I was wondering about the section “Too high capacity on NO1-NO2” in the Operational learning points report. Could you please elaborate about the effects of this in the period this has been an error? How much less flow would be reasonable on NO1-NO2 if handled correctly? What would the approximated price effect be? Increased flow from NO1 to NO2 has been a very visible difference between NTC and FB in the parallel run so far, and some more details about this would be an important learning point for stakeholders trying to prepare for FBMC.

Answer provided 22 November

As we stated on the hybrid stakeholder meeting in Stockholm 26 October, we have done deeper analyses on the flows suggested by the flow-based methodology. The flows we see seem realistic based on the simulations we have run, and do not create overloads with contingencies in the grid. The OPL will be updated to reflect this.

I have a few questions about the week 34 parallel run report. It seems to contain some irregular results that I can’t see mentioned in the comments:

1. Different capacities on DK1-NO2?
2. Also for FI-SE3? Maybe something strange also for FI-SE1?
3. What happened with the NTC flow for SE3-SE4 – it is completely different from what we actual observed this week in the NTC market? And the flow DK2-SE4 also affected?

Answer provided 22 November 2023

1. About the NO2-DK1 situation

In NTC, the capacities on the HVDC interconnectors are manually limited either if there is a physical limitation on the cable or if there are internal grid limitations. For flow-based, the capacity is only limited if there is a physical limitation on the cable. For internal grid limitations, the flow-based methodology solves this on its own. For this week, there were limitations on Rød-Porsgrunn due to an outage. The CNEC sent to flow-based allowed for 20% overload, while not in NTC. This was probably the reason why the capacity on NO2-DK1 was higher in flow-based. We are looking into if the CNEC we sent had too high capacity, or if the NTC capacity was too limited.

2. Regarding FI-SE3

During week 34 there were outages in Sweden which restricted the flow on SE3-FI in NTC. Flowbased allowed for higher capacities for both directions (SE3>FI and FI>SE3). This was explained in more detail during the bi-weekly stakeholder meeting 28 September, please refer to the presentation (slide 20: Case Fennoskan + Outage in SE3).

3. Regarding SE3-SE4

There was a mistake in the NTC-flow results (FAAC NTC). As communicated during the Stakeholder meeting 26 October (see slide 5 in presentation), this error was present for week 31 to week 35 and has since been corrected. This error only affected the NTC results presented.

Do you provide a price comparison in the different zones that a change would have from the old system to the flow-based system?

Answer provided in October

Yes, you can find it in the CCM EPR market report appendix published weekly on the subpage Simulation Results. For example, the appendix file for week 35 can be found here. Please refer to page 11 onwards.

Also, the numerical data of required information can be found in the Excel file Market Simulation Results week 50 (2022) - xx (2023). Please note that the name of the file and the content is updated on a weekly basis. The file is available under the headline "EPR data on periods longer than a week" on the subpage Simulation Results.

When looking at RAM of PTDF constraints representing capacity on the external borders, I can see several cases that they are different from production ATCs. Could you please help me understand the cause of these differences?

The question is why when there was zero capacity in prod, in EPR there was capacity for the line (DK1-SE3, DK1-DK2)?
And for SE3-SE4 it is the other way (no capacity given in EPR, while there is full capacity in prod). Also, the question about difference in capacities when none are zero.

Answer provided in October

For the borders DK1-SE3, SE3-FI and DK1-DK2 there was internal limitations constraining the NTC domain. This was better represented with FB which allowed for higher flow on these borders.

For the SE3-SE4 case I think you have compared the wrong borders. SWL is represented in the topology as its own border and fore this period its capacity was 0. But there was capacity allocated on the AC border SE3-SE4.

The spreads out of Euphemia for 14 September  were quite striking and I was expecting to check the impact of the parallel run. I was expecting especially for SE3 and SE4 significant changes in NEX and (at least visible) deltas in prices… but in fact we can hardly observe any change there.

Checking with the (excellent) tool Netto Position Nordic Flowbased Analysis - Dashboards - Grafana (boerman.dev) one would say that there would have been space to change the NEX of SE3/SE4. So in fact, to go deeper here in the details of the welfare, I would need the bid-ask per bidding zone, which I don’t have access to.

1. Can you shed some lights on this day in your webinar next week or – if not possible- to publish a short explanation on hot wo interpret this one?
2. Can you consider changing the way that the bid-ask are published in the Nordics? In Italy there are two way of visualizing the whole merit orders:

• • a detailed offer list per powerplant which allows to recognize the behavior of every single unit (I know…. This is a no go for the rest of Europe.)
  •  The aggregated bid-ask for coupled bidding zone> which means that if all bidding zones in one hour have the same prices, then the bid-ask describe the over all merit order of the country BUT if Sicily+ Calabria decouple in one hour, then GME publishes the bid-ask describing 1) the coupled Sici+Cala area 2) the rest of Ita without those two

Maybe you guys can think of something like this? It would mean a lot in term of transparency.

Answer provided in October

For this period there was several outages in the Swedish grid that effects the capacities and flow. These can be found on the NUCS platform.
FB provides a better SEW result then NTC for this hour. We see a minor increase in the price in SE4, but a significant decrease in both FI and SE3.
The NP in SE3 is only changed with 70 MWh and this results in a price reduction of 30 EUR/MWh. This correspond to our assumption that SE3 is an area with very steep bidding curves. However there is a significant change in the flow in and out of SE3 where FB allows a higher import from SE2 and a higher export mainly to FI and SE3.

All prices, NP and buy/sell volumes on MTU and BZ level are available for both NTC and FB on the RCC website.

Regarding the publication of bidding curves on bidding zone level, that is not something that the TSOs can provide as it is data owned by the NEMOs.

As seen the net position changes quite a lot for some areas, but in the Nordics a lot of the power comes from hydro. A change in net position would mean that the hydro reservoirs would have to be filled up or emptied. An average net position change of -1600MW for NO2 for 5000hours would mean -1600MW*5000h/1e6 = -8TWh. NO2 has a reservoir capacity of 34TWh*, they would have to adjust their bidding quite a lot to not overfill their reservoirs.

Same would be true for the rest of the Norwegian areas and SE1 and SE2.

I think I saw somewhere that they did not model the North sea link (NO2-UK, 1400MW) so maybe the extreme NO2 numbers might come from there?

Answer provided in October

North Sea Link (NSL) is modeled outside the SDAC market. The flows on NSL is decided through a separate auction before the spot price is set, and is modeled as independent load/production in the common grid model. Although it is likely that the flows on NSL will affect the other flows in and out of NO2 somewhat, it is probably not enough to account for the 8 TWh of lower production/reduction in NP.

