Questions & Answers

The Nordic CCM project publishes the received questions and answers below. To post new questions, please email

For the abbreviations used, please see the List of abbreviations.


Capacity calculation (parameters / capacity)

Q: Remedial Actions (RA), how are they included in the capacity calculation process?
A: Non-costly RAs are always considered in the capacity calculation process. TSO operators assess which costly RAs can be utilized to increase the capacity, and whether it is economically more efficient to apply redispatch or to submit the CNE to the allocation mechanism without the impact of redispatch being reflected.

Q: Domain Validation – what is it?
A: It is a quality check performed by the TSO operators to validate the capacities calculated by the coordinated capacity calculator (Nordic RSC).

Q: What would happen if you are forced to use intuitive FB?
Some part of the benefits of introducing FB are discarded.

Q: Will there be overloads in FB?
There are no overloads on monitored CNEs (i.e. the CNEs taken into account in the market coupling) in the DA market outcome, but due to changing conditions close to real-time, there may be overloads in the operational hour that are mitigated by means of redispatch.

Q: Can you have negative capacity under FB?
 Yes; however, when a negative RAM is calculated but not applied in capacity allocation, the RAM value shall be set to zero and the potential overload shall be managed by redispatch.

Q: In regard to GSK strategies; what are the choices to be made by the TSOs?
 As we have a zonal market system, the TSOs need, for each time frame, to make assumptions about how a variation in a zonal net position will be 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 FRM, including the uncertainties linked to the GSK. As such, the different GSK options can be assessed by computing the corresponding FRM 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.

Q: Is the GSK system prone to gaming?
 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.

Q: Will the operational expertise and experience be part of the FB capacity calculation process?
 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 or CNTC) capacity domain.

Q: 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?
 Both FB and (C)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 more transparent.

As described in Article 8 of the CCM, to avoid undue discrimination between internal and cross-zonal flows, redispatch (RA in MWh/h) shall be added to the RAM of the internal CNEs, in line with the assessment of operational security and economic efficiency in accordance with Article 9 and 11.


Q: How does the ACER recommendation on internal constraints affect the Nordic FB methodology and what happens if you are not allowed to have internal CNEs affecting cross-border exchange?
 The Nordic CCM follows the ACER recommendation. This is elaborated upon in Article 8 of the CCM.

Q: Are stability / dynamic issues simulated in offline grid models?
 Online grid models are used for the real-time system operations. The CGMs (Common Grid Models) created by the TSOs together with the RSC are intended for offline study purposes, such as capacity calculation. The CGMs currently developed do not allow for dynamic security analysis yet; those studies are currently performed on dedicated dynamic grid models.

Q: What will happen with unforeseen outages of e.g. power plants?
 If the information is available before the DA / ID capacity calculation starts, it will be taken into account. Please note that an unforeseen outage may trigger a recalculation of the ID capacity.

Q: Will the PTDF matrix be stable for all 24 hours?
 No, they will vary from hour to hour, as grid topology and grid usage changes over time.

Q: How to translate what is happening in the real system to the FB world (e.g. outage of a line or generation unit)?
 The UMM (in the future NUCs) system may need to be adjusted to make it ‘fit’ to the FB world. This is under discussion with stakeholders, under the umbrella of the Nordic CCM Stakeholder Group meeting.

Q: To what extent are the exchanges with Germany and the Baltics influenced by a Nordic FB?
 A so-called advanced hybrid coupling will be used. 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 PTDF factors reflecting how the exchange on the DC link is impacting the AC grid elements. Or in other words: the flows on the DCs are competing for the scarce capacity on the AC grid, like the exchanges from any of the other bidding zones (SE1, SE2, NO1, FI, and so on). The exchanges with Germany and the Baltics are thus competing for the scarce capacity in the Nordic grid like the exchanges within the Nordic synchronous area do.

