SMIGHT

It is difficult to say exactly which is ‘better’. As with so many dichotomies it comes down to where you place the emphasis. Smart Meters are certainly better at getting highly granular data but tend to be hindered by data privacy rules and the ability to process and use such high volumes of data. Substation monitoring on the other hand is much easier to roll out but doesn’t offer the same level of granularity. So perhaps is it not a question of either/or, it is more of a question of how they can be used together to supplement each other.

Define better. As you might expect there are competing requirements and there isn’t a simple answer. With unlimited resources one could say that a complete rollout of smart meters would generally be better as the higher granularity of data leads to a much ‘shaper’ image of what’s happening in the network. However, there are some limitations to bear in mind. First is about data, how it is communicated, and what can be done with it. The key points being:

• What is being measured?
• To what level of accuracy?
• How quickly is the data being communicated? i.e. how ‘live’ are the data.
• Who has access to the data and in what form?
• How much location data is combined with the measurements?

Then there’s the question of how much does it all cost. A smart meter costs ca 150€, then the installation costs say 50€. So, let’s multiply this out for a typical residential area served by a 6-feeder secondary substation. Let’s say there’s 150 households, that would cost ca €30,000 to deploy smart meters. To deploy substation level monitoring on all the feeders would be around 6-7 times less expensive.

Our view at SMIGHT is that in an ideal roll out smart meters are the best solution to the problem of bringing transparency into the low voltage grid. However, we observe that this ‘ideal roll out’ hardly ever happens. Sometimes the data is transmitted too late to be useful, sometimes the necessary data isn’t transmitted for it to be useable, sometimes the roll out level isn’t sufficient for it to be a complete solution, and so on and so forth.

On top of this, one must bear in mind that smart meter data by itself isn’t useful (for the purposes of network monitoring and control), it needs to be fed into a digital network model ‘a digital twin’. In and of itself, this is a very useful tool. But once again the theory meets reality. For a digital twin to work the data needs to exist and be accurate. Currently, from what we see in Germany at least, this is often not the case. So, DSOs need to both invest in the digital twin software and conduct a considerable amount of work to get the data into a useable state – whilst at the same time hoping that smart meters will be rolled out rapidly and the data will be suitable. From our point of view this is quite a few aspects that need to come together for this model to reach its potential. At SMIGHT we prefer to take a somewhat more pragmatic approach. We believe that DSOs can achieve 80% of the value of such a setup with only 20% of the complexity and cost. We believe that moving up the chain to the level of the distribution cabinet and secondary substation delivers all the transparency that required in a far easier and manageable way. One major point is also that the DSO is in control of the process. The substations and distribution cabinets belong to the DSO so it has complete control over what it does whereas smart meters require interaction within the property of end consumers.

At the end of the day, smart meters have benefit beyond grid operation such as enabling dynamic tariffs and helping end users to manage their own electricity usage and therefore cost. Plus, there is a very strong mandate in almost all countries to roll out smart meters. So, it isn’t really a question of whether we should adopt one option or the other. It is more of a question of whether smart meters are sufficient for low voltage grid monitoring and control? As stated above if they are used to feed an accurate digital twin, then the answer is yes. But if that digital twin doesn’t exist or is not very accurate then it makes sense to complement the smart meters with LV monitoring devices.

The 80/20 rules say that 80% of outcomes are driven by only 20% of inputs. This implies that we should be able to gain considerable leverage by working out what those 20% are and focusing our efforts on these. So the question for network operators is: What are the few that are influencing the many?

You are most probably aware of the 80/20 rule, also known as the pareto principle. It is almost a force a nature. One thing to clear up first through is one misconception that it is just a way of splitting a group up e.g. 20% of pupils in a school are clever and 80% are not. This is not what the 80/20 rule says – the key thing about the 80/20 rule is it is expressing a causal relationship more like: 80% of a company’s sales come from only 20% of its customers or 20% of its products. Also, it doesn’t have to be a precise 80/20 split it could be 70%/5% rule or a 60%/1% rule it really is about the disproportionate imbalance between how much of a result is explained by only a few inputs. The particularly helpful implication is that we can focus our efforts on the few inputs that have this leveraged effect on the outcomes.

