It’s called the “solar coaster:” The ups and downs the industry faces as solar-friendly policies ebb and flow. And in North Carolina, rooftop installers are in the middle of one wild ride.

On the heels of cutting bill credits for residential solar panels in October, Duke Energy is now poised to offer new rebates for rooftop arrays that are paired with batteries. Combined with federal incentives, the new “PowerPair” rebates could cut the cost of solar and battery systems in half and inject new interest in rooftop solar, which many installers say waned last fall.

“We definitely saw a dip,” said Doug Ager, the CEO and co-founder of Sugar Hollow Solar, describing his company’s business in the last quarter of 2023. But at least in the short-term, he said, “PowerPair will change all that.”

Approved to roll out in May, the pilot program will initially serve only an estimated 6,000 to 7,000 households. But proponents say it could pave the way for a new paradigm in which Duke invests in and manages distributed renewable energy and storage the same way it might a traditional power plant.

“It’s opening the door to active load management from Duke that is going to be increasingly important,” said David Neal, the senior attorney with the Southern Environmental Law Center who helped negotiate the program. Heralding the pilot as one of the first of its kind, he said, “it’s going to be a lot more cost effective than just building new generation to meet expected loads.”

Ultimately, advocates are also hopeful that the solar coaster can be smoothed out a little.

“The rooftop solar industry really has experienced quite a bit of ups and downs,” said Matt Abele, executive director of the North Carolina Sustainable Energy Association, which also helped devise the rebates. There’s still the question of what long-term strategies would support installers, he said. “But I would say this is not an insignificant program in the interim.”

‘The result of…negotiations around net metering’

Greenlit by regulators last month, the rebates grew out of a years-long dispute between Duke Energy, advocates, and the solar industry about how rooftop solar owners should be compensated for the electricity they produce. 

About 40,000 rooftops across the state boast solar arrays, the bulk of them on homes and in Duke territory. The figure accounts for a tiny fraction of North Carolina’s roughly 5 million housing units.

Despite these small numbers, Duke, like other investor-owned utilities around the country, has long sought to lower the state’s one-to-one net metering credit, which it says unfairly burdens both the company and customers that don’t have solar panels.  

Solar installers and advocates contend that rooftop arrays provide more benefits than costs, including cleaner air, fewer electrons lost in transmission, and reduced need for electricity from centralized fossil fuel power plants. Their assertion is backed up by most independent studies of rooftop solar, a 2019 analysis found.

Still, a pair of state laws, both heavily influenced by Duke, mandate a change to the current net metering scheme by 2027. To avoid the bruising battles and excessive fees on solar customers seen in California and elsewhere, some of the state’s leading clean energy advocates and solar installers forged a complicated truce with the utility. 

The crux of the agreement is a move toward “time of use” billing. New residential solar owners are charged and rewarded more for electrons they add to or subtract from the grid during peak demand hours of 6 to 9 p.m. in the summer and 6 to 9 a.m. in the winter. On a monthly basis, any net solar electrons added to the grid are credited at the “avoided cost” rate — akin to a wholesale rate and currently about 3.4 cents per kilowatt hour.

Diligent solar owners can squeeze benefits out of this complex billing scheme, some installers say. But to ease the transition, they also negotiated a simpler, lower-risk “bridge rate” with Duke, in which solar customers enrolling before 2027 get a monthly credit at the wholesale rate for any electrons they add to the grid. 

Regulators on the utilities commission accepted these compromises last March and ultimately ordered new rates to begin October 1. But they rejected another component of the deal, which would have given customers with electric heat an extra rebate for enrolling in Duke’s smart thermostat program, in which the utility can make temperature adjustments from afar.  

“Instead, the Commission directs Duke to develop a pilot program,” their order read, “to evaluate operational impacts to the electric system, if any, of behind the meter residential solar plus energy storage.” 

PowerPair is the result. “This program was in many ways a result of our negotiations around net metering,” Dave Hollister, the president of Sundance Power Systems, said over email.

‘Possibly a win-win for everyone’ 

Devised after months of conversations between Duke, solar installers, clean energy advocates, and others, the new rebates would be based on the size of the solar array and battery and capped at $3,600 and $5,400 respectively. Combined with a 30% federal tax credit, the cash back could cut the cost of an average $40,500 system down to less than $20,000. 

