Pennsylvania, the epicenter of the country’s fracking industry, isn’t a vanguard in clean energy development. It ranks squarely in the middle of U.S. states in terms of solar deployment, with about 540 megawatts of solar installed as of mid-2020, less than half a percent of its total generation capacity, according to the Solar Energy Industries Association.
About four-fifths of that is distributed solar of less than 5 megawatts, the maximum system size eligible for net metering under state law. Of that, about 180 megawatts consist of residential rooftop solar systems less than 15 kilowatts, according to data from the Pennsylvania Public Utility Commission (PUC).
That’s a decent amount of rooftop solar, but it's certainly not enough to cause the kind of voltage fluctuations, two-way power flows or “duck curve” energy supply-demand imbalances that are starting to disrupt power grids in Hawaii, California, Arizona and other solar-heavy states.
But for PPL Electric Utilities, which serves about 1.4 million customers in eastern Pennsylvania, the fact that it only has several thousand rooftop PV systems on its system — compared to the more than 1 million in California — isn’t a good reason not to start to plan ahead for managing its future growth.
PPL won a $3.3 million Department of Energy grant in 2017 to work with General Electric on testing a distributed energy resource management system, dubbed the Keystone Solar Future Project, meant to enable more control over these conditions. In 2019 it asked the state PUC for permission to expand that program across its service territory in order to forestall the kind of solar integration problems other more PV-rich utilities have experienced.
But PPL’s 2019 proposal for a distributed energy resource management system quickly ran into opposition from solar vendor Sunrun and clean-energy advocates including the Natural Resources Defense Council (NRDC). In their view, PPL’s plan would threaten to undermine solar systems’ value without any proof that its goal of solving potential grid problems was worth the cost. The dispute spurred a months-long regulatory battle with harsh words exchanged between PPL and its opponents.
Last week, the utility filed a settlement agreement with NRDC, advocacy group Sustainable Energy Fund and the PUC’s Office of Consumer Advocate that could set the stage for a first-of-its kind, head-to-head test of direct utility control versus automated grid responses for solving grid disruptions caused by distributed energy resources (DERs).
PPL spokesperson Joe Nixon declined to comment on the details of the settlement proposal while awaiting regulatory approval. But he said that PPL believes “it will benefit our customers and further enable DERs in our service territory while supporting the state’s vision of renewable energy growth to address climate and sustainability objectives.”
Mark Szybist, senior attorney with NRDC’s climate and clean energy program, said the pilot “could be a really valuable tool to understand how utility management and monitoring of distributed energy resources should work [and] what the relative costs and benefits are. We’re hopeful that the learnings from this pilot could inform this discussion, both in Pennsylvania and other jurisdictions.”
The pros and cons of utility DER control
The dispute leading to last week’s settlement reflects a nationwide argument between utilities and DER industry groups over how to manage distributed energy’s impacts on the grid, one that’s been reflected in venues from interconnection regulations to smart inverter pilot projects.
Utilities are eager to constrain DERs from pushing voltages above or below safe operating limits, triggering protective equipment by pushing power up distribution circuits, and otherwise disrupting grid operations. But the same techniques that utilities can use to gain visibility and control over how DERs operate can also undermine their value and thus reduce incentives for customers to install them, as Sunrun and NRDC argued.
First, PPL’s plan would have required all new DERs to pay for additional communications and control equipment — specifically, communicating meter collars from startup ConnectDER to augment the utility’s smart meters. Second, it could have opened up solar systems to having their output curtailed or shifting their smart inverters to providing reactive power, reducing their net-metering revenue.
Sunrun and other DER providers aren’t against tapping their systems for grid values; many are already doing it, if only at a limited scale. Nor are they opposed to utilities planning ahead for levels of DER penetrations that haven’t yet occurred. But they’re leery of utilities being in sole control over how that’s done — and dead-set against being forced to absorb the costs.
“To decarbonize our economy in the way we have to [in order] to minimize the effects of climate change, we need a lot of distributed energy resources, and we want the costs of those resources to be as low as possible,” Szybist said. As utilities develop DER management systems, “it’s important that the benefits of all that infrastructure and investment be commensurate with the costs.”
Control group vs. “control" group
The settlement agreement in Pennsylvania works around these conflicts in several steps. It’s limited to a pilot-scale deployment at first. And the utility, not customers, will pay for additional equipment and installation costs to enable its control.
Critically, the new pilot establishes two separate groups of DERs to study: a set of solar systems subject to active utility management and a control group with smart inverters that automatically respond to grid disruptions that the utility can only monitor, not control.
Both groups’ inverters will be set to automatically correct localized voltage shifts outside industry-standard operating ranges as part of a volt/VAR control scheme. They’ll also all be set to avoid common problems, such as tripping offline during minor voltage disruptions and thus increasing grid instability.
These are standard autonomous features of today’s smart inverters, and they’re required for all new installations in California, Hawaii and a handful of other states, said Harry Warren, co-founder of Center for Renewables Integration and an expert witness in the PPL proceeding. “Let’s identify the benefits we can get out of that before we place them under active, real-time utility management.”