Q: There are currently no phase shifters in the Nordics. If such a device is installed, does it fit in the FB methodology?
 Phase shifters can be implemented in the FB method in the same way as a DC link, where the allocation mechanism sets the power flow on the controllable device.

Q: Under FB, will the capacity on the DC cables deviate from the nominal capacity (e.g. due to the west-coast cut)?
 No, the capacity on DC connectors will be the nominal value; it is the market clearing algorithm that determines the optimal flow on the DC cable. By applying the advanced hybrid coupling, 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.

Q: Loop and transit flows under FB and NTC: are they taken into account?
 Loop flows originate from an internal BZ trade, and are taken into account in both FB and CNTC capacity calculation, as they are part of the CGM basecase. Transit flows originate from exchanges between BZs. Their impact is taken into account in the allocation in FB only.

Q: Are losses in the AC grid taken into account in the FB model?
 No, as this would overcomplicate the model.

Capacity allocation (market results)

Q: How are you able to perform market simulations today?
We are using the simulation facility in Euphemia, but with a limited geographical scope.

Q: What setup has been used in the market simulations?
Historical order books and capacities in the CWE, UK, Baltics, Poland, and the Nordics for the NTC market simulations (today’s reference situation). For the Nordic FB market simulations, the same setup is used but the NTC capacity constraints in the Nordics are replaced by FB constraints.

Q: During parallel runs, will you use both FB plain and FB intuitive to be able to compare the two?
No. It is the assessment of the Nordic TSOs that FB Intuitive (FBI) is not in line with legislation and decreases the welfare generated in the day-ahead market. The Nordic TSOs put the following main argument forward to support this assessment: to suppress non-intuitive flows, FB-intuitive decreases the capacity domain below what can be justified based on arguments of operational security and economic efficiency, hence FBI is not compliant with Regulation (EC) No 714/2009, point 1.7 of Annex I and as such it must be concluded that FBI leads to undue discrimination.

Q: Currently there is quite often one single price in the Swedish price areas; FB may change this. Will TSOs provide hedging instruments for the retailers?
 Whenever there is a price difference under FB, most area prices will differ, but the differences between the area prices will be smaller. At the other hand, we would expect more hours with a single Nordic price (more price convergence). As such, the system price forward as a hedging tool may prove even more useful in the FB world. The link to the FCA implementation is made in this respect, where the introduction of transmission rights is currently under discussion. NRAs will decide whether there are sufficient hedging possibilities inside bidding zones and between bidding zones or if additional measures are needed.

Q: If you change the maximum price at the PXs will the outcome of the optimization change?
 No, in essence not (unless the market clears at the maximum price).

Q: In reference to the Belgian situation; even when the Belgium price is at 3000 EUR, there is a risk that Belgium doesn’t get the energy; could this happen in the Nordics?
 Indeed, in the FB mechanism it is not only the bid price, but also the impact of a bid on a network congestion (by means of the PTDF factors, aka “flow factor competition”) that determines whether or not a bid is contributing to the maximum social welfare and is accepted. The behaviour mentioned, is mainly linked to the non-equally-sized bidding zones in CWE, and to the price bounds implemented in the allocation mechanism. The bidding zones in the Nordics are more equally sized, and a mitigation (‘patch’) has been implemented in Euphemia that prevents price taking orders (orders submitted at the price bounds set by the exchanges) to be curtailed because of “flow factor competition”.

Q: What is the optimization that will be used in the FB allocation mechanism?
 It is the same as today: it is the social welfare (consisting of consumer surplus, producer surplus, and congestion rent) that is optimized.

Q: Why is the Congestion Revenue (CR) part of the social welfare?
 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; congestion revenue is a natural by-product when transmission capacity turns out to be a scarce good.

Q: Are the simulation results – so far - in line with those in CWE, when they compared FB and NTC?
 Yes, they are. Overall, FB provides more capacity, higher DA welfare, and leads to a lower price spread between the bidding zones. An overall income redistribution has been noted: lower congestion income, lower producer surplus, and a higher consumer surplus (compared to the current NTC world), this redistribution though naturally varies between scenarios and locations. FB may also allow for higher exports from the Nordics to the continent, compared to today’s NTC world, leading to a higher Nordic producer surplus.

