM artiklile 12 Metoodika ettepanekut koos selgitava

dokumendiga avalikult konsulteerinud ENTSO-E konsultatsioonikeskkonnas perioodil

30.10.2023 kuni 30.11.2023.3

22.07.2024 jõudsid kõik asjaomased riiklikud reguleerivad asutused kokkuleppele taotleda

Metoodika ettepaneku muutmist vastavalt CACM artikkel 9 lõikele 12. Vastavalt CACM

artikkel 9 lõikele 10 konsulteerisid asjaomased riiklikud reguleerivad asutused omavahel, tegid

tihedat koostööd ja kooskõlastasid oma tegevust, et jõuda Metoodika kooskõlastamise osas

kokkuleppele. 23.07.2024 edastas Konkurentsiamet Eleringile vastavasisulise taotluse.

23.09.2024 esitasid Põhivõrguettevõtjad ühiselt asjaomastele riiklikele reguleerivatele

asutustele muudetud Metoodika ettepaneku, mis oli ühiselt heakskiidetud kõikide Balti

koordineeritud võimsusarvutuse ala põhivõrguettevõtjate poolt.

30.09.2024 esitas Elering Konkurentsiametile ka eraldi taotluse eelnimetatud muudetud

Metoodika ettepaneku kooskõlastamiseks.

18.11.2024 toimus kohtumine Balti koordineeritud võimsusarvutuse ala riiklike reguleerivate

asutuste ja Põhivõrguettevõtjate vahel, et konsulteerida asjaomaste põhivõrguettevõtjatega

Balti riiklike reguleerivate asutuste tehtavaid muudatusi Metoodika ettepanekus. Eelnimetatud

muudatused puudutavad peamiselt Metoodika vastavusse viimist Euroopa Parlamendi ja

nõukogu määruse (EL) 2019/943 artiklis 16 sisalduva nõudega tagada turuosalistele

kättesaadavus koordineeritud netoülekandevõimsuse meetodi puhul vähemalt 70%

talitluskindluse piiridele vastavast piirkonnaülese kauplemise olemasolevast võimsusest,

võimsuse arvutaja (kui organisatsiooni) ülesannete täpsustamist, piirkonnaülese võimsuse

valideerimisega seotud täpsustusi ning muid väiksemaid muudatusi. Detailsem muudatuste sisu

on välja toodud Balti koordineeritud võimsusarvutuse ala riiklike reguleerivate asutuste ühises

seisukohas Metoodika ettepaneku kohta (Lisa 2).

21.11.2024 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, vastavalt CACM artikkel 9 lõikele 5 ja vastavalt

Euroopa Parlamendi ja nõukogu määruse (EL) 2019/942 artikkel 5 lõikele 6, et tagada

2 Balti koordineeritud võimsusarvutuse alasse kuuluvad Eesti, Läti, Leedu, Poola, Soome ja Rootsi. 3 https://consultations.entsoe.eu/markets/baltic-ccr-tsos-propsal-da-and-id-ccm/

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Metoodika ettepaneku kooskõla CACM ning Euroopa Parlamendi ja nõukogu määrusega (EL)

2019/943. Balti koordineeritud võimsusarvutuse ala riiklike reguleerivate asutuste tehtud

muudatused Metoodika ettepanekus puudutavad peamiselt Metoodika vastavusse viimist

Euroopa Parlamendi ja nõukogu määruse (EL) 2019/943 artiklis 16 sisalduva nõudega tagada

turuosalistele kättesaadavus koordineeritud netoülekandevõimsuse meetodi puhul vähemalt

70% talitluskindluse piiridele vastavast piirkonnaülese kauplemise olemasolevast võimsusest,

võimsuse arvutaja (kui organisatsiooni) ülesannete täpsustamist, piirkonnaülese võimsuse

valideerimisega seotud täpsustusi ning muid väiksemaid muudatusi. Detailsemalt on

muudatuste sisu välja toodud Balti koordineeritud võimsusarvutuse ala riiklike reguleerivate

asutuste ühises seisukohas Metoodika ettepaneku kohta (Lisa 2).

Kokkuvõte

Konkurentsiamet töötas läbi 30.09.2024 Eleringi poolt ametile kooskõlastamiseks esitatud Balti

koordineeritud võimsusarvutuse ala põhivõrguettevõtjate ühise võimsusarvutusmeetodi päev-

ette ja päevasisese perioodi jaoks, vastavalt CACM artikkel 20 lõike 2 sisule 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 CACM-st tuleneva regulatsiooniga.

CACM artikkel 9 lõike 14 kohaselt tingimuste ja meetodite väljatöötamise eest vastutavad

põhivõrguettevõtjad ja määratud elektriturukorraldajad peavad avaldama 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 13 kohaselt konfidentsiaalne.

Arvestades eeltoodut ja tuginedes ELTS § 93 lõige 6 punktile 6 ja CACM artikkel 9 lõige 7

punktile a)

otsustan:

kooskõlastada Elering AS poolt Konkurentsiametile esitatud Balti koordineeritud

võimsusarvutuse ala põhivõrguettevõtjate ühine võimsusarvutusmeetod päev-ette ja

päevasisese perioodi jaoks, vastavalt Komisjoni määruse (EL) 2015/1222, 24. juuli 2015,

millega kehtestatakse võimsuse jaotamise ja ülekoormuse juhtimise suunised, artikkel 20 lõike

2 sisule.

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

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Lisad:

1. Capacity calculation methodology for the day-ahead and intraday market timeframes

within the Baltic Capacity Calculation Region

2. POSITION PAPER BY ALL BALTIC CAPACITY CALCULATION REGION

NATIONAL REGULATORY AUTHORITIES ON THE ALL BALTIC CAPACITY

CALCULATION REGION TRANSMISSION SYSTEM OPERATORS’ PROPOSAL

FOR CAPACITY CALCULATION METHODOLOGY FOR THE DAY-AHEAD

AND INTRADAY MARKET TIMEFRAMES WITHIN THE BALTIC CAPACITY

CALCULATION REGION

Capacity calculation methodology for the day-ahead and intraday market

timeframes within the Baltic Capacity Calculation Region

Among:

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

23rd September 2024

Vilnius, Riga, Tallinn, Helsinki, Stockholm, Warsaw

2

1 TABLE OF CONTENTS

2 GENERAL TERMS ...................................................................................................................................................................3

3 DEFINITIONS..........................................................................................................................................................................4

4 CAPACITY CALCULATION AND VALIDATION PROCESS .......................................................................................................6

5 CRITICAL NETWORK ELEMENTS AND CONTIGENCIES ........................................................................................................7

6 OPERATIONAL SECURITY LIMITS..........................................................................................................................................7

7 ALLOCATION CONSTRAINTS.................................................................................................................................................8

8 GENERATION AND LOAD SHIFT KEYS ............................................................................................................................... 10

9 REMEDIAL ACTIONS........................................................................................................................................................... 11

10 IGM AND CGM DATA ......................................................................................................................................................... 11

11 TOTAL TRANSFER CAPACITY (TTC) CALCULATION PRINCIPALS ...................................................................................... 11

12 TOTAL TRANSFER CAPACITY (TTC) CALCULATION FOR INTERNAL AC CROSS-BORDERS INTERCONNECTORS IN BALTIC TSOS CONTROL AREA.................................................................................................................................................................. 12

13 TOTAL TRANSFER CAPACITY (TTC) CALCULATION FOR CROSS-BORDERS WITH HVDC INTERCONNECTORS .............. 12

14 TRANSMISSION RELIABILITY MARGIN (TRM) CALCULATION METHODOLOGY OF AC CROSS-BORDERS INTERCONNECTORS IN BALTIC TSO’S CONTROL AREA............................................................................................................. 12

15 TRADING CAPACITY CALCULATION MATHEMATICAL DESCRIPTION OF NTC CALCULATION FOR DAY AHEAD TIMEFRAME OF INTERNAL BALTIC AC INTERCONNECTORS IN BALTIC TSO’S CONTROL AREA ............................................. 14

16 INTRADAY AVAILABLE TRANSMISSION CAPACITY CALCULATION OF INTERNAL BALTIC AC INTERCONNECTORS IN BALTIC TSO’S CONTROL AREA .................................................................................................................................................... 14

17 TRADING CAPACITY CALCULATION RULES BETWEEN ESTONIAN AND FINNISH POWER SYSTEMS ............................. 15

18 TRADING CAPACITY CALCULATION RULES BETWEEN LITHUANIAN AND SWEDISH POWER SYSTEMS ....................... 16

19 TOTAL TRANSFER CAPACITY (TTC) CALCULATION FOR LITHUANIAN - POLAND AC CROSS-BORDER INTERCONNECTOR ...................................................................................................................................................................... 17

20 TRADING CAPACITY CALCULATION RULES BETWEEN LITHUANIAN AND POLISH POWER SYSTEMS FOR DAY AHEAD TIMEFRAME ................................................................................................................................................................................. 18

21 INTRADAY AVAILABLE TRANSMISSION CAPACITY CALCULATION BETWEEN LITHUANIAN AND POLISH POWER SYSTEMS ...................................................................................................................................................................................... 19

22 CROSS-ZONAL CAPACITY VALIDATION AND COORDINATION METHODOLOGY ............................................................ 19

23 CAPACITY CALCULATION FALLBACK PROCEDURES ......................................................................................................... 20

24 PROVISION AND ALLOCATION OF TRADING CAPACITY .................................................................................................. 20

25 FIRMNESS ........................................................................................................................................................................... 20

26 RULES FOR AVOIDING UNDUE DISCRIMINATION BETWEEN INTERNAL AND CROSS-ZONAL EXCHANGES. CCR RULES FOR EFFICIENTLY SHARING THE POWER FLOW CAPABILITIES OF CRITICAL NETWORK ELEMENTS AMONG DIFFERENT BIDDING ZONE BORDERS ........................................................................................................................................................... 21

27 IMPLEMENTATION OF THE METHODOLOGY ................................................................................................................... 21

28 LANGUAGE ......................................................................................................................................................................... 22

29 APPENDIX 1: USE OF ALLOCATION CONSTRAINTS .......................................................................................................... 23

3

2 GENERAL TERMS

1.1. The Capacity calculation methodology within the Baltic Capacity Calculation Region is required

by Article 20(2) of the Commission Regulation (EU) 2015/1222 establishing a guideline on capacity

allocation and congestion management (CACM Regulation).

1.2. Capacity calculation methodology within the Baltic Capacity Calculation Region (hereinafter

referred to as “the Methodology”) are set to define:

1.2.1. Cross-Zonal Capacity calculation, provision and allocation rules between Estonian and Latvian

power systems;

1.2.2. Cross-Zonal Capacity calculation, provision and allocation rules between Lithuanian and Latvian

power systems;

1.2.3. Cross-Zonal Capacity calculation, provision and allocation rules between Estonian and Finnish

power systems;

1.2.4. Cross-Zonal Capacity calculation, provision and allocation rules between Lithuanian and

Swedish power systems;

1.2.5. Cross-Zonal Capacity calculation, provision and allocation rules between Lithuanian and Polish

power systems.

1.3. Article 9(9) of the CACM Regulation requires that the expected impact of the Proposal on the

objectives of the CACM Regulation is described. The impact is presented below in paragraphs 1.4.1

- 1.4.7.

