Charging Electric Vehicles: the Challenges Ahead

Forget the latest Tesla announcement, the fanciest new concepts, or the scramble of traditional automakers to add electric drivetrains to their product mix. Yes, electric vehicles (EVs) will get cheaper, better and more diverse: that’s just inevitable technology progress.

What you should be focusing on is charging them up. The most challenging and disruptive changes lie within the electricity system. Here I’ll give just a brief flavour of the issues, divided into four sections as follows:

  • The Electricity Mix
  • Distribution Networks
  • Fast Charging
  • Autonomous Vehicles

My aim is to get you thinking, so I’ll be raising far more questions than I answer!

I’m certainly not raising these questions because I’m pessimistic of solving them – quite the opposite. But it’s only by asking them that we can start to develop solutions and identify new business opportunities which will take us in the right direction.


The Electricity Mix & Price Signals

At a macro level, the overall increase in electricity demand due to EVs is likely to be just a few %, often less than 10%. On the one hand that doesn’t sound a lot. Nevertheless it’s still a significant chunk of new power generation capacity (or an increased utilisation of existing capacity). At the very least it could reverse the trend of decreasing electricity use seen in markets like here in the UK.

More significant than average changes in demand, will be when these changes occur – and how they fit with changing supply.

For example, in cool northern climates demand is already greatest in the winter. The additional demand from EVs may be enhanced in the winter too, as a result of their reduced efficiencies in cold weather: meaning more charging is needed to achieve the same mileage.

The UK is one market where the removal of coal is a carbon policy priority. It’s one that has been progressing well: coal has been disappearing from the electricity mix at a rapid rate in recent years. In 2017 however, during the top 10% hours of highest electrical demand, coal provided a sixth of Britain’s electricity. Those peak demand hours occur during early evening cold winter evenings – just when many people are arriving home and in temperatures where EVs are operating least efficiently. So when the coal is gone (as is government policy), what will replace both that missing supply and the additional requirement as EVs push demand up?

The rise of EVs adds extra emphasis to a question of dependable supply capacity that existed anyway.

On the other hand, in summer there is likely to be excess energy available in the middle of a sunny day, due to large solar capacity. Will EVs be able to soak up that excess? That would be great, because prices, at least at a wholesale market level, will be low. Adding EV demand could avoid both these prices going negative and the curtailment of clean energy. Cheap charging would be good for consumers and increased demand would boost the value of solar energy. But does the middle of a sunny summer day coincide with when people want to be charging? If it doesn’t, will prices – when at the retail level – prove low enough to shift their behaviour?

There will also be times of plentiful or excess energy due to wind, but since these are much more variable, it’s impossible to model the impact based on any regular schedule. Price-taking here would need to be a much more ad-hoc, automated response.

Of course the volatility of prices in a system depends strongly on the flexibility of the system itself. Extremes, whether high or low (even negative) are symptoms of inflexibility. Excesses of energy may prove more attractive to store elsewhere (in stationary energy storage systems) or to export, or to utilise through other demand response mechanisms (refrigeration, heating and more). Indeed as EV fleets expand, their aggregated charging response will itself likely become an important source of macro system flexibility, smoothing out the very price signals that initially guided it.

It’s worth noting that where volatility is high and hence changes in tariff could prove attractive, concerns have already arisen around “changeover points”: for example multiple cars all starting to charge the moment a tariff change signal occurs. Systems do already exist to mitigate this though, delaying or spreading charging initiations to avoid unwanted local spikes in power draw from the distribution grid. (We’ll focus on those nasty spikes in the next section).

At larger penetration of EVs though, how far can charging delays be pushed, without consumers missing out on tariff benefits or fretting over their state of charge?


Distribution Networks & Demand Diversity

If everyone on your street decided to switch on their electric oven at the same time, a fuse at the local substation would likely go “pop”. Everyone would find themselves in the dark (with those electric oven owners limited to eating salad).

In other words, grid capacity is already sized around demand diversity, rather than scaled to accommodate synchronised maximum demands. This approach keeps costs down by avoiding sizing infrastructure to meet very, very unlikely scenarios. It isn’t aggregated energy that matters here, it’s power demand at any specific moment in time.

One key problem with the idea that EVs will automatically take advantage of low prices driven by excess solar or wind energy is that this could decrease demand diversity (if they all choose to start charging at the same time). And EVs, especially future ones with faster chargers, are bigger draws on power than electric ovens!

