Bankrupt California utility Pacific Gas & Electric has come under fire on many fronts for the scope and execution of its self-imposed blackouts last month. The blackouts will continue as the company pursues a decade-long grid-hardening project.
Electric utilities bear the solemn mission of keeping the lights on, but PG&E's intentional shutoffs leave customers to fend for themselves. That divergence from standard operating procedure poses a question for the embattled utility: How will it take care of its millions of customers who lose access to power when the risk of starting a wildfire gets too high?
The October fires and shutoffs inspired a flurry of commentary on how microgrids and distributed energy could save the day by localizing power production and allowing communities to operate independently of the fire-threatened grid. Though sensible in theory, microgrids must navigate a thicket of regulatory and logistical barriers before they can serve as an effective tool during California blackouts.
Greentech Media dug into what action, if any, PG&E has taken to build local grid resilience that softens the blow of its power shutoff strategy. Not much has happened yet, but the utility is doing more than the casual observer might realize.
PG&E does not operate any community-scale microgrids, though it is working on one in Humboldt County. But it recently built two "resilience zones" that provide temporary backup power in fire-prone Napa County towns, and it plans to scale this concept to 40 other communities.
Microgrids remain stuck between possibility and execution. The technologies that power them are mature and already at work in numerous privately located projects, but few utilities have actually built community-based grid controls. Other utilities have taken that initiative, however, and their early efforts could serve as models for PG&E as it grapples with the new era of regular shutoffs.
Solutions are coming
PG&E has addressed the wildfire crisis with a mixture of short-term and long-term actions. The power shutoffs tackle the immediate risk that grid equipment will start another deadly fire. The utility also launched a widespread wire-inspection effort and added networked reclosers to help isolate outages on the grid, allowing more targeted shutoffs.
As far as efforts to keep homes and businesses up and running during a public safety power shutoff (PSPS), PG&E has had one big idea: the resilience zone.
“The resilience zone is designed to be quickly isolated from the broader electric grid when a PSPS is initiated and to receive power from temporary mobile generation connected to a new pre-installed interconnection hub,” the utility stated in an April update on what it deemed an “innovative concept.”
PG&E has completed two resilience zones, in the Napa County towns of Calistoga and Angwin; both operated during the earlier October shutoff. In Calistoga, the zone kept the downtown business district powered up, while the one in Angwin energized a fire station, a gas station, a medical facility and a student housing block.
Those two are pilot projects. The Angwin site tested a smaller community system, whereas Calistoga covered a larger footprint with more substantial energy needs. Going forward, the utility will select locations for resilience zones by studying historical weather patterns, talking with communities to identify their needs, and looking for feasible sites that are particularly remote or likely to suffer longer outages, spokesperson Paul Doherty said in an email last week.
"PG&E intends to develop 40 resilience zones/temporary microgrids using the selection criteria stated above over the next three years to help reduce PSPS impacts," Doherty said.
These projects are part of the general rate case filings PG&E submits every three years. Grid wonks may be interested to know that the wires upgrades and new equipment installed for a resilience zone count as capital investments and therefore earn a regulated rate of return. The fuel costs and labor to operate the resilience zones count as an expense, which does not generate profit for PG&E.
As for permanent multibuilding microgrids, PG&E kicked off its first attempt in January, Doherty said. The company is working with local stakeholders to build a microgrid near Arcata, Humboldt County to back up 18 customers including the local airport and Coast Guard station. The program won grant funding from the California Energy Commission and will feature solar generation and EV charging backed up by a 2-megawatt/8-megawatt-hour battery.
The value of "temporary microgrids"
When people think of microgrids, they typically refer to permanent equipment that allows a local area to produce, store and control its own electricity.
But PG&E's resilience zones offer local control on a temporary basis. They rely on the utility to mobilize and deliver generators and fuel in the event of a shutoff. That creates operational risk, adding to the utility's to-do list in an already stressful time.
Indeed, the rollout of the Angwin resilience zone during the shutoff proved "somewhat problematic," according to a report by county governments, citing the local fire chief.
"It appears that PG&E initially directed power to Pacific Union College, which has its own co-gen plant and therefore did not need the power," the report states. "Napa County understands that it took over an hour for PG&E to correct the error and supply power to Angwin's fire station and the rest of the resilience zone."
Actual wildfires, the risk of which would prompt the shutoff in the first place, could interrupt the shipment of generators and their fuels into fire-prone territory.
But, Doherty said, the impermanent approach allows PG&E to provide backup power to a larger swath of its 70,000-square-mile territory.
"Stationary generation resources would result in less flexibility, as the ability to move such resources around the system would be highly unfeasible, and they may not be appropriately sized for all locations," he said. "Furthermore, temporary generation resources can be brought in as needed, and with advanced warning typically seen with these types of wind events, PG&E can stage these generation resources where and when it is required."
For the same price of a few microgrids, PG&E can develop many more "temporary microgrids," he added.
Moving beyond diesel generators
PG&E's mobile generator concept differs from the new wave of high-tech microgrids popping up around the country.
