Keeping trees near electric wires trimmed back may not save those wires from damage in a hurricane or tropical storm if branches are flying and trees are uprooted outside a utility’s right-of-way, said ERCOT CEO Pablo Vegas. 

A big storm, with wind and rain, “can create an environment where trees can fall from outside of the right-of-way into it and create just as much damage,” Vegas said during an Aug. 7 online briefing on the grid impacts of extreme weather, hosted by the U.S. Energy Association. 

When Tropical Storm Beryl recently roared through Texas, “there was a lot of the vegetation outside of the utilities’ right-of-way that came into play,” Vegas said, “We’re starting to have conversations about ― how do we work more closely with homeowners who can see risky vegetation that could be compromising the electric infrastructure that happens to be outside the right-of-way?” 

Driven by increasingly frequent and disruptive weather intensified by climate change, discussions of grid reliability and resilience ― defined as the ability to bounce back after such events ― have become industry imperatives, regularly included at conferences and online forums like the USEA briefing. 

What’s new, according to Vegas and other speakers at the Aug. 7 event, is the growing power demand from data centers, and the opportunities and challenges it creates, all of which must be factored into plans for extreme weather.  

Rather than seeing data centers as passive load requiring firm, baseload power, Vegas looks at the massive new installations as potential grid assets that could help maintain equitable access to electricity for all customers. 

Backup generation at data centers, critical for ensuring 24/7 power, could be used for emergency demand management, he said. “We could lean on those customers and say, ‘Hey, we need you to disconnect from the grid for a short period of time. We need to you to use your local generation to alleviate the pressure, so that those who don’t have [backup power] will have adequate capacity to serve during this time of scarcity.” 

Andrea Staid, principal technical lead at the Electric Power Research Institute (EPRI), talked about the need to expand ideas about what “extreme weather” might mean as climate change affects all forms of power generation. 

“Extreme from a weather perspective might no longer be extreme from a system stress perspective when you’re thinking about the grid with increasing renewables,” Staid said. “Wind lulls and solar droughts … are extreme from a resource adequacy perspective, but not so much from a pure weather perspective.” 

EPRI researchers look at interregional transmission as one possible solution as renewable “resources become uncorrelated across larger spatial regions,” she said. “It comes down to data … just having a sufficient amount of data to really capture the [impacts] of these distributions when you’re looking at rare occurrences of both wind and solar droughts.” 

But Ravi Seethapathy, executive chair of Biosirus, an industry consultant based in Canada, countered that different approaches and strategies may be needed when a specific area is hit repeatedly with severe storms. “I’m not quite sure whether that interconnection all over the United States will actually help that area,” Seethapathy said.  

Resilience will need to be multilevel, he said, isolating and protecting certain sections of the transmission grid, using non-wires solutions, such as microgrids, for local reliability, topped off with better public awareness and education.  

“We have not been able to condition the public to take certain quick measures to manage [those storms],” Seethapathy said. “We are constantly on a 24/7, 365, by-the-minute kind of time frame … and maybe all these events are telling us, ‘You now need to be a little more resilient, by way of [changing] your daily practices.’ … 

“That’s the approach we’re advocating.” 

Managing Costs

The pace and cost of extreme weather events continue to rise, according to industry veteran David Owens, formerly executive vice president of the Edison Electric Institute. In the past three years, the U.S. has seen 66 major weather events causing more than $1 billion in damages. The total price tag, from 1980 to today, is $2.8 trillion, he said. 

Owens deftly summarized the challenges for utilities, regulators, grid operators and other industry stakeholders: “How do we mitigate the risk? And how do we, at the same time, not expose electric consumers to exorbitant costs? What are some of the technologies that we can employ?” 

Meeting future load growth will be expensive, “regardless of what happens with climate and extreme weather,” Staid said. Integrating extreme weather resilience into long-term planning for load growth could result in “only a small adder on top of a very big cost to make sure you can ride through these extreme heat events, these extreme cold events.” 