The flow-based simulation results are based on NTC bids and the bids will likely change when flow-based goes live. The producers in NO2 would probably need to reduce their water value somewhat to reflect the new capacities provided by flow-based, but to what extent is outside our scope. The reason why NO2 is impacted this heavily is probably more related to the large increase of flow from NO1 to NO2 that has been made possible in flow-based, rather than the impact from NSL.

There’s a major mismatch between the cnec names in JAO publication tool and EPR grid constraint matrix (GCM) on week 34. Practically all the anonymized cnecs have different identifiers for each source, and some other cnecs are also missing from one source. The problem is also there with cne names, and also on week 33.

This issue should be fixed, as it prevents us from validating the cnec-level results of our internal modeling vs. EPR simulations. This is key information for us as we prepare for go-live.

Answer provided 4 October 2023

Yes, the anonymization process employed on the JAO platform differs from that used for gc_matrix, resulting in distinct anonymization outcomes, as you indicated. Given competing priorities, we do not anticipate implementing a cross-referencing mechanism between the anonymization outcomes of JAO and gc_matrix at this time.

Considering publication timelines and deadlines, the TSOs offer the following guidance:

• For analyzing the most up-to-date daily FB parameters related to the DA FB market, it is recommended to utilize JAO data. This is because the energy delivery day "D" is published prior to 12:00 noon on the preceding day, denoted as "D-1."
• In preparation for the CCM g0-live during the EPR phase, TSOs advise stakeholders to rely on gc_matrix for comprehensive grid and market assessments. The gc_matrix provides cumulative weekly information including FB parameters such as PTDFs and RAM, along with market-related results such as shadow prices and market-induced flows.

I have created flow-based calculators for the Nordics but am unable to get my calculations within an acceptable margin of error using the publication tool data. I use a linear algebra solver to solve the final domain for maximizing zones and then cross-reference this against the published max NP. This results in major differences mainly for DK1, which suggests I am missing some form of constraint for the Danish zones. I already identified missing equality constraints for the virtual hubs and overall balance and added those (resulting in quite a decrease in the difference) but cant think of any more. I did notice that you publish a MaxBflow but according to the handbook that is something that is calculated, not an extra constraint. Allocation constraints on the external virtual hubs seem to be included in the final domain itself. Could one of you perhaps help me with understanding what goes wrong and why I see differences between the calculated values using the final domain and the published max boundaries?

Answer provided 4 October 2023

Yes, the MaxBflow published is a calculated value, not a constraint. The reason for the discrepancies is most likely due to the currently published results being a simplified calculation. In the handbook at JAO section 6.5 the calculation of the min/max NP is described as ‘The current version of the calculation is only a simple approach that for each bidding zone takes the minimum and maximum net position among the set of net positions which have been found to yield a minimum or maximum flow on any CNEC according to the calculation described in section 6.4.4.’

https://test-publicationtool.jao.eu/PublicationHandbook/Nordic_PublicationTool_Handbook_v0.2.pdf

This simplified calculation that does not directly work on the objective of maximizing the net position of a bidding zone. But rather it takes the largest and smallest NPs from the decision variables used in calculating max and min flows on CNECs. The simplified method is not guaranteed to return the global extremes because the same maximum flow could be realized with different configurations of bidding zone net positions. We have no explanation why the difference is more outspoken for DK1.

We have an update coming live in December where the maximum and minimum NP calculation should follow the logic given below:

• NP_max(n) <- maximize(NP(n))
• NP_min(n) <- minimize(NP(n))

Subject to the same following constraints: Constraints

Coupled pairs of virtual bidding zones include:

(DK1_SK, NO2_SK)
(DK1_KS, SE3_KS)
(DK1_SB, DK2_SB)
(SE3_SWL, SE4_SWL)
(FI_FS, SE3_FS)

Bidding zones belonging to the “Jutland” area include all zones with name beginning with “DK1” the rest are placed in Nordics.

So, the currently published min/max net positions does not serve as a particular good reference for your test. But hopefully you can recognize the above logic in your implementation.

I have questions regarding your information on an update coming in December: reiteration of earliera info. As far as I can see the allocation constraints of your listed constraint 2 are published in the final domain data set. Or is there another place where they are?

One thing I don’t fully understand is the fourth constraint that you listed. What exactly are those extra Jutland net positions? Are the DK1_* hubs something special? That could also explain why my calculations were so excessive different from the published calculation compared to the rest.

Answer provided 4 October 2023

The Jutland constraint is very important. It is essentially what keeps the balance of the entire Central European synchronous area. Spanning two synchronous areas in one capacity calculation region means that we have to split the balance constraint as such: 1 for Nordics and 1 for Jutland/Central Europe.

Allocation constraints are included among the flow-based domain parameters with type=ALLOCATION_CONSTRAINT. They have a single non-zero zone-slack PTDF of +/-1 (depending on if it is maximum or minimum net position being constrained) and RAM set equal to the constraint on net position. You can hence choose not to implement constraint number 2, as this is already satisfied by constraint number 1. But the formulation in const. 2 allows for a more efficient implementation.

Why does flow-based means a higher strain on the interconnector compared to NCC?

The TSO’s are investigating a need of ramping restrictions on Fenno-Skan when FB is implemented. What will that mean for the flows?
When will the TSO’s be ready to take a decision regarding a possible restriction?

If the restrictions is implemented – will the flows at Fenno-Skan still be higher than currently, when FB is launched?

Answer provided 4 October 2023

Based on the Nordic Flow-based parallel run results, Flow-based allocated flow between two consecutive market time units (so called ramping) have exceeded technical limitations regularly with the Fenno-Skan (FI-SE3) interconnector. Exceeding technical limitation means that HVDC interconnector cannot physically provide flow that has been allocated in the Day-ahead market. Currently ramping has been applied on HVDC interconnections from Nordic synchronous area to other synchronous areas, but not internal HVDC interconnections such as Fenno-Skan.
Assessments of ramping on Fenno-Skan are currently on-going. Fingrid and Svenska kraftnät will inform on the results of the assessment when ready.
Ramping limitation is expected to have minimal effect on Fenno-Skan average flows. The total transmission capacity will not be affected.

How will this new method of coupling the Nordic countries be expected to affect the flows to and from the continental Europe, specifically the Netherlands, Germany and Poland?

Answer provided 4 October 2023

Currently, we described in the NRA EPR report that more flows going out of the Nordic CCR, i.e. more export from Nordic to the EU continent. You can find the data for the allocated flow for each border on the Nordic RCC website. The data from the start of the external parallel run until the latest available data is continuously updated in the file called "Market Simulation Results week 50 (2022) - 31 (2023)". In the sheet "F_AAC," you will find the allocated flow in both NTC and FB for all borders and MTUs. If you want to investigate more details per border, please look into this data indicated above.

