Electric vehicles are transitioning from a specialized market representing approximately 1% of US car sales to an anticipated mainstream market of almost 25% of new car sales within seven years.1 The growing demand for electric vehicles is fueled by consumer demand and environmental awareness, state greenhouse gas reduction targets, federal and state subsidies, electric utility policies related to infrastructure development, and targeted electricity charging rates.
With the EV boom looming, there are numerous policy considerations for encouraging EV purchases, but from a cost recovery and rate design perspective, there are two main issues that utilities and regulators need to take into consideration. First, whether targeted utility programs related to EVs should be subsidized by other utility customers, and second, does it make sense to have separate rates for EVs.
The decision to purchase an EV or convert a fleet to electric vehicles includes factoring in fuel cost savings and hence electricity rates. However, electricity fueling costs are less than 15% of the lifetime ownership costs. Other considerations include the initial purchase cost, tax incentives/rebates, availability of the charging infrastructure, and special privileges such as parking and use of HOV lanes. Given the relatively low percentage of ownership costs associated with electric charging, targeted EV rates are as much about managing utility infrastructure costs as they are about encouraging EV purchases.
Arguments for and against cross-subsidizing EV rates and services
Incentive rates to encourage the adoption of EVs are receiving increased attention from policy makers and regulators. Incentive rates can take multiple forms but are typically associated with discounting the price of electricity and/or with subsidizing the cost of the establishing infrastructure to support EV charging at either the customer’s premise or in public spaces. If the utility customer is offered a below cost-based rate, then a cross-subsidy is created that may need to be funded by other customers. Practically, there is not a clear distinction between a subsidy and cost-based service. For example, incentive industrial development rates to new facilities or expanding an existing facility are frequently priced at marginal cost so that all customers are better off for attracting load that the utility would not otherwise capture. If the utility is selling incremental load above marginal cost the rate can be argued to be cost-based but if the rate is less than what other customers are paying, it can be argued to be a subsidy. In addition, there can be non-utility benefits including local economic development and tax revenue. Likewise, an EV rate could reflect marginal costs and provide extensive societal benefits (including reduced greenhouse emissions) depending on one’s perspective on the externalities associated with internal combustion engines.
Even though there is not a bright line on whether an incentive rate is being created, it is important for; utilities and regulators to think about the long-term implications of creating incentive rates for EVs. Based on forecasts that EVs will become a significant portion of vehicle sales in the next decade, the cross-subsidy could become substantial and translate into a meaningful rate increase for other customers. Recent experiences with net metering highlight some of the issues with incentive rates. They are controversial to eliminate once created, and they can move from being a negligible cost to a boisterous debate about cost shifting. Consequentially, any incentive rates for PEV’s should incorporate a sunset provision. Sunset provisions could include a known date for the end of the tariff, a pre-established number of participants, or potentially a phase down over time. These types of provisions are often relaxed or waived; however, it sends a signal to the EV owners that discounts will not be permanent. Therefore, we urge consideration of sunset provisions if incentive rates are implemented.
The issue of subsidization also arises in conjunction with developing EV charging infrastructure. Forty-three states and Washington DC are looking at policies to encourage the expansion of both public and private infrastructure for EV charging.2 These policies include defining the role of electric utilities in developing this infrastructure or offering rebates to customers that install level 2 charging stations. There is regulatory precedent where rates at utility compressed natural gas (CNG) stations at least partially recovered the costs of the infrastructure. A consideration of whether the cost of electric vehicle charging stations should be subsidized is who is paying for the subsidy. As with the debate on subsidies for net metering, there is the concern that EV ownership is more heavily concentrated in upper-income households and whether those customers should be subsidized by lower income residential customers.
