Q: BNetzA and E-Control have agreed in a bilateral agreement that 4.9 GW of capacity would be allocated as long-term allocation rights, starting in October 2018: how will this threshold be taken into account in the regional capacity calculation methodology, and how will it affect available capacities on other borders? Is the countertrading and redispatching capacity in Austria sufficient to ensure such capacity level?

A: The methodology for taking into account the DE/AT LT capacity does not differ from other CWE-borders and is described in the public approval documents. Limitation of DE/AT-exchanges can have a positive effect on the exchange on other CWE borders. The results of the external parallel will evaluate this impact.
For the time beeing there are no indicators that countertrading and redispatching capacity in Austria is in-sufficient.(published 29/05/2018)


Q: How will this bilateral agreement (4,9 GW of capacity allocated as long-term allocation rights) be considered in the cost sharing methodology for coordinated redispatching and countertrading?

A: On CORE level there are ongoing developments of the methodology for coordinated redispatching and countertrading according to CACM. However, the developments are still not that advanced to answer this detail. (published 29/05/2018)


Q: At the MP Conference on 24th Nov, we were told that a meeting would be held on the 21st of December 2017 between NRAs, NEMOs and TSOs, and that a decision would be made regarding the choice between Flow Based and ATC for the day ahead market. Could you please provide an update on this decision?

A: DE-AT BZB project parties would like to inform Market Participants that the decision has been made to continue with the implementation of the target model of FB MC on the DE-AT border in the CWE region. Considering the disadvantages of an NTC solution on the CWE FB Market coupling, CWE TSOs recommended to CWE NRAs to integrate the DE-AT border split in the CWE Flow-Based Market Coupling.

In January, CWE NRAs reached an agreement for FB MC subject to final approval according to the national approval processes and formal decision to be taken by the Board for some of the NRAs.

All parties are therefore working on implementing the FB capacity calculation method for the 1st of October 2018.


Approval process

Q: Critical network elements and external constraints need to be made transparent. The current status of CWE FB seems not yet approved by all NRAs. Is the opinion from 2015, giving green light to start with FB but under several conditions, still valid?

A: The question refers to general aspects of CWE FB and not to DE-AT specifically. NRA FB go-live conditions are still valid and CWE partners still work on them, however with shared resources with CORE. Synergies with CORE are applied.

Q: What is the new value for the German External Constraints and what are the new critical elements introduced?

A: Currently this is part of the internal experimentation process between NRAs and TSOs. More information to the market will be part of the external SPAIC and details of possibly changing parameters will be provided at a later stage.



Q: Regarding balancing, TSOs have only indicated that the objective is “to maintain as much as possible the current arrangements”: this implies there could still be some changes. More detailed information on where possible changes could still happen and what are the possible options is thus absolutely necessary.

A: The public consultation on details related to balancing has been performed 12 March to 15 April 2018, which gives further insight in the planning of TSOs. Taken into consideration the remarks received by Market Parties during the consultation, TSOs will submit the approval documents to the relevant NRAs. (published 29/05/2018)

Q: The firmness of Long-term capacities is very important. How do you see the future possibilities of balancing? If an interim solution is implemented for the capacity calculation, it is important to get a timetable for the switch to the target model.

A: Regarding Firmness, arrangements will be the same as on other borders. As for Balancing, the objective to maintain as much as possible the current arrangements


Q: Which ideas exist regarding the use of transport capacities for the balancing market?  Will there be only TSO-TSO models or can capacity also be bought by market particpants?  (TSO-BSP-model)?  If not, why?

A: It is foreseen to only implement cooperations based on the TSO-TSO modell, which is also the case for the currently existing cooperation. Moreover, the target model defined in the guideline on electricity balancing is the TSO-TSO model.


External SPAIC & External Parallel Run

Q: TSOs indicated in their responses to the Q&A that parallel runs are still under consideration – When will a decision be taken whether a parallel run will be conducted?

A: As required by NRAs, an external parallel run will start on 01 July 2018. (published 29/05/2018)

Q: What, where and when will all the necessary information on the parallel run be provided to market participants?

A: All necessary information will be given to Market Parties during the next Market Parties' Conference which is foreseen for the 5th of June. (published 29/05/2018)

Q: Will FBMC parameters and Net exchange positions for DE, AT, NL, BE, FR be published to market participants during the parallel run?

A: During the external parallel run, project parties will publish FB parameters, prices, MRC Net positions, CWE Net position, intuitive patch activations and welfare indicators. (published 29/05/2018)

Q: When and where will the external SPAIC results be published?

