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This article was produced for ProPublica’s Local Reporting Network in partnership with High Country News. 

When Yakama Nation leaders learned in 2017 of a plan to tunnel through some of their ancestral land for a green energy development, they were caught off guard.

While the tribal nation had come out in favor of climate-friendly projects, this one appeared poised to damage Pushpum, a privately owned ridgeline overlooking the Columbia River in Washington. The nation holds treaty rights to gather traditional foods there, and tribal officials knew they had to stop the project.

Problems arose when the Federal Energy Regulatory Commission, the agency in charge of permitting hydro energy projects, offered the Yakama Nation what tribal leaders considered an impossible choice: disclose confidential ceremonial, archaeological and cultural knowledge, or waive the right to consult on whether and how the site is developed.

This put the Yakama Nation in a bind. Disclosing exactly what made the land sacred risked revealing to outsiders what they treasured most about it. In the past, disclosure of information about everything from food to archaeological sites enabled non-Natives to loot or otherwise desecrate the land.

Even now, tribal leaders struggle to safely express what the Pushpum project threatens. “I don’t know how in-depth I can go,” said Elaine Harvey, a tribal member and former environmental coordinator for the tribal fisheries department, when asked about the foods and medicines that grow on the land.

“It provides for us,” echoed Yakama Nation Councilmember Jeremy Takala. “Sometimes we do get really protective.”

Although government agencies have sometimes taken significant steps to protect tribal confidentiality, that didn’t happen with the Pushpum proposal, known as the Goldendale Energy Storage Project. Tribal leaders repeatedly objected, telling the agency that if a tribal nation deems a place sacred, they shouldn’t have to break confidentiality to prove it — a position supported by state agency leaders and, new reporting shows, at least one other federal agency.

Nonetheless, after seven years, in February FERC moved the project forward without consulting with the Yakama Nation.

The process known as consultation is often fraught. Federal laws and agency rules require that tribes be able to weigh in on decisions that affect their treaty lands. But in practice, consultation procedures sometimes force tribes to reveal information that makes them more vulnerable, without offering any guaranteed benefit.

The risks of disclosure are not hypothetical: Looting and vandalism are common when information about Indigenous resources becomes public. One important mid-Columbia petroglyph, called Tsagaglalal, or She Who Watches, had to be removed from its original site because of vandalism. And recreational and commercial pickers have flooded one of Washington’s best huckleberry picking areas, called Indian Heaven Wilderness, pushing out Native families trying to stock up for the winter.

The Yakama Nation feared similar outcomes if it fully participated in FERC’s consultation process over the Goldendale development. But there are alternatives. The United Nations recognizes Indigenous peoples’ right to affirmatively consent to development on their sacred lands. A similar model was included in state legislation in Washington three years ago, but Gov. Jay Inslee vetoed it.

The requirements of the consultation process are poorly defined, and state and federal agencies interpret them in a broad range of ways. In the case of Pushpum, critics say that has allowed FERC to overlook tribal concerns.

“They’re just being totally disregarded,” said Simone Anter, an attorney at the environmental nonprofit Columbia Riverkeeper and a descendant of the Pascua Yaqui and Jicarilla Apache nations. “What FERC is doing is so blatantly, blatantly wrong.”

The Yakama Nation has been outspoken in its support for renewable energy development, including solar and small-scale hydro projects. But not at Pushpum; it’s sacred to the Kah-milt-pah people, one of the bands within the Yakama Nation, who still regularly use the site.

The proposal would transform this area into a facility intended to store renewable energy in a low-carbon way. Rye Development, a Florida-based company, submitted an application for permits for a “pumped hydro” system, where a pair of reservoirs connected by a tunnel store energy for future use.

FERC has offered few accommodations for the Yakama Nation on the Goldendale project.

FERC spokesperson Celeste Miller told High Country News and ProPublica in an email that “we will work to address the effects of proposed projects on Tribal rights and resources to the greatest extent we can, consistent with federal law and regulations. This is a pending matter before the Commission, so we cannot discuss the merits of this proceeding.”

“FERC legally doesn’t have to do very much here,” said Kevin Washburn, a dean of the University of Iowa College of Law, a citizen of the Chickasaw Nation of Oklahoma and a former assistant secretary of Indian affairs at the Department of the Interior. “Consultation is designed to open the door so tribes can get in the door to talk to decision-makers.” According to experts, the process can range from collaborative planning that addresses tribal concerns to a perfunctory discussion with minimal impacts, depending on the agency.