Q: It has been mentioned that counter-intuitive flows have a significant impact on the welfare. What will be your recommendation on this one?
 This is an integral part of the FB system. The counter-intuitive flows will relieve congestions in the system, thereby allowing for flows to be induced by market exchanges leading to an overall higher socio-economic welfare.

Q: In general: what do you think about the effect of flow based on the Nordic system versus CWE? Since we have a lot of price areas already, while Germany for example is just one big area with a lot of internal bottlenecks; will the effect of flow based be limited here? Are most of the bottlenecks quite good handled in the price area division already?
In theory, the FB approach is more efficient with more bidding zones especially for meshed grids. However, the incremental benefit of adding more bidding zones declines. Adding more bidding zones with the current NTC system may not be efficient, compared to the implementation of the flow based approach. This is due to the extended grid information that is provided to the allocation mechanism in FB. In addition, in the FB approach, the interdependencies between cross-border trades and the flows induced on the CNEs are taken into account in a better way compared to the NTC approach.

Intraday market

Q: ID in CWE is not functioning well, what preventative measures are being done in the Nordic methodology to not end up in the same situation?
 When the CWE region went live with the FB DA system, they applied DA left-over capacity as initial capacity for the ID market, without having a dedicated ID capacity calculation based on updated grid models. CWE is in the process of having a dedicated ID capacity calculation. This is what is foreseen in the Nordic region as well: after the ID gate opening, a dedicated capacity calculation based on updated input data (D-1 CGM) is to be performed. This should prevent some of the claimed issues mentioned for CWE.

Q: FB is the better capacity calculation methodology close to real time (ID, balancing). Why start with DA instead of ID?
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 as soon as possible.

Q: There is a risk to end up in a corner of the FB domain after the DA stage, and that the ID trade is stuck.
A: Capacity calculation is a continuous process: by using the latest information available, 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. 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 Flow Reliability Margin (FRM) reserved at the DA stage can thus partly be released on the ID stage. Please note that this provides an automatic balance: if the variability in the system increases, a larger need for ID capacity may be foreseen. This larger variability is likely to increase the uncertainty for the TSOs in their DA capacity calculation: a larger DA FRM needs to be taken into account, thereby shifting more capacity to be released at the ID stage.

Q: If you use non-intuitive FB in the DA market, how will this work out on the ID market?
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.

Q: Is there less capacity for the ID after FB is introduced?
On the contrary to today, where the ID capacity is left-over capacity, the ID will have its own dedicated capacity calculation based on dedicated CGMs.  But assuming that FB is more efficient on the DA, we might face situations where there is less capacity left for ID (in certain directions).

Q: Is it true that the optimal solution (in terms of welfare), referred to, holds only for the spot market?
 Indeed, the welfare assessed is ‘day-ahead welfare’ only. Welfare considerations of subsequent market timeframes, ID and balancing, are not considered.

Q: How to split capacity between DA and ID?
 Capacity calculation is a continuous process: by using the latest information available, 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. 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 Flow Reliability Margin (FRM) reserved at the DA stage can thus partly be released on the ID stage.

Q: Shouldn’t there be the same capacity calculation methodology (CCM) for DA and ID?
 The CACM requires that a CCM is proposed for both the DA and the ID; they can be different. As the first release of the XBID solution does not support a FB model, FB ID is not feasible initially.

Q: Can FB work with a continuous ID trading mechanism?
 From a theoretical point of view, FB parameters (PTDFs and RAMs) can be used as constraints in a continuous ID trading mechanism.

Q: FB is more in line with the physics of the grid and seems to a better approach than the NTC. Your aim is to use FB in DA, while for ID CNTC is foreseen? This doesn’t make sense: the closer to real-time the more detailed the capacity calculation should be.
 Yes, indeed. It is the target to have a FB ID, but the first release of XBID does not allow using a FB capacity domain.