A: The publication of the results of the external SPAIC (standard process to communicate on and assess the impact of significant changes) is planned for 1st June 2018.

They will be published at the respective section ("DE-AT BZB Project") on JAO's website.

Q: I have a few questions to the parallel run for the market split for the German and Austrian price zone.

Is the 1st of July 2018 still the start time for the parallel run?

Will the results (prices, block bids, aggregated curves, etc.) be publically available?

In case the results will be available, on which platform is it planned to publish the data?

A: Current planning foresees the start of the external parallel run on 1st July 2018.

The publication-items and the access to the data will be communicated in the Markt Parties Conference on 5th June and will afterwards be published on  JAO's website (section ("DE-AT BZB Project").

Q: Will the parallel run cover the entire FB area or only for DE-AT BZB area?

A: The whole CWE FB area.



Q: Which parties are involved in the project?

A: The introduction of congestion management on the German-Austrian border is organized by the German and Austrian TSOs (50Hertz Transmission GmbH, Amprion GmbH, Austrian Power Grid AG, Tennet TSO GmbH and TransnetBW GmbH), in joint cooperation with the nominated electricity market operators (NEMOs) of Germany and/or Austria (EPEX Spot SE, EXAA Abwicklungsstelle für Energieprodukte AG and Nord Pool AS). Since the inclusion of the new bidding zone border into CWE Flow Based market coupling and into CCR Core is intended, there is close alignment with these projects and its parties.


Q: Is the implementation still subject to regulatory approval?

A: Project parties expect that the detailed design of capacity calculation and capacity allocation mechanisms will require regulatory approval. Independently from legal requirements, project parties are committed to provide as much transparency as possible to regulatory authorities and all further interested stakeholders.


Q: How is the bidding zone review linked to this project?

A: The ENTSO-E bidding zone review and the preparation for the introduction of capacity management on the German-Austrian border are generally treated as two separate projects, i.e. the bidding zone review will continue as previously planned. However it should be noted that all predefined scenarios that are going to be analyzed in the bidding zone review already foresee two independent German and Austrian market areas. Apart from the future configuration of bidding zones in Europe, the introduction of a bidding zone border between Germany and Austria is also required in order to maintain safe grid operations.


Q: Do the results of the flow factor competition study have an impact on this project?

A: The flow factor competition study is currently conducted within the CWE project. In case the study concludes that the principles and methods of capacity calculation and allocation of the CWE Flow Based market coupling require adjustments, these will certainly also be applied on the future German-Austrian bidding zone border.


Q: How is the interaction with the grids of neighbouring countries considered in this project?

A: The introduction of capacity management at the German-Austrian border requires careful preparation, which will include extensive simulations of the impact on grid operations. These simulations will also be conducted in the framework of the CCR Core project, and they will cover the impact on the transmission networks of neighbouring countries.


Q: What are the consequences for the German Grid Reserve mechanism?

A: In April 2016, German regulator Bundesnetzagentur assessed the required amount of generation capacity for the Grid Reserve during winter period of 2018/19. This assessment already takes into account the introduction of capacity management on the German-Austrian border. Compared to past winter periods, and as a consequence of the introduction of capacity management, the required amount of generation capacity for the Grid Reserve will be significantly lower.


Q: what are the adjustments to the established FB DA capacity calculation foreseen?

A: The method and principles as defined for Flow based and in operations today will not change, but adjustments have to be made to the system and procedures to support the introduction of a bidding zone border.


Q: What timeline is foreseen for the implementation of the new bidding zones?

A: a high-level time-line is defined together with the project parties and involved regulators. The deadline for implementation of the day ahead and intraday process is October 2018. The target solutions defined, the technical feasibility and planning will be detailed in the coming months to have a better view on the more detailed activities towards the implementation


Q: How will market parties and other stakeholders be informed/involved?

A: the project parties defined 4-step approach to ensure involvement of all relevant stakeholders and also ensure information is available publicly. These steps are the following:

1. Create a specific web page with regular publications on the project status
2. Intensive dialogue with concerned TSOs & NRAs.
3. Intensive dialogue with German & Austrian market associations
4. Pursue CWE Consultative Group (x2/year) to broadly involve and inform stakeholders

Q: will simulations be performed and published and will a parallel run be organized?

A: in cooperation with CWE market parties an approach was defined to inform market parties on the possible impact to facilitate the anticipation of the changes that will be implemented (SPAIC). This will also be performed for this project and will be published as well. A parallel run is considered, but project parties are assessing the need, the added values and feasibility to perform this.


