Utility involvement in developing EV charging corridors is somewhat controversial, as retail groups and regulators look to ensure a competitive environment for private investment. Nevertheless, utilities have a key role to play in siting and managing the upcoming expansion of EV charging infrastructure and the additional peak load that infrastructure creates.

What’s Happening

The Department of Energy and Department of Transportation are set to disperse $5 billion to states to support the addition of 500,000 EV charging stations. This is linked to aggressive goals for electrification of the transportation sector. EV sales continue to grow at a modest pace, but the Biden Administration has set a goal of increasing new EV sales to 50 percent of all cars sold by 2030. Many utilities have recognized the opportunistic problems related to the EV shift and have filed transportation electrification plans with utility regulators.

Why it Matters

In addition to the half a million units expected to be installed as part of the federal funding package, private investment is expected to significantly add to that figure. Even if many of the units are 150 kW -- a size at the low end of charging speeds demanded by consumers – the charging infrastructure in place by 2030 could add 75 GW of potential peak demand. (This is without including the corresponding expansion of residential chargers.)

To effectively manage this rising demand, distribution utilities bring experience gained from balancing large commercial loads that can be applied to managing charger networks. Additionally, the ability to apply the software management solutions that can be run in conjunction with smart grid technologies and grid edge sensors allow utilities to gain insights about how consumers use EV charging at home, while offering incentive programs for charging off peak.

What’s Needed

Analytics using AMI and sensor data can now be used to determine the numbers and usage patterns of chargers. But as residential chargers become more ubiquitous, real-time data and grid-edge control will be needed to balance peak load. It is crucial that utilities are involved in planning and siting public charging infrastructure that is grid connected. The power requirements of public chargers are estimated to rapidly increase over time, with the potential to cause significant variations in load throughout the day.

As public and private charging networks grow, the challenge for utilities is that proprietary software, apps and controls from many smart charger vendors do not always integrate well into utility systems. Furthermore, there may be a requirement for charger management software to have multitenancy capabilities, allowing utilities to share data or access with retailers, system operators or generation utilities. To smoothly integrate these requirements, existing standards will need to develop guidelines for software integration.