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PC-03 - Framework Guidelines on Capacity Allocation and Congestion Management for Electricity
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PC-03-FG-ECA-and-CM
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| BRACCO |
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| PC-03-AESNI-U |
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| PC-03-ALPI2-I |
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| PC-03-ALPIQ-2 |
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| PC-03-BALTI-I |
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| PC-03-BARRJ-Y |
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| PC-03-BIERC-O |
Christoph Bier
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VIK e.V.
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c.bier@vik.de
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++49-201-8108423
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Germany
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| PC-03-BNEDE-1 |
Arndt Börkey
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bne
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arndt.boerkey@bne-online.de
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+49 30 400 548 15
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Germany
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| PC-03-BOLAS-L |
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| PC-03-BRITB-V |
Damian Bach
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BritNed Development Limited
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damian.bach@britned.com
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+44 7970 042119
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Netherlands
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| PC-03-CBI00-Y |
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| PC-03-CBIUK-C |
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| PC-03-DANSK-X |
Henrik Lind
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Danske Commodities A/S
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lind@danskecommodities.dk
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+4528308004
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Denmark
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| PC-03-DANTR-G |
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| PC-03-DEWAT-D |
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| PC-03-EDFFR-X |
Boursier
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EDF
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josselin.boursier@edf.fr
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+33 (0)1 40 42 32 47
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France
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| PC-03-EDISO-N |
Andrea Pompa
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Edison SpA
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andrea.pompa@edison.it
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+39 02 6222 8573
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Italy
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| PC-03-EDITH-Z |
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| PC-03-EFET-X |
NA
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EFET
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stefano.bracco@acer.europa.eu
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+XXX
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| PC-03-EGELH-O |
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| PC-03-ENBWD-C |
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| PC-03-ENDES-S |
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| PC-03-ENECO-2 |
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| PC-03-ENELI-N |
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| PC-03-ENERG-9 |
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| PC-03-ENERN-V |
Ruud Otter
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Energie-Nederland
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rotter@energie-nederland.nl
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+31 70 311 4366
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Netherlands
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| PC-03-ENTSE-M |
Ana Pravica
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ENTSO-E
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ana.pravica@entsoe.eu
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+3227410986
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Belgium
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| PC-03-EPEXS-T |
Wolfram VOGEL
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EPEX Spot SE - Exchange Council of EPEX Spot
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w.vogel@epexspot.com
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0033173036132
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France
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| PC-03-EUREL-N |
NA
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NA
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stefano.bracco@acer.europa.eu
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NA
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| PC-03-EUROP-L |
MANUEL COXE
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EUROPEX
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manuel.coxe@europex.org
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+3225123410
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Belgium
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| PC-03-EWEAB-A |
Paul Wilczek
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EWEA
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paul.wilczek@ewea.org
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+3222131834
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Belgium
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| PC-03-EXXDA-9 |
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| PC-03-FERDM-Q |
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| PC-03-FSEDK-C |
Anders Plejdrup Houmøller
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FSE secretariat
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aph@norenergi.dk
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+45 28 11 23 00
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Denmark
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| PC-03-FUBER-X |
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| PC-03-GASNA-U |
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| PC-03-HECKM-H |
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| PC-03-HUHTO-U |
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| PC-03-IBERB-J |
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| PC-03-IBERS-L |
Sergio Arteta
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Iberdrola
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sarteta@iberdrola.es
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917842312
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Spain
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| PC-03-IFIEC-K |
Luis de Miguel
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IFIEC
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luis.de-miguel@arcelormittal.com
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+352 4792 2367
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Luxembourg
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| PC-03-JPMCH-G |
Catherine Sutcliffe
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J.P. Morgan
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catherine.a.sutcliffe@jpmchase.com
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02077422722
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United Kingdom
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| PC-03-KREST-W |
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| PC-03-LANGG-T |
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| PC-03-MACHV-Y |
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| PC-03-MCLEG-R |
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| PC-03-MUHSY-J |
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| PC-03-MURLA-C |
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| PC-03-NAEOI-P |
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| PC-03-NORDP-U |
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| PC-03-OESTE-8 |
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| PC-03-PETVV-U |
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| PC-03-REDEL-9 |
Antonio Lucio-Villegas
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Red Eléctrica de España, SAU
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alucio@ree.es
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+3222272702
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Belgium
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| PC-03-RWEST-A |
William Webster
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RWE Supply & Trading GmbH
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william.webster@rwe.com
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+44 (0) 1793 892612
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United Kingdom
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| PC-03-RYANA-O |
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| PC-03-SCHLE-Q |
Schlegel Walter / Meier Mathieu
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ElCom - Swiss Federal Electricity Commission
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walter.schlegel@elcom.admin.ch / mathieu.meier@elcom.admin.ch
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+41 31 322 57 24 / + 41 31 322 52 46
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Switzerland
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| PC-03-SOLVY-O |
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| PC-03-SONCH-Z |
Charlotte Søndergren
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Nordenergi
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chs@danskenergi.dk
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+4522750424
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Denmark
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| PC-03-SSEUK-R |
Will Steggals
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SSE
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will.steggals@sse.com
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07837383386
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United Kingdom
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| PC-03-SWECO-H |
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| PC-03-SWISE-9 |
Beat Moser
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swisselectric (swissenergy)
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beat.moser@swisselectric.ch
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+41 31 381 64 00
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Switzerland
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| PC-03-SWISS-H |
Alexander Wirth
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Swissgrid
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alexander.wirth@swissgrid.ch
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+41 585802720
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Switzerland
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| PC-03-TOLEG-X |
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| PC-03-VATTE-I |
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| PC-03-VERBU-S |
Walburga Hemetsberger
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VERBUND AG
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walburga.hemetsberger@verbund.com
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+32 2 227 1151
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Austria
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| PC-03-VILCA-X |
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| PC-03-WARTJ-A |
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| PC-03-WUNNM-A |
Dr. Michael Wunnerlich
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BDEW German Association of Energy and Water Industries
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michael.wunnerlich@bdew.de
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+32 2 771 9642
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Belgium
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| PC-03-WWFEU-7 |
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not assigned users
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| PC-03-POMPA-W |
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| 2 | Please, provide your comments here (in case you exceed 3.500, add the rest to point 3)
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| | Maximum length: 3500 characters |
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PC-03-FG-ECA-and-CM
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| BRACCO |
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| PC-03-AESNI-U |
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| PC-03-ALPI2-I |
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| PC-03-ALPIQ-2 |
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| PC-03-BALTI-I |
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| PC-03-BARRJ-Y |
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| PC-03-BIERC-O |
VIK, the German association of industrial energy intensive consumers, welcomes the Draft Framework Guidelines on Capacity Allocation and Congestion Management for Electricity as an essential part of creating an internal energy market in Europe. VIK has supported the European goal of creating an integrated energy market from the beginning. It is essential for European industrial consumers that Europe creates a level playing field where consumers can purchase electricity at competitive non-discriminatory prices. Competitive commodity prices can only be achieved by competition in a well organized, transparent, and liquid market.
