The power market design column - Consultation on EU network code for demand response demands a response

The consultation by ACER on a new European network code on demand response is closing on Thursday. The draft code is a kind of guideline. It doesn’t have many concrete rules. The Member States must draw up these rules themselves. What is more serious is that the basis for this code has not been thought through. In particular, it is unclear how a local market – or rather, the delivery of local services to the system operator – is related to the functioning of the electricity market.

(This is a translation of an article published at Energeia.)

What does this new network code contain?

The title of the new European network code – demand response – is misleading. It is not just about demand response, it is also about storage and generation. Nor is it a code that only concerns small-scale or decentralised capacity. The code concerns the delivery of two types of services: balancing services that can be delivered to the TSO and local services that are delivered to the local SO . The local SO is the system operator to whose grid a grid user is connected. For parties connected to the transmission grid, the TSO is the local system operator. Local services include congestion services and voltage support services. The code regulates how these balancing services and local services can be delivered and how the cooperation between the system operators involved should proceed. Although, not much is regulated in concrete terms.

A new code would not have been necessary

This new European network code already has quite a history. It was first proposed under the assumption that the existing EU network codes would not cover demand response, as these codes where drafted by the TSOs and not by the DSOs. ?That was a huge misunderstanding. Demand response has always been an integral part of the European rules. If it were necessary to improve aspects of demand response or the unlocking of flexible capacity connected to the distribution grids, it would have been better to adjust the existing network codes. But the promotors of a new network code gained the upper hand. The train started its journey and it is difficult to stop a moving train.

The new code goes against the subsidiarity principle

The new network code actually only regulates that the various Member States must draw up national rules for balancing services and local services. It is determined what these national rules must comply with, but there is no real harmonisation.

The subsidiarity principle applies in the European Union. This principle justifies intervention by the Union when the objectives of an action cannot be sufficiently achieved by the Member States, but can be better achieved at Union level ‘by reason of the scale and effects of the proposed action’. This principle should therefore also apply to the new network code and means that this code should only be introduced if matters are regulated that the Member States themselves cannot regulate properly. This does not seem to be the case here and therefore the new code should not be introduced at all. But the Brussels machine is well-oiled when it comes to producing new legislation and regulations. When it comes to blocking or removing unnecessary rules and enforcing existing rules, the machine easily gets stuck.

The concept of "local market" is unnecessary

The new code is not only unnecessary, it could also cause a lot of misery. The code introduces the concept of local markets and then these local markets are seen as an integral part of the wholesale electricity market.

The concept of local market is defined in the code as the entirety of institutional, commercial and operational arrangements that establish market-based procurement of local services. The point is that these local services that the system operators need are not standard products that can be purchased on the wholesale electricity market. They are very specific services that of course need to be financially compensated. This compensation could be regulated, based on costs, with the regulator determining what a reasonable compensation is. But it could also be a compensation where the grid user himself indicates what compensation he needs. The latter is then called a market-based compensation. But it would have been better if that had been called a non-regulated compensation. And the non-market-based compensation could then have been called a regulated compensation.

When it comes to congestion services, it has already been stipulated in the Electricity Market Regulation that a market-based compensation must be applied in first instance with the non-market-based compensation as the exception. The new network code builds on that. It stipulates that a non-market-based compenstaion is only permitted if the regulatory authority has granted a derogation.

The whole idea of a local market for congestion services is based on quicksand. Firstly, congestions are always local in nature. There is by definition a limited number of grid users who could provide those services. Secondly, each congestion is only active for a limited part of the time. Usually there is no problem, there is no local market and certainly no liquidity. And that is fine. Less network congestion is excellent.

A market-based compensation can work. But then not necessarily in the form of a competitive bidding process – as the draft network code prescribes – but in the form of a bilateral negotiation between grid user and system operator, within certain frameworks. Such a framework could be the principle that a grid user may not have a disadvantage, but also no advantage by providing the congestion service. It is obvious that the grid user may not have a disadvantage. After all, he helps the sytem operator. But it seems less clear that he may not have an advantage. Yet that is important because otherwise the level playing field is disrupted. A grid user would gain an advantage over a competitor who is connected to another system operator, who did timely invest in grid reinforcement and suffers much less from grid congestion.

A local market is not an integral part of the wholesale market

So the first problem is that a local market is not a real market. The second problem is that the new network code sees local markets as an integral part of the wholesale electricity market and places them alongside the well-known segments of the wholesale market, such as the intraday market and the imbalance market. However, that is a mistake. All segments of the wholesale market are aimed at bringing supply and demand together via a price signal. A local market doesn’t do that. A local market, as envisaged in the draft network code, is about providing a service to a system operator, so that the system operator maintains the operational reliability of his grid and thus facilitates the actual market.

For example, the code states that bids between the local markets and the segments of the electricity market must be able to be exchanged. That is a nonsensical condition. For example, intraday transactions are energy transactions. Congestion services, on the other hand - also when it comes to redispatch - are always capacity products. Take for example a 10 MW power plant that has not yet sold its production. It can offer its production for each hour on the intraday market with a sales bid of 10 MWh. If it finds a buyer, it will eventually have to produce 10 MW. But the producer is not limited in its production capacity. If, for example, the price on the intraday market were to fall sharply, the producer can buy back the 10 MWh sold. And in the end, it will not produce anything.