Q: The Federal Government has supplemented the Stromnetzzugangsverordnung, by introducing a uniform German electricity bidding zone.

A: The German Federal Government has ensured with the supplement of the Stromnetzzugangsverordnung that in the event of a change of the existing bidding zone configuration, a participation of the Federal Government and the public is ensured. 


Impact on other regions

Q: How will you involve CORE and especially East countries from CORE region?

A: The DE-AT border is part of the Core project, hence Day-ahead, Intraday and Long-term capacity calculation methodologies developed in Core will equally apply to  the DE-AT border.


Q: What does the split imply for the whole CORE region?

A: The DE-AT border is part of the Core project. From the ongoing analyses within Core, the impact on the Core region can be deduced.


Q: What is foreseen for the effect outside CWE borders?

A: The impact on borders outside of CWE are not investigated by the DE-AT project at the moment. From the ongoing analyses within Core, the impact on the Core region can be deduced.


Q: What is the expected impact on DE-PL border?

A: Impact on borders outside of CWE are not investigated by the DE/AT project at the moment. Instead, the ongoing design efforts in CCR Core also include analysis of interdependencies of different borders, including DE-PL and DE-AT, both of which are part of the Core region.



Q: Will the the Intraday Gate Opening Time for DE-AT change after the DE-AT BZB split on 1st of October 2018?

A: As of 1st of October, the Gate Opening Time will be aligned with the one applicable in CORE 22:00. If an ACER Decision foresees another Gate Opening Time Core-Borders in the future, this will be handled accordingly in Core. (published 29/05/2018)

Market impact

Q: Is the capacity valid for commercial schedule exchange nomination DE<>AT or for physical load flows?

A: The capacity meant and offered is transmission capacity for commercial schedule exchanges and not physical flows.


Q: Which methods will be used for the future cross border capacity allocation for the different directions AT->DE and DE->AT respectively?

A: The same method for capacity allocation will be used in both directions. The methods are described in the presentation of the MP Conference, published on JAO's website.


Q: How the DE/AT split and the minimal long-term cross-border capacity at 4.9 GW will influence FCA, FB and the whole future energy market?

A: TSOs expect that the future power market in the region will be mainly characterized by the implementation of a harmonized capacity calculation mechanism and an implicit market coupling on all borders of the CCR Core. The DE-AT border will be part of this capacity calculation region from the very beginning, meaning that a regionally harmonized capacity calculation mechanism will be applied to that border in the same way as to all other borders of the region. However, the exact design of the capacity calculation mechanism is still subject   to regulatory approval. At this point in time, TSOs therefore cannot detail the effect of market coupling in CCR Core on a specific border of the region.


Q: You guarantee 4,9 GW of LT capacities. When this capacity is nominated but does not respect Security of Supply, what measures do you take?

A: Re-dispatch measures will be taken to respect grid security measures.


Q: Belgium's commercial import possibility seems heavily reduced by the current CWE Flow-based solution which has an impact on prices in Belgium. To which extent will the proposal of the DE-AT BZB split have an impact on Belgium? What will be the impact also in terms of costs, of guaranteeing such a huge amount of 4,9 GW and will it lead to a high activation of the LTA inclusion patch?

A: The project is still in the internal experimentation phase, currently the view is only on FB results, which are still under evaluation with CWE NRAs and TSOs. General conclusions are available, the expectation is that the situation should improve for CWE countries significantly.


Q: Are there any estimates on how the volumes from FB MC will increase the cross boarder capacities?

A: The external SPAIC/experimentations and the external parallel run will provide information on the anticipated results of day ahead capacity calculation.



Q: How much transmission capacity will be offered via JAO? How much via annual, quarterly or monthly products? How much at the spot market?

A: Long term capacity is allocated via JAO. The split for LT capacities is 60 % (yearly) and 40 % (monthly). For October until December 2018 only monthly capacity will be allocated, i.e. 100% monthly. Calculation of day ahead and intraday calculation is explained in the presentation.


Q: Which kind of transmission rights will be offered to the market?

A: DE/AT BZB TSOs plan to offer yearly, monthly, daily and intraday products on the German Austrian bidding zone border. Daily and intraday products are planned to be allocated in an implicit manner (via CWE FB MC / XBID) whereas for monthly and yearly products there will be an explicit allocation via JAO. The type of long-term products (PTR UIOSI or FTR Options) is currently under elaboration. The choice of the LT product design by TSOs is subject to NRA approval.


