- Growing numbers of utilities will soon see electricity demand peak during the coldest winter months, highlighting the need for customer-side technologies and energy efficiency to keep the grid stable, according to new research from the American Council for an Energy-Efficient Economy (ACEEE).
- Electrification, including space heating, water heating and electric vehicle (EV) charging, could double or triple winter utility loads, according to ACEEE. A combination of aggressive demand-side management (DSM) resources, however, could help to slash peak loads by more than a third in some areas.
- Duke Energy could find up to 1,400 MW of targeted winter DSM in its North Carolina and South Carolina territories, according to a study by Tierra Resource Consultants. "It is a significant resource we can bring to bear, but it is clearly nascent," firm principal Tom Hines said during a recent discussion of ACEEE's conclusions.
Electrification is a key strategy to eliminating carbon emissions, but it also means utilities will need to add generation and address shifting load profiles. The collapse of the Texas grid, when faced with a historic cold snap, highlights the importance of the issue, according to ACEEE Utilities Program Manager Mike Specian.
Most utilities in the United States currently see peak demand in summer, to address cooling loads, but, Specian said that will change. Some utilities already face winter peaks, particularly in the Northwest but also in the upper Midwest, Vermont and parts of the Southeast, he said.
"Many states will trend towards becoming winter-peaking by mid-century," Specian said during an April 15 webinar discussing the study's findings. New England could become a winter-peaking region by 2040, he said, driven by residential space heating.
ACEEE's report concludes that as air conditioners and buildings become more efficient, summer loads may drop. And with natural gas furnaces being replaced with electric heat pumps, and solar production lower during the winter, grid stress during the coldest months will increase.
"And if something like a polar vortex hits ... you can wind up with a lot more winter electric load than there was beforehand," said Specian. "Sometimes on the order two to three times more. That's a challenge we are going to have to collectively figure out how to handle."
ACEEE considered a range of DSM measures in the study, including: home weatherization, residential smart thermostats, commercial advanced rooftop controls and energy information management systems, efficient lighting, water heating demand response, managed EV charging, load shedding through HVAC programs, and the installation of air source and geothermal heat pumps.
Summer and winter peaks are driven by different technologies, last different durations and are met by different fuels, warned Specian. That means utilities must adjust their approaches. "We need to be mindful that the solution set for winter peaking constraints is going to generally be different than mitigating summer peaks," he said.
ACEEE's report finds utilities and other DSM program administrators can mitigate winter peaks and constraints "by drawing upon and scaling up the few existing programs that specifically target winter peak demand reductions through energy efficiency and demand response."
In New England, ACEEE found a comprehensive package of DSM resources could reduce load peaks by 34.2% by 2040, while a business-as-usual slate of resources will only lower peaks 6.7%.
Duke Energy evolves into dual-peak utility
To address similar issues, Duke Energy undertook a winter peaking study associated with its 2020 integrated resource plan (IRP), according to Tierra Resource's Hines, who worked on that analysis.
The Duke study looked at winter peak energy efficiency and overall DSM opportunities in North Carolina and South Carolina. Duke is evolving into a dual-peaking utility, said Hines, as the penetration of grid-scale and distributed solar rises.
Duke is finding summer peaks "are not growing nearly as fast as winter peaks, in terms of net loads, due to the impact of solar," said Hines. "This is a great thing for clean energy, but is [also] a real emerging issue."
Duke's DSM programs "historically focused on summer peaks, because that's been their issue," said Hines. Today, Duke sees a gap of about 1,000 MW between its summer DSM programs and what those programs deliver in winter. And, the utility's IRP forecast a 2035 gap of about 1,200 MW between summer and winter peak solar generation, he added.
Hines touched back to the idea of adjusting existing resources.
"With all of the experience we have on summer DSM, don't throw out the baby with the bathwater," he said. "Look at how programs can be evolved, look for programs that provide both summer and winter savings ... It's clear, we need to start thinking proactively and building out some winter peak DSM."
The Tierra study found that by 2040, Duke could potentially provide 1,100 MW to 1,400 MW of winter peak targeted DSM, utilizing many of the resources ACEEE considered in its report.
"We did a lot of work thinking about what is coincident to winter peaks, and what are the drivers for customer interest in DSM programs," Hines said. The study looked at advanced rates, including critical peak pricing, time of use, workplace EV charging, and "bringing along some harder to reach segments," including mobile home residences where resistance heating is common and the structures are not efficient.
The study conclusions "confirmed the promising potential of combining innovative pricing and demand-management technology," Lon Huber, Duke's vice president of rate design and strategic solutions, said in an email.
Following the study, Duke Energy Carolinas and Duke Energy Progress each received regulatory approval and have implemented DSM programs leveraging smart thermostats, Huber said. Both utilities also plan to "pursue additional opportunities with stakeholders in both its Energy Efficiency Collaborative and as part of the soon-to-be-launched comprehensive rate design review."