Q: The SH information tool shows the border flows based on the Nordic NPs. If you plug in the DA NPs that are determined by the PXs, can you assess the expected ID capacity?
 No, the TSOs will perform a new capacity calculation for the ID, based on an updated CGM.

Data provision and tools provided

Q: Are you able to do an NTC extraction from the FB domain (for information purposes)?
Yes, but you have to be aware that the NTC domain extracted from the FB domain is arbitrary – there is actually an infinite solution space. Also, the extracted NTC domain is by default smaller than the FB domain.

Q: Will the shadow prices of the internal CNEs be published?
A: This information will be shared with the NRAs for their monitoring purposes.

Q: What is the shadow price?
 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.

Q: For how large area are you creating prototype CGMs?
A: The entire Nordic area (SE,NO,DK,FI) is included in the prototype CGM. The market simulations though, cover a larger area.

Q: During the external daily parallel operation, will the FB capacities and simulated market results be published on a daily basis?
 Yes, it is of utmost important to have this in place at that time.

Q: Is input expected from the generators to build the D-2 CGM?
 No, it is a TSO-only forecast, for the moment.

Q: Does the FB model in the SH information tool include the voltage and dynamic limits?
 Yes, it does, expressed as Fmax on PTCs (power transfer corridors).

Q: In the published simulation data, can you identify from the hourly results if a constraint is internal or cross-border?
 Though the constraints are anonymized, the geographical information on the bidding zone, or the bidding zone border, where the CNE is located, will be published.

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

Q: Will the PTDFs published in the Nordics contain readable CBCOs with the same IDs from day to day? Indeed, “decoding” of the PTDFs seems to be a big topic in CWE.
In general, the intention for the Nordic TSOs is to focus on transparency and provide as much information as possible. This is covered in the Article 30 of the DA/ID CCM. However, due national security concerns by the Swedish and Norwegian TSOs, it is decided that the only information that can be published for Sweden & Norway is which bidding zones the CNE starts/ends in and the physical parameters attached to the CNE. For Danish and Finnish CNEs, no such limitations have been identified.

Q: Will the common grid model be available?
It is not likely that the common grid model will be publicly available.

Q: What about information about transmission outages that are published in UMMs today? 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).
Outage information will be published, but it is not yet clear in which format the information will be provided. This is due to the change from NTC to FB, where capacity has a different meaning compared to the current NTCs.

Q: Is there a possibility to have 10-14 days forecast for the PTDFs published?
All published capacities, DA, ID and long term will be derived based on available common grid models. As of today, there are no plans for the creation of CGMs within the timeframes between daily and monthly. Thus, it is not foreseen to publish PTDFs for 10-14 days forecasts. However, the monthly forecasts, adjusted by information for planned outages which will be published, might provide a simple basis for such forecasts.

Other questions linked to CCM

Q: What is the difference between CACM & FCA?
They are different legal texts (guidelines), CACM handles DA & ID, FCA relates to the forward capacity allocation, thereby handling the long-term timeframes.

Q: Why wait 1.5 years after CCM approval until the start of parallel runs?
We need to develop IT tooling and internal processes before we can start operating the new CCM, however we are already now performing calculations in the prototype tools developed within the CCM project. If the final tools are realized earlier, we can naturally start earlier – there is no reason in itself to wait for the planned date, but we estimate that this is the time needed for IT and business development.

Q: Are you using D-2 information for the DA capacity calculation?
Indeed, in order to have a common European model and a coordinated process, the CGM process needs to start at D-2. The Nordic RSC will look into updating the CGM according to the latest information as an input for the coordinated DA capacity calculation.

Q: What will happen if the parallel runs do not deliver?
A: We cannot go live before FB works properly. KPIs need to be set to monitor this.