In creating such an integrated market, it is important to take into account the achievements reached so far. This is especially valid with regard to the bidding and price zones. While the overall aim of market integration is to create larger zones, ultimately leading to one single zone, it is important not to fall back behind what has been achieved up to now. Therefore, on the path to only one single zone, it is essential that existing zones will be integrated into larger price zones. It would be a significant step backwards to split up existing price zones. This has to be avoided, since it would reduce liquidity, thus weakening functioning markets.
That means: Although introducing new market zones might be justified from the Capacity Allocation and Congestion Management point of view, it usually has negative impacts on electricity market functionality and competition, especially when it means that existing zones would be split up, destroying functioning markets.
For example, the German single price zone has been extended to Austria in the past. This is an example of successful integration of existing zones. Splitting up such a zone, possibly even in more than two smaller zones, would clearly be a step backwards with respect to the overall goal of market integration. Moreover, in Germany, recently, steps have been taken by the regulator to create a more integrated balancing market, by enforcing stronger cooperation between the four balancing zones. This has led to an increase in liquidity in the balancing market as well as a reduction in balancing costs. Such achievements would be thwarted if the market would be split up.
Therefore, VIK advises against changing existing zones without an in-depth analysis on the local and overall effects. It is important to create zones not solely according to network topology. Instead, the definition of a bidding zone should be on the basis of the most economical solution. In some cases this might be network topology. But it could also be the case that – maybe with some investments – another solution becomes more appropriate. Estimations of the overall socio-economic benefits of new bidding zones should be taken into account. Zones should be defined on the basis of creating the greatest social welfare for the market as a whole. In that sense, it is also important to consider criteria like market power.
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| PC-03-BNEDE-1 |
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| PC-03-BOLAS-L |
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| PC-03-BRITB-V |
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| PC-03-CBI00-Y |
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| PC-03-CBIUK-C |
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| PC-03-DANSK-X |
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| PC-03-DANTR-G |
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| PC-03-DEWAT-D |
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| PC-03-EDFFR-X |
EDF welcomes the opportunity to answer this ACER consultation related to Capacity Allocation and Congestion Management (CACM). These draft Framework Guidelines, built on an Initial Impact Assessment (IIA) and on an evaluation of the responses to the public consultation carried out by ERGEG in 2010, describes accurately the goals to be achieved on the intraday, day-ahead and forward timeframes as well as on the capacity calculation.
From EDF’s perspective, these orientations are globally in line with the strategic model on CACM that have been addressed at European Union level through the work done by the Project Coordination Group and the additional guidance from the Ad Hoc Advisory Group and, since 2011, the ACER Electricity Stakeholders Advisory Group.
The attached comments address, in a detailed manner, the specific questions and issues raised by this consultation on the proposed Framework Guidelines (FG) on CACM. Through its complete response, EDF wishes to highlight the following key points:
- Most importantly, for cross-border intraday, the interim step shall allow a direct OTC access to the CMM on all borders. This open infrastructure should not be considered as a minor interim step since it will provide all the major improvements that the market can expect in terms of TSOs coordination, harmonisation of products and rules and coordinated intraday capacity calculation to maximise volumes;
- For forward markets, FTR options issued by the TSOs on all the European borders shall be the rule for coupled markets. In other cases, PTR rights with UIOSI will also be an acceptable solution;
- The Flow Based method, if clear added value is demonstrated, shall be cautiously implemented in order to ensure market adaptation and confidence (extensive parallel run, ATC and FB analysis of the interactions on different borders and timeframes);
- If the implementation of the Flow Based methodology jeopardizes the fast achievement of the price Market Coupling for a region (like in the CEE zone), then EDF prefers to move first to an ATC Market Coupling, which brings the highest increase of overall social welfare and which is now clearly familiar to all market players;
- When addressing the definition of bidding zones, costs/benefits analyses and tight consultation of market participants shall be conducted under NRAs scrutiny to ensure that these decisions effectively lead to increased overall economic efficiency, taking into account possible negative impacts of smaller bidding zones (operational difficulties, liquidity, etc.);
- The easy implementation of these FG provisions on CACM is highly dependent on the removal of national market design barriers on all timeframes, in particular for intraday markets;
- The extension of price market coupling should be pragmatic and based on a common TSOs/PXs analysis of the existing initiatives and of the available solutions.
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| PC-03-EDISO-N |
ACER FGs go in the right direction as regards the implementation of the Target Model for European Electricity Market as defined in the Florence Forum (December 2009). Nevertheless, we think that FGs should be more explicit on the need to establish interim steps for specific issues, such as the evolution from bilateral ATC calculation towards coordinated ATC and/or flow based methods, direct OTC access to CMM and the implementation of continuous trading in intra-day markets. An explicit provision of interim steps for these topics would help market players and TSOs to smoothly adapt to the new regulatory framework.
As far as cross-border capacity calculation is concerned, Edison shares ACER position on the possibility for TSOs to choose either the flow-based (FB) or the coordinated ATC method. As correctly stated in these FGs, capacity calculation methods should be approved by NRAs after a consultation with relevant stakeholders, whereas market parties should have enough time to adapt to these new methodologies. However, we think that the FB capacity calculation shouldn’t be seen a priori as preferred to coordinated ATC, when clear empirical evidences are still lacking. Yet, whatever calculation method is finally implemented, a high level of transparency is greatly needed. The reliability margins used to calculate available capacity and the methodologies/assumptions selected to define the common grid model should be published and adequately justified by TSOs.
As regards delimitation of zones, we agree with the definition provided in these FGs. Nonetheless, we think it should be clarified that the existence of different bidding zones, at national and European level, doesn’t prevent the creation of a single price zone. Furthermore, when stating that zone delimitation should be coordinated with balancing zones, ACER should make clear that balancing areas overlapping bidding zones cannot be excluded.
As regards intraday markets, we believe that CACM methodologies for cross-border interconnections should be fully compatible with the methodologies in force at national level, e.g. in case of pool markets. A harmonization extended to national capacity allocation and congestion management practices in intraday is much needed in order to maximize cross-border exchanges of electricity without additional restrictions imposed to market players as a result of internal constraints.
