More than 40 electric industry professionals, regulators and academics joined this week’s EnVision Forum, sponsored by FERC and Virginia Tech. The two-day event — held virtually because of the COVID-19 pandemic — explored the “bold visions, novel theories and creative partnerships” needed to address the “innovations and limitations that are driving what’s next in [the] energy future.”

FERC Commissioner Neil Chatterjee took a lead role in organizing the conference, as he did for the first conference in 2019. (See Overheard at EnVision Forum.) Expressing optimism for the future of the North American energy grid, he nevertheless warned attendees that the challenges on the horizon leave no room for complacency.

“We have the momentum to make huge strides modernizing our energy systems and creating a cleaner, more reliable grid to power the future for the next generation,” Chatterjee said. “But to be done effectively, big changes require everyone to be rowing in the same general direction. … We may not agree on everything. In fact, we most certainly will not. But we can agree on the challenges we need to tackle and begin to pivot and face them together.”

Here are some more highlights from the event.

Hurdles Ahead for Renewable Integration

In a panel on “Electrical Energy Systems of the Future,” participants expressed excitement about the potential of new technologies to improve the efficiency of the grid. However, they also warned that system operators, planners and regulators are far from ready for their full adoption.

“We’re seeing a wealth of new technologies finally becoming more economical … from microgrids, to distributed renewables, to distributed energy storage, to things like electric vehicles and smart homes,” said Ben Kroposki, director of the Power Systems Engineering Center at the National Renewable Energy Laboratory. “The challenge is, how do we get all of these things to work together in a large, cohesive way so that we can make sure that we’re creating the most intelligent and reliable power system and taking full advantage of all these distributed assets?”

Jill Anderson, senior vice president of customer service at Southern California Edison (SCE), provided a ground level view of the challenges of these rapid technological changes. Simply charging electric cars, for example, poses a major headache for utilities that are used to assuming that their customers’ energy needs can be counted on to stay in one place.

“We’re going to have all this demand coming from devices that are not even stationary. … You can charge your car at your house one day and [at] the local grocery store the next day. And as a utility, that’s going to make load forecasting a lot more difficult,” Anderson said. “It’s going to require … very sophisticated tools for us to be able to … model such a dynamic demand, along with an increasingly dynamic supply coming from the intermittent resources” like wind and solar, along with battery electric storage systems.

In addition to preparing the grid for new pressures from the customer side, Anderson said utilities can also be proactive about researching and implementing new technologies to lower bills or improve reliability for consumers. For the latter case, SCE is actively pursuing the installation of distributed energy resources like rooftop solar and battery energy storage systems; the utility is seeing “3,000 to 4,000 new solar connections every month in Southern California” and expects the amount of storage systems deployed in its territory to grow by 50% this year.

CAISO CEO Elliot Mainzer continued this theme, saying that 2021 seems poised to be “the big debut for energy storage on the California grid,” with about 2,000 MW of batteries operating on the grid this summer. However, he also amplified Kroposki’s warning that a lot of work lies ahead in integrating all these technologies into a functional whole.

“I think the evidence … at this point tells us that we really haven’t yet lined up on technology, economics and regulation to fully unleash the capabilities of those resources,” Mainzer said. “And we’re spending quite a bit of time working with utilities in California that are really looking at that whole chain of activities, from interconnection to the capacity price, [trying] to figure out where is the friction in the system [and] what’s the business model that really unleashes those capabilities?”

Prepare for Resources’ Behavior Quirks

Another tipping point for the North American grid is the rapidly shifting energy mix, led by concerns about climate change and the falling price of renewable energy. With these new resources displaying their own unique behaviors, utilities will need to adapt quickly or risk the kind of instability that fueled February’s winter crisis in Texas and the Midwest. (See ERCOT was ‘Seconds and Minutes’ from Total Collapse.)