Is it simply per border, or do you count the “real” non-intuitive flows? The reason for asking is that in the recent ACER report: https://acer.europa.eu/sites/default/files/REMIT/REMIT%20Reports%20and%20Recommendations/REMIT%20Quarterly/REMITQuarterly_Q2_2023.pdf

I can see the following:

1. it has a positive net position (net exporter) and
2. it has a price that exceeds that of all its neighbouring bidding zones.

Is the above in line with the way Nordic RCC created the graph showing occurrence of NI-flows? Is there a standard definition of non-intuitive flow?

Answer provided 4 October 2023

The NI-flows in the market report are counted as hours per border where the AAF-flow are positive in the direction going from a high-price area to a low-price area.

We were not aware that ACER had more focus on a certain subset of NI-flow, but that is something we will have to look at. Thank you for letting us know.

I see that in EPR topology, we no longer have DK1A/NO1A/NO2A.

1. Are the cumulative capacity limits for NO1-NO3 + NO1-NO5 not needed anymore (or somehow taken care of by PTDF constraints)?
2. Similarly for DK1-SE3 + DK1-NO2. For the latter set of lines, currently we also have a cumulative ramping limit. How is it handled in NFB configuration?
3. Similarly for SE3-NO1 + SE3-DK1
4. Similarly for DE-NO2 + NL-NO2. I see in EPR data a lineset is introduced containing DE-NO2 and NL-NO2 for which cumulative ramping limits are given. These two lines are defined as NL-NO2 (Biddingarea_From = NL, Biddingarea_To = NO2), and NO2-DE (Biddingarea_From = NO2, Biddingarea_To = DE) in database, which means that the up direction of one is towards NO2 and the other is from NO2. However, in table Lineset_members, in the Direction column we have “1” for both lines, while I expect “-1” for one of the lines. Can you help me understand why?

Answer provided 4 October 2023

Please see the answer for each sub-question below.

1. The cumulative capacity limits (line sets) will not be needed in the day ahead market after transitioning to flow-based market coupling. Indeed, the additional degrees of freedom given by these line sets are now redundant with the even greater degrees of freedom provided by the ptdf constraints
2. Ramping limits cannot be replaced by flow-based parameters and will still be relevant after transitioning to flow-based. This is to ensure that the changes in import/export of the Nordic synchronous area can be managed with the available balancing power. Group ramping limits will still be used after flow-based go-live.
3. Same as “b”
4. The questions suggest that the asker has access to market simulation input data, which is not accessible to the general public. Questions from the NEMOs regarding errors in the topology configurations in the flow-based market simulations is better directed to the simulation and analysis working group for a more swift resolution. However, in this case the SIWG had it confirmed that there indeed was an error in the group ramping configurations. We thank you for the notice which led to the error being corrected for future simulations. The impact of the error on previous is estimated to be minor.

I was looking for updated information on the go life date of FBMC on your website. Would you be able to communicate the current planning?

Answer (updated 7 November 2023)

Nordic Flow-based Market Coupling is expected to go-live in October 2024. For more information, please refer to the News update on the same date.

My main problem is to understand how the time-unit in the MarketResults file for the NetPositions is set compared to the JAO website. Is the NetPositions in UTC or CET? As I understand it is in CET, as there is missing one hour 26. March? I have multiplied the PTDF’s with the NetPositions to look at the market flow and compare it with the RAM.

As for the results of my calculations I have observed that there are multiple times where NP*PTDF is bigger than the RAM. I was wondering if you have a good explanation why this occur and what the consequences are for this. I have added an example when it is an overflow of 76 MW. (Where I think I have used the time units correct, but I am not entirely sure)

Answer provided 4 October 2023

The time stamp on JAO is CET. Time stamp on net positions data and other market simulation results are Energy delivery date and MTU number. And as the MTU numbers largely follows the CET format (except for those days where we shift from summer to winter time and vice versa), the MTU number should normally match the hour of CET time stamps used on JAO.

The flow you calculate as the product between PTDFs and Net positions can be compared to the Grid Constraint Matrices that are published on a weekly basis on the NRCC homepage. The column AD “FLOW FB” should match your result.

However, it does not match for your example for the 16th of March. The most likely reason is a data inconsistency on our side. I see that we had issues on this date and that a fallback domain was published to JAO. This incident could have led to different sets of flow-based parameters were used in market simulation than what is currently showing on JAO.

If you have particular interest in this date we can try to investigate the issue more. Otherwise, I would suggest that you continue your analysis on the remaining EDDs.

Answer provided 4 October 2023

Yes, there will be ILF on these HVDCs with one terminal outside of the Nordic CCR, just like today.

Will it be possible to fetch the factors from somewhere?

Answer provided 4 October 2023

The values inherit from the NTC method. The current values can be found in the CCM EPR handbook. The revision of the ILF is out of the scope of the Nordic CCM project, depending on the approval process of the NRAs on the concerned cables.

Are virtual zone pairs modelled in the same way as the ALBE/ALDE zones for the ALEGrO Cable in the CORE flow-based domain? Specifically, the exchange between ALBE and ALDE is treated as an ATC exchange (not flow based), thus NEX_ALBE = - NEX_ALDE != 0. See also pages 7 & 8 here. I assume this would also apply for the Nordics and in analogy also for single virtual zones representing HVDC interconnectors connecting to bidding zones outside of the Nordic Flow-based topology, i.e., the NEX for such single virtual zones would correspond to the flow going / from the corresponding external bidding zone, correct?

Answer provided 4 October 2023

Virtual bidding zones are used to represent end-points of HVDC interconnectors or AC interconnectors to other (non-Nordic) regions. Some of these interconnectors (e.g. DK2-DE/LU) are part of the HANSA capacity calculation region, which performs capacity calculation by means of the ATC method (see: https://eepublicdownloads.entsoe.eu/clean-documents/nc-tasks/EBGL/FCA_A10.1_CCR%20Hansa%20-%20LT%20CCM%20-%20Legal%20document_for%20submission.pdf).

HVDC interconnectors with both terminals located within Nordic CCR are modelled as equality constraints. For example for Skagerrak HVDC connecting DK1 and NO2 we have the virtual bidding zones; DK1_SK and NO2_SK. In market coupling the net-position of those virtual bidding zones must satisfy:

NP(DK1_SK) + (1-ILF)*NP(NO2_SK) = 0 , if NO2 is exporting or

NP(NO2_SK) + (1-ILF)*NP(DK1_SK) = 0 , if DK1 is exporting

where ILF is the Implicit Loss Factor defined for the HVDC (3.0% for Skagerrak and 0 for all other internal Nordic HVDCs – values are subject to annual revisions)

Are the sum limitations implicitly included in flow-based or do they coexist with flow-based constraints?