For customers, the deal is “actually really, really good in terms of the economics,” one installer said. And for Duke, the rebates could prove a low-cost strategy for smoothing out spikes in demand and strengthening the resilience of the grid.

“Cost effective and dispatchable customer-sited resources are key components of our clean energy transition,” Lon Huber, a senior vice president at Duke, said in an email. “We are committed to expanding the scope and adding ways for our customers to deploy grid beneficial technology.”

Customers will be divided into two equal cohorts. Those subscribed to the simpler bridge will allow the utility to remotely control their battery up to 18 times a year and will earn an extra $37 a month on average. Enrollees in the more complicated time-of-use rate plan, on the other hand, won’t get monthly incentives but would have control of their batteries. 

“It will be interesting to see how many folks will allow Duke to control their battery and who wants to have that freedom and independence to manage their customer-generated electricity themselves,” Hollister said. “ We deal with so many folks who are looking for self-reliance and the idea of ‘smart grid’ is somewhat of a third rail for them.”

Already, batteries are popular options for rooftop solar customers. Installers say between a quarter and 40% of their clients were already choosing them for a variety of reasons, from a desire to save money to a quest for energy security in the face of outages. 

Sugar Hollow Solar’s Ager said residential storage fits with the western North Carolina vibe. “Being in the mountains,” he said, “people just want batteries.”

With the PowerPair, the percentage of solar arrays paired with storage will undoubtedly rise, and many installers predicted it would double. 

“I fully anticipate us selling tons of systems with batteries,” said Brandon Pendry, communications and outreach specialist with Southern Energy Management, one of the state’s oldest installers and a negotiator for both the bridge rate and the PowerPair scheme. 

To avoid the problem installers and their clients faced with the last round of rooftop solar rebates — when demand far exceeded supply each year and available grants disappeared in minutes — the architects of the program gave it an overall cap of 60,000 kilowatts but no annual limits. That way, rooftop solar and battery owners can get the rebates on a rolling basis.  

“In this case, there is only one capacity and it’s not time dependent,” said Pendry. “It’s just: when it runs out, it runs out.”

If customers choose the maximum allowable size of a 10 kilowatt solar array, a total of 6,000 households could benefit. But no one really knows when the capacity will be reached, with some predicting 18 months from May and others estimating as few as four. 

Duke projects it will connect 11,400 residential rooftop systems this year. But a spokesperson said it was simply too early to tell when PowerPair rebates would dry up. 

Once they do, the hope is that data gathered during the pilot will inform whatever comes next. 

“It may possibly be a win-win for everyone,” Hollister said, “especially if it can be extended or transformed into a more permanent program.” 

‘A better and better investment’

Since half of the PowerPair cohorts will be using the bridge rate, there’s some chance a permanent program would extend that rate’s life — a key priority for some in the industry.  

No matter what, while most installers contacted for this article eagerly await the pilot, they’re also clear-eyed about their business plan for the future.

“We have been installing solar in [the state] for over a decade and have certainly seen lots of incentives come and go, said Jesse Solomon, vice president and director of sales for N.C Solar Now, in an email. “But we have always been able to design the investment to make sense for our clients.” 

Solar installers also focus on the overall trends buoying their industry: Fossil fuels are becoming more expensive, while the materials designed to harness and store forever-free sunlight are getting cheaper.

Every year Duke raises rates, said Pendry of Southern Energy Management, “solar becomes a better and better investment.”

In North Carolina, Duke Energy to offer rebates for rooftop solar paired with batteries is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

When Wisconsin’s largest coal plant, the Columbia Energy Center, closes in the next few years, a carbon dioxide-filled “battery” developed by the Italian company Energy Dome will take its place. 

The installation is billed by its backers as a potentially crucial development in the clean energy transition. The European Investment Bank announced at the COP28 climate conference this month that it is backing a similar project by the same company in Italy.

The balloon-like facility will use electricity to compress carbon dioxide when demand is low. When demand is higher, it can generate electricity by letting the carbon dioxide expand to drive a turbine. 

While energy storage can lower emissions, clean energy advocates say the climate benefits depend on whether the projects also drive development of wind and solar. A single pilot project is unlikely to do so, but a successful test could show new ways to manage those variable sources in the future that don’t require natural gas as a “bridge fuel.” 