Q: Will long term transmission rights be in the form of PTRs or FTRs? When will the decision be taken? If PTRs: Are there already some thoughts regarding „Use-it-or-lose-it/Use-it-or-sell-it“ etc.?

A: DE-AT parties (TSOs & NRAs) have proposed PTRs. However, the final determination is dependent on processes in the Core region and Core TSOs have decided by majority voting on FTR options. TSOs have submitted this proposal to NRAs, NRAs have 6 months to approve this proposal or request amendments. If PTRs the "Use-it-or-sell-it" Rule would be applied.


Q: What kind of changes are planned regarding the fact that despite transmission rights being issues, FTRs will not allow for the nomination of cross boarder schedules for the BRP?

A: It is the nature of FTR that market participants cannot nominate a cross border schedule. For physical delivery, market participants can sell/buy on local NEMO or OTC markets. Concerning price differences between the local markets, FTRs provide a sufficient financial hedge, as their owners will receive a remuneration equal to the day ahead market spread.


Q: Why has it not been considered, that in AT it will be mostly about the demand for quarterly products (especially during winter)?

A: Monthly and yearly products are the standard products on most of the European borders for many years already. Further products may lead to fragmentation of the volumes available for long term allocation.


Q: Why have market needs for capacity management products for several years in advance - e.g. for hedging - not been considered?

A: Multi-annual products for cross border transmission rights are basically not applied on any European border. One of the reasons for this is that the availability of the underlying infrastructure cannot be planned with sufficient certainty for such long periods.


Q: What kind of rules exist for secondary trading of transmission right?  Is "repackaging" of transmission rights possible e.g. purchase of yearly product, sale of 1-4 quarters? Are there any notification obligations for the trade in transmission rights?

A: Provisions for secondary trade are described in the harmonised allocation rules (HAR). In principle transmission right holders can transfer/sell the rights to other eligible market participants or return them to TSOs. In the framework of secondary trading (cf. harmonised allocation rules) the right holders are free to transfer/sell parts of their rights to other market participants on bilateral basis.


Q: When will the Flow-based parameters be published?

A: It is very important to have the Flow-based parameters before the annual auction for 2018.  The CWE FB parameters will be calculated on a daily basis and published ex-ante and ex-post under the same conditions as today.



Q: How will cross-border re-dispatch activations been made transparent?

A: All cross-border re-dispatch activations are published on the ENTSO-E transparency platform according to Regulation (EU) 543/2013 (Transparency Regulation) Art. 13 (1).a.


Q: Which impact is re-dispatch expected to have on the volume of the capacity?

A: In general, re-dispatch it is necessary in order to ensure secure network operation in all situations. In order to ensure availability of re-dispatch resource on short notice, respective reserves need to be contracted in advance. APG will take into account the foreseen LT capacities (4.9 GW) when contracting these reserves.


Q: What happens with energy generated in relation to re-dispatch in Austria? Are they on the Austrian electricity market?

A: Energy of re-dispatch is not part of the Austrian electricity market. When applying re-dispatch TSOs request one (or more) power plant(s) in one area of the grid to reduce its generation and (a) power plant(s) in another area of the grid to increase generation in order to mitigate overloading of lines. Hence, no additional generation or load is created and could be available at the market.


Q: Re-dispatch is now internal and will be cross-border in the future? Who will pay for the XB re-dispatch?

A: Re-dispatch is already today XB, not cross-zonal and different entities are involved. The magnitude of re-dispatch will change.


Q: Could similar information to the parallel run data be published on re-dispatch costs?

A: Publications related to re-dispatching can be found on the ENTSO-E transparency platform and on the German site "netztransparenz.de". No additional publications are foreseen.



Q: What will change from now about APG scheduling? Will there be differences or will all remain the same?

A: Changes in the scheduling processes are described in the documents 20180323_Konzept_BKV_DE-AT_final & 20180322_Konzept_BKV_DE-AT_Formate_final which can be found on the project website: www.jao.eu ->Support ->DE-AT BZB project -> Publications & Meetings

Q: Will there be a test environment for scheduling to check formats and compliance?

A: Yes, there will be a test environment for the exchange of schedules.



Q: When will details on the congestion management for DE-AT border available in order to start necessary adaptations?

A: The design of capacity allocation is, to large extent, already defined and communicated/published (cf. presentation of the conference). Pending details will be defined soon and communicated as soon as possible. Since TSOs also have to adapt common and local processes and IT systems, they basically have the same implementation constraints as market participants.


