Whether gas microgrids fit with California’s carbon-cutting and local air-quality regulations is far from clear, said Tim Victor, associate director of eMobility at Scale Microgrid Solutions.
His company is building a microgrid for transport company Quality Custom Distribution (QCD) in La Puente, California, that will combine 1.45 megawatts of rooftop and carport solar with 3 megawatt-hours of battery storage to cover most charging needs, as well as power needs for the site’s refrigerated warehouses. Scale also included a 1.5-megawatt gas-fired backup generator — but that’s for grid emergencies, not to run around the clock.
The project is “supposed to save them money in the first year,” Victor said, and will also allow the site to charge more of the 30 Volvo electric trucks it’s deploying than its current grid connection would allow. Scale will own and operate the microgrid on behalf of QCD.
California regulators have made some allowances for on-site generators to run during grid emergencies, despite the state’s stringent local air-quality mandates. But it’s less clear how regulators will deal with newly built projects that plan to rely regularly on running gas-fired generators, he said.
“I’ve heard both sides of the equation from customers. Some say, ‘All we care about is getting the trucks on the road.’ Others say, ‘if we care about our sustainability goals, we can’t just replace diesel with natural gas.’”
Companies choosing the gas-fueled on-site power option contend that they offer a better alternative to leaving truck-charging sites in grid limbo, which will result in years-long delays in replacing diesel trucks with battery-powered trucks.
That’s how Adam Simpson, chief commercial officer of Mainspring Energy, framed the choice. Its low-emissions linear generators supply 3 megawatts to Prologis’s Denker site to charge trucks and batteries, and the startup has more EV-charging projects in the works through its partnership with parking infrastructure services giant ABM.
“You have this gap where the utility told you, you can’t get power. You have the choice. You can wait for the utility for three, five, or seven years, and continue business as usual, and continue diesel emissions. That’s your baseline,” Simpson said. “Or you can do on-site power generation, with or without energy storage, and bring it in within your timeline, and do that very cost-effectively.”
Mainspring’s linear generators also have the ability to switch to lower-carbon fuels such as ammonia or hydrogen as those become available, he noted. “We can start today with what’s readily available and transition over time.”
The promise of alternative fuels relies on several unknowns, such as whether those fuels will become available in large-enough quantities and at low-enough prices to cost-effectively make the switch. The calculation of the carbon emissions impact of on-site, gas-fueled generation instead of utility power also relies on hard-to-predict factors, such as how quickly California’s utilities can achieve the state’s aggressive grid decarbonization targets.
Getting utilities and charging hubs on the same page
In the short term, however, the more pressing question is how utilities will choose to work with truck-charging sites that want to supply their own on-site power.
California’s utilities are eager to capture the electricity sales that large-scale EV charging will bring and may well be leery of seeing those sites supplant grid power with their own on-site supply.
In response to some of the EV-charging projects that Mainspring and ABM are working on, Simpson said that utilities have compressed three-to-five-year wait times for grid interconnections to about a year or so. He took that as a sign that utilities “do care about this growing load and being able to charge for it.”
On the other hand, California’s utilities are already under immense pressure to expand their grids to serve not just EV-charging hubs but increasing electricity demand from all classes of customers. That’s why, even though utilities would like to serve every electron of demand from their own grid, both they and regulators are pushing ahead with programs to align grid buildouts with customer-supplied power.
That’s one of the goals of the “flexible interconnection” programs being developed by Pacific Gas & Electric and Southern California Edison. The primary purpose of these programs is to allow large customers to use more power at times when grid capacity is available, in exchange for agreeing to throttle power use when capacity is strained.
PG&E’s first flexible interconnection customers include pilot projects at a Tesla EV-charging hub in the Central Valley and a PepsiCo facility in the Central California city of Fresno that has two Tesla megapack batteries to support the 50 Tesla electric semitrucks it’s deploying over the next six months.
As long as flexible interconnection customers stay within the utility-prescribed limits on how much power they draw from the grid hour to hour, it doesn’t really matter whether they do it by curtailing their charging loads or using their own on-site solar, batteries, or generators, said Alex Portilla, PG&E’s director of grid edge innovation.
In that sense, customers that can generate some power themselves are “both the challenge and the solution,” he said. PG&E wants to connect more EV-charging sites more quickly to increase electricity sales to a new class of customer, which reduces the burden on customers at large to cover the costs of the utility’s rapid grid expansions.
Victor of Scale Microgrid agreed that “flexible interconnection is a huge path forward. It’s a way for a utility to get access to a certain amount of energy consumption and still meet the needs of that customer.”
“The way I always pitched this when we started having conversations with utilities is to make sure they understand our goal is not to never come to you for more power, but to make it easier for you to plan this out,” he said. Outside of a handful of projects under the ongoing flexible interconnection pilot programs, “that conversation hasn’t progressed past the theoretical, but it seems to be generally welcomed.”
What’s needed, said NFI’s O’Leary, is clear direction from California utility regulators on how to standardize these kinds of cooperative approaches, to provide fleet operators like NFI more certainty in their planning.
“The most important thing from the fleet perspective, when we’re deciding when, where, and how we’re doing these projects, is to look at the total cost of ownership. We have to know how much it’s going to cost us to run that fleet,” he said. “The sooner the fleets have that information, the clearer our decisions can be and the clearer our conversations with customers.”