“Right now we have nothing that can buffer a 4 megawatt solar field,” said Oliver Schmitz, director of the Grainger Institute of Engineering at the University of Wisconsin and a technical adviser on the Energy Dome project. “If we show this works now using whatever energy mix we have, we have the certainty” to deploy more renewables paired with it in the future.

Last year, Wisconsin got 37% of its electricity from natural gas and 36% from coal, according to the Energy Information Administration. Nuclear provided 16% of electricity used in Wisconsin and non-hydro renewables provided less than 1%, according to the EIA. These energy sources will largely power the battery until the state’s energy mix changes drastically. 

A goal of Wisconsin’s Energy Dome, slated to be the first commercial-scale application of the technology, is to drive more renewable development, according to Alliant Energy, the utility that co-owns the Columbia coal plant.

“The expansion of energy storage infrastructure is key to accelerating the transition to cleaner, more sustainable renewable energy,” said Alliant Energy spokesperson Tony Palese. “As we retire older fossil fuel facilities and add additional renewable resources to our generation portfolio, energy storage solutions help to ensure system reliability and meet customer needs.

“Importantly, energy storage systems can complement the variable nature of renewable resources and help balance energy demands. This in turn can help reduce reliance on traditional, dispatchable fossil fuel resources.” 

But the 20 MW Energy Dome alone won’t likely drive new renewable development. Even if the project is successful and more Energy Domes are built, as Palese said is possible, some other challenges still stand in the way of deploying more renewables.

Alliant Energy is the largest utility owner-operator of solar in Wisconsin, with over 250 MW deployed and 839 MW more slated for completion by mid-2024. Since Wisconsin is part of the MISO grid, the Energy Dome also pulls from a system where renewables are expanding quickly, but also plagued by a clogged interconnection queue, transmission constraints and other issues.

Alliant owns 1,700 MW of wind across Wisconsin, Iowa and Minnesota within the MISO grid, Palese noted, and is also expanding solar in Iowa. Meanwhile, in the future an Energy Dome could draw energy directly from wind or solar farms rather than the grid, Palese added.

“As we operate and evaluate various aspects of the Energy Dome system’s performance, we envision it could become a model for additional energy storage development for grid applications or directly connected to wind or solar developments,” Palese said.

Citizens Utility Board executive director Tom Content said CUB would likely only support the project if it is genuinely aimed at expanding renewable deployment, and he would oppose any new natural gas generation to feed the Energy Dome.

“Energy storage technologies beyond lithium-ion batteries are being actively studied and can be key elements of the nation’s energy future,” he said. “It’s encouraging to see innovative concepts such as this get funding to be explored, proven and become more economical over time.”

A promising pilot

In September, Alliant Energy received a grant of up to $30 million from the U.S. Department of Energy to develop the Columbia Energy Storage Project. It will cover 12 acres of the coal plant site south of Portage, Wisconsin, including a large dome holding a balloon that can inflate and deflate as carbon dioxide is compressed and decompressed inside it.

When wind or solar power is abundant, the energy can be used to compress carbon dioxide gas into a liquid. When extra energy is needed, the liquid will be allowed to decompress, turning back into gas and powering a turbine to generate enough electricity to power up to 20,000 homes. 

The dome and balloon are part of a closed loop system, meaning no carbon dioxide will be released, and no carbon dioxide delivery is needed after the initial setup. The project will tap into the grid infrastructure already onsite at the 1,112-MW coal plant, the last coal plant in Alliant’s fleet.

This is billed as the first-ever test of the technology at commercial scale. A much smaller 2.5 MW project is operating in Sardinia, Italy, where a new 20 MW Energy Dome is planned with the funding announced at COP28 — $25 million from the European Investment Bank and $35 million from the firm Breakthrough Energy Catalyst.

The Wisconsin project will explore whether the high efficiency rate of up to 75% achieved at the small project can be replicated when a much larger volume of gas is compressed. Carbon dioxide is especially suited for such an application since unlike other gases, it can be liquified at ambient temperatures.

Mike Bremel, Alliant director of engineering and customer solutions, said Alliant put out a request for information on battery storage proposals in spring 2022, seeking projects that could provide 10 hours or more of reliable energy.

