Has anyone determined what demand factors would apply for multiple electric vehicle charging stations? i.e. a multifamily project with 110 EV chargers. When calculating the loads, are these to be included at 100% or can a demand factor be applied when sizing for the distribution and/or service? Contact online >>
Has anyone determined what demand factors would apply for multiple electric vehicle charging stations? i.e. a multifamily project with 110 EV chargers. When calculating the loads, are these to be included at 100% or can a demand factor be applied when sizing for the distribution and/or service?
The contribution provides the basis for the integration of charging infrastructure for electric vehicles in the future planning of urban distribution power systems. It tackles the relevant factors for future planning of distribution power systems, which are the distribution of the charging points and their expected electric load demand.
Is anybody aware of the demand factor in NEC, which can be used to calculate total demand for multiple electric vehicle chargers? For example: if one level 3 charger is rated 400 kW and project requires 8 chargers per transformer, can 3200 kW demand be reduced per NEC?
understanding of the EV demand charge issue. We provide some context as to how utility costs are recovered, why demand charges for commercial customers are levied, the issues that inclusion of such demand charges in rates cause for EV charging, and some alternative solutions to address those issues. 2
The results show that in 73% of the day, none of the EVs are charging, and only in 0.1% of the daytime, a maximum of five EVs are charging simultaneously. There is no point in time when six, seven, eight, nine, ten or all eleven EVs are charging simultaneously, which again argues for the use of DF s.
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Ali, S.; Wintzek, P.; Zdrallek, M. Development of Demand Factors for Electric Car Charging Points for Varying Charging Powers and Area Types. Electricity 2022, 3, 410-441. https://doi /10.3390/electricity3030022
Ali S, Wintzek P, Zdrallek M. Development of Demand Factors for Electric Car Charging Points for Varying Charging Powers and Area Types. Electricity. 2022; 3(3):410-441. https://doi /10.3390/electricity3030022
Ali, Shawki, Patrick Wintzek, and Markus Zdrallek. 2022. "Development of Demand Factors for Electric Car Charging Points for Varying Charging Powers and Area Types" Electricity 3, no. 3: 410-441. https://doi /10.3390/electricity3030022
Ali, S., Wintzek, P., & Zdrallek, M. (2022). Development of Demand Factors for Electric Car Charging Points for Varying Charging Powers and Area Types. Electricity, 3(3), 410-441. https://doi /10.3390/electricity3030022
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With the transition to electric vehicles, utilities are becoming the new “gasoline wholesalers” as they provide critical fuel for transportation. Understanding their complex energy rate structures could make or break your EV charging business. Demand charges, in particular, can be toxic to your bottom line.
There’s an ongoing industry-wide debate about how utilities should handle demand charges. Fully disbanding demand charges would cost utilities something like $2.9 billion per year in opportunity cost, not to mention their initial $90 billion or so capex outlay to support getting power to the charging stations in the first place.
As traditional fuel stations transition to EV charging, having adequate knowledge of retail charging economics—and specifically how new cost and revenue levers impact a site’s profits and losses—will be vital for their growth and success.
Commercial and industrial (C&I) facilities typically have much higher peak power needs than residential homes so utilities must build out the local grid to reliably meet their maximum power demand. Utilities recover the cost of this additional infrastructure through demand charges on company electric bills.
Demand charges are a function of power in kilowatts (how much energy you need in a given period) and accompanied on a bill by energy costs (the total kilowatt-hours of your energy use). They are typically based on your highest level of grid use during an interval (typically 15 minutes in the U.S.) or billing period (usually a month) according to a fixed dollar-per-kilowatt rate.
While demand charges are somewhat logical for factories that use large, sustained loads throughout the day, things get a bit hairy when considering EV sites. An EV site might require more power than a factory but only uses it for few minutes per day. Yet, the site is penalized at the same rate as the factory.
Cole Rosson
In a real-world example, assume a typical national highway corridor EV charging site with four, 150-kW DCFCs for a potential peak load of 600 kW. There are plenty of reasons the site may never hit its peak load, but for simplicity’s sake, let’s say it does. If it’s in the Northeast, it could have a demand charge of about $15/kW. Multiply that by a 600-kW peak and you’re at a $9,000 charge per month!
Going a step further, we can break down that cost per charging session. Assume 300 sessions per month, or about 10 a day, which equates to $30 per session. To put that in perspective, the average revenue per session today is about $16, meaning that the site would be operating at a net loss of $14 per session. You’d need to almost double the EV volume to break even on just the demand charge, before considering other costs of good sold.
Utilities and public utility commissions recognize the EV demand charge issue and have funded programs that either waive demand charges or have special volumetric rate structures to significantly reduce them (EVgo published a concise guide here) to minimize the barrier of entry as much as possible for site hosts to invest in infrastructure today to support EV adoption tomorrow. However, many of these programs are made to reintroduce demand charges as EV volume increases.
We calculated National Grid’s EV rate, for example, which is based on a site’s total energy use divided by the power over a given period, known as load factor. This would cut demand charges by 100% at up to 26 charging sessions per day, 50% up to 36 sessions per day, and 0% by 37 sessions per day. This rate favors mid-size sites with average usage and penalizes small sites and large sites with high usage. While it’s a great program for the next few years, it still could negatively impact smaller independent sites or even NEVI-style corridor sites within high traffic areas, and certainly future profit margins.
If we put on a utility stakeholder hat to estimate the potential business impact or lost opportunity cost, we’d end up with a hole of approximately $2.9 billion. If we assume NREL’s projected 180,000 direct current fast chargers with an average output of 150 kW, that gives us a peak national load of 27 million kW. The average demand charge in the U.S. is $9/kW, so that equates to about $243 million in demand charge revenue per month, and $2.9 billion per year. If we consider that 168 investor-owned utilities cover most of the states with high EV penetration, that’s an annual demand charge impact of $20 million per utility before the $90 billion CapEx investment of about $500 million per utility.
If utility rates stay the same, then the average revenue per charging session would need to more than double to cover additional infrastructure costs. If the cost per charging session decreases, then the utility or ratepayer will need to absorb the initial $90 billion plus $2.9 billion more each year.
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