Q: How did TSOs take into account the lead times on the side of market parties (e.g. for IT adjustments) for the implementation of the bidding zone border?

A: As a general principle, the congestion management on the border between Germany and Austria will not differ from any other border in MRC. The separated bidding zones in Germany and Austria will continue operating as usual. Market parties will have the opportunity to extensively test the changed environment during the external parallel run, starting 01 July 2018. The implementation date of the bidding zone border and the duration of the external parallel run were part of the overall agreement between the involved regulatory authorities. TSOs are aware of necessary changes/implementation (processes, IT) on market parties‘ side. TSOs (and NEMOs) themselves are in the same situation.


Q: Until when are the 4900MW expected to be reviewed and amended?

A: Basis for amendments will mainly be the long-term capacity calculation methodology in the Core region, which is still under development.
Hence updates can earliest be expected after implementation of the coordinated long-term capacity calculation.


Q: Was the decision concerning the inclusion of DE-AT border to the CWE FB coordinated in CORE CCR with all NRAs?

A: Due to the fact that the integration of the DE/LU-AT border is based on EU GL 714/2009, CWE NRAs are asked for approval. CORE NRAs have been informed about the approval process.


Q: Will there be any changes to nomination and scheduling procedures between the TSOs within Germany and in Austria as a result of the bidding zone split project? What are the major IT changes the market participants should be planning for?

A: Due to the fact that there is scheduling at the DE-AT border already today, only minor changes in formats are needed. See also the resp. Publication: https://www.amprion.net/Strommarkt/Engpassmanagement/Deutschland-Österreich/


Q: How shall we expect the cap being optimized? When will it be reduced to 4.9 GW and when not? And if no reduction occurs how much cap should we expect as NTC in the FB domain? how much will be reserved for the tertiary reserve from DE to AT? And will this amount be taken away from the commercial availability? ( so with restrictions, the 4.9 will be reduced by the cap reserved for tertiary reserve?)

A: The capacity for the day-ahead market on the DE/LU-AT border will be calculated on the basis of the published CWE FB Methodology.
In case it is below the long-term capacity of 4.9 GW, it will be increased to 4.9 via LTA-inclusion. In case the FB domain reaches higher values there is no capping.
Details concerning the reservation for balancing have been tackled within the Conference.


Q: Is the 20%-minimum RAM rule taken into account in datasets 2b, 2c?

A: No, the 20%minRAM has not been considered in the external SPAIC as it has only been implemented on 24/04/2018 in D-2 when the external SPAIC was already been performed.


Q: Is the data set complete, i.e. with the latest version of CBCOs?

A: Yes, the data set is complete. There are no further updates planned.


Q: Do we understand correctly that the usage of the LTA patch increases with the DE-AT split?

A: Yes, an increased application of the LTA patch was observed in the SPAIC scenario with the DE-AT split.


Q: What does external constraint mean?

A: The Flow-Based methodology is based on load flow calculations. For each hub, there can be additional lower and upper limits to make sure the grid respects the security of supply.External Constraints are stable values and limit the FB domains


Q: Why did you use the 50% alteration approach and not 40% or 60%? It looks like the 50% has been randomly chosen.

A: The 50% approach is a medium value as no proper historical datasets were available. The SPAIC process is not based on fundamental models and could only rely on historic order books. It should be noted that the 0% and 100% scenarios are very unlikely and that a choice in favour of 40% or 60% would also be difficult to justify in a more precise way.


Q: The FB Domain is expanded through the BZB split but in 90% of the cases it is violating the grid. Is the split situation a safe grid situation and will it be checked in the X//run?  

A: Considering the current situation with unlimited capacities between DE and AT, any chosen value is a reduction of capacities. If these capacities are feasible today, the split should bring an improvement of the network security situation.
TSOs are obliged to have a safe grid situation and are discussing how to ensure that X//run values will respect this safety. 


Q: The BZB split was supposed to reduce north-south flows in Germany. Has this been proven thanks to the SPAIC?

A: The SPAIC is a formalized approach and does not foresee to analyze such aspects. But gives Indication on the effect on prices and netpositions. Resulting load flows are not subject of the analysis done.


Q: How are redispatch capacities calculated in the SPAIC and how are they split?

A: Redispatch analysis has not been in the scope of the SPAIC.


Q: What is the foreseen methodology for the calculation of capacities allocated for balancing purposes? How will the CBA been performed and which elements are taken into account for this analysis? 