One UK analysis concluded that in a town with a population of 6,800, just 900 EVs entering the system could lead to brownouts (through a drop in the voltage of supply). At a more local level, a pilot project showed problems when just five 3.5 kW chargers were connected to a network cluster (with 134 dwellings) and charged at the same time. That project concluded that 32% of UK low voltage circuits (312,000 in total) would require reinforcing if 40% – 70% of customers had EV’s with 3.5 kW chargers (i.e. very slow ones, with 7kW now becoming the norm). That was estimated as a present-day cost of around £2.5bn. Ouch. Luckily pilots aren’t just about identifying problems, they’re about solving them too. This same one tested a system to avoid much of that reinforcement cost by managing charging when local grid capacity started to be strained.

In the absence of diversity, managed charging is thus essential in addressing the potential conflict between cheap energy supply and expensive grid upgrades. It shouldn’t just be driven by least-cost wholesale electricity, starting the process as soon as this is available. It should account for grid constraints and distribution costs too. It’s also worth noting that managed charging itself imposes some costs, such as installation and maintenance of the required communication infrastructure.

In practice, distribution network upgrades won’t be a nationwide issue, certainly not at the start of the EV growth story. Some localities – wealthier urban streets – will have greater concentrations of EVs and/or greater concentrations of larger EVs (attached to higher-power chargers).

This raises interesting policy and socioeconomic questions.

Should the costs of local grid upgrades be spread across other electricity consumers, those elsewhere and even without EVs, in order to enable drivers to access to cheap electricity? Or should demand charges (based on each consumer’s peak power requirement) become a much more significant element of domestic electricity bills?

Should electricity charges, whether based on demand or on energy consumption, become differentiated down to the local level through new “nodal marginal pricing” regimes. These take account of specific congestion conditions within the grid, with high prices discouraging consumption where congestion is high. Such pricing schemes exist at the wholesale market level in a number of electricity markets around the world, but not yet at the distribution level.

Is a better solution to avoid charging EVs directly from the grid; charging stationary storage systems instead. That could be done when it makes most sense in terms of grid capacity and/or energy cost, spreading a low power draw through the day. Then EVs could charge from this stationary storage, at a faster rate, when it makes most sense for a consumer’s own mobility needs. What are the economic and aggregated energy implications of that approach, given that each extra storage roundtrip involves energy losses?

If the solution is to be a combination of several or all of these options, which combination will be both comprehensible and acceptable to consumers, while efficient in terms of reducing grid reinforcement costs? Are these goals even all deliverable at the same time?


Fast Chargers & “Filling Stations”

The last section focused on home-based charging – and it certainly seems reasonable to assume that, unless unable to, most EV owners would like to have a charger at home. Nevertheless, distribution constraints mean that unless they are prepared to pay for the privilege of higher power, this charger will likely remain slow.

Yet there is clearly lots of interest in fast charging, with ever-increasing sets of headline numbers around how powerful these will be (350kW being the highest I’ve seen thus far).

Fast-charging could be key in overcoming anxieties around range. If you know you’ll be able to stop for just a short time, then leave with a battery full enough to get you where you are going, that’s one major inhibitor of EV uptake gone. It doesn’t matter that most people might have 90-95% of their journeys within the range of EVs – that other 5% can still give cause for concern. Not so, if one quick stop solves that rare problem.

In the UK, around 40% of car owners live in homes where installation of a charger remains problematic (for example shared residences or those without off-street parking). For them, the need to visit a “filling station” may be a necessity rather than a nicety. It remains to be seen whether these public or privately-operated chargepoints will be in similar locations as now (as Shell, for one, hopes) or elsewhere – supermarkets, car parks and so on.

Utilisation and demand diversity will prove key to identifying the grid requirements, the costs and hence the business cases in any eventual outcome.

Fast charging may flatten aggregate demand curves (i.e. a macro system impact), but increase local capacity issues (through short-but-high peaks at specific locations). Bear in mind that ten 350 kW chargers would require an infrastructure capable of handling 3.5 MW. In current fossil-fuel forecourts, 20 pumps are not uncommon: that would require 7 MW of infrastructure support in a single spot. Proposed solutions to very high demand chargepoints range from siting them close to high-speed electrified rail lines, to utilising stationary battery storage too (as suggested for domestic charging in the last section).

