U.S. utilities face a high-stakes paradox with electrification.
Between the transition to electric vehicles, building electrification, and growing demand for data centers, load growth is inevitable. And that means higher sales and more capital investments with a regulated rate of return for utilities. However, rapid, uneven, and unplanned demand could strain existing power systems, and ultimately compromise safety and reliability.
One study from the National Renewable Energy Laboratory found that projected electrification could cause demand to swell by up to 55% between 2015 and 2050.
Distribution networks will face highly localized challenges, including shifting usage patterns and higher loads, especially with recent legislation aiming to accelerate electrification, from the Inflation Reduction Act to city-wide bans on new natural gas hookups.
In some instances, utilities may even be unaware of new loads to the distribution system — residential customers often have no obligation to inform their utility when purchasing or charging an EV, for instance. So utilities may find themselves chasing and trying to accommodate load growth as it materializes, rather than planning for it in advance.
This reactive planning leads to a patchwork of costly, disproportionate solutions. Higher costs could lead to customer dissatisfaction, concern from regulators, and increasing operational violations of existing distribution equipment.
And some utilities may not have the visibility and responsiveness on their distribution network to remain flexible, proactively enable distributed resource connections and other electrification measures, and protect systems from violations that damage utility and customer equipment. However, there are clear steps utility executives can take to get on track.
The moment to measure
Questions abound as utilities prepare for increasing numbers of distributed energy resources and load: Where, how, and when will they impact electricity usage? Are existing grids able to handle those changes?
Utilities should prioritize answering these questions to both determine where urgent infrastructure upgrades are needed, and outline corresponding costs.
The place to start is accurate projections of distributed generation adoption, such as rooftop solar, EVs, and appliances such as heat pumps. These projections help utilities understand the time and location of load changes, which is necessary to plan for new infrastructure.
Via an estimate of the grid impacts of rising distributed generation and EV penetration and heating electrification for a northeast utility, ICF projected that the number of substations and circuits would need to increase by 50% and 38% over 30 years, respectively. By 2050, the utility is projected to need to invest over $15 billion to add 300 new substations and 700 new circuits to safely accommodate the growth.
Over the course of a typical winter day for the utility, a single transformer’s load profile changes gradually as the impacts of EV charging and home heating use become pronounced in the early morning and late evening hours.
But load additions affecting the system are not far off; this particular substation is expected to be over its thermal limit in all hours as soon as 2030. By this time, shifts in the usage pattern can already be seen with the effect of unmanaged EV charging in the evening. Over time, the load peaks become much more pronounced in the morning and evenings. Without load management solutions, by 2050 the peak load is projected to be nearly three times the substation’s rating, or 240% bigger than it was in 2021.
How to manage the load
Stressed infrastructure from rapid load growth is not inevitable.
If utilities know which circuits and substations are likely to be overloaded, they can use targeted techniques like managed charging, time of use rates, and flexible load management to help shape future load. Utilities can also target specific customers to adjust their power use to align with the grid’s needs.
These programs can use a portfolio of cost-effective, behind-the-meter DERs to manage growing loads and delay the need for new grid infrastructure. While the customer usage datasets required would necessarily be richer in spatial and temporal granularity than is typical today, the good news is that several companies already possess this information by way of smart meter deployments.
Our team’s analysis differentiated EV charging from premise-level hourly advanced metering infrastructure data and found that charging events led to peak loads for residential customers that were roughly four times as large as non-EV peaks (which come, for example, from the use of appliances in the evening hours).
The right upgrades
As loads exceed current infrastructure capacity, without proper planning and investments, utilities may end up scrambling to upgrade the grid to accommodate increased demand.
With new sources of data, a utility can not only identify targeted areas for incentives to shift usage behavior, but can also simultaneously consider areas for grid reinforcement. It can execute bottom-up grid analyses, drawing on various data streams — from smart meters, customer information, and prior DER deployment, among others — to forecast and plan for the changes to come.
Rather than reacting to seemingly arbitrary pockets of load growth, for instance, utilities can instead project where and when future electrification loads and impacts will arise. Analyzing new load patterns can inform strategies, including targeted grid upgrades, to accommodate inevitable growth.
Utilities can also use the information to create hosting capacity maps so customers and fleet owners can make informed infrastructure placement decisions. Load management strategies such as managed charging programs, flexible load management initiatives, and time-of-use rates may further help delay the need for new capital investments, especially at low EV penetration rates.
Effectively estimating the size of electrified loads is vital to understanding and meeting customer needs and societal objectives. Taking an analytical approach to prepare for growth ensures the electrification wave is beneficial to utilities and cost-effective for customers.
Maria Scheller is a vice president at ICF, focused on the power sector, and Chris Watson is a senior director at ICF, focused on electrification. The opinions represented in this contributed article are solely those of the author, and do not reflect the views of Latitude Media or any of its staff.