“Energy Dome was at the top of our list, basically because of its round-trip efficiency of 75%, and even more importantly the fact that it’s a really simple process that uses off-the-shelf components,” Bremel said. “The compression of CO2 to liquid has been done for over a century. It’s a reliable process that the industry and folks understand.”

Alliant was planning on a capital outlay of about $5 million, he said, whereas about $60 million would be needed for the Energy Dome project.

Around Thanksgiving of 2022, the company “stumbled upon” notice of a DOE Office of Clean Energy Demonstrations grant specifically for long-duration energy storage projects, Bremel said. The grant allows the project to move forward as a 50% cost-share between the federal government and Alliant as well as the two other utilities that own the Columbia Energy Center, WEC Energy Group and Madison Gas and Electric.

Unique attributes

Eight other projects received DOE grants, including one developing iron-based batteries at retiring coal plants in Minnesota and Colorado; and one using zinc bromide batteries in tandem with renewables in Manitowoc, Wisconsin. Bremel noted that Energy Dome was the only mechanical energy storage technology selected; the others involve thermal or chemical (battery) energy storage.

Schmitz said that compared to the many energy storage systems he’s studied — including lithium ion and flow batteries, thermal systems, molten salt — “this one is a huge storage solution at scale.”

“It can really be used to buffer renewable energy production,” Schmitz said. When excess solar or wind energy is being generated, “you can absorb it and spit it out again when the grid needs it. The specific technology uses very traditional subsystems: compressors, regular turbines, materials that withstand pressure. It’s standard engineering combined into a high-performance system.”

Compared to batteries that involve precious metals and potentially other supply chain challenges, the Energy Dome can be built on-site using domestically sourced technology, including as many components as possible from Wisconsin, Bremel said. If the project is successful, more similar domes may be built on the Columbia coal plant site, he added.  

“Because it does use up substantial amounts of space, it’s pretty well-suited for rural solutions, rural resiliency,” said Bremel, noting a local microgrid could be built around the energy storage.

The utilities will be studying how the project can be used for load-following, providing less energy than its total capacity at a given time and extending how long it can provide energy.

“We could potentially have twice the duration,” Bremel said. “Once we understand this project more, there is potential to marry several domes to a single generation and compression source.”

Community involvement

There has been much public concern about carbon dioxide pipelines and carbon sequestration, including in light of the disaster in Satartia, Mississippi, during which a carbon dioxide pipeline ruptured, the gas displaced oxygen and scores of people were sickened.

But Bremel said the dome poses little risk. There will be sensors to detect leaks in and around the facility, and “in the event there was a leak at the gas stage, it’s not going to leak at a very fast rate because it is at atmospheric pressure — it’s not at thousands of PSI” as in a pipeline, Bremel said. 

He said the project also involves very little environmental impact, including after its decommissioning expected after 25 to 30 years. Concrete will be poured around the dome perimeter, and the land directly underneath will be relatively untouched, Bremel said. The largely steel and plastic components can be recycled.

Alliant plans to seek needed approvals from the state Public Service Commission in the first half of 2024, and hopes to begin construction in 2025 and operation in 2026.

The University of Wisconsin, which works with Alliant through its Clean Energy Community Initiative, is helping lead a community engagement process and development of a community benefits agreement, conditions of the DOE grant.

“There is supposed to be a two-way engagement around energy justice, environmental justice, workforce and good jobs,” Schmitz said. “Communities guide the process, bring in their priorities and concerns.”

Madison Area Technical College will help develop a clean energy jobs pipeline around the storage project, building on its role leading a national consortium of community college energy programs. And University of Wisconsin faculty will likely study issues like whether the dome impacts birds, Schmitz said.

Schmitz noted that the Energy Dome itself won’t create many jobs after construction is done, since “it is very low maintenance, very reliable.” But clean energy advocates hope the large dome’s presence will help raise awareness about clean energy more generally and encourage locals to work in the clean energy economy. That means the benefits for renewable deployment could go beyond the role of bridging intermittency.

“The best thing that can happen is visible projects like this have an immediate impact because they excite potential workers to think about this sector,” Schmitz said. “Maybe they become a solar installer or wind technician. Our workforce is strong on manufacturing and building things, so we want to upskill people into the clean energy domain.”

Can a balloon-like battery move the needle on clean energy in Wisconsin? is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

A battery storage development is replacing a fossil-fuel-burning power plant in western Massachusetts, providing a model that supporters say could be emulated elsewhere.