Answer provided 4 October 2023

In the Nordic method for flow-based capacity calculation, linesets are only used for combining ramping limitations (E.g. NO2A imposes a combined ramping limit on NO2-NL and NO2-DE/LU). The ramping limits will coexist with other flow-based parameters.

While looking at JAO's data for the Nordic flow-based model, I couldn't help noticing that the only variables that are considered are net positions of all the Nordic areas and flow variables between Nordic areas and virtual bidding zones. It appears that flows between areas that are not connected by one of the lines that give rise to a virtual bidding zone are discarded. As a consequence, no CNE constraint depend, say, on any flow between Norway and Sweden, because none of these lines are associated to a virtual bidding zone. In particular, no CNE anywhere in the Nordics depends directly on any flow from and to NO1. For instance, there is a CNEC with name "Border_CNEC_SE2_NO3", but the associated PTDF coefficients show an intricate combination of many flows and net positions instead of a more natural constant vector with all its coefficients except one equal to 0. Is there a reason why the present model has been favored over a model with all existing flows between regions?

Answer provided 4 October 2023

We are not sure we understand the question so we explain the difference between a ZoneToZone-PTDF and a ZoneToSlack-PTDF in the hope that it will help. Those are two different things and can be used for different purpose. Both are available on JAO, so you don’t need to calculate them yourself.

What is a ZoneToZone-PTDF and a ZoneToSlack-PTDF?

The PTDF_BZ (ZoneToSlack) describe how the Border CNEC SE2-NO3 are affected by an increased export in BZ. E.g If the export is increased in FI with 100 MW, then it will release the flow on the Border between SE2-> NO3 with 3,286 MW. In practice does this mean that there will be a flow 3,286MW from NO3->SE2.

The PTDF_BZfrom_BZto (ZoneToZone) describe how Border CNEC SE2-NO3 are affected by a flow from BZfrom to BZto. This means an increase in export in BZfrom and a decrease of the same amount in BZto. This is calculated by PTDF_BZfrom minus PTDF_BZto = PTDF_BZfrom_BZto

Just because we increase the export in SE2 and increase the import in NO3 is there no guaranty that all the flow will be on the border SE2-NO3.

Th PTDF-value z2z_SE2-NO3 show that with export of 100MW in SE2 and import of 100 MW in NO3 will 54 MW be transformed on the border SE2-NO3. The rest 45 MW will be transported on other paths. Eg. SE2->SE1->NO4->NO3, SE2->SE3->NO1->NO3 or another way.

The ZoneToZone value is 1 if all the flow will run on that CNE.

According to the NRA-process you are supposed to deliver this data with just 2 weeks time-lag.

Answer provided 4 October 2023

Thank you very much for your patience. According to the current EPR arrangement with the NEMOs and the NRAs, there is a grace period of 2 weeks. Afterwards, the TSOs need 1 week to process and publish the data and results. So, in fact the results can be published at least 3 weeks after the energy delivery week.

However, in this case we didn’t deliver in time according to the process. After the internal checks, here are the reflections on the delay. It was caused by the reruns of the simulations of weeks 20 and 21 due to the following reasons:

• Week 20: There was an issue in the input data for week 20 (we were missing the external borders), so we created the data again and the simulations were rerun
• Week 21: 1 energy delivery day was missing in the simulation, and the max price threshold was reached due to a wrong setting. Additionally, when the TSOs asked the NEMOs to rerun the simulations, there was an issue with a session dump file that took 2-3 days to be solved.

We are constantly working on improving the data processing and publication processes and we hope to avoid the same errors in the future.

Answer provided 4 October 2023

Yes, it was due to an error in translating NorCap output to JAO input following the NorCap release 5 entering into service. The errors data published to JAO for EDDs 8 and 9th of June have now been corrected.

There are a lot of 0 for the RAM 8-9 June at JAO and it has been informed that it is due to errors.

Answer provided 4 October 2023

No, we don't expect the error to impact go-live. Although the error impacts the quality of the FB domain for these two days, the reason behind the error has been corrected.

It seems that the ATCE values are too high compared to the maximums NTC of 500 MW for this direction and 600 MW in the other direction (from PowerPoint-presentation (nordpoolgroup.com))

Answer

The physical capacity on NO2-NO5 is closer to 900 MW, but the NTC values are lower because of the consideration that some of the physical flow triggered by the trades from NO2-NO1 will fall on NO2-NO5.

The ATCE ID values make sense when looking at the PTDFs of the NO2-NO5 CNEC. When trading happens from NO2 to NO5, only 1/3 of the trade will be physically present on NO2-NO5 border CNE. So If we allow for 3500 MW ATCE trade from NO2 to NO5, only 3500/3= 1200MW will actually fall on that line. Also, a trade of 3500MW from NO2 to NO1 (this is approximately max capacity) will induce a flow of about 12% on NO2-NO5 (~400MW). So, the resulting flow from NO2 to NO5 will be around 1600 MW. This is higher than the thermal limitation on the CNEC.

In some cases, the DA FB market has ensured that around 900 MW will flow from NO5 to NO2. Thus, we can give this 3500 ATCE trading to the market, because using all this trade will result in first 900 MW change to zero, and then 900MW from NO2 to NO5. So it is possible to go from a scenario of 900 MW NO5-NO2 in DA, to 900 MW NO2-NO5 in the ID market. And to do so, you need to provide the market with ~3500MW ATCE of trade, such that the actual flow on NO2-NO5 will be 900MW.

First, the count and the percentage in the appendix reports don’t match. For example, for week 8 below, the count is 115 so the percentage should be 115/168 = 68% but the table states 34.2%. Second, it seems that the count is off. On the same week, a number of intuitive flows of 115 hours would mean that there would be more than 115 hours with higher prices in SE3 than in SE4, which is not the case. For that same week, I count 11 hours with non-intuitive flows in the direction SE3>SE4 and 6 hours in the opposite direction.

Answer

Currently the table shows both SWL and the AC border of SE3-SE4 together but they are modelled separately in FB. The market simulation outcome indicates that there are a lot of non-intuitive flows on SWL but not on the AC SE3-SE4 border and when you sum the SWL and AC flows together. The TSOs are discussing how to update the non-intuitive reporting table.

No, it is included in the FB process.

I find it strange that the five groups for 2 hours only made 21 questions. That this short answers on these 21 questions would combined all the discussions made during the 2 hours is very strange. In the light of being able to share the information to all stakeholders I find this odd. We would also like to have notes of all comments made during the session before lunch from the project and NRAs in meeting notes published.

