Grid readiness for road electrification: Turning challenges into opportunities

The road to electrification for light duty vehicles (LDVs) is approaching a tipping point, with 42% of global LDV sales expected to be electric by 2030, provided the supply of essential metals can support it. We are also seeing momentum building in the heavier segments of transport electrification, with more than 300,000 electric trucks and ~800,000 buses in use worldwide as of 2022 according to the IEA.  

However, a key challenge for widespread transport electrification — beyond affordable EV availability — is making sure electricity distribution networks can cope with the extra energy demanded by these vehicles, and that Charge Point Operators (CPOs) can deal with the rapid expansion of all aspects of their business. Compounding this, it’s crucial that both transmission and distribution grids can access sufficient energy that comes from renewable sources, in order to realise the overall CO2 reduction that EVs promise. 

Several issues have been consistently flagged across geographies. Firstly, when CPOs select locations for chargers, they often lack sufficient visibility of grid capacity. This leads to a significant share of projects being cancelled or delayed, and budgets increased after the network capacity checks. Secondly, even when networks are aiming to proactively publish information on their hosting capacity, they do not always have the resources to keep it up to date — especially when there are multiple connection applications that require extensive effort to process, and that can exert effects on capacity very quickly. This problem is exacerbated if the regulation does not allow networks to proactively invest in building out capacity unless they can point to existing interest from customers. By that point it may be too late, which leads to delays and additional cost. 

To summarise, CPOs are facing bottlenecks that include slow permitting times, lack of standardisation in procedures, and poor visibility of existing capacity. All this comes on top of lengthy time frames for grid upgrades generally, plus a lack of flexibility in network tariffs, which can make the business case for CPOs unviable. 

This article looks at how we can jointly address these challenges and turn them into opportunities. The distribution grids need to plan for target levels of EV penetration and proactively shape optimal locations and modes of charging — in close coordination with customers, city planners, developers and EV infrastructure investors. 

Grid capacity and growing EV demand 

Within a fully electrified landscape, post 2035, grid demand from road transportation could theoretically surpass existing system capacity at current peaks. Taking Germany as an example, assuming 52 million EVs (once all light duty vehicles are electrified) charge at 4 kW simultaneously, this would demand more than 200 GW compared with the current peak demand of less than 100 GW — before even considering commercial vehicles. While it is unlikely that EV charging periods would coincide across a power system, it is nonetheless possible that many EVs will be charging at the same time within a distribution transformer or zone substation area, potentially causing issues.    

Fortunately, there is a way to mitigate the risks, if we are able to provide the right mix of convenient charging locations for vehicles to charge at the right times – at home, workplace, destination, en-route, loading areas, and depots, - and incentivize optimal charging patterns. Proactively planning for EV infrastructure and shaping charging patterns with the right energy tariff designs and incentives can ensure that the impact of increasing EV demand does not create unnecessary issues for the energy system.  

However, as we have seen, major challenges already exist in some regions at the local distribution transformer / feeder level, while other locations enjoy a substantial amount of under-utilised capacity and will not require an upgrade to the grid. With grid hosting capacities differing significantly across locations even within the same distribution network, planning for EV charging rollout becomes a very site-specific challenge. 

Months, or even years, to get an EV charger connected to the grid 

EV charging developers currently lack sufficient visibility of grid capacity. As a result, they may make connection requests based on a ‘connect anywhere’ policy — the notion of a basic right to connect anywhere on the network. But in areas where the grid is already heavily congested, this results in higher costs and long connection times, making some charging stations projects unviable. One way the CPOs are trying to deal with it, is applying for multiple alternative locations – which in turn increases the network’s effort and time to assess these parallel applications. In many cases this means it might take months for the grid to explore a particular location, and potentially several more months or even years to upgrade capacity. Fastned, one of the key pan-European HPC (High Power Charging) CPOs, has experienced slower roll-out in the Netherlands partly due to these delays, and is now likely to postpone its 2025 rollout target as a result. 

Taking these factors into account, we believe that distribution networks — in collaboration with CPOs, their customers and broader ecosystem players — are best placed to drive and orchestrate the most efficient and timely planning for EV infrastructure while finding best ways to utilize existing grid infrastructure and site locations (e.g. roadside parking, fleet depots and petrol stations) and leverage local renewable generation at the same time. 