So how might we be able to use this in tackling the energy transition particularly from a DSO perspective? Here are some ideas as to where the 80/20 probably exists and therefore where we could benefit from exploring this further:

• 80% of the load on an LV network will be cause by 20% of customers – so if you want to control the load on your network you only need to control these 20%.
• 80% of the voltage issues caused by roof top solar happen only 20% of the time – so you only need to find a solution for this 20% of the time i.e. if you need to curtail their output it won’t be that much.
• 80% of the fluctuation in load on any given feeder can be explained by just 20% of the connections.
• 80% of the flexibility capacity on a network will be accounted for by only 20% of the resources. So, you need to find these and get them engaged to make flexibility work.
• 80% of the faults on your network will be caused by issues on only 20% of your feeders. Find out what they have in common and focus your efforts on dealing with that e.g. where they all laid by the same contractor, are they all laid in a particular type of area, are they all a particular type of cable?

SMIGHT helps DSOs identify the 20% of feeders that are causing 80% of the threshold violations and enables them to monitor and control them. LV network monitoring doesn’t have to cover the whole network, it can be focused on those points which are most critical.

Currently what we pay for electricity is mainly dictated by the fuel that is bought and subsequently burnt to generate the electricity. Even the price of electricity we buy from renewable sources is currently dictated by the cost of fossil fuels due to the merit order mechanism. But what happens when in the future we no longer need to ‘pay for the fuel’ i.e. renewals are fuelled by the sun, and the sun famously doesn’t send a bill for the energy it sends us. Will this make electricity free to use?

Countries like New Zealand and Iceland have long been able to cover almost all their energy needs via renewable energy sources and aren’t connected to other larger grids for their electricity price to be impacted by wider markets. Their citizens don’t enjoy free electricity, so this should give us an indication as to the answer to this question.

Sadly, it is unlikely that electricity will become free in the future, but we can expect to pay for electricity differently. To understand why electricity won’t be free in the future we need to understand what makes up our energy bill. An average European household’s electricity bill is made up of 3 distinct thirds each roughly the same size. About one third is the electricity itself, then there’s the grid charges, and the final third is then taxes and levies. When the electricity bit itself doesn’t cost anything then the other two thirds still remain i.e. we still need to pay for the grid that gets the power from where it is produced to where it is consumed, and most likely the government will still need the tax revenue.

Whilst the fuel for the renewable energy is free, the infrastructure isn’t. When you look at a coal power plant most of the cost is derived from the fuel itself and the cost of the plant itself is spread over many decades and this is much more insignificant. In the case of renewables almost all the cost is in the infrastructure and none in the fuel i.e. if a wind turbine produces 1 watt hour of energy or 1GWh it costs the same to have built the wind turbine.

Often the road network is used as an analogy for the electricity grid with the motorways being the high voltage transmission grid, the regional ‘B roads’ being the medium voltage regional grid, and the local town and village streets being the low voltage grid. Taking this analogy further we could ask ourselves how we pay for roads and whether this can inform the way we think about how we might pay for our electricity in the future.

• In some countries vehicle owners pay a flat road tax based on the vehicle they drive which covers unlimited access to all roads – this would be analogous to having to pay a flat grid fee regardless of the amount of energy used but based on your maximum load.
• In other countries there are tolls for using the motorways based on the amount you use them – this would be analogous to only paying grid fees as and when you pull power from the grid i.e. if you have a high degree of self-sufficiency and only need to occasionally pull power from the grid, then you only have to pay a small amount.
• In some countries there’s a bit of a mix where there’s some flat rate tax combined with tolls for certain vehicle types e.g. heavy goods vehicles, or for certain stretches of road that needed a lot of investment. The analogy here would be that we all pay a relatively low fixed grid fee but those with high loads would pay a much higher fee, and whenever you in effect use a piece of high-cost infrastructure e.g. a high voltage direct current (HVDC) transmission line you pay an additional fee.