However connected, fast and super-fast chargers will compete for charging revenue with slow and domestically-sited charging demand. Opinions vary on which will predominate.

National Grid have suggested it might be better to build a few thousand super-fast charging forecourts of >3 MW capacity rather than undertake a large scale rebuild of the domestic electricity infrastructure. As they put it: “it may well be that the charging from home option may not be in the long term interest of the consumers even with smart chargers.”

That approach conflicts with one which links domestic charging and a consumer’s own electricity supply: charging their car from their own PV rooftop, perhaps with stationary storage too. That’s an attractive, “in control” concept for many consumers. It also removes some other concerns they may have. Would relying on a fast charging station mean queues at peak times? Would every “pump” be interoperable with every car?

Current opinion appears to favour relatively slow home-charging as the dominant mode, while recognising rapid charging networks will certainly be required. They may be used relatively infrequently, as emergency, “unplanned” charging options or on rarer long journeys – and will likely be priced as such. At a recent conference in London, National Grid suggested that as few as 50 ultra-rapid chargepoints in key locations could solve range anxiety issues here in the UK; and at relatively minor cost.

Beyond “slow” and “fast” charging, there’s wireless charging. Who’s to say we’ll need to plug in at all: maybe one day the battery charge will be topped up at every parking spot? Or a little bit added every time we pause, at a junction or traffic light? If that seems like science-fiction, be aware that the technology already does exist.


Fully-autonomous EVs

The impact of fully-autonomous EVs is one which promises to be significant at all levels within the electricity system, both macro and local.

One key question concerns overall energy use. Will AEVs increase or decrease driven miles? There are a lot of variables that feed into answering that question.

How many AEVs will simply replace private vehicle ownership on a one-to-one basis? How many will be shared AEVs (SAEVs), whereby a single car replaces several privately owned ones, through car sharing or “Mobility as a Service” (MaaS) schemes? In either case, will the AEV experience prove so pleasant that more journeys are made, perhaps even reducing demand for public (mass) transport? Or will route-sharing and efficiency algorithms, plus other SAEV fleet management software get people from place to place with less overall driven miles?

There is some evidence that ridesharing may increase usage: one study concluded that, between 2013 and 2016, ridesharing services increased miles driven in New York City by 600 million.

From an individual charging and network perspective, the requirements and changes created by AEVs are highly uncertain. Nevertheless, we can theorise some impacts.

It is likely that SAEVs and MaaS businesses in particular will depend on access to fast charging: after all, time spent charging a battery is time not spent charging customers. The latter is an opportunity cost, which will certainly exceed the electricity charging costs.

On the other hand, a shared vehicle fleet will be smaller than an individually-owned one. That probably mean fewer chargers overall will be needed, to service fewer cars; though these cars will need to charge up more often.

Some analysts suggest shared fleets will favour centralised super-charger locations, cost-optimised for fleet-owners by locating close to substations and away from congested grid nodes. On the other hand ride-sharing is likely to be particularly attractive as a business within densely populated areas, where utilisation rates are high but centralised charging sites may be limited.

Location and timing issues will be interlinked. Perhaps peaks will occur before and after each commute period? But where will these occur? For the morning commute, an “after” peak might take place at central city locations close to which cars have converged. But where will the AVs have charged up prior to rush hour? Will they spend the night at suburban charging centres, or themselves first commute out of the city in order to bring people back in?

New behavioural patterns of mobility create big implications for the electricity grid. Will new behaviours drive grid changes or will grid constraints limit behavioural change? The answer is probably just a question of the timeframe we choose to consider.


Confused? I hope so!

If you thought the most interesting issues in the transition to electric vehicles lay in the progression of the vehicles themselves, then hopefully I’ve changed your mind.

Instead I encourage you to look far more closely at how all those batteries will be charged, both from a macro (energy mix) perspective and from a local grid network one too.

How many chargers will we need, where will they be and who will operate them?

The road to answering such questions will be winding and awash with intersections and route choices. It will involve business models which may make sense in the short-term but prove to be dead-ends in the long-run. It will depend on the interplay between electricity supply options, market operations, grid costs, policy choices and consumer behaviour (both rational and irrational).

It will be an exciting journey!


(This article was first published on LinkedIN: you can connect with me here)


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