Where is the load, one year after COVID-19 shutdowns?

Where is the load, one year after COVID-19 shutdowns?
By Nick Turman-Bryant, Ali Bozorgi, Ph.D., and Steve Fine
Apr 14, 2021

The world changed last March when the coronavirus outbreak was officially declared a pandemic and the first stay-at-home orders were issued across much of the country. It wasn’t hard to hypothesize that the shift to working and living mostly within our homes would have a corresponding shift in the demand for electricity.

In our initial analysis published in early May 2020, we noted that not only did we see a shift from commercial to residential demand, but the scaling back or shutdown of some manufacturing operations resulted in a net decline in electric demand. But we cautioned that demand was “dropping, shifting, and still stabilizing” and we didn’t know where it was going next.

Here, one year out, we take another look at the trends in electrical load.

Lingering uncertainty

Uncertainty remains the watchword. Looking at the data from the past year (see Figure 1 below), it’s clear that we're neither back to normal pre-COVID levels nor are we at last year's level of full closure of businesses and buildings. It’s too soon to answer if this lower net demand represents a “new normal” or if we’ll eventually return to pre-pandemic levels.

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Impact of lockdown on peak demand

Overall, most states in our analysis followed the same general pattern of peaks and valleys. The weather-normalized data shows a big, initial dip in demand at the confluence of post spring break travel and the peak of stay-at-home orders for almost all states in our analysis. The primary exceptions were Florida and California, which both surged to pre-pandemic levels over the summer.

A second dip happened in October due to additional shutdowns triggered by a second wave of COVID-19 infections in the fall. The exception in this case was Texas, which saw a slight increase in demand over the same period. The demand dip was also not as pronounced in either California or Florida, which is hard to explain as the two states took very different approaches to their COVID-19 response. For example, Walt Disney World in Florida reopened in July 2020 as much of the state’s restrictions were lightened or lifted altogether. On the other hand, Disneyland in California isn’t scheduled to reopen until April 30 as the state imposed some of the country's toughest restrictions.

Our analysis also shows that residential demand across the regions analyzed is now only 2% higher than pre-pandemic levels (see Figure 2 below), compared with a 12% increase in April last year. The enormity of the shift in demand was most apparent in the PJM territory (all or parts of 13 states and the District of Columbia) and in New York. In the fourth quarter of 2020, Manhattan had the most available office space since the early 2000s. The situation looks to be stabilizing, with 300,000 city workers scheduled to return to the office in May. But overall the rebound in the commercial sector is lagging behind residential, resulting in an overall drop in net demand of roughly 5%.

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Impact of lockdown on different sector load percentages

Hybrid formats of remote and in-person work are likely, increasing uncertainty of what that will mean for load. In general, all heating and cooling systems need to be running no matter what percentage of people are in an office building. Although whether these systems can “take advantage” of lower occupancy is largely dependent on the sophistication of their sensing and control systems. As most buildings currently have more traditional systems, it is possible that the return to pre-pandemic commercial load—plus more people working at least a few days at home—could in fact lead to a potential net demand increase.

Ways to manage and mitigate uncertainty

DER technologies already play a role in helping utilities handle extreme weather events and natural disasters. They are also uniquely positioned to help utilities manage this post-pandemic uncertainty. This is true especially on the demand side where customers can influence their own electricity consumption. Presuming there will be an ongoing need for increased time spent at home while working, residential customers will increasingly demand reliable power.

Take for example the comprehensive pilot program ICF ran in the SMECO service territory to demonstrate the benefits of smart thermostats to utility customers. Beyond the energy savings at the meter from using each device, peak load also significantly decreased during demand response events while maintaining high customer satisfaction. For the company, the ability to accurately measure energy savings while satisfying customer expectations made flexible load management and a full roll-out of smart thermostats a win-win situation.

While increasing resiliency at home takes on greater importance, the return to office spaces is a prime opportunity for companies to go beyond the norm. Commercial buildings have always had more automated systems and emergency backup (e.g., diesel generators). As the push is on to improve ventilation and indoor air quality, could the larger deployment of truly “smart” buildings with localized temperature sensors and localized control of air movement be far behind?

Improving operational agility

The uncertainty around COVID-19 speaks to the need for increased business agility, particularly rapid adaptation and innovation to deal with unexpected events. From an operations perspective, utilities quickly instituted agile solutions such as remote work options, work pods, and safety measures to get critical staff back in the field, and improved control room operations.

COVID-19, of course, isn't occurring in a vacuum. Utility companies have had to manage through this era of uncertainty while dealing with the “usual” crises: fires, floods, hurricanes, and extreme cold events in locations across the country. The pandemic became one more area of planning uncertainty. While planning for climate resilience hasn’t always been at the top of the agenda, the increase in extreme weather and unforeseen events like COVID-19 is causing many utilities to take a more proactive approach. To modernize planning, utilities will need to understand their load at a more granular level and be increasingly conscious of the implications of extreme events on load and grid capacity—which is why our analysis is so important.

We ended our piece last year with many unanswered questions due to the nature of the pandemic’s rapid disruption of the economy and uncertain duration. It’s one year out and we’re still left with important questions:

  • What happens to load if we enter another COVID-19 wave?
  • Will the decrease in overall demand be a continuing trend or will we see a reversion to the past baseline?
  • For utility participation models, do we treat 2020 as an anomaly? Or is the historical baseline no longer relevant?
  • And how does that vary by region and in relation to individual state policies?
We help our clients stay on top of changes to the electric system by keeping a close eye on events that impact the grid, including February’s winter storm in Texas. We will continue to monitor the evolving pandemic and “new normal” for further analysis on load impacts.
Meet the authors
  1. Nick Turman-Bryant
  2. Ali Bozorgi, Ph.D., Senior Manager, Distributed Energy Resources Analytics

    Ali is a distributed energy resources expert with experience working on energy economic analysis and forecasting with advanced modeling tools and optimization to support our utility clients. View bio

  3. Steve Fine, Vice President, Distributed Grid Strategy + ICF Climate Center Senior Fellow

    Steve brings over 30 years of experience working at the confluence of energy, environment, and economics to evaluate and design workable solutions to our biggest energy challenges. View bio