The project is only financially viable, however, because of a unique state incentive program designed to cut emissions related to peak electricity demand. 

Power company Cogentrix is developing the facility at the site of the former West Springfield Generating Station, which was shut down in June 2022. The $80 million project includes 45 megawatts of storage that will be able to send electricity onto the grid for up to four hours. It is expected to come online sometime in 2025. 

“This will be really big, and set a nice precedent for transitioning from fossil fuel to storage and renewables,” said Rosemary Wessel, founder of No Fracked Gas in Mass, a program of the Berkshire Environmental Action Team.

This transition is happening at a time when there has been increased discussion about the role of so-called “peaker plants” — facilities that are only called upon at times of peak power demand. Peakers are generally older facilities that emit more greenhouse gasses than other plants, and the power they generate is more expensive. 

Utilities have said peaker plants are necessary to ensure a reliable electricity supply in emergencies and times of high demand. Wessel’s organization and other environmental groups, however, argue that storage technology, especially when paired with renewable generation, can also meet these needs. They contend no new peakers should be built, and old ones should be taken out of use as quickly as possible. 

“These are really the low-hanging fruit for starting to take existing fossil fuels off the grid,” said Wessel, whose group has been pushing power companies that own peaker plants in western Massachusetts to consider transitioning to renewable energy generation and battery storage.

The West Springfield story

The plan for the West Springfield plant came about when longtime energy developer Chris Sherman, vice president of regulatory affairs at Cogentrix, wanted to take his work in a new direction. He has a background in clean energy — he was project development manager for the ill-fated Cape Wind offshore wind plan — and was interested in returning to this work. 

His employer put him in touch with Wessel, who had reached out to the company about the future of the West Springfield Generating Station. The plant first started generating power in 1949, initially burning coal. In the 1960s it was converted to an oil-burning plant, and in the 1990s the ability to burn natural gas was added. It was officially shut down in June 2022. 

Once power plants shut down, the land is often hard to redevelop, Sherman said. However, the properties are already surrounded by the infrastructure needed to send power into the grid, so building battery storage and renewable energy installations on these sites is a promising strategy. 

Sherman and Wessel met in June 2021, and it was quickly clear that their goals aligned. The two began working together to create plans for the site, which had not yet closed officially. Their collaboration, Sherman said, has made it easier to bridge the perceived gap between the logistical, technological, and financial aspects of his work, and the environmental and social concerns of community members.

“If I were to just call people and say ‘energy developer,’ they might not be willing to enter into an objective discussion,” Sherman said. Wessel “has done an incredible job at generating interest and then facilitating communication in the broader stakeholder community.”

The plan that emerged is a pragmatic one that attempts to satisfy environmental goals while also dealing with the financial realities of the energy market. The initial plan calls for charging batteries during times when demand and emissions are lower, and then discharging at times of higher demand. Cogentrix hopes to eventually install solar panels to make the energy it stores even cleaner and lower cost. 

The project is now in the early permitting stages, with the goal of beginning site work over the coming winter and installing battery containers in the spring. 

West Springfield leaders have expressed support for the project and the chance to put the property, formerly the largest taxpayer in the city, back on the tax rolls, noting that revenue took a hit when the plant closed last year. They are also pleased to see emissions-free batteries and solar panels take the place of the pollution the former plant created. 

“I look forward to the potential redevelopment of this site,” said West Springfield Mayor William Reichelt. “Though we are in the early stages of what’s possible, overall any improvement to the site will certainly benefit the community and the region.”

Proving the potential

Because the plan for the site represents a new sort of energy development, existing revenue models don’t necessarily apply. Sherman had to work hard to convince investors that the novel approach will turn a profit. There is enough room on the site to develop about 100 megawatts of storage, but his investors are only willing to back 45 megawatts until they see convincing results, he said. 

A small amount of revenue will be made by charging batteries during times, such as overnight, when prices are lower, then selling the power back onto the grid and higher-demand, higher-priced times. Another block of money will come from participation in the regional capacity market, in which power sources are paid for committing to be available to provide electricity at some future point. 

Additionally, almost half of the project’s revenue is expected to come from the Massachusetts Clean Peak Standard, an incentive system unique to the state. The standard, which took effect in 2020, offers incentives to clean energy generators and battery storage owners that discharge power into the grid at times of peak demand, helping to lower the demand on power plants. 