“We absolutely need to keep this extreme weather and climate change in mind, but if we plan ahead of time, it shouldn’t drive the cost up significantly,” she said. 

Seethapathy again said a shift in thinking and in relations between utilities and regulators may be needed.  

“We have got a system where the regulator [and] the utility have got a relationship and things are moving very slowly. Why are the costs so high? It’s because we are using the methodologies of 50 years ago,” he said.  

For example, undergrounding of transmission or distribution lines need not mean burying them four feet deep, Seethapathy said. “Cable protection” can be laid at ground level or “just shallow, below ground,” he said. Existing standards “are just out of whack with today’s times.” 

Lessons Learned

Joining Vegas on the USEA panel, CAISO CEO Elliot Mainzer and MISO Senior Vice President Todd Hillman talked about the lessons learned from previously unprecedented weather events like the 2021 winter storm in Texas, commonly called Uri, and the 2020 August heat waves and rolling blackouts in California.  

In the wake of 2020, California tackled resource adequacy ― ensuring it has enough power on reserve to cover emergencies ― with a vengeance. The state has kept existing generation online ― in particular, the Diablo Canyon nuclear power plant ― while adding more than 20,000 MW of new generation to the grid and “a pretty amazing fleet of lithium-ion batteries, now over 9,000 MW, managing that evening peak in tandem with solar,” Mainzer said.  

CAISO also leans on its Energy Imbalance Market, Mainzer said, “taking advantage of transmission connectivity across broad geographies.” EIM is expanding with new lines into New Mexico and Wyoming, and implementation of its voluntary day-ahead market ― expected to come online in 2026 ― will “offer even greater optimization,” he said. 

“The economics are very compelling, but it’s going to be the reliability benefits ― by reducing the need for energy emergency alerts, calming down the system and taking advantage of wide-area dispatch ― that I think ultimately will provide the greatest customer value,” Mainzer said. 

Hillman said MISO is following an “all-of-the-above” strategy, including its Joint Transmission Interconnection Queue with SPP, aimed at providing more interregional transfer capacity. The $1.8 billion package of projects is expected to go to FERC for approval “very soon,” he said.

Like CAISO, MISO also seeks to beef up its generation, with some of the 350 GW of projects ― mostly wind and solar ― in its interconnection queue, Hillman said. However, MISO’s attempts to set an annual cap on interconnection capacity were turned down at FERC in 2023, and the grid operator has delayed opening the queue for new 2024 applications until it sends a revised proposal to the commission. (See MISO: New Interconnection Queue Cycle to Wait on MW Cap Filing.) 

Hillman also spoke about a shift in thinking about risk parameters under way at MISO. With operations covering 15 states, “we’re looking at any and all resources, that they can stay online as long as they possibly can, despite the pressures on the system. But we’re also looking at what the real value of each asset is worth, what’s called accreditation. So, really, what are those values when you get into a risk situation?” 

The dayslong power outages of Uri notwithstanding, ERCOT has yet to focus on developing more interregional transmission lines. Rather, Vegas said, “we’re starting to look at other steps of voltage in our transmission system, stepping up from what we have today across Texas, a 345-kV system. [We are] starting to evaluate, could a 500- or 765-kV system with a strong backbone network built across the state provide added resiliency should we have isolated areas of intense issues that could come from things like weather events? 

“We think that there’s a lot of potential value to that kind of an infrastructure investment that not only supports resiliency but can also support the tremendous load growth that we’re all talking about too.” A new surge of solar and storage on the system also could help ERCOT ride through the traditionally high-risk times when solar power drops off the system during summer sunsets, Vegas said. 

“This may be the last year that we have real significant risk at solar sunset,” he said. “If we continue to see that trajectory by 2025 into 2026, we could see the summer risk period significantly mitigated because batteries are picking up some of the transition solar ramps as we see the wind come on in the evening.”