TODAY’S STUDY: Building More EV Fast-Chargers
Overcoming Barriers to Expanding Fast Charging Infrastructure in the Midcontinent Region
Dane McFarlane, Matt Prorok, Brendan Jordan, and Tam Kemabonta, July 2019 (Great Plains Institute)
Increased adoption of electric vehicles (EVs) has the potential to significantly and positively impact the electric utility sector and its customers. EVs offer utilities load growth opportunities without necessarily increasing coincidental load peaks. They can also help minimize new investments in generation and distribution infrastructure and actively match load with expanding renewable generation. Studies have shown that for EV owners with access to home charging configurations, most EV charging will occur at home which presents opportunities for load management over longer charging periods.1 Outside of the home, public charging remains a crucial enabling factor for significant adoption of EVs. In particular, strategically located direct current fast charging (DCFC) will enable longer trips, higher mileage-per-day usage, and charging by people without access to home or workplace charging.
Numerous studies demonstrate the importance of public DCFC in enabling higher rates of EV adoption.2 3 4 5 6 However, a study by the National Renewable Energy Laboratory (NREL) found that the Midcontinent region, and the US in general, has far less public charging infrastructure than what is required to achieve greater levels of EV adoption.7 The region currently has 425 DCFC plugs at charging stations and NREL’s analysis indicates that 4,020 plugs will by needed by 2030. This suggests a gap of 3,595 dedicated DCFC plugs at public charging stations. At $60,000-$100,000 per plug, this would require an investment between $215-$360 million over the next 11 years. In addition to capital and construction costs, the NREL analysis found that operating costs, including the costs of electric demand, present a huge barrier to the economic feasibility of DCFC stations.
This white paper is intended to study a specific barrier to providing adequate DCFC services in the Midcontinent region and nationwide: electric utility demand charges. For most utilities, the demand charge is based on the demand (kW) measured for a billing month that is required to supply the maximum 15 minute-average amount of energy used by the customer in a billing month.
In terms of high wattage (50 kilowatts and above) electrical equipment, DCFC is a unique use-case characterized today by relatively high-power capacity and low-energy utilization. This means that the operating cost incurred through capacity or demand charges often can far exceed the cost for energy usage. As the analysis in this white paper demonstrates, this situation can lead to operating costs that far exceed the revenue these chargers can receive from customer payments. Importantly, it is clear from the results of GPI’s analysis that demand charges are a primary factor in DCFC station economics, representing the majority of costs in most scenarios studied here.
GPI investigated the economics of operating a DCFC station along a specific highway corridor along Interstate 94 from Minnesota to Michigan, passing through the service territories of many electric utilities. The analysis presented here demonstrates that there is a high degree of variability from one utility service territory to the next. In some service territories, it is possible to economically operate a DCFC station today with the current rate tariffs, even with low utilization. In some territories, because of tariff structures designed for conventional commercial and industrial equipment, it may never make economic sense, even with very high utilization. As the market demands higher capacity DCFC, moving from 50 kilowatt (kW) to 150 kW and higher to enable faster charging, the economic challenges presented by utility demand charges are further exacerbated.
Addressing this issue is complicated. Demand charges exist for a reason and are based on a “cost-of-service” philosophy, which asserts that electricity system users should pay for any costs they impose on the system. Every utility has a different system and customer base and will approach this challenge in different ways. At the same time, analysis suggests both that DCFC is a critical element in enabling EV adoption and that managed Level 2 charging at home and the workplace offers significant benefits to the electric system. There is clearly a balance to be struck between possible costs imposed by DCFC in certain settings, and considerable benefits from the increased EV adoption it can enable.
This white paper highlights the main considerations in designing a demand charge tariff structure that is suitable for encouraging DCFC investment, highlights approaches taken by some utilities, and presents information for utilities and regulators to consider as they are seeking their own solutions to this problem…
This analysis found that demand charges are one of the most significant cost factors in DCFC operation. Most utilities in the region base their demand charge on the demand (kW) measured for a billing month that is required to supply the maximum 15 minute-average amount of energy used by the customer in a billing month. As seen in figure 6 later in this paper, DCFC economics are challenging at higher power levels such as 350 kW and 450 kW, where nearly all stations that break even or generate profit are those operating in utility territories where there is no demand charge. Demand charges represented the majority of costs in most scenarios studied by this analysis. As a result, the demand charges present in utility rate schedules are a key determining component of a DCFC station’s ability to break even or generate profit.