How networks operators and industry stakeholders can tackle the challenges 

At the core of a successful response to the challenges is collaboration between key stakeholders, including municipalities and local councils, as well as CPOs and distribution grids. 

Three key areas specifically require grids to develop new capabilities to support the EV charging infrastructure roll-out, in parallel with broader energy demand electrification: 

1. Advanced network planning approaches, including co-location with Renewable Energy and Storage (RES+) and improved visibility of hosting capacity, plus a longer term focus and better awareness of EV penetration and charging patterns locally — enabling more efficient selection of location and better use of resources 

1. Flexible solutions including connection agreements and smart charging, including V2G capabilities – enabling the optimal timing of charging

1. Transparency, standardisation and automation of the connection process  

a) Advanced network planning approaches 

Distribution grids need the ability to model future charging needs and impacts under various scenarios. These include understanding EV penetration by location; charging patterns and ability to influence these via flexibility management; current and future rooftop solar PV penetration; and storage availability and requirements. It translates into modelling the upcoming impact on grid infrastructure, considering storage availability and requirements, and assessing the need for investment many years in advance. Many networks globally recognise that they have to take on these challenges, and they are keen to make progress — however, the current regulatory framework might need to be adjusted in many cases. 

In the context of once-in-generation shift in electricity consumption, the networks need to be able to plan for a longer time frame of 10-20 years, rather than current 3-5 year periods that most regulatory frameworks allow. It also requires proactively planning for the expected levels of EVs, instead of waiting for requests to come through. Lastly, the ability to work jointly with municipalities, developers, energy providers and CPOs to shape investment is essential. 

All of this requires a fundamental shift in the regulatory paradigms, of which we are already seeing signs. As an example of novel approaches in this area, the EU market design proposal includes a mandate for national regulators to adapt remuneration schemes for transmission and distribution, among other things, in order to foster the so-called ‘anticipatory investments’. In other words, it’s an attempt to accurately anticipate the needs of customers so that the network is actually ready when they demand it.  

To summarise, the regulatory change is about i) being able to look out longer term, ii) planning for target levels of EVs, instead of waiting for requests to come through, and iii) building the ability to work jointly with municipalities, fleet owners, energy players and CPOs to shape electricity network, local generation and storage, and EV charging networks in close coordination. 

We are already seeing some CPOs teaming up with generators to apply for grid connections in two-sided requests, in order to accelerate grid access and raise resource efficiency. Distribution grids need an ability to expand these innovative ways of working; for example, by looking at sites where EV charging can be supported by local solar generation and co-located storage.  

In this vein, Australian distributor Endeavour Energy found that EVs, if charged at the right time, can complement grid battery storage by absorbing surplus solar energy, thereby mitigating feeder and transformer overloads and reducing PV curtailment in local areas. This approach looks set to improve service levels considerably; we’ll take a deep dive into Endeavour Energy experience in a separate article as part of this series.  

b) Flexible solutions and connection agreements 

Flexible connection agreements and smart charging are key to unlocking the potential of advanced planning. Examples include the Flexpower 3 pilot by Alliander, in which optimised charging allows for more charging stations without overburdening the grid. EV charging infrastructure can actually add more flexibility to the grid through time of use (TOU) tariffs, more advanced smart charging, and eventually, vehicle to grid (V2G) technology - as demonstrated by UKPN and Octopus collaboration in the UK, or Elia group in Belgium (see exhibit).  

We have seen some CPOs already leverage dynamic pricing and subscriptions to improve customer economics while reducing their impact on the grid. EVGo launched a time-of-use tariff pilot in US, with on-peak and off-peak differentiated rates; E.On has piloted dynamic pricing in Denmark. The E.On system gives customers significant discounts at times when renewable generation is more prevalent, while reducing potential peaks. The Australian Renewable Energy Agency (ARENA) and energy retailer AGL joint Electric Vehicle Orchestration Trial found that time-of-use tariffs can play an immediate role in moving charging to off-peak periods; they also discovered that overall residential EV charging load was smaller and more diverse than expected.   

