California's big regulatory push to open a vibrant market for microgrids is running behind schedule and has not yet solved several key problems. The effort yielded no workable proposals for the 2020 fire season, when PG&E is once again set to rely heavily on diesel generators.
It's still not clear how third-party developers and communities will be able to build microgrids that provide local resilience while getting paid adequately for their services to the state's increasingly renewable-powered grid. But early missteps aside, the California Public Utilities Commission is pushing ahead on at least some of the work mandated by AB 1339, the 2018 state law that created it.
California is the U.S. leader in distributed solar, behind-the-meter batteries and electric vehicles, and it has one of the most aggressive zero-carbon energy mandates in the country. It's also facing a massive challenge in managing a power grid that's caused deadly wildfires. Microgrids could prove to be a critical tool for adapting its power system to all of these challenges, and how California manages that challenge could set an example for the rest of the country.
Next month, the CPUC is set to vote on a proposed decision (PDF) that will meet at least some of the law’s mandates for a regulatory framework to boost the commercialization of microgrids. The proposed decision will bring some short-term aid to third-party microgrids. 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, as well as new programs to boost utility-community cooperation on larger-scale microgrids.
However, the most challenging barriers to widespread microgrid development are yet to come. Those include thorny issues of sharing utility grid control across multiple microgrid users, how utilities will manage departing load charges for self-powered systems, and creating utility tariffs that can clarify how microgrids can earn revenues for the services they provide.
“Track 2 of the proceeding is intended to address those longer-term issues,” said Jin Noh, senior policy manager for the California Energy Storage Alliance. “But we haven’t made our way around to them because the CPUC is so focused on urgent 2020 needs.”
Interconnection, net metering changes
The CPUC’s proposed decision will prioritize several steps that could help boost behind-the-meter batteries for the upcoming fire season.
First, it orders California’s investor-owned utilities to create “standardized, pre-approved system designs for interconnection of resiliency projects that deliver energy services during grid outages” — specifically, solar, battery and solar-storage projects. Interconnection complexities and delays are a major headache for distributed energy resources, and utilities have made major improvements in those processes over the past decade.
Interconnection can be even more challenging for microgrids that combine multiple technologies behind a single meter. The CPUC’s proposed decision leaves them out, however, which is a disappointment to microgrid developers.
“Interconnection streamlining is great stuff,” Baird Brown, principal of consultancy eco(n)law and co-counsel of the Microgrid Resources Coalition, representing vendors including Engie, Eaton, Bloom Energy, NRG and Scale Microgrid Solutions, said during a Wednesday webinar. But, he said, “We have members that were ready to install the equivalent of a microgrid in a box,” which will have to wait for later decisions from the CPUC to get the same standardized treatment.
The proposed decision will also adjust net-metering tariffs for solar-storage systems to broaden their resiliency value. Those changes include allowing batteries to charge from the grid right before fire-prevention blackouts — not just from their associated solar panels — and requiring the state’s investor-owned utilities to remove storage sizing limits from its tariffs.
That’s a big deal for solar-storage systems at homes and businesses, including those funded under the state’s Self-Generation Incentive Program (SGIP), which is directing hundreds of millions of dollars toward wildfire resiliency for low-income and medically vulnerable communities.
But the CPUC’s proposed decision didn’t take the additional step of requiring all new net-metered systems to be capable of islanding themselves from the grid, said Ed Smeloff, director of grid integration at advocacy organization Vote Solar. That’s an oversight, considering how many rooftop solar and battery systems in the state have to shut down during grid outages because they haven’t been set up to run on their own, Smeloff said. “Why should we be doing something this fire season that can’t be islanded?”
Multi-user microgrids: A work in progress
The CPUC’s proposed decision makes much less concrete progress toward “multi-customer microgrids, which would typically use the distribution utility’s lines and other assets,” Smeloff said. “That’s a much more complicated issue."
Utilities are reluctant to allow privately operated microgrids to use their power lines or even cross utility rights of way. There are compelling reasons for that: Utilities are responsible for maintaining safe operations and are often barred by law from making concessions on that front. Still, this has largely limited today’s microgrid developments to individual buildings or campuses with their own distribution equipment.