Q1 Nevertheless, on borders where market coupling has not been implemented yet, PTRs should be maintained, since they enable market players to take full advantage of price differentials across the borders.
We finally wish to highlight that the choice between FTRs and PTRs should be left to TSOs under the approval of NRAs. In this process, market players should be fully involved through public consultations.
FTRs issued by the TSOs should be preferred as more flexible tools compared to PTRs, where the allocation of cross-border capacity in the day-ahead market carried out through a single price coupling contributes to achieve price convergence between adjacent borders.
Q2 We believe that in some markets (e.g. pool markets) the implementation of an implicit auction regime on top of continuous trading can be a valuable interim solution to improve intraday market functioning. This opportunity would enable TSOs to gradually adapt their control systems to the real time checks and settlements required to implement cross-border intraday exchanges with continuous trading
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| PC-03-EDITH-Z |
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| PC-03-EFET-X |
NA
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| PC-03-EGELH-O |
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| PC-03-ENBWD-C |
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| PC-03-ENDES-S |
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| PC-03-ENECO-2 |
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| PC-03-ENELI-N |
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| PC-03-ENERG-9 |
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| PC-03-ENERN-V |
This is the input for the ACER consultation on CA-CM of Energie-Nederland. Energie-Nederland is an association representing the commercial Dutch energy industry.
Consultation questions
Question 1: As price-based market coupling is the mandated capacity allocation method in the day-ahead framework, should FTRs be preferred to PTRs for long term capacity alloca-tion?
FTRs should be the preferred option, provided that markets have enough liquidity:
• FTRs utilising the day-ahead market are more efficient than PTRs with UIOSI secondary markets
• FTRs provide for further liquidity increase of day-ahead markets
• FTRs can only work properly if there is a reliable reference price, capacity owners must have certainty to be able to buy and sell at the reference price
• FTR should be an option rather than an obligation and require harmonised rules for finan-cial firmness.
Question 2: Is implementing implicit auctions on top of continuous trading considered to im-prove the intra-day market?
• Continuous implicit trading is preferable because it allows instant market access to any available capacity.
– Auctions cause delays not flexible enough for intraday markets.
– Auctions are not needed to incorporate welfare effects correctly to the mar-ket.
• Auctions cause distortions: If some markets were allowed to opt for an auction model, neighbouring countries with continuous trading have to implement two intraday markets (implicit plus gate auctions). This is not acceptable since such a market segmentation re-duces liquidity!
Question 3: Is allowing direct OTC access to the Capacity Management Module important as a transitional feature?
• Very important, in particular in cases of unplanned outages or commissioning of power plants
• These arrangements are typically of complex nature (last minute “squeeze in”, typically combining different power plants, optional pricing of a power plant)
• Simple bids are not sufficient to book necessary capacity for these arrangements
• Limited liquidity of some intraday markets make bilateral arrangements necessary
• OTC access of the capacity should be implemented on all borders until complex products are available (the framework guidelines should specify OTC access as a interim require-ment)
Question 4: Should the draft Framework Guidelines be more explicit in the area of compensa-tion? If yes, please indicate how.
The FG are not clear about curtailment, firmness and compensations:
Regarding compensations
In 6.2: Allocated capacity that has been paid for and which becomes subject to a force majeure is reimbursed for the period of that force majeure.
In 6.4: The CACM Network Code(s) shall require that, except in the case of force majeure, capacity holders shall be compensated for any curtailment
Regarding curtailment
• ACER draft:
– Curtailment only in case of emergency situations (6.4)
– Compensation for curtailment based on market spread (6.4)
But in case of force majeure event, reimbursement of capacity price (6.2)
Evaluation: Clear rules for PTRs, but what about FTRs?
• No curtailment of FTRs unless force majeure event?
• Before \ after nomination not clear
Regarding firmness of nominated capacity
“All nominated capacity shall be firm. Physical firmness is the preferred approach, but finan-cial firmness may be accepted in case of explicit auctions.” (6.4)
• What happens to nominated capacity in case of emergency situations and force majeure events?
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| PC-03-ENTSE-M |
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| PC-03-EPEXS-T |
Dear all,
Please find enclosed EPEX Spot Exchange Council response to the ACER public consultation on the Framework Guidelines on Capacity Allocation and Congestion Management.
Kind regards
Wolfram VOGEL
Head of Public Affairs & Communication
EPEX Spot SE
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| PC-03-EUREL-N |
NA
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| PC-03-EUROP-L |
EUROPEX welcomes the consultation by the Agency for the Cooperation of Energy Regulators (ACER) which follows the previous consultation by ERGEG on the Draft Framework Guidelines on Capacity Allocation and Congestion Management for Electricity of November 2010 and the respective initial impact assessment.
See more in the attached file...
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| PC-03-EWEAB-A |
General remarks:
EWEA welcomes the timely uptake of the Framework Guidelines on Capacity Allocation and Congestion Management for Electricity (FG CACM) by ACER shortly after the draft FG on the same topic by ERGEG and hereby provides its view on this matter, as the deployment of renewables, particularly wind power, and the integration of European electricity markets, are mutual drivers. EWEA has already commented on the ERGEG Framework Guidelines on the same topic giving our views on selected questions where deemed relevant, in particular on general issues and on intraday capacity allocation: http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20PUBLIC%20CONSULTATIONS/ELECTRICITY/draft%20Framework%20Guideline%20CACM%20Electricity/RR/CACM-E_EWEA.pdf
For this reason these comments will only focus on actual issues in the ACER FG CACM and refer to the previous EWEA response where relevant.
Regarding the scope of these FG, EWEA would like to point out that these FG should be carefully coordinated and consistent with the upcoming Framework Guidelines on balancing and subsequent network code(s) as the functioning and design of intraday and balancing markets are closely interrelated.
Furthermore, there is still no consistent use of the terms "intermittent" and "variable" generation in the regulators’ documents. As already stated in the ERGEG consultation, EWEA recommends using the qualifier "variable" when referring to wind power generation, rather than "intermittent", which means starting and stopping at irregular intervals.
Capacity allocation and EU priority access and dispatch provisions in the RES Directive 2009/28/EG
According to European Directive 2009/28/EC producers using renewable energy sources have priority access or guaranteed access to the grid and system operators will give priority dispatch to renewable electricity installations, and that appropriate grid and market-related operational measures are taken in order to minimise the curtailment of electricity produced from renewable energy sources . In order to ensure consistency with these provisions EWEA calls for a reference in the FG CACM to this Directive.
In view of these legal requirements in the Renewable Energy Directive EWEA urges ACER and ENTSO-E to proceed with electricity market integration on a basis that does not jeopardise the deployment of renewable electricity necessary to deliver Europe’s agreed decarbonisation objectives.