Answer

As stated at the stakeholder meeting, we made notes of all answers that contain “new” information compared to our earlier information (for instance reports, Q&As, presentations and publications) as well as all questions related to the consultation that remained unanswered after the meeting ended. We will publish all of those, as well as stakeholder questions relating to the consultation received by e-mail during the consultation period. We haven’t been able to answer and publish all questions in one go, but we are delivering as fast as we can and aim to publish all this week. I

published one batch on Monday, another batch today and expect to publish the rest tomorrow. If we receive additional questions, we will publish them as well.

As our sessions before lunch was just presentations, we didn’t make any notes from them. We made some notes from the NRA session, but need their OK to publish, as it was their session and responses. This confirmation is currently in process and we will publish as soon as possible.

The timeline is fixed and it is not possible to extend the deadline. The consultation timeline have been shared and presented well in advance and we need to deliver to the NRAs in time.

The GSK strategies are for each TSO are published in the JAO publication handbook, section 9.1.5 at present.

The GSK factors that relate a change in bidding zone net position to a change in load or generation at a given node will not be published as it is a very large amount of data and the use case for this is not clear.

Forecast of wind and all other production and consumption estimate are used in the calculation of Fref and F0 and will therefore affect the capacity available for the market. Please refer to the approved DA/ID CCM equation 9 and 10.

A difference between the TSOs' estimate of a production/consumption unit and the market participant buy/sell volume in each BZ are managed by the GSK. If there is large forecast error over time, this can be handled by a larger FRM value on the affected CNEs.

The better forecast the TSOs can make, the more capacity can be made available over time for the market participants.

The new LT CCC processes with FB methodology (the Nordic LT CCM) are currently under System development at Nordic RCC. As part of the LT CCM go-live, a 6-month parallel run period will be held during which time these LT CCC process related domains (i.e., Y-1 and M-1) are going to be calculated and published.

The eventual “go-live timing” of the publication of Y-1 (yearly) and M-1 (monthly) FB parameters will follow the LT CCM defined deadlines. Please refer to the approved LT CCM for further details.

The focus has been on the NRA EPR evaluation report and there have not been resource at the TSO to perform extra simulations on days with fallback or backup.

We will get back to you on this question.

Given the arbitrage possibilities in ID, the market participants are likely to use them and change the (border and CNEC) flows of DA. Can you provide an overall SEW assessment, considering the DA market outcome-induced flow and the ID arbitrage-induced flow and maybe the counter-trade costs?

Answer

No, it is not possible to compute the ID arbitrage SEW and adjust the DA SEW by the ID arbitrage SEW and the counter-trade costs.

The Danish windpark is modelled like all other production and consumption units and will therefor effect the F0 values. (Mostly in DK2)
Landing cables from the windpark and to shore (Bjæverskov) are not modelled as CNEs and will therefor not constraint the market solution. These are handled in the capacity on the interconnector from DK2-DE which is calculated by CCR Hansa. See the Hansa DA CCM.

Finnish P0 and P1 cuts are included to basecase but these cuts are there due to voltage and dynamic stability contraints. Currently CNECs´ thermal limitations within P0 and P1 cut are modelled with contingencies.

The first thoughts of how the UMM information would look like in the form of FB parameters (when LT CCC processes are going live), were presented in a Stakeholder event on June 29th 2022. Please refer to the presentation on the NUCS methodology at the stakeholder event on June 29, 2022 for further details.

The percentage at the beginning of the NO CNECs refer to the loading of the CNE based on the 'Statnett backoffice pre-computation'. It is not the actual loading of the CNEC in FB, which should come from the NRCC. In short, the percentage at the beginning of the Norwegian CNECs has no practical meaning for the SHs.

Please also refer to EPR handbook.

There is a need for hydro power producers to accurately forecast their water value to avoid flooding or empty reservoirs. All from 1-year forecast to 20-year forecast. 1-5 years is most important.

Answer

The TSOs understand the needs of the hydro producers to evalute the long-term effect of introducing FB on the water value. However, such analysis requires the Nordic TSOs to create an opinionated FB orderbook, amongst other assumptions, and draw conclusion upon these assumptions. The TSOs cannot fulfil the request.

The LT will be implemented 12 months after the go-live of the DA/ID CCM.

The FB domain for all four quarters within an hour will be the same.

Network tariff is not connected to the FB implementation. Network tariff is set on a national level by each national TSO. There is no foreseen change by the FB implementation.

The new LT CCC processes with FB methodology (the Nordic LT CCM) are expected to go live a year after DAFB go-live. Until that point in time, the long-term related capacities are going to be calculated by each Nordic TSO (as today) and published as NTC values.

The existing principles and processes associated to NUCS messages will continue when DA-FB is live. A first enhanced solution for NUCS platform (temporary until LT CCC (FB) go-live) will present the available and respective unavailable capacities as ”Reference Max and Min net position”, ”Max and Min Net Position”, and ”Unavailable Export and Import” for the respective bidding zones to accommodate the FB methodology. These unavailable capacities will correspond to the NTC values provided. However, the actual NTC values will most likely not be shown in NUCS messages because they do not provide any relevant information, cf. the FB methodology.

Since in the ID timeframe the cross-border ATC values will be applied until FB is implemented in XBID, this NTC representation of NUCS messages could still be relatable. In DA-FB parameters, the outages planned for trading day are already considered and only effects of unplanned outages to ID timeframe must be considered after DA-FB calculation results are available.

When LT CCC (FB) is going live (a year after DAFB go-live), it is expected that there will be a new process utilizing the FB methodology, to compute and further visualize the NUCS messages and their associated available/unavailable capacity within NUCS platform.

Physical flows.

The change in modelling of the series capacitors was already implemented for NTC since before the FB EPR. From the 1st of March 2023, the management of the series compensation in FB is the same as in NTC.

If figures (or long texts) cannot be included in ENTSO-E consultation tool, can they be provided by email?

Answer

The ENTSO-E consultation tool doesn't allow for figures, graphs or any other kind of image elements to be used. If you would like to illustrate your point using figures/graphs, you are welcome to provide this information via e-mail to ccm@nordic-rcc.net. This also applies if your response exceeds a word limit of the ENTSO-E consultation tool.

In the normal case, flow-based parameters will be published before 9:30 on D-1. In exceptional cases, parameters may be updated until 10:00 CET. Exceptional cases could include updates due to unplanned outages of cirtial importance or replacement of backup domains. The time to process an update of flow-based parameters is longer than the time it takes to update NTC values (how long it takes depends a bit on the
change; IVA provision takes a few minutes, while changes involving sending of new IGMs could take an hour before the results are published). Hence, there may be situations during parallel run, where the window for updating flow-based parameters has surpassed but updates can still be made to the NTC values. This leaves a possibility for discrepancy by allowing NTC values to include unplanned outages happening between 9 and 10 in the morning of D-1, while the flow-based parameters might not include these. Our records from EPR does not indicate that this risk has materialised yet. But it is a possibility.