Allie Detrio, chief strategist for consultancy Reimagine Power representing the Microgrid Resources Coalition, said in Wednesday’s webinar that a bill being considered for this year’s legislative session in California, SB 1215, could help overcome this barrier by allowing microgrids to cross intervening streets if they’re funded by state grants such as SGIP or the California Energy Commission’s EPIC program.
This bill from state Senator Henry Stern, who also authored SB 1339, would also create a program to help communities identify critical facilities and get utility help in designing microgrids to back them up, she said. But with the state facing a massive budget shortfall from the COVID-19 pandemic, it’s unlikely to include funding to build those microgrids, Detrio noted.
The CPUC’s proposed decision does support a PG&E program that would direct up to $70 million over three years to helping local and tribal governments to coordinate future microgrid development. It also orders all three investor-owned utilities to share grid infrastructure data with governments, which is valuable for differentiating sites that can be easily integrated with distribution grids from those that can’t, Smeloff said.
How utilities could help (or hurt) microgrids as grid players
One of the biggest barriers targeted by SB 1339 is the lack of regulations to value the full array of services microgrids can provide into the broader utility systems they’re connected to.
CPUC’s proposed decision doesn’t take specific steps toward that goal, but it does contemplate allowing utility San Diego Gas & Electric to test out a “local area distribution controller” software platform to manage its own microgrids.
The software is from PxISE, which is owned by SDG&E parent company Sempra, and would coordinate the operations of batteries, generators and distribution grid switches and controls at Cameron Corners, the Ramona Air Attack Base, and Desert Circuit 221, three microgrids SDG&E could complete by the end of 2020.
Smeloff noted that this kind of utility effort is an important step toward enabling more complex microgrids, which "requires a system controller to reliably serve multiple customers.” The risk, however, is that by managing microgrids that it doesn’t own as well as those it does, it could open the utility to accusations that it’s favoring its own systems over third-party microgrids. “I am assuming the commission will approve it — we recommended they do not — but if they do, they need to precondition that to not allow San Diego to use it elsewhere.”
The CPUC’s proposed decision noted that Sempra picked PxISE in a competitive procurement overseen by a third party that found it outclassed its competitors on price and capability. But the proposed decision also said it intends to subject its implementation to “affiliate transaction rules” meant to prevent utility affiliates from giving preferential treatment to their own resources over others.
The tricky issue of microgrid tariffs
A similar problem could arise from PG&E’s mention of plans for its own “community microgrid tariff,” Smeloff said. While PG&E didn’t provide any more information on what it has planned, the CPUC hasn’t yet progressed to taking on the challenge of microgrid tariffs, and any that are developed should be done openly with full stakeholder participation, not behind the scenes by a single utility, Smeloff said.
In Wednesday’s webinar, eco(n)law’s Brown agreed that “as much as we want tariffs, we don’t think the way to do that is to say, ‘Here’s one for the communities, one for the businesses, one for the big guys, one for the little guys.’” Any work on that front must be done “in a public process that’s overseen by the commission.”
Some combination of these two things — a utility control systems that can manage microgrids’ contribution to the larger grid, and tariffs to value that contribution — is a critical next step for the CPUC, Brown said. Without them, microgrid developers worry that their efforts, far from being valued, will be punished by utilities assessing “exit fees” such as departing load charges or standby charges, he said.
These charges, meant to compensate ratepayers for the lost utility revenue that comes from large commercial and industrial customers departing a utility’s service, are problems for microgrids around the country, not just in California, Brown said. They’re especially problematic when the microgrids in question are actually providing positive attributes, such as providing community resiliency that a utility finds itself unable to provide because it’s forced to shut off its power lines to prevent them from starting wildfires.
Beyond that, microgrids “can allow for much higher penetrations of renewable distributed energy resources” by balancing local fluctuations in solar power and demand in ways that centralized utility control systems struggle to manage, MRC co-counsel Christopher Berendt, an attorney with law firm Faegre Drinker, said in Wednesday's webinar.
“This approach — asking utilities to focus on what services they can procure from microgrids that deliver on the smart grid promise to ratepayers and communities — that’s where we see great promise.”