While California is home to some of the largest U.S. metropolitan areas, the state includes many smaller communities tucked into remote mountain and desert locations. Greenville—the town largely destroyed in August’s Dixie Fire—had a population of 1,129 in 2010, and that’s actually large compared to others in the area. Often located at the end of long transmission lines, these towns represent unique challenges to electric utilities during fire season. Local, renewably powered microgrids are now being considered as an alternative that could reduce related costs and risks.
A challenge for utilities is that transmission lines and related equipment can spark fires. Lines can be blown down by high winds common during fire season, and trees can be blown down against them if vegetation management programs don’t maintain proper clearances. Both situations have caused numerous fires within Pacific Gas & Electric’s (PG&E) service territory and have proven to be fodder for the lawsuits that forced the utility into bankruptcy. A tree falling against a remote line is suspected to have caused the Dixie Fire—a stretch of line that, coincidentally, had been targeted for burial.
A second issue remote connections raise is the expense of rebuilding them should the lines, themselves, be burned. According to PG&E’s website, new overhead lines can run $800,000 per mile, while undergrounding those lines can cost upwards of $3 million per mile. Both can prove to be costly investments if they’re only going to serve a community of a few hundred people.
Some utilities are looking at small community microgrids to bring power to remote customers instead of replacing destroyed lines. This is less expensive upfront, and removes the need to maintain a reconstructed line.
PG&E took this approach with a new installation in Mariposa County, near Yosemite National Park. There, the five metered customers—two homes, a visitor information center, a transportation facility and a telecommunications facility—had been getting their electricity from a temporary diesel-fueled generator since the October 2019 Briceburg Fire destroyed the 1.4-mile line connecting them to the PG&E grid.
In April, the utility flipped the switch on a new, largely containerized system called SolarContainer from BoxPower, a Grass Valley, Calif., a startup selling microgrids developed out of research conducted at Princeton University. The system’s design brings together solar panels, battery-based storage and a backup propane generator. The panels are mounted on the system’s shipping container, where the batteries and generator are stored. The Briceburg setup has an additional ground-mounted solar array, as well. The utility claims up to 89% of the system’s annual production will come from the solar system, which is certainly a significant environmental improvement over the previous diesel generator.
PG&E also hired BoxPower to maintain the system, though both companies can control it through cellular or satellite connections.
This isn’t a one-off effort, either. The utility’s 2021 Wildfire Mitigation Plan identified hundreds of areas where the microgrids could be installed, and it has established a target of 20 installations by the end of 2022.
Another California electricity provider has been more proactive in adopting remote microgrids, deciding such a system could reduce needs for line hardening in a particularly hard-to-reach location during the fire season. Instead of hanging new insulated conductors and extensively clearing trees in the area, Liberty Utilities can simply turn the line off for the six months when risks are highest, thanks to its own new BoxPower system.
The customer was the Sagehen Creek Field Station in the 9,000-acre Sagehen Experimental Forest, an education and research facility run by the University of California, Berkeley. It’s located in the Central Sierra Nevada, north of Truckee, Calif. A 4-mile, 90-pole distribution line serves the facility, and local service provider Liberty Utilities was facing a $3 million bill to upgrade it to meet fire-safety needs. By avoiding those costs with the new microgrid, the utility expects to save $2 million over the system’s lifetime.
This project is designed to operate with 97% renewable energy, with a total of 20 kilowatts of solar capacity and 68 kilowatt-hours of energy storage and propane backup installed on-site. That will provide sufficient capacity for the utility to de-energize the distribution line from June through December. There’s also the possibility of making the site fully self-sufficient by adding more generation in the future.
About The Author
ROSS has covered building and energy technologies and electric-utility business issues for more than 25 years. Contact him at [email protected].