3 steps for utilities to proactively manage an influx of electrification

3 steps for utilities to proactively manage an influx of electrification
By Owen Goldstrom, Maria Scheller, and Surhud Vaidya
Feb 23, 2024

For electric utilities across the U.S., electrification is the proverbial double-edged sword. On the one hand, the promise of load growth could drive increased sales and capital investments. On the other hand, existing distribution networks are feeling the strain from rapid and uneven peak demand growth. This growth comes mainly from widespread electrification of transportation and heating sources, as well as growing demand from data centers, resulting in potentially negative impacts to system safety and reliability.

Are existing utility processes sufficient to capture the spatial and temporal characteristics of electrification? Do they prioritize grid upgrades needed to ensure reliable operation? This article covers the three key steps utilities need to take to proactively manage electrification, which can be much less visible and harder to project than data center demand growth.

  1. Measure electrification impact.
  2. Undertake load management strategies.
  3. Implement targeted grid upgrades.

In recent years, several studies have quantified the stark implications of the adoption of electric vehicles (EVs) and building electrification. For example, NREL’s Electrification Futures Study found that aggregate U.S. peak electricity demand could grow from 717 GW in 2015 to between 838 GW and 1,111 GW by 2050.

The Inflation Reduction Act (IRA) and the Infrastructure Investment and Jobs Act (IIJA) as well as local level actions (for example, bans on new natural gas hook-ups) will likely accelerate electrification, especially of transportation. But utilities may not always be aware of when new loads are added to the distribution system.

Residential customers often have no obligation to inform their utility when purchasing or charging an EV, while the usage of public chargers can be hard to predict. Utilities may find themselves in a reactive posture, pursuing load growth across their distribution systems as it materializes. Similarly, utilities may find it difficult to predict the location of medium and heavy-duty EVs that comprise fleets. The power drawn by medium- and heavy-duty vehicles is several times larger than that of a typical residential light-duty EV.

Delays in being able to assist in a customer’s electrification journey could lead to dissatisfaction, concern from regulators, and increasing operational violations of existing distribution equipment. Hence, the key questions for utilities are: where, how, and when electrification will impact electricity usage—and whether existing utility distribution infrastructure can accommodate new load.

Measure electrification impact

To answer these questions, companies could employ both top-down and bottom-up analysis methodologies. Both types of approaches could help utilities prioritize infrastructure upgrades to areas of the electric distribution system that urgently need them, as well as estimate costs for these investments.

While top-down approaches may require less granular data and generally entail less complexity compared to bottom-up methods, the choice of analysis depends on several factors, and most importantly, the questions the utility is trying to answer. At a high level, both types of analysis follow a relatively similar approach, starting with accurate projections of the adoption of EVs and appliances such as heat pumps in their respective service territories. These projections can aid in building an understanding of the temporal and locational characteristics of new loads, so that new infrastructure can be right-sized.

Using a top-down methodology to estimate the grid impacts of rising 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%, respectively, over a 30-year period. The results of this analysis showed that under a high electrification scenario, the utility would need to invest over $15 billion by 2050 in order to add 300 new substations and 700 new circuits to safely accommodate load growth.

Figure 1 shows the hourly load profile (inclusive of distributed energy resources (DERs), such as solar photovoltaics) of a single transformer bank substation at this utility on a typical winter day. As shown in the chart, the load shape changes gradually, as the impacts of EV charging and home heating use become pronounced in the early morning and late evening hours.

Overloads start to materialize in 2030 and increase in magnitude thereafter. In 2030, strategies such as managed charging may prove effective at shaving EV charging peaks and ensuring that the substation operates within the guardrails of its thermal limits. However, such measures are unlikely to prove effective in later years as the pace of electrification quickens. By 2050, and absent load management solutions, the peak load is projected to be nearly three times the substation’s rating and has grown by ~240% relative to a 2021 baseline.

Undertake load management strategies

Rapid load growth and stressed infrastructure is not inevitable. Armed with information on which circuits and substations are likely to be overloaded, utilities can use various techniques—including managed charging, time of use rates, and flexible load management—to help shape the load. Utilities could also assess the feasibility of targeting specific customers, or clusters of customers through programs to adjust their loads in alignment with the timing and location of grid needs.

These programs can use a portfolio of behind the meter DERs in a cost-effective manner to manage peak loads from electrification and delay the need for new infrastructure investments. While the datasets required for the analyses that underpin such programs would necessarily be richer in their spatial and temporal granularity, the good news is that several companies already possess this information by way of smart meter deployments.

For another utility client, we used proprietary algorithms to discern EV charging from premise–level hourly advanced metering infrastructure (AMI) data. We found that EV charging events led to peak loads (for residential customers) that were approximately four times those of non-EV peaks (for example, from the use of appliances in the evening hours). As seen in Figure 2, it is observed that a residential customer’s load repeatedly spikes in the hours just after midnight. Such patterns are consistent with overnight EV charging.

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Implement targeted grid upgrades

By having this data at its fingertips, a utility could quickly identify areas for grid reinforcement and evaluate the need for new programs or incentives to shift EV charging behavior. They can execute bottom-up grid analyses, drawing on various data streams (smart meter data, customer information, and prior DER deployment, among others) to assist in forecasting, planning for, and managing DERs and load growth on their systems.

The implications of the growing electrification trend are clear. As loads begin to exceed the ratings of the distribution system equipment designed to supply them, utilities may find themselves chasing electrification clusters where grid capacity is insufficient to accommodate new load.

Delays in attaining electrification goals are likely to be viewed unfavorably by customers and regulators. Nonetheless, the tools and processes are available today for utilities to execute electrification strategies and maximize the value to customers from electrification trends.

Rather than reacting to seemingly arbitrary pockets of load growth, utilities could project where and when future electrification loads and impacts will arise. The data could also be used by utilities to create hosting capacity maps, so that 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.

Estimating the future magnitude of electrified loads and their temporal and spatial characteristics is of vital importance to utilities. Developing an understanding of these needs is essential to meet customer and societal objectives, and subsequently planning and executing distribution grid upgrades and expansions.

Electrification is growing. Robust analytical approaches are an essential step to ensuring that the impending electrification of vehicles and buildings is a boon for utilities amidst years of declining load.

Meet the authors
  1. Owen Goldstrom, Senior Energy Markets Consultant
  2. Maria Scheller, Vice President, Energy Power Markets
  3. Surhud Vaidya, Lead Energy Markets Consultant
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