The difficulty here of course is that we can’t ‘track your specific electrons’ and you can’t decide where they come from at any given moment – so at some point this analogy breaks down. I think what we can take from it though is that our energy bills in the future will probably be likely to be a single fixed charge for a certain level of maximum load and that we won’t pay for the energy i.e. we will pay for kW max as opposed to kWh. In this world the companies operating the assets would be compensated directly for the investment and operation regardless of their output e.g. if a wind turbine costs €10million to build and €20,000 a year to maintain, and had a 20 year useful life then the company operating would get €10 million split of 20 years plus an interest rate plus the operating costs as a charge (ca €570,000 per year) and they would have to vary their supply based on grid signals. It then becomes the grid operator’s job to get the most out of the installed base of producers and storage whilst maintaining a stable supply. Perhaps in such a world we could do away with the unbundling concept and have the grid operators managing the grid along with the production and even selling directly to the customers. It is worth noting that in some areas of the US this is the case i.e. you have a local ‘utility’ which produces, delivers, and bills for the power.

In a world where there are many smaller distributed producers, many of whom are also consumers (I’m mainly talking about roof top solar installations). Then this would create an interesting shift. Currently, there’s a problem experienced by the grids in that those operating roof top solar systems always want to sell their excess production back to the grid. However, they tend to want to do this all at the same time which causes two problems: Negative prices on the wholesale market and grid congestion. If these prosumers were instead compensated based on the investment as opposed to the energy production this could do away with this issue as there wouldn’t be the need to consider whether and how to compensate them for curtailment.

In such a future world we will need to have smart grids as we will have highly intermittent supply, coupled with highly variable and flexible demand. SMIGHT offers a solution to help distribution network operators take the first steps toward creating a smart local grid by digitising their secondary substations and distribution cabinets.

The energy transition presents a grid operator with two problems: first is an overall increase in load, this is thanks to energy which used to be supplied in the form of oil and gas (motor transport and heating) being switched to electricity. The second is a large increase in volatility/dynamism both on the supply and demand side of the equation.

To be able to handle the general increase in load (the first problem), the only thing that grid operators can do is build out and reinforce the grid. This is their ‘core business’ so in principle isn’t a problem for them. However, it is not without its difficulties. The energy transition does not and will not happen evenly across the grid (we can intuitively understand this when we consider how particular demographics are spread out and how certain groups will act in similar ways), therefore the need to reinforce the grid will happen in particular places so the network operator needs to know where and when to intervene and for this they need transparency in their grid.

The increase in variability of supply and demand is a much more difficult challenge for network operators. First there’s the issue of the size of the peaks. The issue being that it is not economically feasible to build out the networks to be able to handle these occasional very high peaks. A good analogy is to think of this in terms of the road network i.e. it doesn’t make sense to build a road network with the capacity to ensure there aren’t any traffic jams on the busiest day of the year as most of the time there’d simply be massive overcapacity, and this has a high cost attached. The generally accepted solution to this problem is so called ‘peak shaving’ which is the idea of getting users to shift their consumption to another time and therefore reduce the peak. To be able to implement this the network operator first needs to know when and where such a peak is going to happen and second, they need a mechanism by which to send signals out to loads to get them to change their behaviour. The solution that is emerging for this is the combination of real-time network monitoring and flexibility markets. The network monitoring enables the identification of the peaks, and the flexibility markets enable the signalling of the requirement to shift loads.

At SMIGHT we offer distribution network operators the tools and capabilities they need to first identify where in their network they need to already reinforce the grid. Then we can help them identify where and when peaks are and will occur. Finally, we also provide the capability to interface with flexibility platforms or other control systems to then send out the signals to shift loads. In essence we help DSOs to maintain control and stay ahead of the energy transition.

The rich can afford to produce and store their own energy yet still require a grid connection. The poor are footing the bill for this. All of this is driven by the fact that our grid fees are based on consumption. This must change!

