Comparing the levelized cost of electric vehicle charging options in Europe

The study addresses how much it costs to charge electric vehicles (EVs) across Europe and how these costs vary by charging option and country. Against the backdrop of the Paris Agreement and the EU’s transport decarbonization goals, EV adoption is rising as purchase prices fall, shifting attention to use-phase costs. Unlike transparent gasoline and diesel pump prices, EV charging costs are complex and depend on charging location, power level, time of use, and pricing schemes. Prior research has often relied on uniform electricity price assumptions or examined limited geographies or specific charging contexts, leaving a gap for a consistent, Europe-wide comparison across charging options. This paper models the levelized cost of charging (LCOC) for passenger EVs across 30 European countries and 13 charging options, disaggregating cost components to reveal drivers of variance and to inform users, transport modelers, and policy makers.

Previous studies recognize that EV charging costs extend beyond average electricity prices to include infrastructure costs, utilization rates, and tariff structures. Much of the existing work focuses on specific sites, technologies, drivetrains, or localized geographies, limiting generalizability. A recent comprehensive analysis covered a broad set of options and tariffs for the United States, but a consistent, cross-country European assessment had been lacking. The literature also highlights variability in utilization rates at public charging and the importance of taxes, levies, and tariff design in overall charging costs, underscoring the need for a standardized LCOC framework applicable across diverse European contexts.

The authors develop an LCOC framework, building on levelized cost methods from electricity generation and prior LCOC work, to compute the long-term average cost to the consumer per kWh charged at the plug for 13 charging options across 30 European countries. Charging options are defined by combining four charging sites (residential grid, residential with rooftop PV supplement, commercial privately accessible such as workplace/fleet, and commercial publicly accessible) with power levels: low AC (<2.3 kW), medium AC (3.7–7.4 kW), high AC (11–22 kW), and DC (50 kW). User profiles (Wallbox user, Wallbox user with PV, Socket user, Commercial user, plus an Average user) allocate charging energy shares across options to reflect realistic behavior; aggregated user LCOC is a weighted average of option-specific LCOC by country. Infrastructure costs include: equipment (database of 232 charger models from 37 manufacturers, categorized by quality standard suitable to site), installation (mechanical/structural, electrical distribution, permitting and other expenses; materials assumed uniform across countries; labor scaled by country-specific construction/electrician wages), and O&M (2% of equipment cost for residential and privately accessible commercial; 4% for publicly accessible; plus €180/year service costs at public sites for billing/network/load management). Grid connection reinforcement costs are excluded due to inconsistency across regions. VAT is applied to residential infrastructure costs per country but excluded for commercial operators. Electricity costs use Eurostat 2019 average prices: household band DD (5,000–14,999 kWh/year) for residential grid charging with a 10% reduction to reflect night/time-of-use charging; non-household band IB (20,000–499,000 kWh/year) for commercial sites (excluding VAT). For residential PV, country-specific hourly overlaps of modeled residential charging load and PV output determine the share of charging supplied by PV; electricity cost is a weighted average of rooftop PV LCOE and residential grid tariff. Charger efficiencies at the plug are modeled: 100% for socket (low AC), 99.5% for medium/high AC, and 92.1% overall for DC (transformer and charger). Publicly accessible sites include a 2% transaction fee. Levelization uses a 15-year project life. Discount rates: 3% for residential sites (reflecting household/social discount rates) and 7% for commercial sites (typical corporate cost of capital). Yearly charging energy inputs determine utilization; for commercial sites, well-utilized stations are assumed based on empirical studies; for residential, yearly charging demand is derived from average national driving distances, BEV real-world consumption (17.4 kWh/100 km), and a 75% home-charging share. European averages are population-weighted across countries. Sensitivity analyses explore input uncertainties, highlighting utilization rate as a key driver.