When providing a congestion service, things are very different. If the power plant offers its free capacity of 10 MW to the system operator and the system operator calls for that bid, the power plant will actually have to inject 10 MW to relieve the grid. This activation is normally accompanied by a correction to the energy schedule of the producer in question. This means that the system operator purchases the 10 MWh produced and supplies it to another producer - on the other side of the congestion - who is requested to produce less than planned. Although this is also an energy transaction, it is primarily a capacity product. The production facility must inject 10 MW and is no longer allowed to buy on the market and reduce its own production.

GOPACS and ETPA

The idea of exchanging bids for congestion services and intraday transactions is not a new idea. On the contrary. It has even been put into practice in the Netherlands. GOPACS, the system operator platform for the provision of congestion services) and ETPA (the electricity exchange with a platform for intraday trading) had this functionality in operation until recently. Market parties could place bids on ETPA and if these bids were provided with information about the location in the grid, these bids were passed on by ETPA to GOPACS. As soon as the bid on the intraday market of ETPA was selected, the bid from GOPACS was removed and vice versa.

The problem with this approach is that two different products are covered with the same bid. If a system operator selects that bid via GOPACS, the market party in question must supply the capacity and is limited on the market. If the bid is selected via ETPA, there is no limitation on the capacity. Market parties that used this functionality had to increase their bid price, compared to a bid that would only be available on the intraday market. The market price was therefore increased.

This functionality has now been stopped between GOPACS and ETPA. Reportedly, the reason for this was not the problems outlined above, but ETPA's accession to XBID (the European coupling of the intraday markets).

ACM also falls into the trap

Placing the local markets as part of the wholesale market alongside the other segments of the wholesale market is a persistent error, which not only appears in the new European code. The Dutch regulator,(ACM) has also fallen into that trap.

In a recent code proposal on participation in the European platforms for balancing energy, TenneT, teh Dutch TSO, had proposed that it would also be allowed to use the balancing product MARI for congestion management in the future. ACM rejected that proposal in its decision. ACM's reasoning for the rejection is entirely plausible. But the point is that ACM also writes that market parties can choose on which market they offer their flexibility. ACM therefore sees congestion management as a market and suggests that a market party can choose whether to offer its free capacity on the local market (the market for congestion services) or on the “other market segments”.

ACM apparently doesn’t realise that it could encourage market parties to withhold capacity, which could constitute a violation of REMIT. After all, if free capacity is only used on the market for congestion services, that capacity is not available for balancing supply and demand. It is then possible that the market price is affected. And it is even possible that this behaviour will cause congestion that the same grid user will then have to resolve by providing a congestion service.

How should it be?

The solution is not to see the provision of congestion services as an integral part of the wholesale electricity market, but to place it separately. It must then be made clear that market parties can be active with the same capacity on both “markets” at the same time, or even have to be active on both “markets”. ?After all, withholding capacity from the wholesale market is prohibited and participation in congestion management is often also mandatory. Of course, it must be arranged properly that if the offered capacity for the grid is activated, any outstanding bids on the wholesale market are removed.

In this way, price formation is not disrupted and market parties can also ask for different prices for the very different products. Bid prices on the wholesale market are in principle free (as long as there is no market power) and market parties are disciplined by competition. The bid price for the delivery of congestion services is then not completely free, but should be based on the “no disadvantage, but also no advantage principle”.

caffolding without foundations

The draft EU network code demand response does not deserve a beauty prize. It was not necessary because adapting the existing codes, to the extent necessary, would have been a better option. Furthermore, this code should not have been adopted at all on the basis of the subsidiarity principle, because the draft code leaves the drafting of concrete rules to the Member States. The code consists only of scaffolding and the Member States may decide for themselves which house they will build behind that scaffolding.

But the biggest concern is that the code does not provide a foundation for the construction of these houses. The concept of local market is confusing and there is a lack of understanding of how a local market is related to the wholesale market for electricity.

It is to be hoped that ACER receives good contributions to its consultation and then takes another very critical look at the draft text. Because an internal European power market needs concrete and harmonised rules. There is no need for European legislation that will lead to a range of different national rules, based on principles that are not correct.

This is my 39th column on power market design issues. The earlier columns covered the following topics:market restrictions and congestion management, balancing, monitoring reliability: EU power market reform, EU market interventions, review of the CACM Regulation,?market myths and price formation,?system support balancing,?Blackouts,?the importance of ACER,?Flexibility and foisonnement,?reliability and load shedding,?regulation of congestion income,?dynamic network tariffs,?energy communities,?scarcity pricing,?the Florence Forum,?active system management,?network planning & sector coupling,?off-shore assets,?intraday capacity hoarding and pricing,?interconnectors,?international comparison of market designs,?cross-border capacity calculation,?flexibility,?cross-border capacity,?electric time and unintended exchanges,?EU Network Codes,?price formation and zero marginal cost generation,?simplicity in the Clean Energy Package,?smart grids,?storage,?auto-generation,?balancing,?VoLL,?demand side response,?interconnectors?and the?Economist on market design.

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Paul Giesbertz

[email protected]

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