The energy transition has seen the advent and proliferation of the so called ‘prosumer’ – this is a consumer who is also a producer (in contrast to the past where producers and consumers of electricity were always distinctly different). These prosumers can invest in their own production and storage facilities (mostly solar panels and domestic batteries) and thereby reduce the among of electricity they need to buy. The problem is: What we pay for the use of the grid is based on the amount of electricity we buy in total. This was fine when we were all consumers, however this no longer works when prosumers still require the use of the grid but use far less total electricity from the grid and therefore pay a much smaller contribution to the upkeep of the grid. The perverse thing that makes this even worse is that in fact these very same prosumers can actually creating higher loads on the network that lead to the need to reinforce the grid which increases the total costs.

Let’s say a well setup prosumer can cover 75% of their own consumption, this still leave 25% of their consumption needing to be covered by the wider electricity system. This isn’t 25% evenly spread every day, this will be periods where 100% of the prosumer’s demand needs to be covered by the grid. This means the grid needs to have just as much capacity as if the prosumer didn’t cover any of their own requirements. This in turn means the costs of running and maintaining the grid remain the same, however these costs will now be spread over a much smaller volume of total consumption i.e. if before in the year the consumer cost the network €100 and this was spread 1:1 over all the kWh of consumption, now with only 25 units of consumption this €100 cost is applied to the 25 units. In a world of only prosumers all behaving in the same way, this means everything remains in balance i.e. it costs everyone the same amount in total, but in the real world not everyone is a prosumer and not all prosumers behave in the same way.

The bigger issue here is for those who can’t afford to become a prosumer. To demonstrate this, we need to zoom out to the wider network. Let’s consider the oversimplified situation where a network has 1000 connections, 50% of which are customers who are consumers-only and 50% who are prosumers who are coving 75% of their need themselves. In the previous world where all were consumers-only the network capacity needed to be a nominal 1000 units and cost €10,000 per year. So, each consumer would be charged €10 per year for their use of the grid. In the new world the capacity and therefore the cost remains the same as the 25% of the prosumers demand still needs to be covered. However, now the costs will be spread across 625 units of consumption i.e. a cost of €16 per unit in comparison to the previous €10. So, the prosumer sees their costs fall from €10 to €4, and the consumers-only see their costs increase from €10 to €16. This is of course oversimplified; however, this dynamic is happening out in the market.

So, what should we do about it? This is really a political question and therefore sits with the government and regulator, but here are some ideas:

• Means tested subsidies for solar panels and battery storage i.e. help lower income households access the same technology that high income households can access.
• Feed in tariffs for solar systems and battery storage (in most countries when someone feeds their electricity into the grid, they are not charged for this usage of the grid yet they are causing a load that the grid has be to be able to handle)
• Fixed grid fees irrespective of total usage, perhaps coupled with maximum load. That way it is still an equitable system.

Multiple solar installations installed out on long feeders, as you typically see in rural settings, have become one of a DSO’s biggest headaches. This is because of two factors:

1. The ‘simultaneity factor’ is extremely high i.e. all the solar arrays behave in the same way at the same time.
2. The solar arrays need to produce a voltage higher than that of the network to be able to feed their electricity in.

This leads to large spikes in voltage during sunny periods, and this is a problem for DSOs as they are required to maintain a stable voltage level of 230v +/- 10%. The consequence of these higher voltages can be damage to more sensitive electronic devices and/or financial penalties for the DSOs for not complying with regulatory requirements. In turn, this leads to DSOs being particularly cautious about allowing solar systems to be connected to their networks, which then in turn leads to a slowing down of the instruction of low carbon electricity production.

So, the question is: How can DSO allow more solar installations without at the same time allowing voltage level violations?

If you talk to any DSO who has parts of their network with significant portions of roof top solar installations, then you’ll hear them talk about voltage issues. What are these issues, what are they caused by, and what can a DSO do about it?

What is the problem?