Q: There seems to be a big difference between NTC and CTNC?
A: CNTC is comparable with NTC, based on commonly-agreed principles though. CNTC is more coordinated, e.g. in the sense that a CGM is used. From a market perspective, there are no differences in how the constraints are expressed.

Q: What are the problems with the CGM?
Within the framework of ENTSO-E, a new standard has been developed for IGMs/CGMs, the so-called CGMES. The format and processes will remove most obstacles that TSOs bump into today. As the CGM process is currently under development, the CCM project has developed a prototype CGM using existing standards. A brief description of the process:

Each TSO makes a “photo” of its grid in its SCADA/EMS system, being a load flow model which contains the loads, generation, lines, voltages, power flows and so on. There are issues linked to the translation from the SCADA/EMS (very detailed so-called ‘breaker’ model) to a load flow model (‘branch-node’ model). The grid models of each TSO are called the IGMs (Individual Grid Models), and the process where the IGMs are put together into a CGM (Common Grid Model) is referred to as the merging process. When the IGMs are not created at exactly the same time (“photos” are taking at different times), deviations may occur among the models that need to be evened in the merging process; the bigger the deviations, the harder it can be to merge the models. In addition, some TSOs are in the process of replacing or upgrading their SCADA/EMS systems, making this task a bit more difficult.

Q: Are there no common Nordic grid models used at this moment in time in the operational NTC capacity calculation?
 Today there are common Nordic grid models, but not with an hourly market time resolution for the purpose of capacity calculation. Or in other words: there are no hourly common Nordic forecast grid models used today in the Nordic capacity calculation. Within the Nordic CCM project those common grid models are being created (prototypes!) for the sole purpose of the development and testing of the capacity calculation methodology (at the same time, this is the main source of the data quality issues that the project is facing). These common grid models are only temporary models for the purpose of the project, anticipating the models that will be delivered by the European CGM project. It is those models that are to be used in the Nordic CNTC / FB capacity calculation; the Nordic CCM project is completely dependent on this input.

Q: Will there still be countertrade / redispatch under FB?
 Yes, for two reasons:

  • not all grid elements are considered in the FB mechanism; only those grid elements that are significantly impacted by cross-border trade,
  • redispatch is an integral part of the capacity calculation methodology

Q: Will the auction structure on the DA be changed?
 No, it is at least not within the scope of this project.

Q: What is the reference for the work that you are doing and the comparisons that you are making?
 The current situation - the operational NTCs and the corresponding market results - are the reference. The current (NTC) market outcome is compared with the simulated FB market outcomes. It is also important to realize that the coordinated NTC (CNTC) values are different than the current NTC values: it is – just like the FB methodology – based on an hourly common grid model and a common capacity calculation approach.

Q: Does the CACM refer to a capacity calculation region (CCR) or the Nordic market?
 It refers to a CCR rather than the Nordic market. Norway is formally not part of the Nordic CCR.

Q: CWE is used quite often as a reference. Does this make sense? The Nordic system is quite different?
 CWE has a FB system in operation, and it is useful to learn from their experiences. But, indeed, the Nordic system is different in many ways: hydro-based system, many dynamic and voltage constraints, and better-balanced bidding zones, to name some of the differences.

Q: This project is a big risk for the market participants. How to manage this risk?
 This is one of the purposes of the parallel run: to create comfort among all stakeholders.

Q: Cost of countertrade: is it harmonized / shared among TSOs?
 Today, all redispatch costs are taken by the TSO itself, whereas for countertrade, the requester pays. TSOs are in the process of defining the countertrade and redispatch, and cost sharing methodologies.

Q: What do you think will be the biggest challenges for analysts trying to make both short term and long term price forecasts?
It is hard to step into analysts’ shoes for the CCM project team members. Indeed, that is why we interact on a regular basis with market participants to hear your views, experiences, and concerns. What we heard so far is that it not so straightforward to replace the NTCs in the stack models / price forecasting simulation software with FB constraints.