We do expect some discrepancy between flow-based and NTC capacities, not due to accuracy of outage information, but due to the inherents differences in the methodologies.

Currently, we are following the CID methdology designed by ENTSO-E and approved by ACER in 2021, but the scheduled exchanges are used instead of the flow-based allocated flow. The CCM project is working on changing this, so it follows the CID methodology.

There is currently ongoing discussion on an amendment of the CID methodology in ENTSO-E.

For the daily process during the EPR, please refer to the EPR evaluation report page 19. In addition, here is more elaboration on the Common grid model alignment (CGMA) process for the D-2 CGM creation. CGMA is a pan-EU process that harmonizes the generation and load forecast from individual TSOs. The harmonized exchanges, net positions, amongst others, are the inputs back to the individual TSOs for creating their individual grid models (IGMs). In other words, the flows on the tielines, net position per bidding zone, per TSO in the IGMs follow the CGMA outcome. Afterwards, the TSOs provide the IGMs to the NRCC, so that all IGMs are merged into one common grid model (CGM) at the NRCC for the subsequent FB CC steps.

The TSOs are doing this as requested.

It is a non-SDAC HVDC cable. The forecast of the NSL is embedded in the CGMs like a fixed generation or load. It is not modelled as a virtual bidding zone like other SDAC HVDCs that are subject to the SDAC market coupling. In other words, the NSL impact on the Nordic CNECs is captured in the Fref and F0 in the FB terms.

They are mostly caused by voltage stability. Some dynamic constraints are caused by osillation of the grids. They are computed offline by the backoffice at the TSOs using dynamic simulations. Further development of the dynamic constraints will take place according to the Table 1 of the approved DA/ID CCM.

The TSOs are aware of the comment/issue. We are working on fixing it.

We are looking ahead. Parallel run is an operational test as well as a test of the methodology. We will not rerun the simulations. The TSOs will continue providing the data / result until go-live.

This can be best answered by Nordpool.

The complete grid model will not be published. In the long-term CC, we will publish some characteristics of the grid model, e.g. the FB parameters, net positions. Details can be found in the approved methodology for long-term CC.

We use D-2 wind prognosis for the FB CC.

Yes, they will be included in the final EPR evaluation report.

No, it is included in the FB process.

There are two legal requirements for FB go-live. The first is that the Nordic NRAs have to confirm that the pre-defined KPIs for the 3-month reporting period have been met and that the results are sufficiently elaborated in the evaluation report. The second is that the EPR is to continue for at least six months after the NRA confirmation of the KPIs being met.

Additionally, there is a need to demonstrate the operational readiness of Nordic FB by successful testing on a pan-EU level.

The Nordic TSOs and the Nordic RCC will not initiate FB go-live until we are confident that the FB process and FB results are viable. As soon as the FB goes live, the current NTC will stop.

The purpose of the 3-month period and the associated evaluation report is to fulfil the NRA requirement for monitoring and evaluatation. The overall EPR period is at least 12 months.

Implementing the FB CC and MC is a learning-by-doing process including all involved parties. The TSOs try to be as transparent as possible, so that the SHs may be able to learn to adapt their own processes to FB.

The dimensioning fault is considered as the most limiting CNEC in our FB CC.

No, we will not rerun the simulations. There was a wrong forecast on the wind in NO4 as inputs to the FB CC and this impacted the export.

It may be that we are giving more capacity for ID market due to relaxation of the flow-based parameters. TSOs are currently assessing the operational security of the calculated capacities, as the responsiblity of the TSOs is to ensure the operational security and providing the capacities to the market within the security limits. Regarding arbitrage, please refer to the consulted version of the EPR evaluation report, page 50.

No. It is possible but very difficult to trace reservoir fillings and we have decided not to do that. It is a known issue when performing the FB MC using the NTC orderbook. The NTC orderbook is the only qualified and factual orderbook that can be used in the EPR. The Nordic TSOs do not plan to create an opinionated FB orderbook and draw conclusion upon the opinionated FB orderbook.

No. We are looking ahead. Parallel run is an operational test as well as a test of the methodology.

Yes and no. We did not anticipate it. But after seeing it we can understand why it happens.

I was thinking that the net positions could be part of the optimization variables but you would then end up with one particular set of net positions in the optimal solution which is not what is desired. Basically, I have difficulty understanding how to capture “for all possible net positions” in an optimization setting.

Answer

No other variables besides the Cn and Cn,o are in the ATCE method. The ATCE method takes the DA FB domain as input to compute the DA NTCs. Under the ID allocation, the extracted NTCs are the constraints, as inputs, for the single intraday market coupling to determine the net positions, and all necessary grid constraints are already represented in the FB domain. If further constraints are needed on the net positions as inputs to the single intraday market coupling, those will be allocation constraints, to be considered directly by the intraday market coupling algorithm.

The Cn and Cn,o are the exogenous variables in the ATCE optimization. This optimization needs to respect the FB constraints, which are on the CNEC level. The extracted NTCs (i.e. Cn and Cn,o, being the results of the ATCE optimization) are on the bidding zone border level. The formula z2zPTDF * exchanges (i.e. exogenous variables) < RAM links the CNEC level z2zPTDF to the bidding zone border level exchanges. The Cn and Cn,o are not directly applied to the RAM of any CNECs.

The FB domain is modelled in the ATCE as z2zPTDF+ * C <= DA_RAM, where z2zPTDF+ refers to the z2zPTDF applying the positive PTDF filter and the threshold parameter. C refers to the variable vector of Cn and Cn,o.

In the mathematical terms, the inequality constraints are modelled as A*x<=b.

• A is the z2zPTDF+
• x is the vector C containing Cn and Cn,o variables
• b is the DA_RAM

Corresponding to the matrix implementation, the z2zPTDF+ is a m-by-n matrix, m is the number of constraints, e.g. the number of presolved CNECs. n is the number of directional borders. Thus, the C is an n-by-1 vector consisting of [Cn and Cn,o], and the DA_RAM is also a n-by-1 vector.

Non-costly RAs are always considered in the capacity calculation process. For the costly RAs it will be assessed whether they are available and can be utilized to increase the capacity on internal CNECs or internal combined dynamic constraints. If they are indeed available, they are applied to ensure the 70% rule despite the costs associated with them.

It is a quality check performed by the TSO operators to validate the capacities calculated by the coordinated capacity calculator (Nordic RSC). Note: the Nordic RSC has changed to Nordic Regional Coordination Centre (Nordic RCC), which is now a separate legal entity.

Some part of the benefits of introducing FB are discarded. ACER decision 04/2020 removed the possibility of having an intuitive patch in the market coupling algorithm; as such, the application of FB intuitive is no longer an option.