For solar systems to be able to feed-in to the grid they need to raise their voltage level higher than that on the cable they are feeding into. Using the age-old analogue of the water pipes and pressure you could image if you wanted to feed-in water back into the water pipes in the road the pump in your house would need to generate a pressure greater than the incoming water pressure for the water to flow ‘backwards’. This increased voltage doesn’t need to be much; it just needs to be higher than the incoming voltage. The problem is based on two factors, the first is that the DSOs must conform to EN50160 which says that voltages need to be maintained within +/-10% of 230v. The second factor is the cumulative effect of separate solar installations i.e. as one system raises the voltage the next needs to raise it further to also be able to feed-in. Another compounding factor is that the solar generation is greatest at the same time and to the same degree for all the systems on a feeder.

What can a DSO do about it?

The first step is to identify the issue, where is it happening and to what extent. This can be done through modelling and simulation packages so long as the DSO has all the relevant data (the emphasis being on ‘ALL’ – these models are only accurate if the whole system is accurately represented). If not all the required data is present then the DSO needs to have some working assumptions to fill the gaps, these assumptions can be refined through taking measurements at certain points in the network and using these measurements to refine the assumptions and thereby get closer to reality.

Once the issue has been clearly identified i.e. where is it happening and to what extent, the DSO has the choice of either a ‘hardware fix’ or a ‘smart fix’. A hardware fix is one where the DSO installs a piece of hardware within the network specially designed to adjust voltage levels such as a transformer with a variable tap changer or a voltage regulator. These have a fixed CAPEX cost which will be reflecting in the network fees. A smart fix on the other hand is one where DSO either sets up a mechanism by which it can communicate with the solar systems and activate some form of curtailment i.e. ask the systems to stop or at least reduce their output. This would have to have some form of compensation as the customer would normally expect to earn money through the sale of the energy generated. Another solution is to try and activate loads (which have the opposite effect on voltage i.e. they reduce the voltage along a feeder). The key thing here is the location of the loads i.e. it doesn’t help if the solar feed-in is high within a particular residential area and the load is increased at an office complex on the other side of town. The load increase needs to happen downstream of the same secondary substation where the voltage increase is being experienced, and ideally on the same feeder. To enable this a high level of information granularity is required i.e. I need to know which assets are installed where and have some level of information about their availability and capacity i.e. an EV charger doesn’t help me very much if the car isn’t plugged in or if the car is fully charged. As you can see this really is an information and coordination problem.

This is where flexibility market platforms can help. In essence, they help match up the requirements for flexibility with the capacity for flexibility. In our example they can help connection up requirement of dropping the voltage with the capacity of EV chargers. Flexibility platforms aren’t the main topic of this article – you can find out more here.

How can DSOs allow more solar systems to be connected without endangering voltage levels?

Another part of ‘the problem’ is that DSOs tend to use models and simulations to work out whether they can allow the connection of additional solar systems. The issue being that these models and simulations tend to be setup with overly conservative assumptions and/or have low quality data feeding into them. At SMIGHT we can help with both issues by feeding these models with real measurements which allows the models to more closely represent reality and thereby usually allow for more solar systems to be connected.

The energy transition brings with it more variability in loads and an overall higher capacity requirement. In principle mesh grids help even out the effects of variability and through greater overall utilisation offer higher potential hosting capacity. However, they are very complex to simulate and therefore difficult to manage under higher loads. This limitation can be overcome through the implementation of Low Voltage monitoring devices at the nodes in the mesh.

A mesh grid is a layout of cables within a grid where there are many interconnections between the cables. This has the advantage of spreading the load more evenly across the grid in comparison to configurations with very few connections. This sounds perfect for the energy transition, doesn’t it? The energy transition beings with it a far greater degree of variability in load, especially on low voltage grids, and generally higher loads. So, isn’t it better to have a grid configuration where these loads will automatically spread more evenly? If you can be sure that all the cables and nodes within the mesh can take the load, then yes. But therein lies the difficulty. Working out how electricity will flow within a mesh grid is complex and therefore working out the impact of new connections and trying to model the grid is very difficult. This can however be solved through the introduction of monitoring. By placing monitoring devices at all the nodes in the mesh you can then see exactly how the energy is flowing.