With lower-capacity DCFC (50kW), profitability is linked with utilization rate and is highly variable based on demand charge tariffs. DCFC stations of 50 kW would not operate profitably in any of the utility service territories at 1 charge per day but would be profitable in all of them at 10 charges per day. Because we expect charger utilization to be low in early years, and higher in the future, you can argue that for 50kW DCFC, higher utilization eventually solves the market failure for DCFC. This may or may not be sufficient to result in third-party investment in 50 kW DCFC. The fact that 50 kW DCFC is not profitable in every utility service territory and at all levels of utilization will make it difficult to build a truly comprehensive DCFC network and make a more fragmented network more likely.
Demand charges are more of a barrier for higher-capacity DCFC, which many industry experts expect will be needed in the future to allow for faster charging rates. For 150 kW, 350 kW, and 450 kW DCFC, a minority of utility demand charge tariffs allowed for profitable operation, even at utilization levels as high as 10 charges per day.
Our analysis makes clear that demand charges are a barrier to the widespread availability of DCFC. It also makes clear that this is not simply a chicken and egg problem that will be solved when there are more EVs and higher levels of utilization at the chargers; demand charges are higher still for higher-capacity DCFC and challenge the economics of operating these chargers even at higher levels of utilization…
According to a review of the existing literature, availability of DCFC is critical to enabling increased EV adoption. Even though the majority of charging by EV drivers is home and workplace charging, publicly accessible DCFC infrastructure is necessary for enabling adoption and necessary to allow for longer trips.
Level 2 charging at home and work offers the greatest opportunity for managed charging to offer grid benefits, for example by avoiding onpeak charging, increasing off-peak charging, and integrating off-peak generation of renewables. The benefits of managed Level 2 charging for the electric grid may not be as large without the existence of DCFC to remove a significant barrier to increased adoption.
By studying actual utility rate structures for a variety of utilities across the I-94 corridor from Minnesota to Michigan, we were able to model the likely economics of operating DCFC based on realistic assumptions about capital and non-energy operating costs and usage. We learned the following:
• Relatively low usage in the near-term translates to relatively low revenue from users.
• Demand charges are a high percentage of the overall cost of operating DCFC, as compared to energy costs and non-energy operating costs. This is exacerbated with higher-power and faster DCFC equipment.
• With lower capacity DCFC (50kW), profitability is linked with utilization rate and is highly variable based on demand charge tariffs. A 50 kW DCFC operates profitably in none of the utility service territories at 1 charge per day and all of them at 10 charges per day. Because charger utilization is expected to be low in early years and higher in the future, higher utilization could eventually solve the market failure for DCFC at 50 kW. This may or may not be sufficient to result in third-party investment. The lack of profitability of 50 kW in every utility service territory and at low to medium levels of utilization will make it difficult to build a truly comprehensive DCFC network and make a more fragmented network more likely.
• The barrier to economic feasibility presented by demand charges is greater for higher capacity DCFC, which many industry experts expect will be needed in the future to allow for faster charging rates. For 150 kW, 350 kW, and 450 kW DCFC equipment, a minority of utility demand charge tariffs allowed for profitable operation, even at utilization levels as high as 10 charges per day.
• There is a high degree of variability among utilities in terms of their demand charge tariffs. Some utilities have more “DCFC-friendly” tariffs that result in DCFC systems operating profitably across a wider range of operating conditions (see this paper’s case studies from Xcel Energy and PG&E). Many utilities have demand charge tariffs that make it difficult for DCFC to operate under many or most utilization levels.
• It is expected that DCFC systems will have low-utilization rates near term, and for utilization to increase over time as EV adoption increases (which will be enabled in part by increasing access to DCFC and network effects of building more chargers). Our analysis suggests that the conditions that are likely to facilitate increased DCFC availability in the region are a combination of reducing DCFC capital costs, which could come through state or utility cost-share in combination with private investment, and adjusting demand charge tariffs.
Demand charges exist for a reason and all utilities will have a different approach to this challenge based on their individual system and customer base. This analysis is not intended to create a “one-size-fits-all” approach, but to give utilities and regulators informational tools to address this problem in the way that works best for their system and customers.