What’s in it for utilities
PPL’s utility-controlled systems, by contrast, will be able to be turned on and off remotely, conduct more active volt/VAR injection and absorption, provide constant power factors in support of grid control schema or actively increase or reduce power output via volt/watt settings. Those are the kinds of capabilities that DER management systems around the world are trying to enable, and they could well offer greater benefits than simple autonomous responses.
PPL noted several circumstances that could require this active control, such as shutting off systems during grid emergencies or adjusting their output amid circuit reconfigurations that alter the operating characteristics of the local grid. It also envisions broader uses of active management, such as using its networked inverters for conservation voltage reduction, which reduces energy waste by lowering unnecessarily high voltage levels, although that’s not part of the initial pilot scope.
Eventually, PPL will be allowed to seek permission to extend the program to more circuits, or even make it a part of its ongoing operations through a new "Distributed Energy Resources Interconnection Service" tariff — but only after it’s worked with the PUC and settlement stakeholders to show if the extra benefits of active management justify the extra costs.
What’s in it for DERs
This kind of active management also offers potential benefits for DERs: the ability to enable interconnection of systems that might otherwise be barred from being added to the grid.
“We’re curious about whether the utility control and management can ultimately make increased DER penetration less costly,” NRDC's Szybist said, “for instance, by reducing the need for distribution system upgrades.”
Utilities can bar interconnection requests or demand that DER developers pay for grid upgrades to solve problems that may only arise in rare circumstances. Warren offered the example of a 100-kilowatt solar system that might overload a circuit it’s connected to only during peak solar generation hours or when an outage elsewhere forces switching operations that put it under more stress.
Being able to order that 100-kilowatt system to reduce output to, say, 50 kilowatts during those rare circumstances is a better option than barring it from interconnecting in the first place, he said. This concept is informing the latest interconnection policies in California and serving as a key test case for smart inverter pilot projects across the country, Warren noted.
PPL’s pilot will track the different levels of “distribution system upgrades avoided” under monitoring, autonomous and active management use cases. It’s possible that “alternative voltage management modes and settings may be used to reduce or eliminate distribution system upgrade costs to interconnecting customers with the customer’s agreement,” the utility states in its settlement filing.
The pilot is also going to track details on how often and in what manner it alters DER operations, and how much they reduce the generation that they get paid for in order to prove that the benefits are worth whatever lost revenue may accrue to the DER host. All this information will be made available not only to the PUC but also to each customer, Warren said.
Alternative grid-DER futures
Plenty of utilities have tested autonomous smart inverter functionality, and many have tested active grid controls. But Warren can’t think of any that have tested both, side by side, at the levels of participation that PPL’s pilot is planning.
“They’ve done some limited studies on limited circuits and...a lot of modeling about how systems would behave under certain scenarios,” he said. “But to have a full, real-world, live-activity comparison — if this pilot is done well, it could provide a lot of interesting information and help tease out what the incremental benefits are of [DER management] systems.”
Utilities around the world are seeking approval to invest tens to hundreds of millions of dollars in DER management system deployments and other advanced grid technology to manage the influx of DERs on their grids. But there’s a chicken-and-egg problem with proposals like these: Often, the costs of a full-fledged DER management system are hard to justify until DER penetration grows high enough to force the issue.
By the time that happens, utilities may be behind in getting the technology up and running to manage the disruptions they face. In that sense, PPL’s efforts in advance of significant amounts of rooftop solar on its system could be seen as evidence of foresight, Warren said. As installations rise, “the advantages of these more sophisticated controls” may become readily apparent.
At the same time, many state regulators — including the Pennsylvania PUC — haven’t yet mandated that their utilities set guidelines for the smart inverters that are coming onto the market, Szybist said. NRDC and other parties petitioned the PUC to include such a mandate as part of its PPL settlement negotiations, but “we’re coming out of this case without that,” he said.
To Warren, that seems like a lost opportunity. “We’re about to launch a new generation of hardware capable of very sophisticated autonomous control,” he said. And it’s certainly a technology that ought to be enlisted for grid support before taking the next step into a full-fledged DER management system deployment.
Pennsylvania may not be a hotbed of rooftop solar, behind-the-meter batteries, electric vehicles and other DERs driving these kinds of policy changes. Over the past decade, its Republican-controlled legislature has rejected efforts to expand renewable energy and energy efficiency standards, and it is now fighting Democratic Gov. Tom Wolf’s plan to bring the state into the Regional Greenhouse Gas Initiative.
But it has hosted some noteworthy distributed energy pilots, such as Philadelphia’s Navy Yard and Pittsburgh’s district microgrid projects, and is considering a community solar bill that could open new markets. If efforts like these do drive more solar growth, utilities in the state may find themselves facing the same kind of challenges as those in Hawaii and California are now facing.
To be clear, NRDC is not yet open to allowing PPL to move ahead with its original plan to extend utility control to DERs systemwide “pending any sort of data that show that the incremental advantages of monitoring and management exceed the cost, compared to simply autonomous functioning,” Szybist said.
But it’s open to learning from the data that does emerge.