Priority access or guaranteed access and dispatch for renewable electricity is required by EU legislation in view of the incompleteness of a liberalised power sector in Europe. The European power sector is still dominated by large incumbents in their respective control zones with very high concentration rates on the electricity wholesale markets . Due to this lack of market access in the power sector in general, EWEA regards priority access or guaranteed access for renewable electricity, and dispatch to the grid as justified.
However, EWEA is also confident that progression is under way to a truly liberalised European electricity system, where most renewable energy sources will have a natural priority in dispatch due to their near to zero marginal cost. This aspect together with additional transmission capacity will eventually help ensure the proper functioning of integrated electricity markets with the design features envisaged in the FG CACM.
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| PC-03-EXXDA-9 |
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| PC-03-FERDM-Q |
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| PC-03-FSEDK-C |
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| PC-03-FUBER-X |
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| PC-03-GASNA-U |
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| PC-03-HECKM-H |
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| PC-03-HUHTO-U |
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| PC-03-IBERB-J |
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| PC-03-IBERS-L |
In general terms, IBERDROLA adheres to EURELECTRIC response, but considers necessary to
highlight certain questions / make certain additions:
· Regarding the questions about the preference between PTRs and FTRs for long term
capacity allocation (Q1), it has to be pointed out that CfDs should be offered not only in
regions such as the Nordic Market, but as the MIBEL as well.
· Additionally, it is important to highlight the aspects that put PTRs+UIOSI ahead of FTRs,
namely:
- Some national public support mechanisms for RES require physical flow of energy to
be accredited with certificates. This would not be possible with FTRs.
- In exceptional cases when Power Exchanges price limits are reached, PTRs allow
perfect hedging as the physical flow must be done, while FTRs do not assure total
hedging in such situation.
- FTRs require participation on the spot markets to be able to undo long term positions
for the delivery-day and that means additional costs due to Power Exchanges fees,
while, with PTRs, if a physical flow is done, there is no need to use spot markets, thus
those fees are saved.
- National fiscal regulations (VAT) applicable currently to financial products may lead
to less competitive behaviours among agents.
Therefore, if the PTR had the same firmness as FTR, then the PTR should be preferred.
We suggest applying for the same firmness for both products.
· Finally, it is important to note that the CACM Network Code must set out all necessary
provisions for the implementation of a pan-European intraday platform supporting
continuous implicit trading. The method for making available such additional capacity, its
pricing capacity and the allocation of congestion rents shall be European wide
harmonised and subject to regulatory approval. In this sense, exceptions should not be
allowed (for instance, regional auctions) as they can eventually go against harmonisation.
ACER should play an active role in fighting such exceptions
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| PC-03-IFIEC-K |
Firstly we have some general comments on the different issues mentioned in the FG. Secondly, IFIEC will provide an answer to each of the four questions in the consultation document.
Capacity calculation
IFIEC believes that in the framework of the target model the introduction of Flow Based (FB) capacity calculation into the pricing algorithm could be a promising way to use the grid optimally.
Definition of Zones
IFIEC stresses the FG should mention the goal of diminishing the number of zones and eventually creating conditions for a internal energy market without congestion as far as economically feasible.
On the path to diminishing the number of zones, IFIEC warns against changing existing (ie: pricing zones should not decrease in sizes) zones without an in-depth analysis and agreement by all the national regulators involved, of the local and overall effects for end-consumers. Above that, it is necessary to have a sufficient number of competing generators in all zones (for example: a minimum of four) in order to promote liquidity, competition and efficient markets.
Day-ahead capacity allocation
The FG should promote the development of trading platforms and make sure their liquidity is increased by allocating cross-border capacity to the market only via the PX in every zone. Block bids and other products should only be allowed if they improve liquidity, cross-border capacity and transparency.
The introduction of market coupling makes real competition between day-ahead electricity exchanges unfeasible. Therefore, physical markets (incl. exchanges) are an extension of the system operation and should be regulated (similar to the TSOs). In order to ensure cost efficiency and stable daily operation, this calculation must be done by one central market coupling organization. A market coupling council must be set up with representatives from all the market players including end user representation.
Forward capacity allocation
Electricity consumers have a basic need to secure their future electricity prices (fully or in part) in zone they are located either hedging with financial/physical market products or with long-term bilateral contracts.
We believe that when the day-ahead market is liquid, well functioning, efficient and provides a representative market price for the underlying product (physical electricity inside the zone) the financial market (for example PX, traders, originators) will provide the necessary products for hedging, whether financial or for physical delivery.
However this is not the case today in most part of EU, so there is need for long term capacity products at least for transitory period. When implementing TRs, it is important that maximum long term capacity is offered to the market for different time frames and quantities by TSOs. TSOs have to provide a market place and act as a market maker for the secondary market.
IFIEC welcomes the discussion about the nature of FTR in terms of options or obligations that has to be done before developing the Network code.
Intraday capacity allocation
IFIEC is worried about the progress that is made towards harmonization of the different intraday markets. IFIEC urges ACER to make sure TSOs and PXs start working on the development of a SOB and CMM as soon as possible. The main focus should be on creating a transparent and liquid harmonized intraday market.
Therefore explicit access to intraday cross-border capacity should be limited to emergency situations to ensure
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| PC-03-JPMCH-G |
We are writing in response to ACER's consultation on capacity allocation and congestion management for electricity and are pleased to have this opportunity to share J.P. Morgan’s views with you on the proposals raised in this consultation paper. Please find attached a letter setting out our views on the issues raised. We have also placed a hardcopy in the post.
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| PC-03-KREST-W |
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| PC-03-LANGG-T |
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| PC-03-MACHV-Y |
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| PC-03-MCLEG-R |
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| PC-03-MUHSY-J |
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| PC-03-MURLA-C |
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| PC-03-NAEOI-P |
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| PC-03-NORDP-U |
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| PC-03-OESTE-8 |
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| PC-03-PETVV-U |
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| PC-03-POWES-P |
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| PC-03-RAPON-J |
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| PC-03-REDEL-9 |
Please, see attached document.
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| PC-03-RWEST-A |
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| PC-03-RYANA-O |
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| PC-03-SCHLE-Q |
Dear Sir/Madam,
Please find below the comments 1 to 5 from the Swiss electricity regulator ElCom. Yours sincerely, W. Schlegel / M. Meier, ElCom Technical Secretariat
1) New sentence to be added to 2nd § under 1.1:
If European countries such as Switzerland not bound by EU legislation but important for the development of EU electricity market are concerned, ENTSO-E and the Agency shall make sure that relevant NRAs and TSOs are adequately involved in the development of the Network Codes.