EV rate design considerations
Utilities and regulators evaluating targeted rates for EVs should evaluate whether separate rates are appropriate, or whether a more widely applicable rate should be restructured so that the rate is agnostic to the end-use. Absent a policy to create a targeted subsidy, one argument is that a separate rate is not needed if the more generalized rate appropriately reflects policies for balancing cost recovery with sending appropriate price signals. In other words, the regulator should not be determining winners and losers with regards to technologies, but that the consumer and market should decide based upon appropriate prices signals. However, the practical issue is that there is often significant resistance to modifying historical rate structures as it inevitably creates winners and losers. This reality creates the path of least resistance of establishing voluntarily dedicated EV rates.
Within the rubric of a cost-based EV rate, there is a wide range of possible outcomes depending on whether the basis is: embedded or marginal costs, long or short run costs, and if it is based on utility costs or also incorporating externalities/social costs. From the utility perspective, a cost-based rate should discourage charging that creates costs of upgrading the utility’s infrastructure. In general, a targeted EV rate is therefore designed to shift charging loads to off-peak hours. Theoretically, a time base demand charge is a more efficient approach than a time-of-use (TOU energy rate) to match the recovery of fixed infrastructure costs with charging demands. As with TOU rates, implementing residential demand charges is challenging. However, as EV users presumably have significant control over when to charge their vehicles, a time-based demand charge for separately metered EVs may be slightly less controversial and the incremental cost of installing a demand meter as opposed to a TOU meter for a residential EV service is minimal.
There are similar considerations for rates for EV charging in public/commercial spaces. These considerations are whether the rate should be subsidized, and should the pricing reflect the time of day and the status of the grid.
One of the issues with dedicated EV rates is the utility’s incremental cost of metering and billing and the customer’s cost associated with adding a meter base with a dedicated circuit. This cost is in the range of $2,000-$3,000/household versus the cost of a utility installing a TOU meter for the entire household for approximately $200. The high initial cost can be a significant barrier, especially if any subsidies on the rate have a sunset date.
Another issue with static TOU energy only rates for EV charging is that these rates are not dynamic, and they tend to be hard to adjust once implemented. At the same time, the grid is dynamic and peak loading shifts as weather changes, new generation technologies are adopted, and consumer preferences change. Given the large investments in AMI and advanced communications, regulators should consider whether a dedicated EV rate should incorporate dynamic pricing and incent the market to sell charging equipment that responds to pricing and grid constraints as well as valuing the system storage associated with a large penetration of electric vehicles. In other words, customers who are adopting new technology and moving to an optional rate should be leading the way for innovative rate design as opposed to adopting the static TOU pricing approach.
An example of a new rate design is SDG&E's pilot program for its Grid Integration Rate, which has an hourly dynamic rate for customers enrolled in the Power Your Drive program. The rate also has dynamic adders for circuit level critical peak pricing. An adder is added to the top 200 historic circuit peak hours. Customers are provided the information on a day-ahead basis through a smartphone app to encourage grid integrated behavior, including the best times to charge EVs.
Considerations for the looming EV boom
EVs are expected to shift from an inconsequential to significant utility load that should be managed to avoid unnecessary grid upgrade costs. While policy drivers for encouraging EVs differ significantly across states, regulators should exercise caution in creating subsidies as the cost of cross-subsidization may grow rapidly with the projected rapid increase in EV sales. If near-term cross-subsidization of charging rates and/or charging infrastructure is deemed to be appropriate, then clear signals should be sent regarding the duration of the subsidy as a subsidy once implemented is difficult to reverse.
While we encourage regulators to adopt wide-spread efficient rate design that is agonistic to the end-use, we acknowledge that state policy may dictate subsidized programs. However, there are practical considerations and challenges, and in some cases, the more palatable approach is to establish voluntary dedicated EV charging rates. In cases where dedicated and voluntary EV charging rates are established, regulators should consider adopting demand charges and dynamic pricing or some combination of innovative concepts rather than resorting to the “old technology” of static TOU rates.
2 NC Clean Energy Technology Center, “50 States of Electric Vehicles: 2017 Annual Review,” p. 9.