“This is the problem with consultation and its lack of teeth,” said Anter. “If the federal government is saying, ‘Hey, we consulted, check that box,’ who’s to say they didn’t?”

There’s another problem with consultation, too: Any discussions with a federal entity are subject to public disclosure. That’s good for government transparency, Washburn said, but it can make tribal nations even more vulnerable. “And it’s why tribes are right to be cautious in what they share with feds,” he said.

That’s an obstacle at Pushpum. Things became even harder there in August 2021, when FERC notified the Yakama Nation that federal consultation would be carried out not by the agency itself, but by the developer. The Yakama Nation pushed back, asserting its treaty rights to negotiate as a sovereign nation only with another nation, not with a private entity. FERC, however, insisted that designating a third party was “standard practice.” The National Historic Preservation Act, signed into law in 1966, says an agency “may authorize an applicant or group of applicants to initiate consultation,” but maintains that the federal agency is still “responsible for their government to government relationships with Indian tribes.”

The Yakama Nation also worried about commission rules that require anything the tribal nation says to FERC be shared with the developer. “It gets very sensitive when we share those kinds of stories,” said Takala, the tribal councilmember. “We just don’t share to anyone, especially a developer.”

Some say FERC could change that internal rule, since it isn’t required by law. “For them to cite their own regulations and be like, ‘Our hands are tied,’ is ridiculous,” Anter said. For months, FERC and the Yakama Nation went back and forth over the conditions under which the tribal government would share sensitive information, with the Yakama Nation repeatedly asking to share information only with FERC.

Ultimately, FERC proposed four ways the Yakama Nation could participate in consultation. In the eyes of tribal leaders, all these options either posed significant risks to the privacy of their information or rendered consultation meaningless.

The first three were laid out in a letter from Vince Yearick, director of FERC’s division of hydropower licensing, sent on Dec. 9, 2021. For option one, it suggested the tribal nation request nondisclosure agreements from anyone accessing sensitive information. Yearick did not specify whether FERC would be responsible for issuing or enforcing these NDAs.

Delano Saluskin, then-chair of the Yakama Nation, called this option “far from the requirements of NHPA or in line with the trust responsibility that the Federal Agency has to Yakama Nation,” citing FERC policies and National Historic Preservation Act law in a February 2022 letter to state and federal government officials requesting support. He added that it “describes a process that does not protect information that is sacred and sensitive from disclosure.”

Alternatively, FERC said, the Yakama Nation could simply redact any sensitive information from documents it filed. This option, however, would leave FERC in the dark about the details of what cultural resources the project would imperil. That would make it harder for FERC to require project adjustments or weigh the specific impacts in its decision about whether to permit construction.

Third, the Yakama Nation could withhold sensitive information altogether, which would present similar problems.

Lastly, in a June 2022 follow-up letter, the commission suggested that the Yakama Nation submit a document “with more details regarding the resources of concern” and a request that some of the information be treated as privileged or withheld from public disclosure.

Overall, Saluskin described FERC’s options as a “failure” to conduct legal consultation in good faith.

A federal agency similarly raised concerns: In May 2023, the Advisory Council on Historic Preservation, which advises the president and the Congress on protecting historic properties across the country, wrote to FERC suggesting that it “provide the Tribes with opportunities to share information that will be kept confidential.” FERC’s rule regarding disclosure, the council said, could insulate the agency from meaningful consultation, “and as a result from any real understanding of the nature and significance of properties of religious and cultural significance for Tribes.”

The concerns over FERC’s engagement with the Yakama Nation are part of a wider discussion of whether and how the U.S. government should protect tribal privacy and cultural resources. Speaking at a tribal energy summit in Tacoma in June 2023, Allyson Brooks, Washington’s state historic preservation officer, said that even though the consent language was vetoed by the governor, state law for protecting confidentiality around tribal cultural properties is still stronger than federal law, which only protects confidentiality if a site is eligible for the National Register of Historic Places.