Other players are focusing more on private charging infrastructure, and especially home charging. For example, Jedlix, Kaluza from OVO and EV.Energy in Europe allow drivers to schedule charging time at home to optimise load balancing and/or make use of the cleanest energy available. Jedlix’s system intelligently adapts to a multitude of factors – most notably, the availability of a customer’s solar panels. With the rise of the electric home, we will see growth in the kind of solutions that can integrate solar PV, home storage, heat pumps, time of use tariffs and even more dynamic tariffs.  

We expect demand aggregators and demand response business models to develop and consolidate, meaning stakeholders must be deliberate and focused about planning for co-location of EVs with generation and storage, in order to boost flexibility on both sides. It is also very important that the network, CPO and market aggregators’ pricing is aligned to convey the right incentive to the customers and fully unlock the benefits of flexibility management for the grid and customers. 

Vehicle to grid charging (V2G) is not yet ready to scale commercially, but there are players that have worked on the opportunity for more than a decade (e.g., Nuvve, Fermata Energy). With long parking hours for EVs at home, workplaces and at certain destinations, as well as niche cases like electric buses, we find interesting grid balancing opportunities. The first commercial electric school bus V2G program in the US has been announced by Highland. This looks particularly promising, since electric school buses are ideal assets for V2G applications, with nearly 500,000 in use in North America which all spend the majority of their time parked up. They could be charging during peak solar generation time, and partially discharging at evening peak demand hours. Fossil fuel-powered buses provide no value when idle, but electric buses can be used effectively as mobile batteries when not transporting students, providing additional power to support grid stability and resiliency. We will continue to see these types of opportunities evolve as grid balancing and energy transition enablers. 

c) Transparency, standardisation and automation of the connection process 

Many distribution grids have started proactively deploying capacity maps and connection portals, with Eurelectric reporting that these are available across 16 European countries so far. However, most capacity maps in use today are designed for generation, not consumption. Networks could proactively highlight the areas where public EV charging is likely to be beneficial from grid support and CO2 perspectives — for example, areas with high PV penetration in which EV drivers park for long periods during the day. 

There are emerging tools in the market that can help automate the connection studies and support self-service for applications, such as Envelio by E.On or Plexigrid digital twin platforms as examples. The leading distributors aim to streamline the entire process from connection pre-checks to analysis of connection options and grid study parametrisation, as well as selecting the best variant and reservations management. Customer requests can be then handled much faster, so much so that network teams could save up to 85% of effort in connection request processing. 

Conclusion 

There can be little doubt that road transport electrification, while representing a major opportunity for the energy transition, is set to challenge today’s grid planning and development approaches. The grid should be a major enabler – not an impediment for EV charging infrastructure rollout.  

The sector recognises the importance of preparing for expected growth in EV adoption, as well as proactive collaboration with the ecosystem players when it comes to the selection of locations and types of charging facilities. Such anticipation needs to be empowered with shifts in regulatory frameworks to promote efficient outcomes for the future. Proactive planning and smart charging, enabled by location-specific analytics and flexible pricing, are set to make the process smarter and less dependent on long grid upgrades. 

Distribution networks, investors, and key stakeholders in the industry must collaborate closely to ensure bottlenecks are overcome, while new business models around flexibility and energy management will need to be planned and activated. 

Thomas Baker is a Global Leader of BCG’s Low Carbon Energy and Infrastructure sector, Managing Director & Partner for BCG in San Francisco and a core member of the firm’s Energy and Climate & Sustainability practices. 

Jennifer Carrasco is a Knowledge Expert in BCG’s Energy practice specialized in EV charging in BCG’s Barcelona office.  

Oxana Dankova is a Global Leader of BCG’s Energy Networks business segment, Partner & Director in BCG’s Energy Practice and Climate and Sustainability practice, based in Australia. 

Pavla Mandatova is a Knowledge Expert in BCG’s Energy practice, focusing on energy networks. She is based in Madrid. 

Nathan Niese is a Partner & Associate Director, Electrification & Climate Change, for BCG in Chicago. 

Anita Oh, Managing Director & Partner, leads the Energy practice for the East Coast of Australia, and the firm’s Digital in Energy and Climate and Sustainability work for Australia and New Zealand.  

Christian Wagener, a Managing Director & Partner in BCG’s Energy Practice, based in Europe.