A: The allocation of cross border capacities for balancing will be based on a weekly Cost-Benefit-Analysis. This CBA will be based on the recent market data. Further details of the CBA will be available soon.


Q: The SPAIC is based on 12 selected Business Days. I have checked the wind infeed for these 12 BDs (on average 5GW) and compared it to the historical wind situation (15 GW), as the wind is the key driver for the FB domain. The 12 BDs do therefore not represent the reality over the year, especially if, in addition, OBKs for windy days have been applied. Why does the clustering of BDs lead to low wind days? Would it be possible to publish results for additional windy days?

A: The 12 BDs are the outcome of the clustering algorithm defined in the SPAIC approach and are therefore representing the average domain in the best possible way. It is unfortunately not possible to re-run the SPAIC for windy days but the external parallel run will give more insight on windy days when they occur in the time period between July and September 2018.


Q: How will you guarantee the 1,5 GW of redispatch reserve? 

A: Austria will guarantee 1 GW of redispatch capacities as of the winter 2018/2019 and 1,5 GW from winter 2019/2020 onwards. This can be provided from sources which are contracted for the Austrian grid reserve or from other power plants which are at the market anyway. Thus redispatch can come from different sources, and power plants can be asked to ramp up if necessary. The existing grid reserve for the summer will be expanded to winter months. Details about the procurement of the grid reserve can be found on APG's website.


Q: What is the rational when you activate the redispatching bids? What does the merit order look like when you activate them?

A: The activation of redispatch cannot be done purely market-based. It is based on general efficiency criteria, i.e. a mix of technical sensitivity and costs. For activation of this reserve, DE TSOs will make a request towards APG and APG will activate this potential, as it is the general usage for all borders.


Q: Are the GSK examples in the approval package real values or just an example? Are these dynamic values?

A: They are an example and need to be recomputed in case of commissioning/decommissioning.


Q: Concerning the assumptions for dataset 2b: has the new interconnector between DE-NL been included?

A: No. An additional separate SPAIC will be run for this change.


Q: LTA inclusion patch: will the patch only be applied to the LT capacities or the full 4,9 GW including Balancing capacities?

A: Whatever is the allocated LTA value, will be covered by the LTA patch


Q: Is there any chance that DE-AT will not be implemented within FB MC and when will a Fallback solution be decided?

A: All project parties are fully preparing for the FB target solution. However, CWE NRA approval is still pending. No complete Fallback solution is being developed in parallel but the second best solution would be a NTC based MC.


Q: How will daily procurement of aFRR reserves fit with monthly and weekly CBAs?

A: The (partial) allocation of cross border capacity is an innovation. In the first step the CBA will be performed on a weekly basis in order to ensure an efficient implementation and operation. The process for CBA might be developed further in the future.


Q: Is it planned to only publish X//run results within the utility tool or also via the web service?

A: X//run results will only be published within a dedicated Utility Tool. Market Coupling results will be published on a dedicated EPEX ftp server.


Q: The timing of the X//run is not the same as the production timing. Does it imply that the X//run will be closer to reality?

A: No, the reason for different timings lie in organizational reasons as it is not possible to perform the X//run activities within the operational shift. The D2CF information is only changed due to the split but not closer to reality. Further input data will remain the same.


Q: Specific contacts on NEMO / JAO side for (post-) go-live?

A: EPEX will distribute member info with relevant contact details. NP can be contacted via specific Key Account Manager. For EXAA, please contact the market operations department. Regarding questions on the FB domain, MPs can address their questions via the Q&A section on JAO website.


Q: How will AT-DE market coupling impact the AT-CH and DE-CH borders?

A: Currently, explicit auctions for the AT-CH and DE-CH borders are already handled separately, and transmission rights for these borders are allocated via JAO. This setup will not change with the DE-AT split. However, the underlying day ahead price for the remuneration of LTTRs will change to the separate AT and DE day ahead prices.

Q: I have one question regarding the hydropower plants (around 3.2GW) located in Austria but currently operated by Germany.
In Vienna last November, we have been told that on 1st October 2018, those hydropower units would be operated then by Austria.
Is there any official communication on this point, and more details like the list of hydro power plants exactly etc.

A: Since the situation and the potential solutions differ for the individual power plants, no general answer can be given on this subject.
In case the control zone or bidding zone is changed for individual power plants, this information will be updated by the power plant operators on the ENTSO-E transparency website (acc. to EU Regulation 543/2013 Article 14.1.b). In addition, TSOs will update their publications on the overall numbers for installed capacity in their control areas.