Without enough utility power, California EV-truck depots try microgrids

Electric truck-charging sites across California face a choice: Wait years to get the grid power they need, or build their own solar, battery, or fossil-gas-powered microgrids.

Over the past few years, many of the state’s biggest truck-charging depots have chosen the build-your-own-power option.

These depots still need grid electricity, but now as a complement to their on-site power. The idea is to craft the fastest, cheapest, and cleanest combination to best meet the state’s decarbonization goals.

Striking that balance is hard. Historically, would-be ​“large-load” power customers like EV truck depots approach utilities with an all-or-nothing proposition — give us all the grid power we need, or we’ll build somewhere else. Utilities in turn are traditionally required to either make sure that their grids can serve these big new customers or deny their requests to interconnect. And both parties face complications when an on-site microgrid enters the equation. If the customers’ microgrid doesn’t perform as promised, for example, that might cause grid reliability risks for everyone else.

But as California’s utilities struggle to meet fast-growing demand for charging capacity to support the state’s aggressive clean-trucks mandates, pressure is growing to find solutions. State regulators are working on policies to speed up grid buildouts, but the trucking and charging industries fear that this regulatory push won’t move quickly enough to meet their short-term needs.

Right now, that means truck-charging microgrids present the best path forward for many operators in California — even with the complications.

Take the state’s biggest truck-charging hub to date, the Prologis and Performance Team warehouse on Denker Avenue near the ports of Los Angeles and Long Beach, which combines 6 megawatts of gas-powered generators and 18 megawatt-hours of batteries to charge up to 96 heavy-duty EV trucks.

That microgrid allowed the Denker site to open in May 2024, several years before municipal utility Los Angeles Department of Water and Power would have been able to expand the grid to serve it. And the benefits go beyond speed. ​“I’m looking at numbers that are very attractive compared to getting service from a utility,” said Henrik Holland, global head of Prologis Mobility, the Prologis subsidiary that installs and manages EV charging for its customers.

“It makes a lot of sense to put generation and storage at the grid edge,” Holland said. ​“We’ve been talking about it for 20 years, how the energy system is going to change from centralized to distributed, and be more bidirectional.”

How truck-charging microgrids can help 

On-site solar, batteries, and generators are already a significant and growing part of the U.S. power mix. When it comes to integrating on-site power with grid operations, ​“EVs are the use case for this stuff,” Holland said. ​“You’re dealing with very peaky loads, with time-of-use issues, with resiliency issues — because these trucks can’t be stranded when the grid goes out.”

Resiliency, along with charging costs, was a motivation behind freight operator NFI Industries’ decision to install a 1-megawatt solar array and 7 megawatt-hours of batteries at its Ontario, California, warehouse. That microgrid, set to be turned on later this year, will help supplement grid power for the 50 Volvo and Daimler electric big rigs that will be charging at the site.

NFI was lucky enough to have ample capacity from Southern California Edison’s grid for its Ontario site, said Jim O’Leary, the company’s vice president of fleet services. But it wanted to make sure that it could keep charging trucks in the event of grid outages, he said.

That source of backup power can also shave costs during normal operations.

High-voltage truck chargers can cause spikes in grid demand, which can trigger expensive demand charges. A microgrid like NFI’s can help keep those spikes in check and avoid those fees. The Ontario microgrid can also help NFI avoid paying the high time-of-use rates that California utilities impose during afternoon and evening hours when the state’s grid is under maximum stress, O’Leary said. Similar concerns about utility power costs have led a growing number of EV-charging sites to install batteries to cushion their peak demands on the grid.

But O’Leary conceded that the economics of its Ontario solar-and-battery microgrid rely on the $27 million in state grant funding the project received. ​“I’m not going to say every site can do what we did,” he said. ​“It’s not going to be realistic with those costs.”

Nor can solar and batteries provide enough power to charge electric trucks on their own — although they can help cover some gaps in grid supplies. That’s the route startup WattEV took to avoid grid shortfalls from derailing its large-scale charging site outside Bakersfield in California’s Central Valley, which opened in May 2024.

WattEV used a $5 million state grant to help finance 5 megawatts of solar and 3 megawatt-hours of batteries to provide some of its power needs. That site was also able to secure about 6 megawatts of grid power from utility Pacific Gas & Electric, said WattEV CEO Salim Youssefzadeh. But that’s a lot less than the 25 megawatts that WattEV had initially sought.

“The utility couldn’t supply that,” he said. ​“We split the project to have one side be fully grid interconnected, and have the other site be powered by solar and batteries.”

The cost and climate math on solar and batteries versus natural gas generators

One challenge with using microgrids to charge EV trucks is that it’s hard to avoid some reliance on fossil fuels.

Most truck depot sites lack the open space required to build solar arrays large enough to power batteries and chargers, Prologis’s Holland said. While some sites can find space for solar on warehouse rooftops or parking canopies, ​“it’s not going to be enough.”

“When it comes to heavy-duty truck charging, where you need 15 megawatts of charging, you’d need 100 to 150 acres of solar for that,” he said. WattEV’s Bakersfield site, for instance, had 119 acres of open land to host the solar arrays powering its batteries and chargers.

That’s why Prologis went with gas-fired generation for its microgrid on Denker Avenue, he said. ​“It’s demonstrated that we can get our power quickly. We built that in five months. It’s resilient, it’s reliable — but it also absolves us from time-of-use and demand charges.”

But time and cost savings are not the only relevant factor for those who operate EV truck depots in California — carbon emissions matter too.

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,” said Victor. ​“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 Microgrids 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.”