2) Q1: At this point in time, both FTR and PTR should be possible for long-term capacity allocation.
3) Q2: Yes; Implicit intraday auctions on top of continuous trading may help to increase the efficient and non discriminatory use of transmission capacity.
4) Q3: Yes; Direct OTC access is important for market participants as long as implicit auction with capacity pricing is not introduced and non-harmonised platforms are used.
5) Q4: No; In our understanding, compensation is closely linked with capacity allocation and nomination methods. Since these methods are not harmonised yet, it is not appropriate to be more explicit in the Framework Guidelines. The capacity allocation, firmness and compensation methods shall be clearly described in the Network codes. ElCom is prepared to support and to contribute to the drafting process.
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| PC-03-SOLVY-O |
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| PC-03-SONCH-Z |
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| PC-03-SSEUK-R |
SSE welcomes the chance to respond to this consultation. SSE is the second largest generator in the UK, with over 11.5GW of generation capacity and the second largest energy supplier. We also have transmission and distribution businesses (although these are not represented here) and a generation and supply operation in Ireland.
General points on EU Network Code development:
It is vital industry views are incorporated as EU network codes are developed to ensure they reflect the practicalities of operating in electricity markets. At present, there is not sufficient opportunity for non-TSO stakeholders (e.g. generators and DNOs) to actively input into the development of grid codes and the current process offers sufficient transparency and accountability. Specifically, a non-TSO forum is needed with review powers over codes.
EU grid codes must also focus only on the areas that require harmonisation to allow trading across borders and not focus on areas which do not affect trade. The benefits of harmonised codes must always be weighed up against the costs in each instance.
The CA and CM Framework Guidelines:
We are generally supportive of efforts to encourage more efficient cross-border markets. Transparency of information and standardisation of products is crucial to achieving this and well as reducing the transaction and legal costs associated with cross-border trading.
As a general point on the guidelines, the terminology needs to be much better and more tightly defined. For example, terms such as “Zones”, “Control Areas”, “Bidding Areas” and “Balancing Zones” need to be carefully defined. As part of this it should also be clarified that the FGs are referring principally to trade across borders rather than within Member State electricity markets.
Specific issues:
• Use-it-or-lose-it (UIOLI) versus Use-it-or-sell-it (UIOSO). We have a preference for UIOSI. This ensures the original buyers can retain adequate value for the capacity they have purchased.
• Flow-based (FB) versus Availability Transfer Capacity (ATC). Different methods are appropriate for different contexts and therefore it is important that the framework guidelines allow for this. In the context of the GB market, we believe ATC methods most appropriate, providing a simple and transparent mechanism which is easier to predict and encourages liquidity. It is also important in providing signals as to where and when transmission investments are needed.
• Pan-European intra-day platform. This is a major undertaking and focusing on regional markets would be the sensible first step where most of the benefits can be realised.
• Section 2.1.3. Information should be made available to all interested parties, not just TSOs.
• Section 5.1. states that use of intraday capacity is obligatory. This term needs to be clarified. It should not imply any penalties as the market already provides strong incentives to use capacity if it is needed.
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| PC-03-SWECO-H |
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| PC-03-SWISE-9 |
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| PC-03-SWISS-H |
Question 1: As price-based market coupling is the mandated capacity allocation method in the day-ahead framework, should FTRs be preferred to PTRs for long term capacity allocation?
PTRs with the Use-it-or-Sell-it option already provide the possibility for both a physical or financial usage of the transmission capacity. This flexibility should be weighed against the potential benefits that freeing up additional transmission capacity for the day-ahead market coupling provides regarding overall market effi-ciency and price convergence. Given a scenario which allocates all physical transmission capacity during the day-ahead market coupling (and intraday), we suggest first of all to investigate whether financial products (such as futures on national hub prices or contracts for differences) are already sufficient to cover the need of market parties to hedge long-term transmission price risks, before considering the implementation of FTRs.
Question 2: Is implementing implicit auctions on top of continuous trading considered to improve the intra-day market?
In terms of an efficient, market-based usage of transmission capacity and consistency with the day-ahead allocation scheme, implicit intra-day auctions (e.g. hourly) are preferable compared to continuous trading, provided they ensure sufficient flexibility to market participants. At any rate, the intra-day target model should be robust enough to handle an increasing trading volume created by variable renewable generation and ensure system security.
Question 3: Is allowing direct OTC access to the Capacity Management Module important as a transi-tional feature?
As long as technically feasible and non-discriminatory, there is no reason to reduce OTC intraday trading possibilities. But as soon as intraday capacity is priced, OTC access to the capacity platform has to be substituted by sophisticated products included in the intraday trading platform.
Both the relevance of pricing intraday capacity and the development of sophisticated products need further examination.
Question 4: Should the draft Framework Guidelines be more explicit in the area of compensation? If yes, please indicate how.
We suggest that the framework guideline clearly distinguishes between firmness (and compensation) before and after capacity nomination deadlines, providing market-spread compensation only in case of curtailments after nomination.
As TSOs are not allowed to obtain any financial benefits from CM, they should neither be exposed to any costs and risks resulting from it. The framework guideline should therefore foresee general provisions to ensure TSO cost neutrality as well as the possibility of a cap for compensations, protecting network tariff payers from undue cost taking regulatory risks into consideration.
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| PC-03-TOLEG-X |
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| PC-03-VATTE-I |
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| PC-03-VERBU-S |
Question 1: As price-based market coupling is the mandated capacity allocation method in the day-ahead framework, should FTRs be preferred to PTRs for long term capacity allocation?
VERBUND comment: In a fully established price-based coupled market there should not be any difference between FTRs and PTRs for long-term capacity allocation. We believe that in the long-term FTRs will prevail because of the design of coupled markets which foresee also a total financial hedge for cross border trades. Nevertheless, in the meantime PTRs are reality in today´s transitional market design.
Question 2: Is implementing implicit auctions on top of continuous trading considered to improve the intra-day market?
VERBUND comment: Yes, under the condition that continuous trading includes capacity auctions instead of having two separate mechanisms.
Question 3: Is allowing direct OTC access to the Capacity Management Module important as a transitional feature?
VERBUND comment: Yes, as long as it remains a transitional feature and there is a clear deadline for use.
Question 4: Should the draft Framework Guidelines be more explicit in the area of compensation?
VERBUND comment: The framework guidelines need to be very explicit in terms of the definition of firmness and the compensations to be paid in the event of curtailment. The chain of events, rights and responsibilities triggered by curtailments day-ahead overall needs to be clarified. As liabilites of TSOs will be at stake, it is unsafe to leave the description for elaboration in the Network Codes.