1.4. The Methodology Proposal contributes to and does not in any way hamper the achievement of

the objectives of Article 3 of the CACM Regulation. Cross-Zonal Capacities within the Baltic Capacity

Calculation Region (hereinafter referred to as “Baltic CCR”) shall be calculated using the coordinated

Net Transmission Capacity approach in a way that facilitates and serves the achievement of the

following objectives:

1.4.1. promoting effective competition in the generation, trading and supply of electricity (Article 3(a)

of the CACM Regulation) by ensuring that maximum Cross-Zonal Capacity (with regards of

operational security) is made available to the market in the Baltic CCR.

1.4.2. ensuring optimal use of the transmission infrastructure (Article 3(b) of the CACM Regulation) by

applying the net transmission capacity approach, compared to which flow-based approach is not yet

more efficient assuming the comparable level of operational security in the Baltic CCR.

The Methodology for the Baltic CCR treats all bidding zone borders within the Baltic CCR equally and provides non-discriminatory access to cross-zonal capacity. Proposed approach aims at providing the maximum available capacity to market participants within the operational security limits. The Methodology for the Baltic CCR ensures non-discrimination in calculation of Cross-Zonal Capacities.

1.4.3. ensuring operational security (Article 3(c) of the CACM Regulation) by taking into account grid

constraints and providing the maximum available capacity to market participants within the operational

security limits.

1.4.4. optimising the calculation and allocation of cross-zonal capacity (Article 3(d) of the CACM

Regulation) and ensuring that Cross-Zonal Capacities in day-ahead and intraday markets are

provided and allocated in a most optimal and reasonable manner by taking into account structure of

the Baltic CCR power system, as well as from one side, operational security limits and N-1 situations

which are limiting capacities, and from another side - remedial actions which can increase capacities.

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1.4.5. ensuring and enhancing the transparency and reliability of information (Article 3(f) of the CACM

Regulation), as this Methodology determines the main principles and main processes for the day-

ahead and intraday timeframes. The Methodology enables Transmission System Operators

(hereinafter referred to as "TSOs") to in a transparent way provide Market Coupling Operator

(hereinafter referred to as "MCO") with the same reliable information on cross-zonal capacities and

allocation constraints for day-ahead and intraday allocations.

1.4.6. contributing to the efficient long-term operation and development of the electricity transmission

system and electricity sector in the Union (Article 3(g) of the CACM Regulation). The Methodology,

by taking most important grid constraints into consideration, will support efficient pricing in the market,

providing the right signals from a long-term perspective.

1.4.7. respecting the need for a fair and orderly market and fair and orderly price formation (Article

3(h) of the CACM Regulation) as well as providing non-discriminatory access to cross-zonal capacity

(Article 3(j) of the CACM Regulation) by providing all cross-zonal capacities for allocations to MCO.

1.5. Principles described in this Methodology cover Cross-Zonal Capacity calculation, provision and

allocation for day-ahead and intraday time horizons.

1.6. 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. Upon synchronisation, the capacity of this interconnector will be

determined considering principles described in whereas (54) of Regulation (EU) 2024/1747.

3 DEFINITIONS

For the purposes of this Methodology, the definitions in Articles 2 of Regulations (EC) No 2015/1222,

No 2019/943, No 543/2013, Article 3 of Regulation (EC) No 2017/1485 and Article 2 of Directive No

2019/944 shall apply. In addition, the following definitions shall apply and shall have the following

meaning:

AAC - the Already Allocated Capacity is the total amount of allocated physical transmission rights.

AST - AS “Augstsprieguma tikls”, electricity transmission system operator of the Republic of Latvia.

ATC - the Available Transmission Capacity of the designated Cross-Border Interconnections, which

is available to the market after each phase of the transmission capacity allocation procedure.

Baltic CCR - Capacity calculation region Baltic. According to ACER decision No 04/2024 on the

electricity TSOs’ proposal for Capacity Calculation Regions Baltic CCR shall include the Bidding Zone

borders listed below:

a) Estonia - Latvia (EE-LV), Elering AS and AST;

b) Latvia - Lithuania (LV-LT), Augstsprieguma tikls and LITGRID AB;

c) Estonia - Finland (EE-Fl), Elering AS and Fingrid Oyj;

d) Lithuania — Sweden 4 (LT-SE4), LITGRID AB and Svenska kraftnat; and

e) Lithuania - Poland (LT-PL), LITGRID AB and PSE S.A.

Baltic CCR TSOs - the transmission system operators for electricity of the Republic of Finland,

Republic of Estonia, the Republic of Latvia and the Republic of Lithuania, the Republic of Poland,

Kingdom of Sweden.

Baltic LFC Block – region which consist of load-frequency control areas operated by Baltic TSOs -

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Litgrid, AST and Elering.

Baltic TSOs - the transmission system operators for electricity of the Republic of Estonia, the Republic

of Latvia and the Republic of Lithuania.

BSPS - Baltic State Power Systems (Republic of Estonia, the Republic of Latvia and the Republic of

Lithuania)

CACM - European Commission Regulation (EU) No 2015/1222 establishing a Guideline on Capacity

Allocation and Congestion Management.

CEP - REGULATION (EU) 2019/943 of the European parliament and of the council of 5 June 2019 on the internal market for electricity

CESA – Continental Europe synchronous area.

CGM – Common grid model.

CGMES – Common grid model exchange standard.

Cross-Border Interconnection - is a physical transmission link (e.g. tie-line or combination of tie-

lines) which connects two power systems.

CSA Methodology – methodology developed in accordance with European Commission Regulation

(EU) No 2017/1485 establishing a Guideline on electricity transmission system operation Article 75.

D-1 – one day ahead planning timeframe.

D-2 - two days ahead planning timeframe.

EBGL - COMMISSION REGULATION (EU) 2017/2195 of 23 November 2017 establishing a guideline

on electricity balancing.

Elering - Elering AS, Transmission System Operator of the Republic of Estonia.

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

ID - intraday planning timeframe.

IDA – Capacity auctions in ID timeframe according to CACM Regulation Article 35 where price

coupling algorithm and of the continuous trading matching algorithm are applied.

IGM – Individual grid model.

Internal Baltic AC interconnectors – Interconnectors between Baltic TSOs in Baltic area, covering

Lithuania – Latvia and Latvia – Estonia cross-borders.

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

Market Coupling Operator (MCO)/Nominated Electricity Market Operator (NEMO) - the operator/-

s of day-ahead and intraday markets in Baltic CCR.

MTU – Market time unit.

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

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planned network conditions for each TSO.

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

Regional Models – These models incorporate data on generation, transmission, distribution, and

consumption within a Baltic region to facilitate effective planning, capacity calculation, and operational

decisions, regional models are essential for optimizing grid operations, ensuring efficient cross-border

electricity trade, and maintaining system stability by taking into account the unique characteristics and

constrains of each region.

Shift Key – means of method used to translate net position changes within a given bidding zone into

estimated changes in the common grid model. This includes both injection increases or decreases

due to generation adjustments (Generation Shift Key) and contribution of load adjustments (Load Shift

Key).

SO GL - European Commission Regulation (EU) No 2017/1485 establishing a Guideline on electricity

transmission system operation.

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

Trading Capacity - The total amount of electricity that can be bought, sold, or exchanged between

market participants or regions within a power system. It represents the limit up to which energy

transactions can occur without compromising the stability and reliability of the power system.

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.

4 CAPACITY CALCULATION AND VALIDATION PROCESS

4.1. Capacity calculation and validation process involves TSOs and Capacity Calculator and consists

of these main steps:

• Input data provision by TSOs for Capacity Calculator (further detailed in Paragraph 4.3).

• Capacity calculation (further detailed in Sections 11 - 21).

• Capacity validation and coordination procedure (further detailed in Section 22).

• Capacity publication to market operator (further detailed in Section 24).

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 Capacity Calculator.

4.2. TSOs of Baltic CCR shall set up Capacity Calculator 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 Capacity Calculator.

4.3. TSOs of the Baltic CCR shall provide to the Capacity Calculator and coordinate between the

TSOs and the Capacity Calculator 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 10).

• Operational Security Limits (according to Section 6).

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• Generation and Load Shift Keys (according to Section 8).

• Critical Network Elements (according to Section 4).

• Contingencies (according to Section 4).

• Remedial Actions (according to Section 9).

• TRM values or input data for TRM calculation (according to Section 14).

• Allocation constraints (according to Section 7).

4.4. If input data for capacity calculation process referred in 4.3 is used as static data and is constant

in daily capacity calculation processes, such data shall be reviewed and shared between TSOs and

Capacity Calculator at least on a yearly basis or upon TSO or Capacity Calculator request.

4.5. In accordance with Article 29 and 30 of the CACM Regulation, capacity calculation shall be

performed by the Capacity Calculator whereas the TSOs shall provide required input data and perform

validation.

5 CRITICAL NETWORK ELEMENTS AND CONTIGENCIES

5.1. Each Baltic CCR TSO shall define critical network elements (CNEs) of its control area for

capacity calculation process.

5.2. The CNEs for capacity calculation shall be defined considering impact computation principles

defined in CSA methodology annex 1 and factor determining impact for CNE shall be cross zonal

power flow exchange. Internal CNEs which power flow filtering influence factor is less than defined in

annex 1 of CSA methodology shall be excluded from capacity calculation process. The TSO shall

update the CNE list in case of significant change in grid topology when influence value for CNE

element significantly changed from average value. If an internal CNE constitute a structural

congestion the TSO shall ensure that cross-border capacities is not impacted by the CNE.

5.3. A contingency analysis is performed for those contingencies which are agreed among Baltic

CCR TSOs. Contingencies shall be agreed and provided among Baltic TSOs and provided to Capacity

Calculator for Capacity Calculation.

5.4. Each Baltic CCR TSO shall provide Contingencies to be used in capacity calculation process

determined in accordance with Article 33 of SO GL and CSA methodology annex 1. Contingencies

shall be elements of TSO observability area. Contingency can be the outage of the following elements:

• Line, cable.

• Transformer.

• Generator.

• Load.

• Busbar.

• Multiple elements combined.

• HVDC.

5.5. Each Baltic CCR TSO and Capacity Calculator shall perform regular review of CNEs,

Contingencies and other input data and evaluate their relevance in capacity calculation process

according to paragraph 5.2. Such evaluation shall be performed at least on a yearly basis.

6 OPERATIONAL SECURITY LIMITS

6.1. Operational security analyses shall be performed with respect of Operational Security limits

applied in Control Areas of Baltic CCR TSOs. Operational Security limits shall be determined by taking

into account thermal limits, voltage limits, dynamic stability limits (including, rotor angle and voltage

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stability, frequency stability, small signal stability) in accordance with Article 25 of SO GL.

6.2. Thermal limits shall correspond maximum amount of electric current that a given network

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

into account ambient conditions (based on TSOs thermal limits assessment procedure). Thermal

limits are applied for performing of steady state analysis.

6.3. Voltage limits shall correspond maximum and minimum voltage levels permitted at given

network node to prevent equipment damage or voltage collapse (based on TSOs voltage limits

assessment procedure). Voltage limits is applied for performing of steady state analysis.

6.4. Dynamic stability limits shall be calculated by evaluating:

6.4.1. Rotor angle stability limits - defined during dynamic stability analysis by applying N-1

disturbances (including three phase symmetrical fault) and analysing behaviour of relative rotor angles

among generators, rotor angle stability is maintained if after fault generators relative rotor angles

among generators don’t exceed critical relative rotor angles values (remain in synchronous operation).

