Utility funding for community resilience against fire-prevention outages doesn’t go far enough, microgrid groups argue.
California regulators have approved a microgrid plan directing $200 million to help communities build networks that can supply power through the state’s extended wildfire-prevention blackouts, a task expected to take years to move from planning to completing its first projects.
But private microgrid developers argue that the plan doesn’t go far enough to allow private investment to bolster resilience for this year’s fire season, or to meet the mandate of a 2018 law calling for tariffs to allow commercial microgrids to flourish.
The microgrid incentive program approved Thursday by the California Public Utilities Commission asks the state’s investor-owned utilities to identify the most cost-effective projects and the most vulnerable communities to be eligible for grants to set up “complex, multi-property microgrids.”
These are much more complicated than installing behind-the-meter batteries or backup generators, as an increasing number of California residents, businesses and critical facilities have been doing to deal with the public-safety power shutoffs that have left hundreds of thousands of people without electricity for hours or days at a time over the past two fire seasons.
Keeping interconnected grid “islands” energized amid broader outages requires specialized equipment, careful management of generation and loads, and technical expertise to maintain grid reliability. This small but critical portion of the total cost of building a microgrid is the target of the $200 million in incentives, which is expected to be spread across more than 15 individual projects.
It also requires utilities and microgrid operators to resolve a complex set of regulatory and operational challenges, from coordinating grid control responsibilities to agreeing on fair cost-sharing arrangements for the work involved.
But with the wildfire threat expected to grow as climate change brings hotter and drier weather, and with years of work and billions of dollars of investment in vegetation clearing, grid hardening and technology improvements still needed to reduce the threat of grid-sparked fires, utilities and regulators are under pressure to find alternatives for communities hit hardest by outages.
Slow progress on microgrid policy
That’s why the CPUC has focused its efforts to implement 2018 state law AB 1339, which mandated the development of commercial microgrid tariffs, on first providing solutions to this problem — so far without success.
The CPUC’s “Track 1” decision in 2019 focused on building microgrids for the 2020 wildfire season, a tight timeline that the state’s investor-owned utilities weren’t able to meet with cost-effective projects. Pacific Gas & Electric, the Northern California utility that last year emerged from a bankruptcy due to liabilities from wildfires caused by its grid failures, has ended up contracting for hundreds of megawatts of diesel generators to move from community to community as a stopgap measure.
CPUC’s “Track 2” plan approved Thursday takes some steps toward a more rapid pace of backup power implementation. Those include adjustments to interconnection and net-metering rules to allow behind-the-meter backup systems to be brought online more quickly and store more grid power. It also allows adjacent government buildings to build power lines to share backup power during outages — something that’s otherwise barred by utility codes.
But companies and communities pressing for more aggressive steps to implement AB 1339’s mandate argue that the CPUC’s actions have fallen short.
“We’re very supportive of vulnerable communities getting incentives for microgrid development,” said Allie Detrio, the chief strategist for consultancy Reimagine Power representing the Microgrid Resources Coalition, which includes many companies building microgrids in the state. “However, the CPUC could do a lot more for a lot more vulnerable and frontline communities by creating a robust tariff that properly compensates grid services and provides resiliency.”
The $200 million in incentives is a welcome step, but it’s unlikely to cover more than a fraction of the state’s demand for backup power, she noted. While it’s hard to predict how far the money will go, the California Energy Commission, the primary funder of the state’s advanced microgrid projects to date, has dedicated $84.5 million in matching funding to develop 20 projects across the state.
“This was a missed opportunity to leverage private-sector investment and capital, without substantial ratepayer funds,” Detrio said.
Microgrid tariffs: A work in progress
CPUC’s Thursday decision orders PG&E, Southern California Edison and San Diego Gas & Electric each to create a microgrid tariff that prevents cost-shifting for their territories. CPUC staff has proposed guidelines (PDF) for such a tariff, aimed at bundling payments for multiple distributed energy resources into a single utility rate structure.
But numerous thorny issues must be resolved in order to meet this goal. One of the biggest blocks for would-be microgrid developers is the lack of regulatory structures to allow them to provide grid services or transmit power between facilities under “blue-sky” conditions, or the vast majority of the time when the grid is up and running, Detrio said.
“Limiting the transmission of power to just ‘black-sky’ conditions takes away a big financial benefit,” she said. “Most customers will not invest in microgrids that are only for backup purposes. Energy savings and resource optimization are also important considerations.”
The Redwood Coast Airport Renewable Energy Microgrid, an $11.5 million solar and battery-powered project being built in Humboldt County, is serving as a test case for those variables. The 2.2-megawatt solar array and 8.8-megawatt-hour battery system provide about seven times the power needed by the airport, Coast Guard station and other customers it serves.
The Redwood Coast Energy Authority, the community choice aggregator that owns and operates the microgrid, is working on a hybrid solar-storage tariff (PDF), now being finalized by state grid operator CAISO, to sell the power on the wholesale market.
“When you get to multi-customer microgrids — sort of like the pilot in Humboldt County — the responsibility of the utility and the microgrid operator have to be thought through,” said Ed Smeloff, director of grid integration at advocacy organization Vote Solar. Beyond the complex arrangements needed to compensate for microgrid power sold onto the grid, “there’s also the issue of the rate charged to the customer behind the point of common coupling.”
PG&E’s plan to institute a Community Microgrid Enablement Tariff (PDF), which would set terms for sharing costs and responsibilities between the utility and third-party microgrid owners, will be merged into the $200 million incentive program.
Fossil fuels vs. renewables, centralized vs. distributed power
Meanwhile, the CPUC and clean energy groups agree that PG&E shouldn’t be allowed to use mobile diesel generators to back up communities for any longer than absolutely necessary, given their air-pollution impacts. Thursday’s decision sets up a process to find ways to “transition to clean temporary generation in 2022 and beyond,” potentially by using alternatives to diesel such as hydrotreated vegetable oil.
But it’s not clear how to replace fossil-fueled generators, which provide the most stable source of backup power, with alternatives that fit into California’s goals to reduce its greenhouse gas emissions. Building the scale of solar and batteries to provide megawatts of power for more than several hours at a time may prove too costly.
Distributed solar and storage systems, like the batteries receiving state funding under California’s Self-Generation Incentive Program, could be linked into broader networks, which could be a focus of the projects seeking funding under the $200 million program.
But this kind of coordination of multiple behind-the-meter resources with central grid generation and controls is still the realm of tightly controlled utility pilot projects. Simply using the remote disconnection capability of already deployed smart meters to isolate backup-power-equipped customers from the grid, a first step in this type of coordination, will require a pilot project to implement, as laid out by the CPUC’s decision.