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| PC-03-VILCA-X |
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| PC-03-WARTJ-A |
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| PC-03-WUNNM-A |
Answer to Q1:
FTRs and PTRs are important for cross-border competition in the forward markets. BDEW believes that FTRs or PTRs with UIOSI shall be implemented between all bidding zones in all parts of the European Union. PTRs in combination with UIOSI – as foreseen by the CACM FG – are in principle already a FTR: If capacity holders decide not to use the capacity, the transmission right is settled financially. We suggest starting with PTRs and UIOSI. If experi-ence indicates that market participants mainly use UIOSI, there should be a consultation of with all stakeholders whether there should be a change from PTRs to FTRs. It would be ac-ceptable to the market to have FTRs at some borders and PTRs at other borders. In any case, FTRs should only be implemented, if there are liquid markets on both sides of the bor-der. Capacity holders must have the certainty that they can buy and sell for the price taken as a reference for the FTR.
The framework guidelines should state that all TSOs shall allocate FTRs or PTRs corre-sponding to the full available capacity. It is the freedom of the market to have other instru-ments in place, like CfDs in the Nordic market, but they should not be considered as a re-placement for the TSO obligations. The reason for this is that they are not fulfilling the re-quirements to enable cross-border competition in the forward market between fundamental competitors.
Answer to Q2:
BDEW wants to point out that intraday markets should be carried out on a “first come - first serve” basis. Continuous trading is efficient as the experience on the French-German border shows. Additional auctions would diminish the efficiency of the intraday market as continuous trading would have to be interrupted while running the implicit auction. In continuous trading all European bids and offers will compete between areas without congestions. As problematic would be that any implicit auction would have to be done on a European basis to ensure European competition and efficient market results. A coexistence of auctions at some borders and continuous allocation at others will severely disturb markets and a transmission of elec-tricity crossing more than one border will become almost impossible.
Answer to Q3:
Yes and this should not only be a transitional feature.
In BDEW’s perception, the current discussion is very much focused on the issue of imple-menting a Shared Order Book (SOB), whereas the discussion on a Capacity Management Module (CMM) as a basis for the SOB is less intensive. BDEW believes that creating a com-mon capacity matrix to pool all available cross-border capacity by the TSOs is essential. This should be an open matrix where all market participants including power exchanges and OTC platforms can freely access and use the capacity. Such an approach has been recently de-veloped on the French-German border, which is working very well. Extending such a capacity matrix to incorporate Belgium, The Netherlands and the German-Danish border would be a major progress for cross-border intraday trading in the CWE region and should also be achievable in a short period of time.
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| PC-03-WWFEU-7 |
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not assigned users
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| PC-03-POMPA-W |
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PC-03-FG-ECA-and-CM
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| BRACCO |
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| PC-03-AESNI-U |
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| PC-03-ALPI2-I |
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| PC-03-ALPIQ-2 |
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| PC-03-BALTI-I |
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| PC-03-BARRJ-Y |
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| PC-03-BIERC-O |
...
Regarding the process of establishing new and integrated zones, it is acceptable that the TSOs should make proposals, which have to be approved unanimously by each affected national regulatory authority. Furthermore, these zones should be stable for a certain period. A continuous process of bi-yearly adjustments of the defined zones would lead to an extremely unfavorable investment climate. Without a clear and robust price signal, which is provided by existing spot markets today (e.g. EPEX spot), future investments in generation capacity may not happen at all.
To conclude, VIK strongly believes that the socio-economic benefits of a very liquid single pricing zone clearly dominate other considerations, and a possible splitting-up of existing zones into several smaller zones would have negative consequences on all market participants. Therefore, zones that are already integrated and have developed a liquid market must be maintained and not be split up, while temporary bottlenecks within such zone should be solved by redispatch, and structural congestion by investments in grid capacity. Redispatch mechanisms should be designed so as to give clear and transparent incentives for grid expansion by the grid operator. When redispatch mechanisms are not cosed-based but market-based, not only generators but also consumers need to be able to participate in this market.
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| PC-03-BNEDE-1 |
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| PC-03-BOLAS-L |
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| PC-03-BRITB-V |
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| PC-03-CBI00-Y |
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| PC-03-CBIUK-C |
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| PC-03-DANSK-X |
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| PC-03-DANTR-G |
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| PC-03-DEWAT-D |
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| PC-03-EDFFR-X |
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| PC-03-EDISO-N |
Q2 (continue) For this reason, implicit auctions should have adequate gate closures in order to provide a level of flexibility as close as possible to the one ensured by continuous trading. This system should also guarantee the coordination with the European platform (SOB). Therefore, we deem it necessary for an implicit auction regime to establish at least 8/10 gate closures per day, with a time span of maximum two hours between the end of the trading and the execution of the offers.
Q3 Direct OTC access to the Capacity Management Module is needed as long as all market needs are not fulfilled through implicit platforms (Shared Order Book). This is especially true as regards interim steps for which only standard implicit products are available, thus preventing market players from taking advantage of all the opportunities offered by cross border intraday trading. For this reason, we think that ENTSO-E should deliver, as a first step, its open Capacity Management Module (CMM) accessible by both OTC and power exchanges. This opportunity given to market players should not contribute to complicate the system and should not be an obstacle to the full development of the intra-day market.
We wish to highlight that the development of cross-border intraday markets requires a convergence of market design at European level in order to guarantee an efficient use of intraday capacity on all European borders. Moreover, it is important that rules in force at national level, e.g. in pool markets, be fully compatible with cross-border market design in order to enable market players to take part to intraday cross-border power exchanges without any additional constraint.
Q4 As far as long-term FTRs and PTRs are concerned, we believe that transmission rights owners should be paid back the price difference between the relevant markets (in case of physical right if this spread is positive in the direction of the PTR) when capacity curtailments due to emergency situations are notified by TSOs shortly before the day-ahead market coupling gate closure (before the nomination deadline for PTRs).
It is of paramount importance that CACM European Network Code(s) explicitly define the period ahead of capacity allocation during which the capacity announced for an auction can no longer be changed. This period should be long enough to allow market players to make their forecasts on market outcomes and to take the required actions. NRAs should monitor TSOs’ compliance on this issue.
Thus, when TSOs are unable to fulfil this obligation modifying data on available cross-border capacity after the agreed deadline for reasons other than force majeure, transmission rights’ owners should be duly compensated. Concerning FTRs, owners should receive compensation also for upward variations of cross border available capacity, when these variations are liable to seriously reduce the value of their financial coverage. In those cases, FTRs owners should receive at least the initial price of the FTR. Moreover, TSOs claiming the force majeure should guarantee full transparency and be subject to a due regulatory supervision aimed at avoiding possible abuses.