6.4.2. Voltage stability limits - defined during dynamic stability analysis by applying N-1 disturbances

(including three phase symmetrical fault) and analysing network node voltages, voltage stability is

maintained if voltage doesn’t exceed critical voltage, which can lead to voltage collapse.

6.4.3. Frequency stability limits - defined by performing frequency stability analysis by evaluating

possible biggest imbalance of BSPS from frequency stability point of view after disconnection of

Lithuania-Poland cross border interconnection. Frequency stability is maintained if imbalance which

occurs after disconnection of Lithuania-Poland does not cause violations of defined boundaries of

underfrequency, over frequency and rate of change of frequency.

6.4.4. Small signal stability limits – defined by performing small signal stability analysis to evaluate

damping level of oscillations caused by swinging of generators in BSPS against other generators in

CESA. Small signal stability limits are maintained if damping of inter area oscillation is not lower, then

defined minimum damping level.

6.5. Operational Security limits used in capacity calculation shall be the same as those used in

operational security analysis performed according to Articles 74 and 75 of SO GL. Each TSO shall

provide thermal and voltage Operational Security limits for electrical system elements within its IGM.

6.6. Baltic CCR TSOs and Capacity Calculator shall perform regular review of Operational Security

limits and evaluate their relevance in Capacity Calculation. Such evaluation shall be performed at

least on a yearly basis.

6.7. Stability limits referred in paragraph 6.4 evaluation shall be performed according to TSOs

stability assessment procedures.

7 ALLOCATION CONSTRAINTS

7.1. In accordance with the definitions in Article 2 points (6) and (7), Article 23(3) of the CACM

Regulation, and respecting the objectives described in Article 3 of the CACM Regulation, besides

active power flow limits on Cross-Border Interconnections, other specific limitations may be necessary

to maintain the secure grid operation. Allocation constraints are determined by Baltic CCR TSOs and

taken into account during the single day-ahead and intraday coupling in addition to the power flow

limits on Cross-Border Interconnections.

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7.2. Allocation constraints can be applied as:

a) Constraint on the cross-border and/or on the global net position (the sum of all Cross- Border exchanges for a bidding zone in the single day-ahead and intraday coupling) considered as balancing constraint, thus limiting the net position of the respective bidding zone with regards to all CCRs which are part of the single day-ahead and intraday coupling described in paragraphs 7.3 and 7.4.

b) Constraint translated into ramping restrictions on HVDCs as described in paragraphs 7.5 and 7.6.

c) Implicit loss factor constraint for HVDC interconnector as described in paragraphs 7.7 and 7.8

7.3. A TSO can also use allocation constraints in case of a central dispatch model for ensuring a

required level of operational reserve for balancing (hereinafter referred to as balancing constraints).

The balancing constraints depend on the foreseen balancing situation and are bidirectional, with

independent values for each market time unit and separately in the directions of import and export.

This is applicable for PSE, for all market time units. The details for the use and the methodology of

calculation of allocation constraints as described in this article are set forth in Appendix 1. Allocation

constraints may be used for an interim period of 2 years following the implementation of this

Methodology. If any 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. In case such a proposal has been submitted, the interim

period shall be extended until the decision on the proposal is taken by all Baltic CCR NRAs.

7.4. A TSO may discontinue the usage of an allocation constraint as described in paragraph 7.3.

The concerned TSO shall communicate this change to the Baltic CCR regulatory authorities and to

the market participants at least one month before its implementation.

7.5. On HVDC Interconnections, maximum Ramping Rate restrictions according to SO GL

2017/1485 (Article 137) are applied during D-1 and ID capacity calculation processes. Maximum

Ramping Rate restriction indicates the maximum possible rate of active power change for sequential

trading periods. The restrictions imply that trade plans on all HVDC connections cannot be changed

with no more than the predetermined maximum Ramping Rate restriction from one trading period to

the next. Ramping restrictions are taken into account in the D-1 Market in order to maintain operational

security. Capacities available for trading during ID Market depend not only on maximum trading

capacities provided by TSOs/ Capacity Calculators, but also on AACs for consecutive previous and

following trading periods.

7.6. Ramping restrictions may be used for an interim period of 2 years following the implementation

of this Methodology. If any of the Baltic CCR TSOs still want to use ramping restrictions after this

period, they shall deliver a proposal for amendments to this Methodology, describing the technical

details for calculating the ramping restrictions and the justification for the need for them latest two

years after the implementation of this Methodology. In case such a proposal has been submitted, the

interim period shall be extended until the decision on the proposal is taken by all Baltic CCR NRAs.

7.7. TSOs may apply implicit loss factors in day-ahead and intraday timeframes in accordance with Article 23(3) of the CACM Regulation. TSOs shall provide these allocation constraints to the Capacity Calculator. The implicit loss factors are calculated as: Output quantity = (1 – "Loss Factor") * Input quantity

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The implicit loss factor is a correction mechanism for a negative external effect incentivising the market to respect the cost of electricity losses on HVDC interconnections in the market coupling.

7.8. The implicit loss factor referred in paragraph 7.7 may be applied on an HVDC interconnection if

an EU-wide net benefit, i.e. an increase of economic surplus can be demonstrated to the NRAs. If

TSOs wish to apply an implicit loss factor, they shall prepare a report demonstrating a net benefit and

shall consult stakeholders for at least one month. The report along with the stakeholders’

considerations shall be submitted to the Baltic CCR NRAs.

8 GENERATION AND LOAD SHIFT KEYS

8.1. The generation and load Shift Keys (hereinafter referred to as "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 paragraph 8.3 and 8.4.

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

paragraphs 8.3 and 8.4. 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

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

algorithm shall be coordinated with Capacity Calculator.

8.3. 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 area generation shift.

b. HVDCs setpoint change.

c. Neighbouring system generation shift.

d. Load shifting in specific area.

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

performed according to following rules:

8.4.1. 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.

8.4.2. 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.

8.5. GLSK strategy applied in Nordic region is described in detail in Nordic CCR Capacity Calculation

Methodology.

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9 REMEDIAL ACTIONS

9.1. TSOs shall provide for Capacity Calculator information on available and applicable non-costly

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

9.2. 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.

9.3. 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.

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

exploited in the DA and ID capacity calculation in accordance with Article 16(4) of the Electricity Market

Regulation 2019/943. Thus, the TSOs shall ensure that Article 16(8) of the Electricity Market

Regulation 2019/943 is adhered to.

10 IGM AND CGM DATA

10.1. IGM, provided by TSO, shall follow rules referred in methodology of Article 17 of the CACM

Regulation and shall consist of valid Operational Security limits, up to date topology data, forecast

data. IGM shall consist of input scenario data describing net positions, grid topology and system

element data for each market time unit and valid for given calculation purposes.

10.2. Capacity Calculator shall use CGM for capacity calculation processes according to Article 17 of

the CACM Regulation. CGM shall consist of IGMs of synchronous area, at least including Baltic TSOs

and Polish power system. CGM shall represent base case model, which includes power transmission

equipment model of synchronous area and scenario describing net positions for each of Control Area

of Baltic TSOs and Polish power system, valid for given TTC calculation purposes.

11 TOTAL TRANSFER CAPACITY (TTC) CALCULATION PRINCIPALS

11.1. TTC shall be calculated by performing Contingency Analyses after applying of N-1 criteria. While calculating TTC Operational Security limits referred in Section 6 shall be not exceeded and determined by selecting the minimum value of:

TTC = min (TTCthermal; TTCstatic_stab.; TTCdynamic_stab.) (1)

Where:

TTCthermal - TTC evaluated considering thermal limits according to Section 6.2

TTCstatic_stab. - TTC evaluated considering static voltage stability limits according to Section 6.3

TTCdynamic_stab. - TTC evaluated considering dynamic stability limits according to Section 6.4

11.2. CNEs which are impacted by cross zonal flows according to Article 29.3(b) of CACM Regulation and Section 5 of this Methodology shall be evaluated during TTC calculation.

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12 TOTAL TRANSFER CAPACITY (TTC) CALCULATION FOR INTERNAL AC CROSS- BORDERS INTERCONNECTORS IN BALTIC TSOS CONTROL AREA

12.1. 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 6 of synchronous area and Control Area of Baltic TSOs.

12.2. TTC is maximum power flow value on Cross-Border between two bidding zone areas resulted from modelling net position variation and contingency analysis. TTC value is obtained by summing up power flow values of cross-border lines above 110 kV after Operational Security limits reached for any CNE while modelling net position increase in exporting area and decrease in importing area and performing N-1 contingency analysis.

12.3. Contingency analysis is performed for those contingencies which are agreed among Baltic

TSOs. Contingencies shall be agreed and provided among Baltic TSOs and to Capacity Calculator according to Section 5.

12.4. The generation and load Shift Keys shifting strategy used in TTC calculations are described in Section 8 of this Methodology.

12.5. If during capacity coordination process according to 22.5 neighbouring TSOs determine different TTC values for the same Cross-Border Interconnection, the lowest value shall be used as a coordinated value.

13 TOTAL TRANSFER CAPACITY (TTC) CALCULATION FOR CROSS-BORDERS WITH HVDC INTERCONNECTORS

13.1. 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 Section 6.

13.2. Maximum permissible capacity on HVDC interconnector can be limited when there is lack of frequency restoration reserves in Baltic LFC Block to cover dimensioning incident. Contingency analysis is performed according to paragraph 1 and it is checked if maximum capacity for each link for each direction could be provided to the market. If contingency analysis reveals that network

security is not assured when the HVDC interconnectors are fully loaded in any direction, then capacity on the cross-border on one and/or both directions is reduced until network parameters do not exceed permissible limits during the analysis.

13.3. The TTC on HVDC interconnector is the minimum capacity value that is the outcome of the Contingency Analyses that are performed by the TSOs on each side of the interconnector.

13.4. The generation and load Shift Keys shifting strategy applied during TTC determination of HVDC interconnector shall be performed in accordance with Section 8.

13.5. TTC of cross-border Estonia-Finland is the sum of permissible capacities on HVDC links Estlink 1 and Estlink 2. When there is a need to limit the capacities on the links according to paragraph 13.2 the links are limited in minimal possible combination - meaning the maximum possible capacity is

given to the market.

14 TRANSMISSION RELIABILITY MARGIN (TRM) CALCULATION METHODOLOGY

OF AC CROSS-BORDERS INTERCONNECTORS IN BALTIC TSO’S CONTROL AREA

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14.1. The Transmission Reliability Margin (hereinafter referred to as "TRM") is a capacity margin needed for secure operation of interconnected power systems considering the planning errors,

including the errors due to imperfect information at the time the transfer capacities have been computed and determined according to Article 22 of CACM Regulation.

14.2. TRM calculation methodology is covering Cross-Border Interconnections between Lithuanian and Latvian, Lithuanian and Polish power systems as well as between Latvian and Estonian power systems.

14.3. For HVDC interconnectors TRM value shall be 0 MW.

14.4. 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 (2):

(2)

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.

̅ arithmetic average value of Xi equal to .

n - number of elements in the data set.

