This is the second installment in our five-part series on key trends influencing the grid edge, or the transformation of the electricity grid from a centralized, one-way delivery system to a networked system integrating distributed energy resources such as rooftop solar, behind-the-meter batteries, electric vehicles and flexible electricity loads. This installment focuses on smart inverters, the digital communications and control-enabled versions of the DC-to-AC power conversion devices for solar and battery systems, and highlights their significant potential — and the barriers that remain — as agents of flexible grid control and DER integration.
Smart inverters can do a lot for power grids facing disruptions from rooftop solar, behind-the-meter batteries and other distributed energy resources.
First, they can solve the problems that DERs create themselves, such as managing voltage sags and surges from high solar production on distribution circuits by injecting or absorbing reactive power or even curtailing output — capabilities that could increase solar hosting capacity without threatening grid stability.
Second, if combined with more advanced communications and controls, they can reduce the need for new utility equipment such as capacitor banks and voltage regulators or defer the need to upgrade circuits and transformers in order to manage increasing amounts of locally generated and distributed electricity.
This isn’t news to people following smart inverter developments in the U.S. Starting with vanguard work on Hawaii’s rooftop-solar-saturated grids, and advancing with California’s leading role in developing a core set of advanced inverter functionalities now embedded in the IEEE 1547-2018 standard, pilot projects in Arizona, Texas, New York, Illinois and other states indicate that utilities can control inverters to solve solar congestion problems and help improve grid power stability.
Meanwhile, industry standards have pushed manufacturers to embed these capabilities in new solar PV and battery inverters — mainly to serve California, the country’s largest market. Starting in mid-2018, California’s Rule 21 required relatively simple, autonomous grid-stabilizing features for all new installations. As of this month, all new inverters must come with a largely complete set of advanced capabilities, including dynamic volt/VAR and volt-watt controls and the ability to communicate with utility or aggregator control and monitoring systems.
As goes California, so tends to go the nation. Minnesota and Maryland now require IEEE 1547-2018 for new solar installations. Other state regulations, such as New York’s Standardized Interconnection Requirements, are following suit. In February, the National Association of Regulatory Utility Commissions passed a resolution for all states to adopt IEEE 1547-2018 for DER interconnection, which is likely to lead to similar requirements across the country in the coming years.
Those include the common use of the IEEE 2030.5 standard for inverter communications and controls, and its Common Smart Inverter Profile implementation from industry group SunSpec Alliance. This “can handle demand response, it can handle different price signals, it can control load, it can control inverter settings," said Tom Tansy, SunSpec chairman.
California's implementation also allows utilities to “send a signal that’s aimed at all the generators on a certain feeder segment, and propagate that signal,” to coordinate responses to match that circuit’s needs, he said. As smart inverters become the norm in California — something utility Pacific Gas & Electric forecasts will happen by 2025 or so — these capabilities could become available from the mass of installed solar and battery systems at large.
Smart inverters could also expand solar penetration limits, traditionally held to about 15 percent of a circuit’s load. That’s already being exceeded on some solar-heavy circuits. But a SunSpec research project funded by the California Energy Commission indicates that autonomous and coordinated smart inverter controls “enable DER penetration rates of 100 percent while improving overall grid reliability.”
What’s more, the report found that enabling the full array of smart inverter grid-supportive capabilities could unlock hundreds of millions of dollars in benefits for California, through a combination of improved reliability and power quality, deferring transmission and distribution grid upgrades, and increasing the share of distributed solar to help the state meet its goal of being 100 percent carbon-free by 2045.
The gap between theory and reality for smart inverters as grid agents
But there’s still a wide gap between what smart inverters can do theoretically and what they can be expected to do at massive scale — a hard truth borne out in many of the same pilot projects that have proven their potential value.
For example, enlisting customers in sufficient numbers to prove out high-penetration inverter capabilities has been a continual challenge and has soured California utilities on relying on them for real-world grid operations. Indeed, the field trial portion of SunSpec’s CEC project was only able to enlist 12 customers.
SunSpec’s report on the trial noted that participating smart inverters were controlled to prevent “unwanted or unpredicted energy export, inadequate reactive power support or unmitigated voltage rises,” which supports prior lab tests indicating that 100 percent solar penetration is feasible.