There are no overloads on monitored CNECs or combined dynamic constraints (i.e. the CNECs and combined dynamic constraints taken into account in the market coupling) in the DA market outcome, but due to changing conditions close to real-time and numerical discrepancies, there may be overloads in the operational hour that are mitigated by means of redispatch.

Yes, however, when a negative RAM is calculated for the DA timeframe, the RAM value shall be set to zero and the potential overload shall be managed by redispatch. This is different for the ID timeframe, where a negative RAM will be applied in the allocation and/or via remedial actions.

As we have a zonal market system, the TSOs need, for each time frame, to make assumptions about how variation in a zonal net position is distributed amongst generating units and loads in the bidding zone. It should be noted though, that there is no difference between the NTC and FB world in this respect, and also – it is done already in today’s NTC calculations – though not as formalized nor coordinated. In FB capacity calculation, all uncertainties in the capacity calculation process add up in the RM, including the uncertainties linked to the GSK. As such, the different GSK options can be assessed by computing the corresponding RM values, reflecting the uncertainty that is linked to the use of the different GSK strategies, and to opt for the one that brings the lowest uncertainty.

The GSK in itself does not affect how a producer is selected over another in the market coupling, as such it is not prone to gaming.

Yes, but the FB capacity calculation is a more formalized methodology than the one applied today so that there is less dependency on operator experience. The TSOs are, however, responsible for providing the input data, as well as for validating the results from the capacity calculation – the FB capacity domain.

There is a perceived disadvantage that under FB internal constraints can be taken into account, as this is not transparent. Would it not be preferable to countertrade or redispatch and have cross-border constraints only?

Answer

Both FB and NTC are equally able to take the same internal constraints into account. With NTC being a “black box” where scenarios and internal constraints are captured in one single value on each bidding-zone border, the level of detail under FB is higher, and the use of internal constraints is more transparent. Countertrade and redispatch are remedial actions (RAs) as defined in Article 9 of the CCM.

As described in Article 8 of the CCM, to avoid undue discrimination between internal and cross-zonal flows, the TSOs will take actions to meet the requirement from Article 16(8) of the Regulation 943/2019. For the costly (and non-costly) RAs it will be assessed whether they are available and relieve flows on internal CNECs or internal combined dynamic constraints (Article 10 of the CCM), and whether it is economically efficient to apply RAs. If RAs are available, they are applied to ensure the 70% rule despite the costs associated with them to meet requirement set in Article 16(8) of the Regulation 943/2009.

The Nordic CCM follows Article 16(8) of the Regulation 943/2019 and the related ACER recommendation 01/2019. This is elaborated more on rules for avoiding undue discrimination between internal and cross-zonal exchanges in Article 8 of the CCM and will be monitored as recommended by ACER in the recommendation 01/2019.

Yes, the stability/dynamic issues are simulated in offline grid models that are enhanced for the dynamic analysis.

If the information is available before the DA / ID capacity calculation starts, it will be taken into account. If the information is available during the DA capacity calculation or after the DA firmness deadline, it will trigger a recalculation of the ID capacity.

No, they will vary from hour to hour, as grid topology and grid usage changes over time.

A so-called advanced hybrid coupling is applied in the Nordic CCR to model the exchanges from/towards the neighbouring CCRs on the HVDC links. A DC link (being a fully controllable active power flow) is an NTC by nature. Combining these NTCs with the FB methodology applied for the AC grid is done by means of the advanced hybrid coupling: the converter stations of the DC interconnectors are modelled as ‘virtual’ bidding zones in the FB system (a bidding zone, without order books though), having their own PTDFs reflecting how the exchange on the DC link impacts the AC grid elements.

Yes, it is foreseen to be modelled as a DC link where the allocation mechanism sets the power flow on the controllable device using ‘advanced hybrid coupling’. However, if the phase shifter is ‘small’, e.g. Charlottenberg-Eidskog (NO1-SE3) being connected to the lower voltage grid, operated jointly by TSO and local DSO, it can be managed directly by the involved TSO/DSO as inputs to the capacity calculation, instead of explicitly modelling it as virtual bidding zones.

No, the capacity on DC connectors will – in principle - be the nominal value; it is the market clearing algorithm that determines the optimal flow on the DC cable. Bymodelling the HVDC links as virtual hubs, the DC links compete with all other exchanges to make use of the scarce capacity in the AC grid. A restriction on the west-coast cut may in this way have an impact on the resulting flow on the DC cable.

No, as this would require a non-linear market model.

They are treated as separate allocation constraints and are provided to the NEMOs to be taken into account in the market coupling. They are not part of the, or expressed as, FB parameters.

Yes, from theory, and yes from a practical point of view, when both the FB and NTC are subject to the same level of operational security.

We are using the simulation facility, which mimics theEuphemia algorithm used for the SDAC in the production environment. More details can be found in the Euphemia Public Description

Historical order books and capacities in the SDAC, reflecting the current market coupling. (. For the Nordic FB market simulations, the same setup is used but the NTC capacity constraints in the Nordic CCR are replaced by FB constraints.

No, in essence not (unless the market clears at the maximum price).

It is the same as today: it is the social welfare (consisting of consumer surplus, producer surplus, and congestion rent) that is optimized. The change is introduced through the constraints to the optimization. NTC applies constraints to the flows on each bidding zone border (NTCs), and FB introduces constraints on the maximum allowed flows on CNEs (PTDF matrices).

Congestion revenue is a natural part of the social welfare when transmission capacity turns out to be a scarce good, expressed by the price difference. Note: The objective function of the NTC and FB market coupling is the same: it is the social welfare that is maximized. Congestion revenue as such is not maximized.

System price is a reference price computed by Nordpool. This work is not related to the Nordic TSOs or the Nordic RCC.

No, it is at least not within the scope of this project.

The majority of the trades occur on the DA. The ID platform XBID cannot support FB yet. As the DA platform Euphemia already supports FB it has been decided to harvest the benefit of FB.

It is possible but not likely, thanks to the design of the ATCE method. The ATCE method uses the DA leftover capacities to compute a transitional solution ID ATC. The Nordic TSOs then apply this transitional solution at the ID gate-opening before the XBID can handle the FB constraints. Given that the DA market clearing point is already at the ‘corner’ of the (original) DA FB domain, the ATCE method is designed to adjust the original FB domain by introducing the ‘maxz2zPTDF threshold’, negative PTDF filter and additional RAM on CNECs where necessary, accepting certain manageable operational risks. In fact, the ATCE method is applied within this ‘adjusted’ FB domain. Consequently, the DA market clearing point is highly unlikely not being stuck at the corner of the ‘adjusted’ FB domain.