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

14.6. For initial operation period after Baltic TSOs synchronisation with CESA, fixed TRM values shall be applied to LT-LV, LV-EE, and LT-PL Cross-Borders. These values shall be applied during a transitory period of at least 1 month . After this period, the TSOs shall calculate the TRMs according

to principles set out in 14.4 and 14.5. Before applying the calculated TRMs, TSOs shall demonstrate to the NRAs that the calculated TRMs do not violate the requirement set in Article 16(8) of the Electricity Market Regulation 2019/943 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

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15 TRADING CAPACITY CALCULATION MATHEMATICAL DESCRIPTION OF NTC CALCULATION FOR DAY AHEAD TIMEFRAME OF INTERNAL BALTIC AC INTERCONNECTORS IN BALTIC TSO’S CONTROL AREA

15.1. Capacity Calculator calculates NTC value for Internal Baltic AC interconnectors and Available Transmission Capacity (ATC) for both interconnection directions. ATC would represent capacity allocations for day ahead timeframe. Calculation shall be performed using following equations:

NTCA>B = TTCA>B - TRMA>B; NTCB>A = TTCB>A - TRMB>A (3)

ATCDA, A>B = NTCA>B - AABCA>B; ATCDA, B>A = NTCB>A - AABCB>A (4)

where:

TTC A>B; TTC B>A - Total Transfer Capacity according to actual power system network status, identified

during TTC evaluation, defined in Section 12 in direction from areas A>B and B>A.

TRMA>B; TRM B>A - transmission reliability margin value calculated according to the methodology

described in Section 14 in direction from areas A>B and B>A.

ATCDA, B>A; ATCDA, B>A – available transmission capacity given to the Day-Ahead electricity market

from areas A>B and B>A.

AABCA>B; AABCB>A – Already allocated capacity for balancing market in accordance with Baltic CCR

methodology for EBGL Article 38 in direction from areas A>B and B>A.

15.2. If during capacity coordination process according to paragraph 22.5 neighbouring TSOs determine different NTC values for the same Cross-Border Interconnection the lowest value shall be used as a coordinated value.

15.3. Final AC Cross-Border ATC value given to Day-ahead market shall be calculated according to formula (4).

15.4. The NTC capacity for AC borders provided by Baltic CCR TSOs for market operations shall be calculated by subtracting transmission reliability margin from the total transfer capacity value for given

cross-border and direction. Baltic CCR TSOs ensure that the TRM shall not exceed 30% of the TTC calculated in accordance with Section 11 of this Methodology. Therefore, NTC capacity availability shall comply with CEP Regulation Article 16(8).

16 INTRADAY AVAILABLE TRANSMISSION CAPACITY CALCULATION OF INTERNAL BALTIC AC INTERCONNECTORS IN BALTIC TSO’S CONTROL AREA

16.1. ATC value is directional and is calculated considering that the TSOs and Capacity Calculator shall, as far as technically possible, net the capacity values of any power flows in opposite directions over congested interconnection line in order to use that line to its maximum capacity.

16.2. ATC for ID market shall be calculated for both interconnection directions according to formulas:

ATCID A>B = NTCID A>B – AABCA>B – AACA>B + AACB>A (5)

ATCID B>A = NTCID B>A – AABCB>A – AACB>A + AACA>B (6)

where:

ATCID A>B; ATCID B>A – available transmission capacity given to the ID electricity market in direction from areas A>B and B>A.

NTCID A>B; NTCID B>A – coordinated Net Transmission Capacity for intraday timeframe for the Cross- Border interconnections in direction from areas A>B and B>A.

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AACA>B; AACB>A – Already Allocated Capacity for the Cross-Border Interconnections in direction from areas A>B and B>A after previous capacity allocation phases that includes DA allocations and previous ID allocations for given MTU.

AABCA>B; AABCB>A – Already allocated capacity for balancing market in accordance with Baltic CCR

methodology for EBGL Article 38 in direction from areas A>B and B>A.

16.2.1. NTCID value defined in formulas (5) and (6) shall correspond to the latest grid situation in ID timeframe with respect to grid topology, generation and load distribution and Operational Security limits. In general case NTCID shall be equal to NTC coordinated in DA timeframe. In case of changes in the network which affect NTC value it shall be recalculated in according to Section 15 and re- coordinated according to paragraph 16.3 between parties for ID timeframe.

16.2.2. AABC value defined in formulas (5) and (6) used for ATC calculation shall correspond to chosen ATC calculation direction meaning AABC variable shall always have positive value.

16.3. In case if during capacity coordination process neighbouring TSOs determine different ATC values for the same Cross-Border Interconnection the lowest value shall be used as a coordinated value.

16.4. As a fallback ID ATC values equal to “0 MW” (zero MW) shall be provided to the Intraday Market

if following conditions occur:

a) In case if DA Market results have not been provided by NEMOs.

b) There are significant changes in the grid that impact cross-zonal capacity value and CGM

including DA trading results is not available.

c) There are significant changes in the grid that impact cross-zonal capacity value and there is

insufficient time to reassess and re-coordinate cross-zonal capacity values.

16.5. ID ATC values shall be reassessed and re-coordinated by TSOs and Capacity Calculator as soon as technically possible and provided to Intraday Market.

16.6. To ensure operational security of power systems reassessment of Intraday capacity value (ATC) shall be performed every time if any of the following situations occur:

16.6.1. Changes in topology of transmission network - unplanned outages or unplanned (earlier) returning to operation of network elements that affect transmission capacities.

16.6.2. Day-Ahead Market results update e.g., in case of fallback procedure applied by NEMO.

16.6.3. Major changes in generation and load plans, renewable generation forecasts changes.

17 TRADING CAPACITY CALCULATION RULES BETWEEN ESTONIAN AND FINNISH POWER SYSTEMS

17.1. TTCs on cross-border Estonia-Finland are calculated by the Capacity Calculator using CGMs that represent the AC-networks of observable areas of synchronous areas that each belong to and validated by the respective TSO on both sides of the interconnector.

17.2. Trading Capacity shall be defined for both interconnection directions according to formulas (3) and (4) on each side of HVDC link. In case if during capacity validation process different NTC values are proposed for the same Cross-Border Interconnection direction the lowest value shall be used as a coordinated value.

ATCFI>EE; EE>FI = min (FI ATCFI>EE; EE ATCFI>EE); min (FI ATCEE>FI; EE ATCEE>FI) (7)

where:

FI ATCFI>EE ; FI ATCEE>FI – ATC between FI>EE and EE>FI Bidding Zones directions, determined by Operational Security limits in Nordic CCR TSOs’ synchronous area or technical limitation on HVDC interconnection (from Finland side),

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EE ATCFI>EE ; EE ATCEE>FI – ATC between FI>EE and EE>FI Bidding Zones directions, determined by Operational Security limits in Baltic CCR TSOS’ synchronous area or technical limitation on HVDC interconnection (from Estonia side).

17.3. The NTC capacity for EE-FI cross-border shall use TRM equal to zero value in accordance with

Article 14.3 of this Methodology. The full TTC capacities shall be provided for market operations and shall comply with CEP Regulation Article 16(8).

17.4. AABC allocation referred in formula (4)) for HVDC shall be defined in the balancing capacity exchange agreements between parties according to EBGL Article 38. In case no capacity exchange agreement is in place, AABC value for HVDC interconnectors shall be 0.

Intraday capacity allocation procedure

17.5. The available capacity after the Day-Ahead Market results is offered to the Intraday Market in line with actual operational conditions. The intraday capacity can be influenced by changed TTC caused by changes in prognosis, topology, and in maintenance plans.

17.6. Intraday trading Capacity on cross-border Estonia-Finland is allocated according to formulas (5) and (6).

18 TRADING CAPACITY CALCULATION RULES BETWEEN LITHUANIAN AND

SWEDISH POWER SYSTEMS

18.1. TTCs on cross-border Lithuania-Sweden are calculated by the Capacity Calculator using CGMs

that represent the AC-networks of observable areas of synchronous areas that each belong to and

validated by the respective TSO on both sides of the interconnector.

18.2. Trading capacity shall be defined by Capacity Calculator for both interconnection directions according to formula (3) and (4) on each side of HVDC link. In case if during capacity validation process different NTC values are proposed for the same cross-border interconnection direction the lowest value shall be used as a coordinated value.

18.3. Capacities for Lithuania – Sweden interconnection shall be defined according to formula:

ATCSE>LT, LT>SE = MIN (SE ATCSE>LT; LT ATCSE>LT); MIN (SE ATCLT>SE; LT ATCLT>SE) (8)

where:

SE ATCSE>LT ; SE ATCLT>SE — ATC between SE–LT and LT–SE Bidding Zones directions, determined

by Operational Security limits in Nordic CCR TSOS' synchronous area or technical limitation on HVDC interconnection (from Sweden side);

LT ATCSE>LT ; LT ATCLT>SE — ATC between SE–LT and LT–SE Bidding Zones directions, determined by Operational Security limits in Baltic CCR TSOS' synchronous area or technical limitation on HVDC interconnection (from Lithuania side).

18.4. When flow-based capacity calculation with advanced hybrid coupling is utilized within Nordic CCR, operational security limits for CNEs within the Swedish AC grid adjacent to the HVDC interconnection are sufficiently reflected by the flow-based parameters of Nordic CCR. When this is the case, the ATC from the Swedish side shall reflect the technical limitation on HVDC interconnection only. When ATC extraction is utilized within Nordic CCR, such extracted capacities may be used to take operational security limits into account.

18.5. The NTC capacity for SE-LT cross-border shall use TRM equal to zero value in accordance with

Article 14.3 of this Methodology. The full TTC capacities shall be provided for market operations and shall comply with CEP Regulation Article 16(8).

18.6. AABC allocation referred in formula (4) for HVDC shall be defined in the balancing capacity exchange agreements between parties according to EBGL Article 38. In case no capacity exchange agreement is in place, AABC value for HVDC interconnectors shall be 0.

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Intraday capacity allocation procedure

18.7. The available capacity is reassessed after the Day-Ahead Market and offered to the Intraday Market in line with actual operational conditions. The intraday capacity can be influenced by changed TTC caused by changes in prognosis, topology, and in maintenance plans.

18.8. Intraday trading capacity on cross-border Lithuania-Sweden is allocated according to formulas (5) and (6).

19 TOTAL TRANSFER CAPACITY (TTC) CALCULATION FOR LITHUANIAN - POLAND AC CROSS-BORDER INTERCONNECTOR

19.1. While calculating TTC, list of considered CNE and contingencies should be determined according to Section 4.

19.2. While calculating TTC and performing contingency analyses after applying of N-1 criteria following Operational Security limits according to Article 25, Article 38 and Article 39 of SO GL shall be not exceeded:

19.2.1. Permanently allowed thermal limits, that correspond to the 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.

19.2.2. Voltage 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.

19.2.3. Dynamic stability limits including:

i. rotor angle stability and voltage stability.

ii. small signal stability (described in paragraph 19.3).

19.2.4. Frequency stability limit is assessed based on Baltic TSOs rules considering commonly agreed and coordinated availability of frequency support measures between Baltic TSOs. HVDC fast frequency response settings shall be agreed between all Baltic TSOs, Swedish TSO and Finnish TSO. Frequency stability limits are calculated by Lithuanian TSO taking into account the following 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.

19.3. TTC values for both directions are calculated considering small signal operational security stability limits (mentioned in 19.2.3.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)) (9)

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

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.

