For the Sake of Reliability, Utilities Need to Be Active Participants in the Coming EV Transition
- Aug 24, 2022 10:56 pm GMT
This item is part of the Electrification of Transportation - August 2022 SPECIAL ISSUE, click here for more
The transition to electric vehicles is growing at an exponential pace, and momentum is building for a 1500-percent increase in new EV sales over the next decade. In the same time frame, utilities prepare to retire approximately 84 GW of firm generation coal plants prompting energy industry experts to ask: Will the grid be able to keep up?
In its most recent long-term reliability assessment, NERC projected an average growth in peak demand of 1 percent over the next 10 years, while forecasting a decline in anticipated reserve margins in most of the country over that period. Pacific Northwest National Laboratory published a report in 2020 that analyzed the impact of adding 24 million EVs by 2028. The report concluded that the existing Western grid distribution system could handle that additional load, but higher rates of EV adoption would require managed charging solutions.
In the second quarter of 2022, EV sales accounted for 5.6 percent of new car sales vs 2.7 percent for in the first quarter of the year. The Biden Administration has set a goal of increasing that number to 50 percent by 2030. At the same time, many global automakers have announced plans to phase out internal combustion engines over the next 15 to 20 years.
What that means for energy infrastructure is still being assessed, but as this transition takes place it’s only logical that distribution utilities be at the forefront of the planning process.
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. Utility involvement in developing charging corridors is somewhat controversial, as retail groups and regulators look to ensure a competitive environment for private investment.
Whether utilities own and operate related infrastructure is secondary to the responsibility they have of reliably supplying the energy for banks of high-speed chargers. As such, they need to have a hand in overseeing the siting, load management and data sharing aspects of public chargers, and have more involvement in the installation of residential chargers moving forward – if for no other reason than to be able to handle the scale at which load requirements are changing.
A residential level two EV charger adds a load equivalent of three air conditioners or two electric water heaters. For utilities to adapt to this significant load, active engagement with consumers is a necessity. The development of new rate models and applications that give EV owners control and flexibility in meeting their charging needs, along with utility options for directly controlling loads when necessary, offers the best scenario for maintaining grid stability and building a new partnership with energy consumers.
In the case of public charging infrastructure, where 350 kW chargers are the becoming the preferred minimum size, the load equivalent more than quadruples. Consider that half a million units are expected to be installed by 2030 as part of this federal funding package, with private investment expected to significantly add to that figure. Even at a more modest 150 kW size, a charging network this large could add 75 GW of potential peak demand on the grid.
At minimum, utility involvement in building out charging infrastructure should include recommendations on charger location, access to real-time usage and metrology data to provide load management capabilities for ensuring the integrity of the grid.
Until recently, the only data available to some utilities regarding EV adoption in their service territories was motor vehicle registration data by county or zip code, which is not granular enough to determine the possible location of chargers on a substation, feeder or circuit. Analytics using AMI 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 prevent overloading during peak and balance loads throughout the day.
Regarding public charging infrastructure, it is crucial that utilities are involved in planning and siting any location 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. This means infrastructure from the charger all the way to the substation needs to be capable of handling peak load requirements. Data visibility and analytics are also required to monitor load and respond to potential issues before reliability is compromised.
Smart grid technologies are already being used to gain insights about how consumers use EV charging at home, while offering incentive programs for charging off peak. 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.
Many utilities already have programs and plans in place for managing large commercial loads. One example that may be applicable is how some rural utilities in farming regions manage geographically dispersed irrigation loads using demand response programs and load switching to ensure lowest cost of operation. For EV charging, most smart chargers have some level of load management and communication capabilities built in. However, for utilities to offer competitive rates for private charging banks – whether roadside, in industrial parks for fleet charging, or in multi-unit house complexes – they will need the ability to monitor and limit or shift load as necessary.
Fortunately, utilities have experience remotely managing system performance with the smart grid technology deployed over the last decade. The hardware and software solutions for EV charging management are already proven to meet requirements in Europe. The next step here will be ensuring all of the participants who need access to network data and control functions are plugged in at the start.
Many utilities have recognized the opportunistic problems related to the EV shift and have filed transportation electrification plans with utility regulators. Concurrently, state transportation departments are coordinating new partnerships with state energy offices, utilities, third parties, community-based organizations, and executive officials. Stakeholders recognize that harmonizing infrastructure, software, rates, carbon impacts, and grid stability requires thoughtful strategy, particularly to manage EV load better. The combined forces of market demand and policy incentives create an exciting opportunity to redesign the way we interact with transportation and the grid. The evolution of grid assets and software present infinite solutions, but choosing the right suite, at the right time, is – at least in part – up to the utilities.
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