So, are mesh networks a good or bad thing for the energy transition? We would say that a smart mesh network is a good thing as it will help increase utilisation and spread the load and effect of the increased variability. And we would also say that a ‘dumb’ mesh network is probably not a good thing as the risk of critical points turning up in the network in an unexpected manner increases dramatically as the energy transition progresses. Indeed, in Germany we see several mesh networks being ‘disassembled’ i.e. reducing the number of interconnections due to this issue. We believe it would be better to install monitoring and keep the benefits of the mesh while regaining oversight and control. Perhaps as the energy transition progresses, we’ll see more mesh networks evolve as DSOs need to connect parts of their networks with plenty of headroom with those parts with limited head room – this will only happen through the introduction of LV monitoring.

Flexibility today is mostly traded in large blocks at higher voltage levels – useful, but only the tip of the iceberg. With the rise of EVs, heat pumps and solar at the low voltage grid, the challenge and opportunity now lie in coordinating these resources locally. By combining NODES’ flexibility market with SMIGHT’s low voltage grid monitoring, points of congestion can be identified and resolved through local flexibility – a practical solution that is already possible today

Currently much of the flexibility that is traded on flexibility platforms is quite ‘high level’ i.e. it is large ‘blocks’ of energy at the higher voltage levels over large blocks of time and well in advance. E.g. I need 50MWh every weekday evening between 16h and 20h from anything hanging off this primary substation for the months of October to March. There is nothing wrong with this per se, as it serves a certain requirement. However, this is just the tip of the iceberg in terms of what could be possible. A large part of the energy transition involves the electrification of cars and domestic heating along with decentralised energy production in the form of roof-top solar all of which is connected to the grid at the low voltage level. These technologies present the distribution grid with both a major challenge but also a solution. The challenge is the high degree of variability and dynamism, for example you can have times of the day with extremely high energy production whilst at the same time having some of the lowest consumption – sunny weekend when everyone is out and about, then this can also flip to the other extreme with no production and extremely high load – dark cold weekday evening with heat pumps running and EVs charging at home. Then there are many variations of this in between and on different time scales.

I said that these technologies were also the solution. They are the solution because they are also controllable – an EV doesn’t have to charge at full speed right now most of the time, a heat pump doesn’t have to run at full power all the time, and the solar power being generated could be stored for later use or even turned down if we don’t need it. The missing piece of the puzzle is one of coordination and communication. Currently, a solar panel doesn’t ‘know’ what the demand is on the grid, nor does it know which storage resources are available on its part of the network, nor does it have any ability to communicate to them. Likewise, the grid operator doesn’t ‘know’ that your EV battery has 60KWh of energy storage that it can ‘lend’ you over the next 12 hour period.

What we need to create is a system/environment/protocol which enables the stakeholders on the LV networks to communicate with one another and in turn adjust their behaviour in response to network and market conditions. There is a perfect future scenario where all resources on the LV networks can seamlessly communicate with one another and be coordinated to an optimal utilisation.

This isn’t possible quite yet, but we can take the first steps towards this. We believe the first steps are to establish where we already need this kind of local load balancing – we already know it won’t be everywhere, and indeed it is only actually in a small number of points in the grid. That already brings down the size of the task to something much more manageable. Once we know where we have issues now that we need to solve, we need to create a communication platform so that the supply and demand actors have a means of communicating with one another.

Another name for such a platform is a market, and indeed there are already marketplaces, and they are called flexibility markets. Also, it is possible to find out where in the low voltage grid there are already points of high load this is done using Low Voltage Grid Monitoring. NODES and SMIGHT want to bring these two worlds together. NODES offers a flexibility market platform and SMIGHT offers a low voltage grid monitoring solution. When you put the two together, you have a solution which can identify points of congestion and then resolve these through flexibility. This is not a futuristic dream, it is a reality today.

Flexible connections are a key component of the energy transition as they enable the connection of Low Carbon Technologies (LTCs) to the grid faster than would otherwise be possible under a ‘normal’ firm connection. Low Voltage Grid monitoring can be combined with flexible connection agreements to only ‘dim’ the connection when it is necessary based on real network loads. As opposed to a more rigid dimming model based on predictions and estimates, which inherently won’t be accurate all the time.