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TTC2(PL>LT) = TTC0(PL>LT) – MaxInf; TTC2(LT>PL) = TTC0(LT>PL) – MaxDem (10)

where:

TTC0(PL>LT); TTC0(LT>PL) – small signal stability limit without N-1 line outages in directions PL>LT and

LT>PL.

MaxInf - biggest N-1 infeed disconnection in BSPS.

MaxDem - biggest N-1 demand disconnection in BSPS.

19.4. The hourly values of matched TTC according to Operational Security limits defined in 19.2.1 - 19.2.3 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)) (11)

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 19.2.1 - 19.2.3 and 19.3.

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 19.2.1 - 19.2.3 and 19.3.

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 19.2.4.

19.5. The hourly values of matched TTC according to Operational Security limits defined in 19.2.1 - 19.2.3 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)) (12)

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 19.2.1 - 19.2.3 and 19.3.

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 19.2.1 - 19.2.3 and 19.3.

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 19.2.4.

20 TRADING CAPACITY CALCULATION RULES BETWEEN LITHUANIAN AND POLISH POWER SYSTEMS FOR DAY AHEAD TIMEFRAME

20.1. 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) (13)

where:

TTC(PL>LT) – TTC of Lithuania-Poland cross border interconnection in direction to Lithuania calculated by Polish and Lithuanian TSOs according to formula (11) as in 19.4.

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 14.6

20.2. NTC values for Lithuania-Poland Cross-Border Interconnection in direction to Poland shall be

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calculated by using following formula:

NTC(LT>PL) = TTC(LT>PL) – TRM(LT>PL) (14)

where:

TTC(LT>PL) – TTC of Lithuania-Poland cross border interconnection in direction to Poland calculated by Polish and Lithuanian TSOs according to formula (12) as in 19.5.

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 14.6.

20.3. TSOs ensure that the TRM shall not exceed 30% of the TTC calculated in accordance with Section 19 of this Methodology. NTC capacity availability shall comply with CEP Regulation Article 16(8).

21 INTRADAY AVAILABLE TRANSMISSION CAPACITY CALCULATION BETWEEN LITHUANIAN AND POLISH POWER SYSTEMS

21.1. The available capacity after the Day-Ahead Market results is offered to the Intraday Market in line with actual operational conditions. The intraday capacity can be influenced by changed TTC caused by changes in prognosis, topology, and in maintenance plans.

21.2. Intraday Trading Capacity on cross-border Lithuania-Poland in direction to Lithuania allocated according to formula:

ATCPL>LT = NTC(PL>LT) - AAC(PL>LT) + AAC(LT>PL) (15)

where:

NTC(PL>LT) - NTC between Lithuanian and Polish power systems calculated in accordance to formula

(13) by taking into account actual value of TTC(PL>LT) and TTC(PL>LT)(F) (TTC(PL>LT) and TTC(PL>LT)(F) used in day ahead time frame for NTC calculation can be changed in case of changes in prognosis, topology, and in maintenance plans).

AAC(PL>LT) - Already Allocated Capacity to the Lithuania-Poland interconnection in the direction from Poland to Lithuania for the time period after previous capacity allocation phases.

AAC(LT>PL) - Already Allocated Capacity to the Lithuania-Poland interconnection in the direction from Lithuania to Poland for the time period after previous capacity allocation phases.

21.3. Intraday Trading Capacity on cross-border Lithuania-Poland in direction to Poland allocated according to formula:

ATCLT>PL = NTC(LT>PL)- AAC (LT>PL) + AAC(PL>LT) (16)

where:

NTC(LT>PL) - NTC between Lithuanian and Polish power systems calculated according to formula (14) by taking into account actual value of TTC(LT>PL) and TTC(LT>PL)(F) (TTC(LT>PL) and TTC(LT>PL)(F) used in

day ahead time frame for NTC calculation can be changed in case of changes in prognosis, topology, and in maintenance plans).

AAC(PL>LT) - Already Allocated Capacity to the Lithuania-Poland interconnection in the direction from Poland to Lithuania for the time period after previous capacity allocation phases.

AAC(LT>PL) - Already Allocated Capacity to the Lithuania-Poland interconnection in the direction from Lithuania to Poland for the time period after previous capacity allocation phases.

22 CROSS-ZONAL CAPACITY VALIDATION AND COORDINATION METHODOLOGY

22.1. Each TSO shall validate and have the right to correct Cross-Zonal Capacity of the TSO's Bidding

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Zone borders or Critical Network Elements provided by the Capacity Calculator in accordance with Articles 27 to 31 of CACM Regulation.

22.2. Each TSO may reduce Cross-Zonal Capacity during the validation of Cross-Zonal Capacity referred to in this Section for reasons of Operational Security according to Article 26.3 of CACM

Regulation.

22.3. Article 26.2 of CACM Regulation (rule for splitting the correction of Cross-Zonal Capacity) is not included in this Methodology because Baltic TSOs network is radial which results in direct flows between areas without any loop flows and splitting of capacities among borders of Baltic CCR is not performed.

22.4. Capacity Calculator shall report cross-zonal capacity reduction in accordance with Article 26.5 of CACM Regulation.

22.5. Capacity coordination process determines final cross-border capacity values to be provided for electricity market. Capacity Calculator shall use TSOs validated cross-border capacity values for coordinating final values. If during capacity coordination process TSOs determine different capacity values for the same Cross-Border Interconnection the lowest value shall be used as a coordinated value.

23 CAPACITY CALCULATION FALLBACK PROCEDURES

23.1. According to Article 21(3) of the CACM Regulation, when the day-ahead capacity calculation for specific DA or ID capacity calculation MTUs cannot be calculated due to a technical failure in the tools, an error in the communication infrastructure, or corrupted or missing input data, the Baltic TSOs and the Capacity Calculator shall calculate the missing results by applying one of the following capacity calculation fallback procedures:

23.1.1. Capacity Calculator shall use latest data available considering available input data sets listed out in Section 10, CGM replacement procedures according to CGMES if CGM is not available and updated grid topology for calculating cross-zonal capacity.

23.1.2. If CGM is not available or Baltic TSOs IGMs are not included in CGM, Capacity Calculator shall create Regional Model (including Latvian TSO, Lithuanian TSO, Estonian TSO and Polish TSO IGMs, which includes all Baltic TSOs interconnectors and use Regional Model for capacity calculation.

23.2. If Cross-Zonal Capacities cannot be calculated, coordinated or provided to market operator by Capacity Calculator then neighbouring TSOs calculate and coordinate capacities for Cross-Border Interconnections among themselves and publish coordinated capacities to NEMO(s).

24 PROVISION AND ALLOCATION OF TRADING CAPACITY

24.1. Capacity Calculator shall provide calculated and validated Trading Capacities and allocation constraints for all trading time frames to MCO for subsequent capacity allocation through implicit auctioning carried out by MCO.

24.2. Trading Capacities within the Baltic CCR are provided and allocated, subject to allocation constraints, in day-ahead and intraday timeframes - Day Ahead Market and Intraday Market. No physical capacity is reserved for long-term capacity on the Baltic CCR borders.

24.3. Trading Capacities provided for trade between the Baltic CCR Bidding Zones are equal to the offered capacities calculated according to the Sections 11-23 of this Methodology, and which is

subsequently allocated through the implicit auctioning following the trading rules established by the MCO, subject to allocation constraints.

25 FIRMNESS

25.1. After the Day-ahead Firmness Deadline, all Cross-Zonal Capacity and allocation constraints are firm for day-ahead capacity allocation unless in case of Force Majeure or Emergency Situation.

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25.2. The Day-ahead Firmness Deadline is 60 minutes before Day-Ahead Gate Closure Time unless there is other deadline included in “All TSOs’ Proposal for the day-ahead firmness deadline (DAFD) in accordance with Article 69 of the Commission Regulation (EU) 2015/1222 of 24 July 2015 establishing a Guideline on Capacity Allocation and Congestion Management”.

25.3. After the Day-ahead Firmness Deadline, Cross-Zonal Capacity which has not been allocated may be adjusted for subsequent allocations, subject to allocation constraints.

25.4. Intraday Cross-Zonal Capacity is firm as soon as it is allocated, subject to allocation constraints, unless in case of Force Majeure or Emergency Situation.

26 RULES FOR AVOIDING UNDUE DISCRIMINATION BETWEEN INTERNAL AND CROSS- ZONAL EXCHANGES. CCR RULES FOR EFFICIENTLY SHARING THE POWER FLOW CAPABILITIES OF CRITICAL NETWORK ELEMENTS AMONG DIFFERENT BIDDING ZONE BORDERS

26.1. 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- border capacities is at least as high as prescribed in Article 16(8) of the Electricity Market Regulation 2019/943.

If cross-border capacities are limited below the level as prescribed in Article 16(8) of the Electricity Market Regulation 2019/943, this shall be described, motivated, communicated, and transparently presented by the TSOs to all the system users without undue delay. The TSOs shall find a long-term solution as soon as possible to correct such a situation and do so in a timely and transparent way. The TSOs shall also inform all system users of actions taken in order to find and execute the long- term solution.

26.2. The methodology, projects, and actions taken for achieving the long-term solution shall be described, motivated, communicated, and transparently presented by the TSOs to all the system

users without undue delay.

The methodology, projects, and actions taken for achieving the long-term solution can be described, motivated, communicated, and transparently presented in existing TSOs' documents:

• TSOs' individual power transmission system development documents.

• TSOs' common power transmission system development documents, e.g. ENTSO- E "Ten

year network development plan".

In case the methodology, projects, and actions taken for achieving the long-term solution is described, motivated, communicated, and transparently presented in existing TSOs' documents, creation of additional explanatory document(-s) or other relevant document(-s) is not required, unless deemed necessary by the NRAs in the Baltic CCR.

26.3. 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.

27 IMPLEMENTATION OF THE METHODOLOGY

27.1. The TSOs shall implement the Methodology when all the following provisions are fulfilled:

a) NRA approval of the Methodology within the Baltic CCR or a decision has been taken by the Agency for the Cooperation of Energy Regulators in accordance with Article 9(11) and 9(12) of the

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CACM Regulation.

b) Baltic TSOs are synchronised with CESA.

27.2. 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 for

the Cooperation of Energy Regulators in accordance with Article 9(11) and 9(12) of the CACM Regulation.

27.3. 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.

28 LANGUAGE

The reference language for this CCM shall be English. For the avoidance of doubt, where TSOs need to translate this CCM into their national language(s), in the event of inconsistencies between the English version published by TSOs in accordance with Article 9(14) of the CACM Regulation and any version in another language, the relevant TSOs shall, in accordance with national legislation, provide the relevant national regulatory authorities with an updated translation of the CCM.

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29 APPENDIX 1: USE OF ALLOCATION CONSTRAINTS

1. Justification for using allocation constraints in the form of import and export limits as described in Section 7.3

The link between net position and operational security limits

Under CACM Regulation, allocation constraints are understood as constraints needed to keep the transmission system within operational security limits, which are in turn defined as acceptable operating boundaries for secure grid operation. The definition of the latter (Art. 2.7 CACM Regulation) lists inter alia frequency limits as one of the boundaries to be taken into account.