Indeed, utilities have been using portable diesel generators to respond to emergencies for decades, said Mark Feasel, who leads the microgrids business at Schneider Electric. It's "tried and true" technology for when extreme weather knocks out power lines.
"It should be part of a stack of potential solutions...deployed," he said. "But there’s no elegance about it; there’s no leveraging new technologies."
Elsewhere, new technologies are helping other companies overcome the considerable upfront expense microgrids impose for the difficult-to-measure value of backup power.
The falling cost of solar panels and lithium-ion batteries means that microgrids can generate power every day, in a way that would not be economical with a diesel backup generator. Revenue from regular power production or battery operations can buy down some of the cost of the backup power. Sophisticated cloud computing also replaces some of the edge computing that drove up costs in the past, Feasel noted.
Companies like Schneider Electric now offer microgrids as a service, which gives a customer backup power without having to buy the equipment outright. The local government in Montgomery County, Maryland used this approach to back up its public safety campus — and boost clean energy in the process.
"The technology...and the business models exist in a non-regulated environment to achieve these things today," Feasel said.
Private citizens or businesses are free to invest their own money in home solar, batteries and generators. Low-income residents in fire-risk zones can access $100 million in state grants for that purpose. And local governments and businesses can install equipment behind their meters, too.
"We don't have time for five-year pilots — we just need to do projects," said Mike Murray, founder and COO of microgrid controls company Ageto Energy.
Communitywide microgrids implicate PG&E's wires, though, and thus have to navigate utility bureaucracy and the regulatory process. The regulatory record on this topic is nascent compared to renewables or storage on their own. The California Public Utilities Commission only launched a formal microgrids proceeding on September 19; opening comments were due October 21.
"It’s really hard for innovators to do business in California," said 38 North Solutions chair Katherine Hamilton, who advocates for companies and coalitions working on grid resilience. "The rules are so complex, you basically have to be in CPUC all the time to understand all the nuances."
She said she hopes the new process, prompted by a law passed last year to help the commercialization of microgrids, will clarify some of the opportunities.
One issue for regulators to sort out is how much ratepayer money utilities should use for local microgrids. Regulators could see such investment as a cost shift from customers as a whole to those who live in fire-prone areas.
Another subject to address is the tension between carbon-emitting diesel generators as a climate adaptation strategy and California's legislative mandate to clean up the grid.
"We have to be careful we don't position microgrids as a panacea," said Jake Levine, a clean energy policy expert at law firm Covington & Burling in Los Angeles. "We also have to keep driving forward on wildfire-mitigation efforts, refocusing utility incentives toward safety, and continuing to prioritize investments in zero-carbon electricity so as to address the core issue, which is a changing climate."
Microgrid lessons from other utilities
Elsewhere in the realm of regulated utilities, several of PG&E's peers are proactively building high-tech microgrids to counteract unpredictable blackouts.
For overcoming challenging circumstances, it’s hard to beat Duke Energy’s effort to power up a communications tower in Great Smoky Mountains National Park. Maintaining a grid connection to the isolated outpost became so difficult that the North Carolina utility tried something completely different: It airlifted a long-duration zinc-air battery onto the mountaintop and hooked it up to a solar array back in 2017. Now the site operates independently of the broader grid.
That Mount Sterling system is tiny — 10 kilowatts of solar capacity with a 95-kilowatt-hour battery. But it could serve as a model for the numerous state and national parks within PG&E’s service territory. Lacking microgrids of their own, several of these parks had to shut down service during the October power cut.
Duke Energy now is building a solar and storage microgrid to keep the lights on in the 500-person mountain town of Hot Springs, North Carolina. When not needed for local backup, the 4-megawatt battery will deliver grid services for the bulk power system. Last month, Duke applied that strategy — building local resilience where the equipment can also serve broader grid needs — to propose battery backup at a county emergency command center in South Carolina.
Farther north, Eversource New Hampshire asked regulators for permission to build a 1.7-megawatt/7.1-megawatt-hour battery to protect the 1,700-person town of Westmoreland from frequent storm-related outages. Instead of building a redundant line that would still be vulnerable to falling trees, this utility wanted to give the town its own localized power source.
Also up north, Vermont's Green Mountain Power used a network of thousands of batteries in customers' homes to keep 1,100 houses powered up during a statewide outage last month.
These examples and others show that regulated utilities are finding ways to address the concerns PG&E articulated about the expense of resilient infrastructure and the challenge of designing it to sustain a prolonged outage. The utilities typically achieve this by using the system for other services during the vast majority of the time when no blackout is in effect. That takes the pressure off the backup use case alone to justify the return on investment, assuaging concerns about helping the local community and not the broader population.
Notably, those other utilities chose to take this approach for outages caused by the vagaries of weather. PG&E intends to cause blackouts before the vagaries of weather turn dangerous. That direct causal role could create more of a social expectation that PG&E proactively build local resilience where it takes away grid power.
Some help is coming. The question now is how soon those 40 projects arrive — and whether the "temporary microgrid" approach is up to the daunting task of coping with an uncertain grid.