“But for that standard, our project would not be viable,” Sherman said. 

Wessel and Sherman both express hope that this project might be the beginning of a trend toward locating storage and power plant sites. Cogentrix is looking at potential projects on sites in Maine, Maryland, and New Jersey. In these cases, the power plants have not yet been retired, though Sherman said the plans should still reduce emissions.

For the concept of replacing peakers with batteries to really catch on, states will need policies that add incentives such as Massachusetts’ Clean Peak Standard that can dispatch stored power at peak demand times, Sherman said. State-backed policies, he said, will help convince backers that such projects are financially feasible. 

“What I need to demonstrate to investors,” he said, “is that we can have predictable, durable, long-term revenue streams.”

Massachusetts’ clean peak incentive puts battery storage project on track is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

The following commentary was written by Karl R. Rábago. Rábago provides consulting advice on clean energy issues across the U.S. from his home in Denver, Colorado. For more than five years, he led the prestigious Pace Energy and Climate Center at the Pace University Elisabeth Haub School of Law in White Plains. And before that, he served as a law professor at the U.S. Military Academy at West Point. See our commentary guidelines for more information.

Progressive states across the country are in competition to lead in clean electricity. California lawmakers have laid out the framework for a 100% clean electric grid by 2035. New England states share a group vision statement for a greener grid. In the Empire State, Gov. Kathy Hochul declared a goal of 70% of renewable electricity by 2030, with the important stipulation that the state reach 6 gigawatts of energy storage by that same deadline.

Her framework relies heavily on utilities and regulators to make this happen, but roadblocks to large-scale storage are popping up left and right. To get to our 6-gigawatt goal, residential solar and storage will be a crucial part of our efforts.

Residential storage (solar and batteries connected to homes and businesses) is easy to get up and running because it’s free of the red tape that plagues large institutions. And, in New York, red tape is everywhere. Due to clerical issues and a bit of foot-dragging, utilities aren’t adding large storage capacity in time to meet the statewide goal. These large-scale energy storage operations will take years to come online.

Meanwhile, installing home solar panels and battery systems can take just days. Combined, enough homes with solar and batteries can offset an entire power plant — good news as the Empire State continues retiring fossil fuel facilities. And, if you still question the impact, residential systems were named by the governor herself as key components to reaching the 2030 goal. 

This isn’t just about hitting the 2030 mark. Residential solar and storage have proven to significantly improve the safety and lives of those who install these technologies.

As a clean energy expert and advocate, I know that solar paired with storage provides crucial backup power to households enduring extreme weather events. Installing panels and a battery is an increasingly quick, painless, and beneficial process.

Through my work with the Energy and Climate Center at Pace Law School, I’ve been directly involved in developing and expanding the state’s energy framework. Take it from me, we can’t discount the immediate benefits that residential storage provides while we wait for utilities to overcome their inertia.

The opportunity for progress in New York is massive. Already, New York has existing mandates to help expand solar and storage incentives. In December, state officials released an extensive roadmap to help power providers meet our storage goals, which emphasized the importance of small-scale solar and storage. Protecting programs like net metering will remain crucial to growing our residential solar and storage footprint, especially since distributed solar and distributed generation complement each other so well.

But that’s just the start to expand and protect this vital resource. Additional options include state-mandated programs, like tax credits and special financing programs, to help ensure affordability and therefore rapid residential storage growth. This would help propel New York toward its clean energy goals, and ensure a better home energy experience for ratepayers with reliable, affordable electricity. 

The stakes couldn’t be higher. We’ve seen the threats of climate change in New York and far beyond. After all, the state of the planet is why we’re cleaning the grid in the first place. This is more than friendly competition with other climate-conscious states; it’s our planet’s future. It’s our future.

The electric sector accounts for 30% of carbon emissions. Cleaning our chunk of the grid (with renewables and storage from the home batteries) is a crucial step in not only curbing climate change, but protecting ourselves from its resulting disasters. While homeowners can do their part by installing solar and storage, they need reassurance and action from the government, utilities and regulators to keep going and growing. 

Commentary: New York’s race to clean its grid starts at the home is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

A St. Paul, Minnesota, startup company is developing an energy storage system to help businesses lower their utility bills and keep the lights on during power outages.