With regard to constraints used to ensure sufficient operational reserves, if one of interconnected systems suffers from insufficient reserves in case of unexpected outages or unplanned load change (applies to central dispatch systems), there may be a sustained deviation from scheduled exchanges of the TSOs in question. These deviations may lead to an imbalance in the whole synchronous area,

causing the system frequency to depart from its nominal level. Even if frequency limits are not violated, as a result, deviation activates frequency containment reserves, which will thus not be available for another contingencies, if required as designed. If another contingency materializes, the frequency may in consequence easily go beyond its secure limits with all related negative consequences. This is why such a situation can lead to a breach of operational security limits and must be prevented by keeping necessary reserves within all bidding zones, so that no TSO deviates from its schedule in a sustained way (i.e. more than 15 minutes, within which frequency restoration reserve shall be fully deployed by given TSO). Finally, the inability to maintain scheduled area balances resulting from insufficient operational reserves will lead to uncontrolled changes in power flows, which may trigger lines overload (i.e. exceeding the thermal limits) and as a consequence can lead to system splitting with different frequencies in each of the subsystems.

Legal interpretation: eligible grounds for applying allocation constraints

Regarding the process of defining what allocation constraints should be applied, it should first be noted that allocation constraints (‘ACs’) are tools defined as to their purpose. CACM Regulation does not enumerate ACs in a form of a list which would allow for checking whether specific constraint is allowed by the Regulation. Thus, the application of provision on allocation constraints requires further interpretation.

CACM Regulation was issued based on Regulation 714/2009 and complements that Regulation. The general principle in Regulation 714/2009 (Art. 16.3), repeated in Regulation 2019/943 (Art. 16.4), is that TSOs make available the maximum capacity allowed under secure network operation standards. Operational security is explained in a footnote to annex I as keeping the transmission system within agreed security limits. CACM Regulation rules on AC and operational security limits (‘OSLs’) seem to regulate the same matter as Article 16.4 in greater detail. The definition of ACs relates to OSLs, so to define what is an allocation constraint, we first need a clear idea of OSLs.

Similarly to the ‘open’ notion of allocation constraints in the CACM Regulation, the definition of OSLs (the acceptable operating boundaries for secure grid operation such as thermal limits, voltage limits, short-circuit current limits, frequency and dynamic stability limits) does not include an enumerative catalogue (a closed set), but an open set of system operation characteristics defined as to their purpose - ensuring secure grid operation. The list is indicative (using the words ‘such as’). The open- set character of the definition is also indicated by systemic interpretation, i.e. by the usage of the term in other network codes and guidelines.

In SO GL, the definitions of specific system states involve a role of significant grid users (generating modules and demand facilities). To be in the ‘normal’ state, a transmission system requires sufficient active and reactive power reserves to make up for occurring contingencies (Art. 18) - the possible influence of such issues on cross-zonal trade has been mentioned above. Operational security limits

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as understood by SO GL are also not defined as a closed set, as Article 25 requires each TSO to specify the operational security limits for each element of its transmission system, taking into account at least the following physical characteristics (...). The CACM Regulation definition of contingency (identified and possible or already occurred fault of an element, including not only the transmission system elements, but also significant grid users and distribution network elements if relevant for the transmission system operational security) is therefore consistent with the abovementioned SO GL framework, and shows that CACM Regulation application should involve

circumstances related to generation and load. Moreover, as regards the way the TSOs procure balancing reserves, it should be noted that the Guideline on Electricity Balancing (EB GL) allows TSOs to apply integrated scheduling process in which energy and reserves are procured simultaneously (inherent feature of central dispatch systems). In such a case, ensuring sufficient reserves requires setting a limit to how much can be imported or exported by the system as a whole (explained in more detail below). If CACM Regulation is interpreted as excluding such a solution and mandating that a TSO offers capacity even if it may lead to insufficient reserves, this would make the provisions of EB GL void, and make it impossible or at least much more difficult to comply with SO GL.

In PSE’s point of view, systemic interpretation allows for consistent implementation of all network codes. In this specific case, understanding operational security limits under CACM Regulation can be complemented by applying SO GL provisions. These, in turn, require the TSOs to apply specific

market mechanisms to ensure that generation and load schedules resulting from cross-zonal trade do not endanger secure system operation. In sum, operational security limits cover a broad set of system characteristics to be respected when defining the domain for cross-zonal trade. With regard to generation and load, this is done by applying allocation constraints, in this case balancing constraints, in the form of import/export limits.

The CACM Regulation provisions on ACs should also be interpreted systemically. They ensure offering maximum possible trading opportunities while preserving system security. CACM Regulation and Regulation 2019/943 should also be interpreted in the light of Union policy on energy as prescribed in Article 194 of the TFEU. The four objectives (to ensure the functioning of the energy market; ensure security of energy supply in the Union; promote energy efficiency and energy saving and the development of new and renewable forms of energy; and promote the interconnection of energy networks) are of equal importance and are balanced against each other, as well as applied

in the spirit of solidarity between the Member States.

In the context of allocation constraints, these principles can be seen as requiring TSOs in each Member State to use market processes to ensure security of supply as far as possible, only limited by legitimate (non-arbitrary) constraints where not applying them could threaten security of supply in one or more control areas.

CACM Regulation provisions on allocation constraints reflect these trade-offs. See e.g. recital (18), which mandates that the Union-wide price coupling process respects transmission capacity and allocation constraints. Therefore, it can be concluded that CACM Regulation does not mandate trading opportunities to the point of endangering security of supply. If there is no arbitrary discrimination, CACM Regulation, along with other codes, allow a TSO to ex ante prevent loss of network stability or occurrence of insufficient reserves.

2. How import and export limits contribute to meeting the CACM Regulation objectives?

Contribution to meeting the CACM Regulation objectives

Recital 2 of CACM Regulation preamble draws a reciprocal relationship between security of supply and functioning markets. Thanks to grid interconnections and cross-zonal exchange, member states do not have to fully rely on their own assets in order to ensure security of supply. At the same time, however, the internal market cannot function properly if grid security is compromised, as market trade would constantly be interrupted by system failures, and as a result potential social welfare gains would be lost. Recital 18 can be seen as a follow-up, drawing boundaries to ensure a Union- wide price coupling process, namely to respect transmission capacity and allocation constraints.

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For the above reasons, one of the aims of the CACM Regulation, as expressed in Article 3, is to ensure operational security. This aim should be fulfilled insofar it does not prejudice other aims. As explained in this Methodology, allocation constraints applied by Baltic CCR TSOs are proportional and do not undermine other aims of CACM Regulation.

Compliance of the three reasons for allocation constraints with Article 23

Article 23 requires that allocation constraints are:

1) a) required to maintain the system within operational security limits and b) cannot be transformed efficiently into maximum flows on critical network elements; or 2) intended to increase the economic surplus for single day-ahead or intraday coupling. As demonstrated under point 1 above, maintaining the transmission system within operational security limits also requires maintaining the necessary reserves to respond to possible contingencies. The inability to efficiently transform these constraints into maximum flows on individual borders is explained below. Therefore, allocation constraints as proposed should be seen as compliant with the CACM Regulation.

3. Detailed reasons and method for calculating allocation constraints by PSE

Allocation constraints in Poland are applied as stipulated in the Article 5 of the Methodology. These constraints reflect the ability of Polish generators to increase generation (potential constraints in export direction) or decrease generation (potential constraints in import direction) subject to

technical characteristics of individual generating units as well as the necessity to maintain minimum generation reserves required in the whole Polish power system to ensure secure operation. This is explained further in subsequent parts of this document.

Rationale behind the 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 integrated scheduling based market model applied in Poland (also called central dispatch system) responsibility of Polish TSO on system balance is significantly extended comparing to such standard responsibility of TSO in so-called self-dispatch market models. The latter is usually defined up to hour-ahead time frame (including real time operations), while for PSE as Polish TSO this is extended to intraday and day-ahead time frames. Thus, PSE bears the responsibility, which in self dispatch markets is allocated to balance responsible parties (BRPs). That is why PSE needs to take care of back up generating reserves for the whole Polish power system, which sometimes leads to

implementation of allocation constraints if this is necessary to ensure operational security of Polish power system in terms of available generating capacities for upward or downward regulation capacity and residual demand1 (this is why such allocation constraints are called balancing constraints). 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- dispatch market, in order to provide generation and demand balance, the TSO dispatches generating units taking into account their operational constraints, transmission constraints and reserve requirements. This is realized in an integrated scheduling process as an optimisation problem called security constrained unit commitment and economic dispatch (SCUC/ED). Thus these two approaches ensure similar level of feasibility of transfer capacities offered to the market from the generating capacities point of view.

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 expected load, which is also

1 Residual demand is the part of end users’ demand not covered by commercial contracts (generation self -schedules).

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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 ED. The results of this day-ahead market are then updated continuously in intraday time frame up to real time operation.

In a yearly timeframe PSE tries to distribute the maintenance overhauls requested by generators along the year in such a way that the minimum year ahead reserve margin2 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 day3, if possible. This process includes also network maintenance planning, so any constraints coming from the network operation are duly taken into account.

The day-ahead SCUC process aims to achieve a set value of spinning reserve4 (or quickly activated, in current Polish reality only units in pumped storage plants) margin for each hour of the next day, enabling up and down regulation. This includes primary and secondary control power pre-contracted as an ancillary service. The rest of this reserve comes from usage of balancing bids, which are mandatory to be submitted by all centrally dispatched generating units (in practice all units connected to the transmission network and major ones connected to 110 kV, except CHP plants as they operate mainly according to heat demand). The remaining generation is taken into account as scheduled by owners, which having in mind its stable character (CHPs, small thermal and hydro) is

a workable solution. The only exception from this rule is wind generation, which due to its volatile character is forecasted by PSE. Thus, PSE has the right to use any available centrally dispatched generation in normal operation to balance the system. The negative reserve requirements during low load periods (night hours) are also respected and the potential pumping operation of pumped storage plants is taken into account, if feasible.

The further updates of SCUC/ED during the operational day take into account any changes happening in the system (forced outages and any limitations of generating units and network elements, load and wind forecast updates, etc.). It allows to keep one hour ahead spinning reserve at the minimum level of 1000 MW, which corresponds to the size of the largest unit in the system.

Determination of balancing constraints in Poland

When determining the balancing 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 horizons.

Balancing constraints are bidirectional, with independent values for each market time unit, and separately for directions of import to Poland and export from Poland.

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

= − ( + ) + − ( + ) (1)

2 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.

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

4These values are regulated by the Polish grid code (point 10.2.11(1)) and subject to change.

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= − + − (2)

where:

PCD - sum of available generating capacities of centrally dispatched units as declared by generators5

PCDmin - sum of technical minima of centrally dispatched generating units in operation

PNCD - sum of schedules of not centrally dispatched generating units, as provided by generators (for wind farms: forecasted by PSE)

PNA - generation not available due to grid constraints

PER - generation unavailabilities adjustment resulting from issues not declared by generators, forecasted by PSE due to exceptional circumstances (e.g. cooling conditions or prolonged

overhauls)

PL - demand forecasted by PSE

PUres - minimum reserve for up regulation

PDOWNres - minimum reserve for down regulation

For illustrative purposes, the process of practical determination of balancing 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 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.

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

is applicable if AImport is lower than the sum of transfer capacities on all Polish interconnections in import direction.

5 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.