But many customers refused to turn over their inverters to outside control. Others lacked robust enough internet connectivity to support the required communications. Even with reliable communications, “California Rule 21 does not preclude asset owners from expressing preferences that are different from those of the grid operator,” the report states — in other words, customers can ignore utility commands if they want to.
Other longer-running projects have shown that automated responses and utility controls can mitigate problems related to high levels of solar penetration. But that doesn’t necessarily mean these results can be replicated across larger swaths of the grid, with many more variables in play.
In Austin, Texas, the Energy Department-funded Shines project has successfully integrated 30 smart inverters into a residential neighborhood with solar panels, batteries and electric vehicle chargers. “My general feeling is that the vast majority of claims in terms of grid support functions, and the impact they can have, are probably correct,” said Scott Hinson, CTO of nonprofit Pecan Street, a Shines project partner.
But “the behavior of masses of these devices with complex control systems — that’s not known.” More work must be done to test each stage of the growth in smart inverter use before the promised benefits can be expected to materialize, he said. “That’s just good engineering.”
Even turning on autonomous voltage management controls carries potential risk, said Brian Lydic, chief regulatory engineer for the Interstate Renewable Energy Council and co-author of a recent paper on IEEE 1547-2018. “The main fear I’ve heard in some states is the potential for oscillations to occur [leading to] inverters working against the purposes of the utility’s own cap banks and voltage regulators.”
As more states require smart inverters, he said, “I’d hope that it leads to the increase of hosting capacity of DERs on the system." But, he added, “We’re between just getting the rules in place and implementing some kind of autonomous response.”
The solar industry-utility divide
Utilities have several reasons to move slowly on smart inverters as substitutes for traditional grid infrastructure. First, as previously noted, they face technical communications and controls challenges and regulatory barriers to forcing customer-owned assets to comply, putting their reliability in question.
Second, almost all U.S. investor-owned utilities earn guaranteed rates of return for infrastructure investments and other capital expenditures (capex). Asking them to replace those investments with operational expenditures paid to customers, as would be the case with smart inverters, goes against their economic interests.
Southern California Edison’s companion project to the SunSpec project, funded by the California Energy Commission and focused on analyzing utility system standards including IEEE 2030.5, found that smart inverters can “support the power grid during normal operation, allowing for better utilization of utility assets, potential investment deferrals, and eventually, higher penetration of DERs.” At the same time, it found that “validating technologies as SCE did in its...project is just the initial step in these efforts.”
Bo Magluyan, director of product management at Outback Solar, an EnerSys company that participated in the SunSpec pilot, said “next-generation platforms” need to be developed to capture the full value of smart inverters. “I think the utilities know that’s something that they have to go and figure out,” he said. But, he added, “It seems like their main focus is more on the bread-and-butter interconnection. […] They’re taking a very deliberate, stepwise approach.”
At the same time, solar companies fear utility control of inverter operations because key grid-balancing functions like reactive power injection and curtailment reduce real power output and solar generation revenues.
A proposal from Pennsylvania utility PPL last year to monitor and manage all new DERs was opposed by leading U.S. residential solar installer Sunrun. Likewise, Illinois since 2019 has offered smart inverter rebates to larger-scale solar installations but saw solar industry pushback to the idea of extending control over them, leading state regulators to postpone a decision on how to tap their capability for grid balancing.
New regulatory models that reduce the emphasis on capex, as with the U.K.’s Revenue = Incentives + Innovation + Outputs regime, can give utilities more incentive to seek out alternatives to infrastructure. So could creating regulations that allow utilities to own smart inverters, as Arizona regulators did with utility APS’ Solar Partners Program project. But there’s little sign of regulators allowing utility ownership of behind-the-meter assets beyond pilot projects.
“Many utilities would be happy to capex behind-the-meter systems, but it has not really gone anywhere,” Ben Kellison, Wood Mackenzie’s director of grid research, said. “Instead, [the approaches taken by] California, Hawaii and Illinois...seem to be the path forward for the next several years, where the utility creates a functionality standard for inverters and determines how and when it will activate or alter the behavior of those resources at a later date, with the commission's approval.”
In order for smart inverters to become more than solutions to solar-created problems, the U.S. will likely have to await the arrival of systems that can coordinate hundreds or thousands of DERs for central control needs and simultaneously manage local interactions that happen too fast for central controls to intervene. Stay tuned for next week’s installment in this series to learn more about progress and challenges on this emerging front on the grid edge.