Vessyll was founded in 2020 by Adam and Zahra Iliff, who moved to the Twin Cities after deciding they wanted to raise their family in the Midwest. The company was recently selected to participate in a regional clean energy accelerator program and is deploying its first system this month as part of a pilot project on a northern California microgrid.

The U.S. energy storage sector is an estimated $7.5 billion annual market with several big-name players such as Tesla, Toshiba and Siemens already holding a stake. Most of the activity has been around large battery systems designed to help utilities manage the electric grid as they also install more variable wind and solar generation.

Where Vessyll sees an opportunity is in the middle tier — bigger than Tesla’s residential Powerwall but smaller than utility-scale systems — in a niche that includes commercial and industrial customers, as well as some larger residential uses.

“Vessyll is ahead of the curve [for a sector] that will grow exponentially, and they have an absolute chance to be a player in it,” said Nina Axelson, president of Grid Catalyst, the Twin Cities-based startup incubator that selected Vessyll this spring as part of its first cohort.

Adam previously worked as a senior project manager in Tesla’s battery division, where he became a student of the technology. His experience there led him and Zahra to try to design an easy-to-use battery system that wouldn’t require much work by contractors to install or set up.

The result is the Vessyll, which holds up to 46.5 kilowatt-hours of power, more than three times the storage of Tesla’s Powerwall. Tesla discontinued its mid-sized Powerpack product last year and now focuses on smaller residential systems and larger utility systems.

“Vessyll is a plug-and-play device that holds more power than other batteries” that target the commercial and residential markets, he said. “We’ve also developed what we call our ‘secret sauce,’ which is the energy management system built into the battery.”

Initially, Adam and Zahra had no preference for the type of battery technology. However, after speaking with scientists and other experts, they chose lithium iron phosphate technology because it uses a water electrolyte that is less prone to fire risk than the chemical electrolyte found in lithium-ion, Zahra said.

The couple also liked that the technology has been around for years and costs less than lithium-ion batteries because it requires significantly less nickel and cobalt. One downside is that it is less energy dense and requires more physical space than lithium-ion technology. 

Adam hopes Vessyll could someday tap Minnesota’s iron ore industry for materials, which he said operates in a much better regulatory environment than other countries. “We’re trying to stay away from child labor and African mining,” he said.

The Vessyll’s controls, he said, offer greater sophistication than other energy storage devices. He said the power output is three to four times faster than competitors, and the software can more precisely transfer stored energy to match building loads.

The first Vessyll pilot begins this month at the Colusa Indian Community in northern California. The tribe has a casino, resort and residences powered partly by large solar arrays functioning within a microgrid. Vessyll will provide uninterruptible power during outages, offering the tribe enough time to start diesel generators capable of providing backup electricity for hours, Adam said.

Bruce Geveden, owner of California-based Geveden Industrial Inc., will install a Vessyll on the tribe’s land. Geveden has known Adam since his years at Tesla and he likes Vessyll’s technology and size. Energy storage has become more popular as California’s utilities have moved to use time-of-use pricing.

“Batteries have become important over the past couple of years to reduce demand charges,” Geveden said.

Adam said Vessyll will ship five units in the third quarter of this year and 15 devices in the first quarter of 2024. Clients pay upfront for batteries before they receive the delivery.

Vessyll builds the systems at the University Enterprise Labs near the University of Minnesota. The long-term dream is to create a factory that would employ 1,500 people and produce a gigawatt of storage annually. For now, Adam has not given up his day job working for a San Francisco solar company, nor has Zahra.

In the short term, Adam said that if he can move to a manufacturing facility, the lead time needed to produce a Vessyll will go from 26 weeks to six to eight weeks. A dedicated manufacturing space with materials on hand “would be fantastic,” he said.

Aaron Hanson, energy program specialist at the University of Minnesota’s Institute on the Environment, said for commercial and residential customers batteries could become more valuable than just backup power as utilities move toward time-of-use pricing. Customers with energy storage will have an easier time shifting electricity use to hours when rates are lower, potentially shaving their utility bills.

Hanson added that battery storage needs more diversity of materials in technological applications. 

“We need more than one approach in battery storage technology,” he said. “It will be interesting to see how this technology performs.”

St. Paul battery startup sees promise in helping businesses manage power is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.