When there is a need to perform the ID capacity calculation reassessment, triggered by the availability of the newly created CGMs, the ATCE method is further enhanced by adopting the ‘shortest distance approach’. This approach eliminates the risk of infeasible solution of the ATCE method, where the latest market point, considering the latest continuous trading information, violates the FB domain computed by the latest CGMs. Please refer to the ATCE descriptive document for more information

DA and ID market flows can be different, like today. The ID capacity will result from a dedicated ID capacity calculation. As such, there may be ID capacity available or not. ACER decision 04/2020 removed the possibility of having an intuitive patch in the market coupling algorithm; as such, the application of FB intuitive is no longer an option.

Conceptually for the transitional solution (i.e. by applying the ATCE method), the ID capacity of a border or a bidding zone, at the ID gateopening, can be larger or smaller than the current NTC capacity for the same MTU. The actual observations of the ID capacity comparison between the extracted ID ATC and the currently operational ID initial capacities can be found in the NRA evaluation report and the ATCE data publication.

Yes, the welfare assessed is ‘day-ahead welfare’ only. Welfare considerations of subsequent market timeframes, ID and balancing, are not considered.

Capacity calculation is a continuous process: by using the latest available information, the most capacity is provided for the upcoming timeframe(s). Or in other words: for the ID timeframe dedicated grid models will be created and dedicated capacity calculation will be performed to serve the ID market as good as possible, considering the already allocated DA capacity. Note, in this respect, that an integral part of the capacity calculation is the assessment of the uncertainty that the TSOs are facing in their capacity calculation. It is expected that the uncertainty for the DA stage is larger than that for the ID stage, as better forecasts are available for the ID and less assumptions need to be made. The Reliability Margin (RM) reserved at the DA stage can thus partly be released on the ID stage.

This is indeed the target: FB for both DA and ID. The CACM requires that a CCM is proposed for both the DA and the ID; they can be different. As the current release of the XBID solution does not support a FB model, FB ID is not feasible initially, and an ATC extraction will be applied as an intermediate solution for ID.

Yes, please refer to the published ATCE method description for the ID gateopening to better understand the relationship between the DA MC results, the extracted NTC and corresponding ID ATC, amongst others.

In short, the ATCE method produces the extracted NTC values based on the DA FB domain and the DA market outcome. Together with the DA AAF information, one can assess/compute the ID ATC, using ID ATC = extracted NTC – DA AAF, for the ID gateopening. As a reminder, the TSOs publish the extracted NTC and ID ATCs for the ID gateopening. After that, e.g. for later ID auctions (22.00 D-1, or 10.00 D) a new capacity calculation may be performed, based on an updated / dedicated (D-1 or ID) CGM.

The FB ID go-live is dependent on many factors. One of the most important aspects is the ability of the SIDC platform handling the FB constraints.

The frequency of the reassessment of intraday cross-zonal capacity shall be dependent on the availability of input data relevant for capacity calculation and execution of intraday auctions, as well as any events impacting the cross-zonal capacity. Please refer to the approved Nordic DA/ID CCM article 21.

Yes, but you have to be aware that the ATC domain extracted from the FB domain is arbitrary – there is actually an infinite solution space. The current DA procedures at the Nordic RCC and TSOs do not include such an ATCE extraction before the DA market coupling.

The shadow prices of all market relevant CNECs will be publicly available on the Nordic RCC website and the JAO platform during the EPR.

The shadow price is a by-product of a constrained optimization; there is a shadow price for each constraint in a constrained optimization. Within the FBMC context, where the FB constraints act as constraints in the market optimization, the shadow price of a FB constraint indicates the social welfare increase when we would increase the margin of the FB constraint with 1 MW. It is a kind of ‘price-tag’ that is labelled to the FB constraint on a specific hour and day.

Yes, it is of utmost important to have this in place at that time. Yes, they are publicly available during the EPR. The FB CC results are available on the JAO website (updated daily including the FB CC results).

The FB MC and other associated information are published on the Nordic RCC website (updated weekly including the market coupling results with daily resolution. The publication is delayed due to grace period of the simulation facility.)

The generator information is embedded in the individual grid models from the TSOs, as inputs to build the D-2 CGM.

Yes, it does, expressed as Fmax on combined dynamic constraints.

In principle, yes. The data may be incomplete on some CNECs.

DK1A and NO1A are virtual areas (DK1A is a sum constraint on the flow on Skagerrak and Kontiskan HVDCs. NO1A is a sum constraint between (NO5 and NO2) and NO1), not having producers /consumers, that are applied under the current NTC.

"Decoding” of the PTDFs seemed to be a big topic in CWE.

Answer

The names and unique IDs of all CNECs are published according the Nordic CCR NRAs’ decision, except the Swedish ones, due to the Swedish national security legislation which covers all Swedish CNECs and all Swedish contingencies associated with the neighbouring countries’ CNEs).

Art 25.3. “Individual Nordic TSO may choose not to identify the CNEC concerned and specify its location when publishing the information referred to in paragraph 2(c) if it is classified as sensitive critical infrastructure protection related information in their Member States as provided for in point (d) of Article 2 of Council Directive 2008/114/EC of 8 December 2008 on the identification and designation of European critical infrastructures and the assessment of the need to improve their protection. In such a case, the withheld information shall be replaced with an anonymous identifier, which shall be stable for each CNEC across day-ahead and intraday capacity calculation timeframes, as well as all long-term capacity calculation time frames. The anonymous identifier shall also be used in the other TSO communications related to the CNEC and when communicating about an outage or an investment in infrastructure. The information about which information has been withheld pursuant to this paragraph shall be published on the communication platform referred to in paragraph 1.”

No. The common grid model will not be publicly available.

How will this be communicated in FB? One of our biggest concerns is how we will be able to assess the effect of grid outages – both in our short term and long term price models. This is both due to outages and other changes in the grid (e.g. new lines).

Answer

The UMM information is published on the NUCS platform. The Nordic TSOs and the Nordic RCC are developing the NUCS methodology to capture the impact of the outage on the FB parameters. Please refer to the presentation on the NUCS methodology at the stakeholder event on June 29, 2022

No. However, the monthly forecasts, adjusted by information for planned outages which will be published, might provide a simple basis for such forecasts. Please note, the results of monthly FB CC, including the PTDF matrices, will be available 1 year after the DA/ID CCM FB go-live.

No, the data publication in the Nordic context is not the same as the continent. The Nordic TSOs will comply with data publication requirements according to the approved Nordic approved DA/ID CCM, Transparency regulation, REMIT and national security legislation.

At least the year-ahead (YA) and month-ahead (MA) capacity calculation. Please refer to the approved LT CCM and the presentation regarding the LT during the June 29, 2022 stakeholder event

The FB domain, and the extracted NTCs based on the FB domain, as interim solution, will be provided to the market participants. The target solution is to provide the FB parameters.