What is a flexible connection?

Essentially flexible connections enable or allow the network operator to intervene (e.g. turndown or turnup the asset connected) to some degree to retain network stability without having to take actions elsewhere in the network e.g. redispatching other resources and thereby incurring costs. The person/organisation wanting to connect essentially agrees to adjust their behaviour according to the grid’s needs in exchange for getting connected to the grid faster. Flexible connections are also referred to as non-firm connections or constrained connections.

[Note: Flexible connections can be at any point in the grid. In this article we are only looking at the topic of connections to the low voltage grid, and not to the medium or high voltage grids]

How do Flexible Connections tend to work?

Sometimes they simply take the form of a contract in which the network operator dictates time windows in which the customer must act in a certain way e.g. between 16:00 and 21:00 the load must not exceed 50kW. An alternative is for the network operator to require the customer to be able to react to signals from the network operator e.g. the customer must be able to reduce their load below 50kW within 15 mins of receiving a signal and the network operator can send such a signal up to 2 times per day between the hours of 6:00 and 23:00, and the period of reduced can be up to 4 hours in duration. There are other forms, but essentially the connection is coupled with some form of agreement with the network operator to change their behaviour from time to time.

How can LV monitoring help enable flexible connections?

The core principle behind a flexible connection is that the load being connected is at risk of causing an over-load of some variety. This risk won’t be constant and will be based on an estimation. So, what LV monitoring does is make this exact i.e. the load is only reduced according to the actual state of the network at any given time.  On a technical level this involves installing an LV monitoring system at the secondary substation to which the customer wishes to connect. This is then coupled to a system which can send signals to the resources in question which need to be dimmed. All of this is possible with SMIGHT’s GRID2 solution and Copilot Module. This benefits the one wanting to connect as they are more likely to be able to operate their load to its full capacity more of the time. The grid operator benefits as the customer will use the network more and therefore pay higher grid fees.

Energy Communities promise to bring cheap electricity to local communities by enabling participants to produce and share electricity together as a cooperative. In an ideal world this would do away with electricity producers, retailers, wholesale markets, and transmission networks. With just the DSOs left to help run these local networks or perhaps even the local networks would also be adopted by the energy communities, resulting in none of the incumbent energy industry left standing. But as is ever the case we don’t live in an ideal world. So, what do energy communities really mean for traditional utility companies?

Energy communities promise to connect households and businesses and enable them to share electricity with one another. For example, my neighbour can in effect charge their EV with the solar power generated by my solar panels, then likewise in the evening I can run my dishwasher using the power stored in my neighbourhood battery storage system. In a world where this is the case then do we need ‘traditional’ utility companies?

To answer this question, we need to first differentiate the different types of utility companies. Of course, we are not talking about the water and gas companies, we are only talking about those involved with the generation and delivery of electricity. Within this space we still need to differentiate the different roles as they will be impacted differently by energy communities. In the electricity marketplace we can see 4 distinct roles, which are legally separated from one another in most countries. We have the energy producers – these are the companies that run generation plants whether it’s an old-fashioned coal power plant or a more modern off-shore wind farm. Then we have the companies that sell electricity to end users – they essentially buy electricity on the wholesale market and then sell it to their customers – these are the companies that we are most familiar with as end users as it is them with whom we have a contract and pay our bills to. Then we have the transmission network operators – these companies transport the electricity from where it is produced to where it consumed via high voltage lines. Finally, we have the distribution network operators who take the electricity from the transmission system and distribute it at lower voltages to the end users. Both the transmission and distribution network operators have monopolies in their respective areas (it wouldn’t be economic to build multiple competing networks) and they are therefore highly regulated to ensure this monopoly position is not abused. The energy producers and retailers operate in a competitive environment driven by market forces, but also see a degree of regulation. In some countries, such as Germany, there is also an additional player: the metering point operator, who is responsible for installing and operating the electricity meters.