- Large cross-country and cross-option variation: Average user LCOC ranges from 0.173 €/kWh in Hungary to 0.330 €/kWh in Germany; Italy (0.327), Belgium (0.324), and Denmark (0.324) are also high. - By user profile (European average, population-weighted): Wallbox user 0.315 €/kWh; Wallbox user with PV 0.300 €/kWh; Commercial user 0.333 €/kWh; Socket user 0.170 €/kWh. Socket charging is 43–49% cheaper than the other profiles on average, though with practical limitations (slow charging, access, limited smart control). - Within-country spread between cheapest and most expensive option averages 0.357 €/kWh; minimum spread Romania (0.317), maximum Switzerland (0.489). Costs generally increase with power level: low AC cheapest, DC fast highest; medium/high AC in-between. - PV vs grid at home: PV reduces LCOC especially in high grid-tariff countries (Belgium, Denmark, Germany) and in Southern Europe (higher PV capacity factors). Italy and Cyprus see 11–24% reductions depending on power level. In contrast, PV increases costs where PV output/capacity factors are low or grid tariffs are low (e.g., Norway +4–10%, Lithuania +12–23%, Hungary +14–26%). Case examples: Germany sees −0.040 €/kWh (−11%) with PV mainly via reduced taxes/levies; Hungary sees +0.019 €/kWh (+10%) due to higher PV energy cost outweighing network/tax savings. - Commercial charging attractiveness varies by country: Often favorable in Eastern Europe (lower annual driving distances raise residential levelized infrastructure costs; commercial tariffs sometimes lower than household), and in countries with significantly lower commercial vs household electricity prices (e.g., Belgium, Netherlands, Sweden). - Cost composition (European average, except Socket user): infrastructure and electricity each contribute roughly half (46–54%) of LCOC. Within infrastructure, installation often dominates over equipment; O&M is minor except at publicly accessible sites. Within electricity, energy cost is key, but taxes/levies significantly raise costs at residential grid sites. - Utilization rate is a critical driver, especially for public/commercial charging with higher capital cost. LCOC per 100 km vs utilization is highly non-linear; low utilization leads to very high costs. High AC often offers the best trade-off between power and capital cost. At roughly 5–15% utilization (depending on gasoline prices), publicly accessible charging can be cheaper per 100 km than fuel costs for efficient gasoline cars today (comparison only on energy/fuel costs). - Policy-relevant components: taxes and levies (RE and environmental taxes) can substantially increase LCOC; installation costs are material and vary with labor costs and procedures; electricity price dynamics matter. Country case breakdowns (e.g., Germany, Denmark) illustrate the contributions and potential impact of tax exemptions on LCOC.

The analysis demonstrates substantial heterogeneity in EV charging costs across Europe, driven by both infrastructure and electricity components that vary by site, power level, and country context. For transport modelers, using electricity prices alone materially underestimates charging costs and obscures differences between charging options; including infrastructure and utilization is essential for accurate EV adoption modeling. For users, cost heterogeneity influences total cost of ownership and may affect purchasing decisions; however, end-user prices can differ from modeled LCOC due to operator pricing strategies, subscriptions, and fee structures. Market observations (e.g., Germany, UK, Switzerland) show public charging prices broadly consistent with LCOC ranges, with 2022 electricity prices influencing the upper end. Equity considerations arise where home charging is less accessible (e.g., apartment dwellers) and public charging is costlier, potentially slowing adoption and disproportionately impacting lower-income users. For policymakers, several levers emerge: reforming electricity taxes/levies for EV charging to avoid cross-sector policy inconsistencies; streamlining installation procedures and grid connections to lower infrastructure costs; monitoring and designing tariffs to keep EV charging electricity prices competitive with fossil fuels; and managing the coverage–utilization trade-off in public networks to avoid very low-utilization sites that inflate costs. Sensitivity analyses indicate meaningful LCOC responses to electricity price changes (±20% electricity price can yield up to ±14% LCOC change for the Average user), emphasizing the importance of electricity market conditions. Overall, appropriately targeted policies can reduce LCOC and support a faster electric mobility transition.

This study provides the first consistent, cross-country comparison of the levelized cost of EV charging across a comprehensive set of charging options in Europe. It shows pronounced cost heterogeneity across countries and charging configurations, quantifies the roles of infrastructure and electricity components (including taxes/levies), and highlights utilization as a key determinant of public charging costs. The results inform transport modeling, user decision-making, and policy design to lower charging costs and accelerate EV adoption. Future research directions include: extending analysis to higher power levels (>50 kW) and emerging charging technologies; adopting dynamic modeling with experience curves for equipment, installation, and O&M and time-varying electricity prices; assessing real-world tariffs and time-of-use impacts more explicitly; increasing geographic resolution to subnational levels; and integrating alternative business models (e.g., co-revenues, vehicle-to-grid services) and network optimization to improve utilization and economics.

Key limitations include: use of 2019 average electricity prices with an assumed 10% reduction for residential time-of-use, which may overestimate or underestimate actual charging costs; static modeling that does not capture future cost trajectories or price volatility; exclusion of on-site storage; assumed uniform equipment net prices across countries; omission of potentially significant grid connection reinforcement costs; commercial utilization modeled as relatively well-utilized stations, not capturing underused sites in emerging markets; national-level resolution only; and limited treatment of diverse operator business models and pricing schemes (subscriptions, session fees, parking fees). Sensitivity analyses partially address some uncertainties (e.g., electricity prices, TOU discounts), but generalizability may still be constrained by these assumptions.