When TSOs realize sufficiently in advance that they have allocated too many long-term PTRs and FTRs, they can use, for instance, secondary markets (both PTRs and FTRs) to withdraw the transmission rights issued in excess.
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| PC-03-EDITH-Z |
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| PC-03-EFET-X |
NA
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| PC-03-EGELH-O |
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| PC-03-ENBWD-C |
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| PC-03-ENDES-S |
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| PC-03-ENECO-2 |
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| PC-03-ENELI-N |
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| PC-03-ENERG-9 |
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| PC-03-ENERN-V |
• Physical firmness preferred approach for FTRs as well?
Regarding firmness of allocated day-ahead capacity
“Reduction of allocated capacity may only be used in emergency situations and force majeure, and when all other means are exhausted (as a last resort measure). Market partici-pants shall not be affected and PXs shall not bear additional costs deriving from such reduc-tions.” (3.3)
• Does that mean that TSOs have to bear costs even for force majeure events? Which practical consequences have reduction?
• What is the difference between “not be affected” and “not bear additional costs”?
Regarding firmness in general
In the original ERGEG draft the interaction between firmness as congestion revenues was recognised as follows:
5.7 Congestion rents shall be used, inter alia, for guaranteeing the firmness of allocated capacity rights, in particular through the activation of coordinated redispatching/countertrade actions.
This paragraph should be reinstated since the explicit direction from the guidelines that congestion rents should be used to guarantee firmness will improve the incventives on TSOs in this respect.
Regarding force majeur
We welcome the definition of force majeure. However the definition could be improved by adding more concrete examples of events which fall under the force majeure definition. At present, depending on each parties explanation of the force majeur criteria, many events could fall under the definition. In particular, there should be a clear statement that curtailments resulting from wind conditions do not fall under force majeure.
General Comments
Regarding flow-based allocation and internal congestions
The draft CACM FG (article 2.2) state that: “While limiting cross-border capacity to solve internal congestion inside a control area is generally not permitted, the CACM Network Code(s) shall provide that if such a situation occurs, it is reported transparently. Detailed information on internal and cross-border congestion and limiting constraints (exact location, exact hour of congestion) shall also be reported to the NRAs.“
This paragraph is worded too vaguely and seems to water down what is already laid down in the Congestion Management Guidelines (Regulation 714/2009). In particular Energie-Nederland underlines that implementation of flow-based allocation might also lead to internal lines (not being interconnectors) being labeled by TSOs as “critical branches”. However, the application of such critical branches while calculating cross-border capacity de facto means that internal bottlenecks are shifted to a zone border. Such practice can only be allowed under certain conditions. Therefore, the application of any internal line as critical branche can only be allowed after proper justification of the need (competitive and welfare effects) of such application and if such application does not lead to discrimination between national and international transactions.
At the same time, it must be emphasized that the existence of critical branches or internal congestions within a zone does not necessarily have to lead to splitting the zone. Likewise, it does not mean that flows on zone borders can never be affected for the purpose of managing internal congestions as TSOs can for example apply cross-border countertrading/redispatch or buy back cross-border capacity.
Also, Energie-Nederland proposes that the CACM FG explicitly rule that ramping restrictions (as currently being imposed by Nordic TSOs o
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| PC-03-ENTSE-M |
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| PC-03-EPEXS-T |
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| PC-03-EUREL-N |
NA
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| PC-03-EUROP-L |
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| PC-03-EWEAB-A |
Intraday capacity allocation
EWEA sees no evidence that implementing implicit auctions on top of continuous trading will necessarily improve the intra-day market. Additional view’s from our side on intraday markets have been already outlined in our previous response to the ERGEG FG CACM (see the link on the previous page). Importantly, instant access to any available capacity must be allowed for and any auctioning delays in intraday markets must be avoided.
In addition, EWEA recommends ACER to be more prescriptive in the current FG CACM on the intraday market design features: gate closure times for the intraday capacity allocation could be one hour before real time.
Moreover, a clear reference to the respective provisions on priority/guaranteed access and dispatch, together with the minimisation of curtailment, should be included as discussed above. To this end EWEA recommends to amend the sentence in the FG CACM on page 11 in italics: The matching rules and algorithm should avoid undue discrimination in matching the different types of intraday products, whilst respecting priority dispatch and access for RES according to European Directive 2009/28/EG.
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| PC-03-EXXDA-9 |
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| PC-03-FERDM-Q |
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| PC-03-FSEDK-C |
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| PC-03-FUBER-X |
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| PC-03-GASNA-U |
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| PC-03-HECKM-H |
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| PC-03-IBERB-J |
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| PC-03-IFIEC-K |
security of supply.
Q1: Depending on the modalities of the FTRs this could be one of the preferred options
It’s important to clearly separate physical and financial market products in order to have a transparent, liquid and well functioning market with a limited potential for market abuse. FTRs and CfDs are “pure” financial products, and therefore compatible with physical markets. FTR “obligations” nets the capacity reservations in opposed direction between zones providing liquidity to secondary markets.
IFIEC sees possibilities for market abuse with PTRs. If the FG authorizes PTRs, the FG must impose measures to avoid misuse of capacity rights or abuse of market power.
Q2:No, IFIEC believes that the time frames are too short in order to organize auctions. Liquidity should be concentrated: Auctions in day-ahead and continuous trading in intraday. Auctions in intraday will incentivise some generators to wait with the bidding until intra-day and weaken the firmness of the universal price reference given by the day-ahead auction.
Q3:IFIEC believes that giving direct OTC access to the CMM module is not important and is also not to the benefit of industrial end-consumers. On the contrary, such access may be abused to block capacity.
• Introducing OTC features will delay the introduction of trans-national intra-day market.
• OTC bids are not put into competition on the market platform which means that not everybody has a fair chance of buying this energy at the OTC conditions.
• OTC access will reduce the liquidity of the intraday market platform and could potentially hurt the spot market by attracting capacity that would otherwise be used there.
• Allowing OTC in a transitional phase is counterproductive as it will slow down the development of the sophisticated products as there will be no pressure anymore and this will give the traders and producers the excuse that the solution will need to remain in place
• trades that really need the sophisticated products will be marginal versus the total intraday trades. as backup the national OTC market still remains in place and finally the grid operators have their balancing in place
• The best solution in order to make sure that sophisticated products will be developed is to abandon OTC from the start and develop the sophisticated products at the same time with the CMM and SOB.