So now that we understand the different players in the market what impact would a perfectly implemented energy community have on each player:

• Electricity Retailer – they would lose all their business as the community provides for itself it doesn’t need to buy electricity from anywhere else.
• Electricity Producer – just like with the retailer they lose out as there’s no need for centralised energy production.
• Transmission operator – this depends a bit on the size of the community. In the case of a smaller community that is geographically confined e.g. a neighbourhood, village, or town then there is also no need for a transmission network as the energy is being produced and consumed at a local level.
• Distribution operator – this is the one player that is still needed as the members of the community still need to be connected to one another for the system to work. If a community were built from scratch, then they could build their own network, however this will not be the case most of the time.

So why don’t we see energy communities toppling traditional utility companies? This comes down to many factors, but here are the dominant reasons:

Not enough storage

Most energy communities are formed around a shared generation source such a solar array. However, a major difficulty is that most of the electricity is produced when most of the community member aren’t at home and able to use it or don’t have enough smart devices to be able to take advantage of electricity when it is being produced. This leads to large portions of the electricity being fed back into the grid. There is usually some remuneration for this but it is of course much lower than what it will then cost to take electricity from the grid later. The best solution is some form of community storage, usually a large battery. With dynamic pricing becoming more and more widespread, this type of step-up will become more and more valuable as the community will be able to benefit from off peak prices in effect being stored in the battery.

Rigid rules leading to ‘wasted’ energy

Energy communities can be setup in different ways in terms of how electricity is allocated out and shared amongst participants. Sometimes this can be very rigid e.g. the amount of electricity produced in any given window is then divided by the number of participants. If a participant can use that electricity at that moment, then great, but if they can’t or if they need more, then the electricity is either fed into the grid or taken out of the grid respectively. This leads to much more electricity being feed into the grid than would otherwise need to be, and more electricity being taken from the grid. This is easy to solve by allowing the available electricity to be shared according to demand at any given moment and then allowing for some form of cross-participant payment for use of another’s share.

Lack of Economies of Scale

The smaller any given grid is, the more difficult it becomes to balance its supply and demand equation. Remember lesson one from Power Grid 101 is that electricity needs to be produced at the same time as it is consumed. The more producers you have and the more consumers you have on any given grid the more that variations are smoothed out. Energy communities are inherently quite small which means the task of matching supply and demand is inherently tricky.

Dominant positions

The incumbent utility companies have massive advantages over energy communities in terms of their size, financial clout, and relationship with regulators and law makers, but also their importance to the rest of the electrical system. With energy communities representing a threat to some of the traditional utility companies it is understandable that they might not be as supportive as one might wish they would be.

Why can’t we all be part of one big energy community?

If the size of the community is one of the reasons why they can struggle to work, then why can’t we orchestrate a nationwide energy community? In some countries this is almost the case, it is just not so obvious. In some countries the main energy producing and retailing companies, along with the grid operators are state owned. So, the profits from this organizations flow directly back into the government which is a proxy for the wider community of a country. But the main reason why we don’t have one big energy company is the size and complexity of the existing system – it is simply very difficult to rethink and rebuild such a system.

How might energy communities benefit traditional utility companies?

Let’s try turning the question of this article on its head. What if energy communities could benefit utility companies. Again, let’s look at each player and see how they could benefit:

• Producers – They could use the collective purchasing power of a community to fund the investment in new infrastructure and shift their business model to helping energy communities run their production assets effectively or access and operate production capacity elsewhere.
• Retailers – They could benefit from having a single coordinated large customer and could position themselves as helping the energy community to buy in the electricity it needs when it isn’t self-sufficient. Plus, they could market the excess electricity on the wholesale market on the community’s behalf.
• Transmission operators – They could shift their model to connecting communities rather than connecting large scale production facilities to population centres.
• Distribution operators – What if they themselves become the facilitators of energy communities and shifted their business model to one where they purely serve their community.

Conclusion

Energy communities are unlikely to topple the large utility companies anytime soon, but their approach to energy sharing and acting in the interests of the community could help us build a better overall energy system. For us to do this we will need strong leadership from the regulators.