“I think the biggest problem is going to be recognizing that 1,000 MW of wind is not equal to 1,000 MW of solar is not equal to 1,000 MW of gas. The capacity factors are all different,” said Bob Cummings, formerly NERC’s senior director of engineering and reliability initiatives, and now president of Red Yucca Power Consulting. “Load balancing is going to have to be done on an instantaneous five-minute basis, and you’re going to have to know everything there is to know about all those … intermittent resources.”

Matthew Gardner, director of system protection at Dominion Energy, emphasized that the operation of these assets is still not fully known, particularly under the wide variety of conditions that may be found on the grid.

“We need to awaken to the fact that we’re not going to be able to simulate our way into the future; we really need to pivot and start to focus on pulling in rich data sets and leveraging cloud computing for planning the future grid,” Gardner said.

“Some of the advancements that we’ve made in the enterprise business intelligence space [are] not necessarily portable to some of the technology and data sets that we’re talking about in the grid space,” he added. “There still is room for improvement in terms of [developing] the full stack of technologies that we’re going to need for the future.”

Vehicle Charging Vexes Grid Planners

In a panel on vehicle electrification, Chris Nelder, manager of the carbon-free mobility practice at the Colorado-based Rocky Mountain Institute, warned that the charging resources needed for a large-scale deployment of electric vehicles are far different from garage chargers at home.

Most charging today is done at home because early adopters of EVs mostly live in single-family homes with a garage and a place where they can plug in reliably overnight. But in the U.S., between one-third and one-half the population do not. Those customers will need chargers too, including dedicated parking spaces.

The thought of installing charging stations in every parking lot may be daunting enough, but this challenge pales in comparison to those required in future for cars, buses and tractor trailers.

Level 2 charging systems installed in homes come in ranges of 3 to 8 kW, most often 6 to 7 kW, and require hours of charging. They are best for managing load based on rates and demand levels.

“For that kind of load, you can do what we call managed charging,” Nelder said. “You can turn the charging up or down depending on grid conditions. You can respond to a demand response event. You can moderate your load if you’re trying to deal with, for example, an employee parking lot full of level 2 chargers and you want to avoid or mitigate demand charges. When you have [a group of vehicles] plugged in for hours and hours at a time, you can do that.”

Level 3 chargers, also called direct current fast chargers (DCFC), are being built in sites with a capacity of up to 350 kW — the idea being “to show up, get the fastest charge you can … and then go on with your day.”

However, “doing managed charging with DCFC is sort of antithetical to the use case. You can’t easily ramp power demands up and down. [So] with DCFC, you really can’t [do managed charging] unless you’re also deploying a significant battery array next to the fast charger and using that to pull power to, for example, avoid adding to the load during a grid peak condition or to respond to a demand response event. But that lards up the site with a very expensive slug of [capital expenditure], and that has its own problems.”

Level 3 isn’t where it ends though, he said. “If you’ve seen a Tesla Supercharging site, you’ve probably seen a whole row of like six Tesla charges. Altogether those comprise about 1 MW of power demand. That’s significant, and it’s not cheap to provide that power. It’s not cheap to the site, and it’s not cheap to provide it for the utility either. So on an [operating expenses] basis, for those charging network operators, they are now running into serious problems with demand charges.”

As the electrification movement expands into medium-duty vehicles, such as buses, garbage trucks and municipal vehicles of various kinds, the charging needs to ramp up also. Depending on the type of vehicle, medium-duty vehicles may use charging stations as low as 60 kW. But as the attention turns to truck stops, semi-tractors could need on the order of 1.7 to 1.8 MW per vehicle.

Nelder said in a recent presentation to Minnesota Rural Electric Association he gave the example of one travel plaza in rural Minnesota with 10 diesel pumps for big rigs and 16 gas pumps for passenger vehicles.

“If you were to convert that one travel plaza over to fully electric at the same capacity, that one travel plaza would require 182.4 MW of power,” he said. “That is approximately 190% of the footprint of the entire electric cooperative in which that truck stop is [located].”

“I don’t think anybody has any idea how we’re going to do this,” he continued.  “We have a very significant scale coming at us that we are not in any way prepared to accommodate.”