Questions & Answers
An interactive Q&A section is currently being developed. In the meantime, the Nordic CCM project publishes the received questions and answers below. To post new questions, please email email@example.com.
For the abbreviations used, please see the List of abbreviations.
Please note that the CCM methodology is subject to change; as such, some of the answers may be altered when the CCM methodology has been finalized.
Capacity calculation (parameters / capacity)
Q: Can you have negative capacity under FB?
A: Yes, in fact you can have that. A negative RAM would force the Nordic market to relieve the congestion. In the case that a negative RAM would arise, it would result from the capacity calculation process though – it is not imposed by a TSO. Note that negative NTCs are used in today’s NTC world.
Q: In regard to GSK strategies; what are the choices to be made by the TSOs?
A: As we have a zonal market system, the TSO:s 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?
A: The GSK does not affect how a producer is selected over another. The GSKs are not based on information from the market, as such – it is a subjective system and thus not prone to gaming.
Q: Will the operational expertise and experience be part of the FB capacity calculation process?
A: Yes, the national operators are responsible for providing the operational security limits (expressed as CNEs), as well as validating the results from capacity calculation – the security 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?
A: Both FB and NTC 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.
Please also refer to the supporting document, section 6.2.2 “Rules for avoiding undue discrimination between internal and cross-zonal exchanges”
Q: How does the ACER recommendation on internal constraints affect the Nordic FB methodology and what happens if you are not allowed to move internal congestions to the border?
A: The ACER recommendation may have an impact on which CNEs are allowed to be used in the capacity calculation, but not on the methodology itself. Most often the limiting CNEs are not located on the border, but inside the area. It should also be noted that many constraints in the Nordic system are dynamic limitations, which are exempted from the ACER recommendation. With the recommendations ACER advocates TSOs to be more transparent, and explain better, how the internal constraint are managed and materialize as cross-border capacity: i.e. to justify the use of internal constraints. It is a general request to the TSOs and should not impact the choice for one or the other CCM. In essence, the recommendation provides an incentive not to build cross-border capacity, but to enhance the internal grid.
Q: Are stability / dynamic issues simulated in offline grid models?
A: Yes, the current prototype CGMs (Common Grid Models) created within the CCM project can only be used for static grid analysis.
Q: What will happen with unforeseen outages of e.g. power plants?
A: If the information is available before the capacity calculation starts, it will be taken into account. Otherwise, it needs to be dealt with as is, just like today.
Q: Will the PTDF matrix be stable for all 24 hours?
A: No, they will vary from hour to hour, as grid topology and state changes.
Q: How to translate what is happening in the real system to the FB world (e.g. outage of a line or generation unit)?
A: The UMM system may need to be adjusted to make it ‘fit’ to the FB world.
Q: To what extent are the exchanges with Germany and the Baltics influenced by a Nordic FB?
A: 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?
A: 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. In CWE, where phase shifters are in operation, they are currently implemented as remedial actions.
Q: Under FB, will the capacity on the DC cables deviate from the nominal capacity (e.g. due to the west-coast cut)?
A: 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 flows under FB and NTC: how can you be in the secure domain if you do not take them into account?
A: Loop flows originate from an internal BZ trade, and are taken into account in both FB and CNTC, as they are part of the CGM. Transit flows originate from exchanges between BZs. Their impact is taken into account in FB only.
Q: Are losses in the AC grid taken into account in the FB model?
A: No, as this would overcomplicate the model.
Capacity allocation (market results)
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?
A: 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, there will be 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. NRA:s 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?
A: 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?
A: 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?
A: 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?
A: 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. Congestion revenue is the value of transporting power between bidding zones.
Q: Are the results in line with those in CWE, when they compared FB and NTC?
A: 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: 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?
A: The CWE region applied DA left-over capacity as initial capacity for the ID market, when they went live with the FB DA system. This is not what is foreseen in the Nordic region. Indeed, a dedicated capacity calculation based on updated input data is foreseen. This should prevent some of the claimed issues mentioned for CWE.
Q: How can DK1 have a different average price in FB compared to NTC, being connected only by DC links?
A: This is due to the price linkage with Southern Sweden and Southern Norway.
Q: You mentioned that counter-intuitive flows have a significant impact on the welfare. What will be your recommendation on this one?
A: This is an integral part of the FB system. Please note that already today, in the NTC world, there are counter-intuitive flows.
Q: Is it true that the optimal solution (in terms of welfare), referred to, holds only for the spot market?
A: 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?
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.
Q: Shouldn’t there be the same capacity calculation methodology (CCM) for DA and ID?
A: 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?
A: Yes, FB can work with 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.
A: 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?
A: No, the TSOs will perform a new capacity calculation for the ID, based on an updated CGM.
Data provision and tools provided
Q: During the external daily parallel operation, will the FB capacities and simulated market results be published on a daily basis?
A: Yes, it is of utmost important to have this in place at that time.
Q: Is input expected from the generators to build the CGM / D2CF?
A: No, it is a TSO-only forecast, for the moment.
Q: What is the shadow price?
A: 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: Does the FB model in the SH information tool include the voltage and dynamic limits?
A: Yes, it does, expressed as Fmax on cuts.
Q: In the published simulation data, can you identify from the hourly results if a constraint is internal or cross-border?
A: No this information is currently not included, the constraints are anonymized and do not contain geographical information.
Q: What are bidding zones DK1A and NO1A?
A: DK1A and NO1A are virtual areas, not having producers /consumers, that are only applicable under NTC. Under FB there are also virtual areas on each end of the DC links.
Other questions linked to CCM
Q: What are the problems with the CGM?
A: 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, 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?
A: 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?
A: Yes, as not all grid elements will be considered in the FB mechanism; only those grid elements that are significantly impacted by cross-border trade will be considered.
Q: Will the auction structure on the DA be changed?
A: 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?
A: The current situation (NTC world) is the reference: the operational NTCs and the corresponding market results are the reference. The current (NTC) market outcome is compared with the FB and CNTC simulated market outcomes. It is 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?
A: 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?
A: 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?
A: 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?
A: Today, all redispatch costs are taken by the TSO itself, whereas for countertrade, the requester pays. TSOs need to define the countertrade and redispatch methodology and the cost sharing method by February 2018.
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