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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 unavailabilities 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 wind farms: forecasted by PSE)

3. demand forecasted by PSE

4. minimum necessary reserve for up regulation

Figure 1: Determination of balancing 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 wind farms: forecasted by PSE)

3. demand forecasted by PSE, reduced by:

3.1 minimum necessary reserve for down regulation

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

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Frequency of re-assessment

Balancing constraints are determined in a continuous process based on the most recent information, for each capacity allocation time horizon, from forward till day-ahead and intraday. In case of day-ahead process, these are calculated in the morning od D-1, resulting in independent

values for each market time unit, and separately for directions of import to Poland and export from Poland.

Impact of balancing constraints on single day-ahead coupling and single intraday coupling

Allocation constraints in form of balancing constraints as applied by PSE do not diminish the efficiency of day-ahead and intraday market coupling process. Given the need to ensure adequate availability of generation and generation reserves within Polish power system by PSE as TSO acting under central-dispatch market model, and the fact that PSE does not purchase operational reserves ahead of market coupling process, imposing constraints on maximum import and export in market coupling process - if necessary - is the most efficient manner of reconciling system security with trading opportunities. This approach results in at least the same level of generating capacities participating in cross border trade as it is the case in self-dispatch systems, where reserves are bought in advance by BRPs or TSO so they do not participate in cross border trade, either.

Moreover, this allows to avoid competition between TSO and market participants for generation resources.

It is to be underlined that balancing constraints applied in Poland will not affect the ability of any Baltic CCR country to exchange energy, since these constraints only affect Polish export and/or import. Hence, transit via Poland will be possible in case of balancing constraints applied.

Impact of balancing constraints on neighbouring CCRs

Balancing constraints are determined for the whole Polish power system, meaning that they are applicable simultaneously for all CCRs, in which PSE has at least one border (i.e. Core, Baltic and Hansa).

It is to be underlined that this solution has been proven as the most efficient application of allocation constraints. Considering allocation constraints separately in each CCR would require PSE to split global allocation constraints into CCR-related sub-values, which would be less efficient than

maintaining the global value. Moreover, in the hours when Poland is unable to absorb any more power from outside due to violated minimal downward generation requirements, or when Poland is unable to export any more power due to insufficient generation reserves in upward direction, Polish transmission infrastructure still can be - and indeed is - offered for transit, increasing thereby trading opportunities and social welfare in all concerned CCRs.

Time periods for which balancing constraints are applied

As mentioned above, balancing constraints are determined in a continuous process for each allocation timeframe, so they are applicable for all market time units of the respective allocation day.

Why these allocation constraints cannot be efficiently translated into capacities of - individual borders offered to the market

Use of capacity allocation constraints aims to ensure economic efficiency of the market coupling mechanism on these interconnectors while meeting the security requirements of electricity supply

to customers. If the generation conditions described above were to be reflected in cross-border capacities offered by PSE in form of an appropriate adjustments of border transmission capacities, this would imply that PSE would need to guess most likely market direction (imports and/or exports on particular interconnectors) and accordingly reduce the cross-zonal capacities in these directions. In the NTC approach, this would need to be done in the form of ATC reduction per border. However, from the point of view of market participants, due to the inherent uncertainties of market results such approach is burdened with the risk of suboptimal splitting of allocation constraints into individual interconnections - overstated on one interconnection and underestimated on the other or vice versa. Consequently, application of allocation constraints to tackle the overall Polish balancing constraints

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at the allocation phase allows for the most efficient use of transmission infrastructure, i.e. fully in line with price differences in individual markets.

POSITION PAPER BY ALL BALTIC CAPACITY CALCULATION REGION NATIONAL REGULATORY

AUTHORITIES

ON

THE ALL BALTIC CAPACITY CALCULATION REGION TRANSMISSION SYSTEM OPERATORS’ PROPOSAL

FOR CAPACITY CALCULATION METHODOLOGY FOR THE DAY-AHEAD AND INTRADAY MARKET

TIMEFRAMES WITHIN THE BALTIC CAPACITY CALCULATION REGION

21 November 2024

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I. Introduction and legal context

The three Baltic countries will synchronize with the Continental Europe Synchronous Area (CESA) in the first quarter of 2025. In addition, considering the Baltic capacity calculation region, (Estonia, Finland, Latvia, Lithuania, Poland and Sweden) (CCR) the National Regulatory Authorities (NRAs) (i.e. Estonian Competition Authority (ECA), Energy Authority of Finland (EV)), Public Utilities Commission of Latvia (PUC), National Energy Council of Lithuania (NERC), Energy Regulatory Office of Poland (ERO) and Swedish Energy Markets Inspectorate (Ei))1, Agreement by all Regulatory Authorities of Baltic CCR on the implementation of a common capacity calculation methodology in accordance with Article 20 of Commission Regulation (EU) 2015/1222 of 24 July 2015 establishing a Guideline on Capacity Allocation and Congestion Management on the 29 January 2021, the Baltic CCR NRAs encouraged the Baltic CCR transmission system operators (TSOs) (i.e. AS “Augstsprieguma tikls”, Elering AS, Fingrid Oy, Litgrid AB, PSE S.A. and Svenska Kraftnät)2 to develop a new day-ahead (DA) and intraday (ID) capacity calculation methodology (CCM). The Baltic CCR TSOs will therefore submit a new DA and ID CCM proposal to the Baltic CCR NRAs in accordance with Article 20(2) of Commission Regulation (EU) 2015/1222 of 24 July 2015 establishing a guideline on capacity allocation and congestion management (hereinafter - CACM Regulation 2015/1222).

Considering these circumstances and pursuant to Articles 9(1), 9(7)(c) and 35(1) of the CACM Regulation 2015/1222, the Baltic CCR TSOs are required to jointly develop an updated proposal of the CCM for DA and ID market timeframes within the Baltic CCR and submit it to all the Baltic CCR NRAs for approval.

In accordance with Article 9(10) of the CACM Regulation 2015/1222, all Baltic CCR NRAs receiving the CCM proposal should reach an agreement and take a decision on that proposal, within six months after the receipt of the proposal by the last Baltic CCR NRA. The date of the receipt of the proposal by the last NRA is 24 January 2024. If the Baltic CCR NRAs request an amendment to approve the CCM proposal, pursuant to Article 9(12) of the CACM Regulation 2015/1222, the relevant Baltic CCR TSO shall submit an amended proposal for approval within two months following the Baltic CCR NRAs’ request. Subsequently, all Baltic CCR NRAs shall reach an agreement and take a decision on the CCM proposal, within two months after the receipt of the amended proposal by the last Baltic CCR NRA.

This document elaborates an agreement of all Baltic CCR NRAs on all Baltic CCR TSOs CCM proposal in accordance with Article 20(2) of CACM Regulation 2015/1222.

The agreement of all Baltic CCR NRAs on all Baltic CCR TSOs CCM proposal is intended to constitute the basis on which each NRA should subsequently make legally binding national level decision regarding approval of the CCM proposal pursuant to Article 9(7)(a) of CACM Regulation 2015/1222.

1 Hereinafter – Baltic CCR NRAs. 2 Hereinafter – Baltic CCR TSOs.

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Each of the national decision should reflect Baltic CCR NRAs agreement reached between TF members and be made within the deadline specified for approval, in this case, until 25 November 2024. NRAs have obligation to inform the relevant TSO about the results.

The Baltic CCR TSOs, in accordance with the CACM Regulation 2015/1222, have prepared an updated CCM for the DA and ID market timeframes within the Baltic CCR.

The Baltic CCR NRAs, in accordance with the CACM Regulation 2015/1222, have prepared a request for amendments and sent it the 24 July 2024.

The Baltic CCR TSOs, in accordance with the CACM Regulation 2015/1222, have prepared an updated CCM for the DA and ID market timeframes regarding the request for amendments within the Baltic CCR and sent 23 September 2024.

The Baltic CCR NRAs need to make a decision concerning the updated CCM proposal by the 25 November 2024.

The legal provisions relevant to the submission and approval of the CCM proposal and Baltic CCR NRAs agreement on the CCM proposal, can be found in Articles 3, 9, 12, and 20, 21, 23 of the CACM Regulation 2015/1222.

Article 3 of CACM Regulation 2015/1222

This Regulation aims at:

(a) Promoting effective competition in the generation, trading and supply of electricity;

(b) Ensuring optimal use of the transmission infrastructure;

(c) Ensuring operational security;

(d) Optimising the calculation and allocation of cross-zonal capacity;

(e) Ensuring fair and non-discriminatory treatment of TSOs, NEMOs, the Agency, regulatory authorities and market participants;

(f) Ensuring and enhancing the transparency and reliability of information;

(g) Contributing to the efficient long-term operation and development of the electricity transmission system and electricity sector in the Union;

(h) Respecting the need for a fair and orderly market and fair and orderly price formation;

(i) Creating a level playing field for NEMOs;

(j) Providing non-discriminatory access to cross-zonal capacity

Article 9 of CACM Regulation 2015/1222

4

1. TSOs and NEMOs 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 or NEMOs, the deadlines for terms and conditions or methodologies may be prolonged by the Agency in procedures pursuant to paragraph 6, jointly by all competent regulatory authorities in procedures pursuant to paragraph 7, and by the competent regulatory authority in procedures pursuant to paragraph 8.

Where a proposal for terms and conditions or methodologies pursuant to this Regulation needs to be developed and agreed by more than one TSO or NEMO, the participating TSOs and NEMOs shall closely cooperate. TSOs, with the assistance of the ENTSO for Electricity, and all NEMOs shall regularly inform the competent regulatory authorities and the Agency about the progress of developing those terms and conditions or methodologies.

[…]

5. Each regulatory authority or where applicable the Agency, as the case may be, shall approve the terms and conditions or methodologies used to calculate or set out the single day-ahead and intraday coupling developed by TSOs and NEMOs. They shall be responsible for approving the terms and conditions or methodologies referred to in paragraphs 6, 7 and 8. 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 or NEMOs, 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.

[…]

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 common capacity calculation methodology in accordance with Article 20(2).

[…]

9. The proposal for terms and conditions or methodologies shall include a proposed timescale for their implementation and a description of their expected impact on the objectives of this Regulation. Proposals for terms and conditions or methodologies subject to the approval by several regulatory authorities in accordance with paragraph 7 shall be submitted to the Agency within 1 week of their submission to regulatory authorities. Proposals for terms and conditions or methodologies subject to the approval by one regulatory authority in accordance with paragraph 8 may be submitted to the Agency within 1 month of their submission at the discretion of the regulatory authority while they shall be submitted upon the Agency’s request for information purposes in accordance with Article 3 paragraph 2 of the Regulation (EU) 2019/942 if the Agency considers the proposal to have a cross - border impact. Upon request by the competent regulatory authorities, the Agency shall issue an opinion within 3 months on the proposals for terms and conditions or methodologies.

5

10. Where the approval of the terms and conditions or methodologies in accordance with paragraph 7 or the amendment in accordance with paragraph 12 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, 7 and 8, within 6 months following the receipt of the terms and conditions or methodologies by the Agency or the regulatory authority 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, to the last regulatory authority concerned in accordance with paragraph 7 or, where applicable, to the regulatory authority in accordance with paragraph 8.

[…]

12.