Q4:Yes, market actors have to have trust on the financial firmness of the capacity. This can be done by providing full financial compensation for the capacity holders in any curtailment, either before or after nomination. Firm capacity facilitates liquid forward and secondary markets with efficient pricing, which are desirable. TSOs have a monopoly with respect to operating, maintaining and developing grids, so it’s natural that TSOs carry the economical burden of the firmness of the grid capacity by providing full financial firmness for the capacity holders.
When TSOs have an obligation to guarantee financial firmness of the capacity, it creates automatically the right (economical) incentives for a TSO to minimize the cost of the curtailment’s (planned or unplanned). Furthermore, FTRs provide strong incentives for the TSOs to increase available capacity as much as possible and avoid capacity disruptions.
The FG should provide correct tools for regulators to monitor the possible gaming of dominant market players in the capacity market.
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| PC-03-JPMCH-G |
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| PC-03-KREST-W |
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| PC-03-LANGG-T |
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| PC-03-MACHV-Y |
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| PC-03-MCLEG-R |
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| PC-03-MUHSY-J |
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| PC-03-MURLA-C |
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| PC-03-NAEOI-P |
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| PC-03-NORDP-U |
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| PC-03-OESTE-8 |
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| PC-03-PETVV-U |
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| PC-03-POWES-P |
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| PC-03-RAPON-J |
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| PC-03-REDEL-9 |
Please, see attached document.
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| PC-03-RWEST-A |
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| PC-03-RYANA-O |
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| PC-03-SCHLE-Q |
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| PC-03-SOLVY-O |
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| PC-03-SONCH-Z |
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| PC-03-SSEUK-R |
Questions asked in the consultation:
Q1. Should FTRs be preferred to PTRs for long-term capacity allocation?
Regardless of whether capacity allocation is determined by FTRs or PTRs the key requirement is that generators should not exposed to the risks of capacity being available that are outside their control.
Q2. Is implementing implicit auctions on top of continuous trading considered to improve the intraday market?
Yes, implicit auctions help to make trading significantly simpler for firms and encourage efficient markets.
Q3. Is allowing direct OTC access to the Capacity Management Module important as a transitional feature?
Yes. Assuming this refers to secondary trading, having this option is beneficial and important.
Q4. Should the draft Framework Guidelines be more explicit in the area of compensation?
Yes, further clarity is required. Compensation should be at least the price that is originally paid for the capacity.
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| PC-03-SWECO-H |
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| PC-03-SWISE-9 |
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| PC-03-SWISS-H |
Additional Comments on Chapter 2: Optimal and Coordinated Use of Transmission Network Capacity
2.1. Capacity calculation
We have no general remarks about that chapter but only remarks related to the text itself:
2.1.1 Capacity calculation methods
2nd §:
We suggest removing the examples in brackets.
[FB method] is therefore considered to be preferred to the ATC method for short term capacity calculation in cases where transmission networks are highly meshed and interdependencies between the interconnections are high [...].
3rd §:
We suggest completing the paragraph:
The CACM Network Code(s) shall foresee that practical usage of the FB calculation and allocation starts only after market participants have been consulted and allowed sufficient time for their preparation and for a smooth transition to the new arrangement. [ "Moreover a successful test phase based on real market and network data must be completed where it is proven that FB yields the same Operational Security as ATC, does not increase redispatch costs and improves Social Welfare."]
4th §:
We suggest removing the example:
Provided that it is done in a coordinated way, ATC is considered as an acceptable method for short term capacity in less meshed networks, [...].
2.2 Definition of zones
Given several cross-border network extensions in the past, nowadays congestion is no longer restricted to political borders, but is rather scattered throughout the European electricity network, requiring a more func-tional definition of congestion zones.
A one-zone-per-country approach would stick to very heterogeneous zone sizes, which results in significant inaccuracies in the capacity calculating process, especially if automated as part of the flow-based methodology. These inaccuracies would have to be mitigated either by larger security margins or by larger redispatch costs, both impeding the efficiency of the capacity calculation system. In conclusion, we suggest that zones should have comparable sizes and be constituted either by countries or by parts of countries ensuring the most efficient gird use possible.
Another option would be that bids submitted to the flow-based market coupling belong to the established price zones, but have to provide a network node ID that is taken into account during the matching process to predict the true impact on the critical network elements.
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| PC-03-TOLEG-X |
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| PC-03-VATTE-I |
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| PC-03-VERBU-S |
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| PC-03-VILCA-X |
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| PC-03-WARTJ-A |
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| PC-03-WUNNM-A |
Follow-up Answer to Q3:
Hence, BDEW calls for the CMM to be implemented independently of the SOB, swiftly giving all exchanges and OTC platforms access. This approach would give markets time to evolve and further develop an efficient design of the intraday markets and to harmonise national in-traday markets. Thus, BDEW supports a step-by-step open access approach to the CMM allowing power exchanges to compete with their solutions and allowing the market to decide for the best system instead of a premature top down decision on functionalities. Right now, the capacity management module should be in focus of all TSOs in the region to deliver the most efficient results for available cross-border capacity in the intraday timeframe. At the same time, efforts should be made to further harmonise the market design to prepare for the SOB.
OTC will safeguard liquidity for the transition
Analyses show that since the start of the EPEX Spot Flexible Intraday Trading Scheme (FITS), market participants use this tool for trading cross-border in parallel with OTC.
BDEW sees this as an important indicator that OTC trading plays an important role in cross-border intraday trading. Thus, BDEW urges regulators not to interfere with a market segment which is commonly used.
In addition, BDEW maintains that any solution for a cross-border intraday platform must facili-tate block bids. Block bids are essential for generators to regard start up and shut down cost and ramping constraints.
Answer to Q4:
Yes, there should be clear rules for the financial compensation in emergency cases and in any other cases where firmness cannot be guaranteed.
Firm transmission capacity is essential for market participants to be able hedge their portfo-lios efficiently and compete effectively outside their home market. It is no use being able to agree a price with a customer, if you subsequently have an open ended risk on the price and availability of the transport capacity to deliver power. The framework guidelines therefore need to be very explicit in terms of the definition of firmness and the compensations to be paid in the event of curtailment.
BDEW urges that physical firmness is preferred for nominated capacity – meaning that the TSOs must provide energy in the curtailed area for capacity holders in the event of a curtailment.
Holders of capacity rights should get paid the market spread if the capacity is curtailed before nomination. The guidelines should clarify that this refers to the day-ahead spread, even if the curtailment takes place before this time.
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| PC-03-POMPA-W |
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ACER
Agency for the Cooperation of Energy Regulators
Address: Trg republike 3, 1000 Ljubljana, Slovenia
Email: info@acer.europa.eu
Phone: +386 (0) 82053 400 |
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