In the event that the Agency, or all competent regulatory authorities jointly, or the competent regulatory authority request an amendment to approve the terms and conditions or methodologies submitted in accordance with paragraphs 6, 7 and 8 respectively, the relevant TSOs or NEMOs shall submit a proposal for amended terms and conditions or methodologies for approval within 2 months following the request from the Agency or the competent regulatory authorities or the competent regulatory authority. The Agency or the competent regulatory authorities or the competent regulatory authority shall decide on the amended terms and conditions or methodologies within 2 months following their submission. Where the competent regulatory authorities have not been able to reach an agreement on terms and conditions or methodologies pursuant to paragraph 7 within the 2-month deadline, or upon their joint request, or upon the Agency’s request according to the third subparagraph of Article 5(3) of Regulation (EU) 2019/942, the Agency shall adopt a decision concerning the amended terms and conditions or methodologies within 6 months, in accordance with Article 5(3) and the second subparagraph of Article 6(10) of Regulation (EU) 2019/942. If the relevant TSOs or NEMOs fail to submit a proposal for amended terms and conditions or methodologies, the procedure provided for in paragraph 4 of this Article shall apply.

13. TSOs and NEMOs 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 authorities or, if no such approval is required, after their establishment, except where such information is considered as confidential in accordance with Article 13.

Article 12 of CACM Regulation 2015/1222

1. TSOs and NEMOs responsible for submitting proposals for terms and conditions or methodologies or their amendments in accordance with this Regulation shall consult stakeholders, including the relevant authorities of each Member State, on the draft proposals for terms and conditions or methodologies where explicitly set out in this Regulation. The consultation shall last for a period of not less than one month.

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2. […] Proposals submitted by the TSOs and NEMOs at regional level shall be submitted to consultation at least at regional level. […]

3. The entities responsible for the proposal for terms and conditions or methodologies shall duly consider the views of stakeholders resulting from the consultations undertaken in accordance with paragraph 1, prior to its submission for regulatory approval if required in accordance with Article 9 or prior to publication in all other cases. In all cases, a clear and robust justification for including or not the views resulting from the consultation shall be developed in the submission and published in a timely manner before or simultaneously with the publication of the proposal for terms and conditions or methodologies.

Article 20 of CACM Regulation 2015/1222

1. For the day-ahead market time-frame and intraday market time-frame the approach used in the common capacity calculation methodologies shall be a flow-based approach, except where the requirement under paragraph 7 is met.

2. […], all TSOs in each capacity calculation region shall submit a proposal for a common coordinated capacity calculation methodology within the respective region. The proposal shall be subject to consultation in accordance with Article 12. […]

[…]

7. TSOs may jointly request the competent regulatory authorities to apply the coordinated net transmission capacity approach in regions and bidding zone borders other than those referred to in paragraphs 2 to 4, if the TSOs concerned are able to demonstrate that the application of the capacity calculation methodology using the flow-based approach would not yet be more efficient compared to the coordinated net transmission capacity approach and assuming the same level of operational security in the concerned region.

[…]

Article 21 of CACM Regulation

1. The proposal for a common capacity calculation methodology for a capacity calculation region determined in accordance with Article 20(2) shall include at least the following items for each capacity calculation time-frame:

(a) methodologies for the calculation of the inputs to capacity calculation, which shall include the following parameters:

[…]

(ii) the methodologies for determining operational security limits, contingencies relevant to capacity calculation and allocation constraints that may be applied in accordance with Article 23.

[…]

Article 23 of CACM Regulation

7

[…]

3. If TSOs apply allocation constraints, they can only be determined using:

(a) constraints that are needed to maintain the transmission system within operational security limits and that cannot be transformed efficiently into maximum flows on critical network elements; or

(b) constraints intended to increase the economic surplus for single day-ahead or intraday coupling.

II. The CCM proposal

The Baltic CCR TSOs: AS “Augstsprieguma tikls”, Elering AS, Fingrid Oy, Litgrid AB, PSE S.A. and Svenska Kraftnät submitted the initial CCM proposal and CCM Explanatory Document on 24 January 2024, as well as the amended CCM proposal on 23 September 2024 to the Baltic CCR NRAs: Estonian Competition Authority, Public Utilities Commission of Latvia, National Commission for Energy Control and Prices of Lithuania, Energy Regulatory Office of Poland, Swedish Energy Markets Inspectorate and Energy Authority of Finland.

The CCM proposal cover cross-zonal capacity calculation, provision and allocation for day-ahead and intraday time horizons. This CCM 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. Upon synchronisation, the capacity of this interconnector will be determined considering principles described in whereas (54) of Regulation (EU) 2024/1747.

III. Agreed Baltic CCR NRAs’ position

By 25 January 2024 all Baltic CCR NRAs received the CCM proposal. On 24 July 2024, after careful evaluation of the CCM proposal and mutual consultations, due to several issues related to inaccurate provisions and insufficiently detailed descriptions of them, Baltic CCR NRAs reached an agreement to a request for amendment on the CCM proposal. The relevant letters expressing Baltic CCR NRAs common view (Request for amendment document agreed by all Baltic CCR NRAs on 24th July 2024) were sent to all Baltic CCR TSOs requesting TSOs to amend the CCM proposal.

The Baltic CCR TSOs, in accordance with the CACM Regulation 2015/1222, have prepared an updated CCM for the DA and ID market timeframes within the Baltic CCR.

By 23 September 2024, TSOs submitted to all Baltic CCR NRAs the amended CCM proposal in accordance with the Baltic CCR NRAs request, together with additional conditions regarding implementation time of the proposed CCM.

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Having assessed the TSOs´ amended proposal, the Baltic CCR NRAs came to the conclusion that even though the amendments are largely in line with the request for amendments, there still are some places to improve. As a result, the Baltic CCR NRAs decided to revise parts of the Baltic DA/IC CCM before the approval, in accordance with Art. 5(6) of Regulation 2019/942 (hereinafter ACER regulation) and Art. 9(5) of the CACM. On 15 November 2024, the Baltic CCR NRAs sent a letter to the Baltic CCR TSOs’ representatives to consult the TSOs on the planned revisions to the methodology.

Baltic CCR NRAs decided to revise the methodology by making the following changes:

1. Add 4.5. paragraph in Article 4: “In accordance with Article 29 and 30 of the CACM Regulation, capacity calculation shall be performed by the Capacity Calculator whereas the TSOs shall provide required input data and perform validation” and align with 15.1 paragraph in Article 15, 17.1. paragraph in Article 17, and 18.1. paragraph in Article 18.

2. Update the 5.2 paragraph in Article 5: “The CNEs for capacity calculation shall be defined considering impact computation principles defined in CSA methodology annex 1 and factor determining impact for CNE shall be cross zonal power flow exchange. Internal CNEs which power flow filtering influence factor is less than defined in annex 1 of CSA methodology shall be excluded from capacity calculation process. The TSO shall update the CNE list in case of significant change in grid topology when influence value for CNE element significantly changed from average value. If an internal CNE constitutes structural congestion the TSO shall ensure that cross-border capacities are not impacted by the CNE.”

3. Amendment in paragraph 9.1 in Article 9: “TSOs shall provide for Capacity Calculator information on available and applicable non-costly and costly remedial actions that shall be used in capacity calculation process.”

4. Amendment in paragraph 9.4 in Article 9: “Countertrading and redispatching possibilities along with other remedial actions shall be fully exploited in the DA and ID capacity calculation in accordance with Article 16(4) of the Electricity Market Regulation 2019/943. Thus, the TSOs shall ensure that Article 16(8) of the Electricity Market Regulation 2019/943 is adhered to.”

5. Amendment in Article 14.6: "For initial operation period after Baltic TSOs synchronisation with CESA, fixed TRM values shall be applied to LT-LV, LV-EE, and LT-PL Cross-Borders. These values shall be applied during a transitory period of at least 1 month. After this period, the TSOs shall calculate the TRMs according to principles set out in 14.4 and 14.5. Before applying the calculated TRMs, TSOs shall demonstrate to the NRAs that the calculated TRMs do not violate the requirement set in Article 16(8) of the Electricity Market Regulation 2019/943. Fixed values provided in Table 1."

6. Amendment in paragraph 15.1 in Article 15: “Capacity Calculator calculates NTC value for Internal Baltic AC interconnectors and Available Transmission Capacity (ATC) for both interconnection directions. ATC would represent capacity allocations for day ahead timeframe. Calculation shall be performed using following equations:”

7. Amendment of Article 17.1: "TTCs on cross-border Estonia-Finland are calculated by the Capacity Calculator using CGMs that represent the AC-networks of observable areas of

9

synchronous areas that each belong to and validated by the respective TSO on both sides of the interconnector."

8. Amendment of Article 18.1: "TTCs on cross-border Lithuania-Sweden are calculated by the Capacity Calculator using CGMs that represent the AC-networks of observable areas of synchronous areas that each belong to and validated by the respective TSO on both sides of the interconnector."

9. Following paragraphs have been updated in Article 26:

a. 26.1: ”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-border capacities is at least as high as prescribed in Article 16(8) of the Electricity Market Regulation 2019/943.

If cross-border capacities are limited below the level as prescribed in Article 16(8) of the Electricity Market Regulation 2019/943, this shall be described, motivated, communicated, and transparently presented by the TSOs to all the system users without undue delay. The TSOs shall find a long-term solution as soon as possible to correct such a situation and do so in a timely and transparent way. The TSOs shall also inform all system users of actions taken in order to find and execute the long-term solution.”

b. 26.2: “The methodology, projects, and actions taken for achieving the long-term solution shall be described, motivated, communicated, and transparently presented by the TSOs to all the system users without undue delay.

The methodology, projects, and actions taken for achieving the long-term solution can be described, motivated, communicated, and transparently presented in existing TSOs' documents:

• TSOs' individual power transmission system development documents.

• TSOs' common power transmission system development documents, e.g. ENTSO- E "Ten years network development plan".

In case the methodology, projects, and actions taken for achieving the long-term solution is described, motivated, communicated, and transparently presented in existing TSOs' documents, creation of additional explanatory document(-s) or other relevant document(-s) is not required, unless deemed necessary by the NRAs in the Baltic CCR.“

10. Add 27.3. paragraph in Article 27: “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.”

11. Some editorial corrections (updating the list of abbreviations and introducing alphabetical order, editing the listing of paragraphs, unifying some notations etc.).

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After revising the methodology by NRAs, the Baltic CCR NRAs have come to the common opinion that the methodology proposal meets the requirements of the CACM. The revised version of Baltic DA/ID CCM can be approved by the Baltic CCR NRAs.

The Baltic CCR NRAs sent the Baltic CCR DA/ID CCM with amendments to the TSOs on 15 November 2024 and informed them that these are the changes the NRAs are making during the revision in accordance with Article 9(5) of the CACM and Article 5(6) of ACER regulation.

The Baltic CCR NRAs need to make a decision concerning the updated CCM proposal by the 25 November 2024.

IV. Conclusions The Baltic CCR NRAs welcome the submitted Methodology proposal. The Baltic CCR NRAs have assessed, consulted and closely cooperated and coordinated to reach an agreement on the Methodology proposal which after the NRA revision meets the requirements of the CACM and can thus be approved by the Baltic CCR NRAs. Thereby, the Baltic CCR NRAs shall take their respective national decisions to approve the proposal regarding Article 9(7)(a) and Article 20(2) of the CACM, based on this agreement, by the 25 November 2024 at the latest.