In Washington, if a tribal historic preservation officer says, “‘X marks the spot; this is sacred,’ we say, ‘OK,’” Brooks declared. She said asking tribal nations to prove a site’s sacredness is like asking to see a photo of baby Jesus before accepting the sanctity of Christmas. “You don’t. You say ‘nice tree’ and take it at face value. When tribes say ‘X is sacred,’ you should take that at face value too.”

That approach is vital to the Yakama Nation, which recently saw a developer involved with a project proposed in nearby Benton County leak information that the nation believed was private.

The Horse Heaven Hills wind farm would be the biggest energy development of any kind in Washington state history. But the sprawling 72,000-acre project overlaps with nesting habitat for migratory ferruginous hawks, a raptor state-listed as endangered.

Court documents related to the permitting proceedings show that the Yakama Nation believed it had identified the locations of the ferruginous hawks’ nests as confidential, in part because the hawks are ceremonially important. In May 2023, the Yakama Nation requested a protective order from the Energy Facility Site Evaluation Council, a state-level analog of FERC. The order, which the council issued, instructed all parties to sign a confidentiality agreement before accessing confidential information, similar to the nondisclosure agreements FERC proposed. If any party disclosed that information, they could be liable for damages.

But the order didn’t stop that information from getting out. In February 2024, the Seattle Times published a story on the Horse Heaven Hills wind farm, which included a map of ferruginous hawk nests — a map that was credited to Scout Clean Energy, the developer.

The Yakama Nation quickly filed a motion to enforce the protective order, alleging that Scout Clean Energy had transgressed by passing protected cultural information to the press.

The developer counter-filed, claiming that even if nest locations were a part of confidentiality discussion, the map itself was not, and that it was so imprecise that the critical details remained confidential. The council ultimately agreed.

Despite the risks, Washburn said that tribes should take any opportunity to share their stories with federal officials, even if the conditions aren’t perfect. “I wouldn’t necessarily encourage tribes to give their deepest, darkest secrets to a federal agency,” he said. “But I would encourage them to meet with FERC and try to give FERC a first-person account of why they think this is important.”

Not all experts agree. Brett Lee Shelton, a member of the Oglala Sioux Tribe and an attorney at the Native American Rights Fund, said FERC is out of step with other federal and state agencies. “It’s hard to believe that it’s anything but disingenuous, using that tactic,” he said. “It’s pretty well known by any agency officials who deal with Indian tribes that sometimes certain specifics about sacred places need to remain confidential.”

And for Bronsco Jim, a spiritual leader of the Kah-milt-pah people, sharing too many details is out of the question. Cultural specifics stay within the oral teachings of the longhouse, the site of the Kah-milt-pah spiritual community. Jim said he doesn’t even know how to translate all of the information into English. “We don’t write it, you won’t see it posted. You won’t see it in books. It’s our oral history. It’s sacred.”

In a push for green energy, one federal agency made tribes an offer they had to refuse 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.

At 1.5 megawatts, the battery destined for a college campus near Petersburg, Virginia, might not be the mightiest in Dominion Energy’s growing storage fleet.

But don’t underestimate its power and reach.

In addition to providing backup power for Virginia State University’s main sports and entertainment venue, it will serve as a hands-on laboratory and research project for engineering students and faculty at the historically Black university.

“This is so exciting,” said Dawit Haile, dean of VSU’s College of Engineering and Technology. “Our students don’t know the challenges we are having to save energy when you need it later. Storage is the missing piece.”

It isn’t the first time the 4,000-student university has collaborated with the state’s biggest utility. For several years, Dominion has lined up professionals to teach students enrolled in a specialized power and energy curriculum. 

That relationship prompted Haile to nudge Dominion when he found out the utility was seeking sites to test metal-hydrogen battery technology instead of a more commonplace lithium-ion model. The appeal of metal-hydrogen, a standard in the aerospace industry, is that the materials are longer-lasting and much slower to discharge.

“We were actually looking for a university so we could pull in the learning aspect,” said Dominion’s Ellen Jackson, program manager for the pilot project. “VSU really wants this to be a visible part of their campus.”

Utility regulators are now reviewing the proposal, which a hearing examiner with the State Corporation Commission has already recommended for approval. If greenlighted, it is expected to be operational by the end of 2027.

“Cost for the whole kit and caboodle is $14.4 million,” Jackson said, referencing the architectural design, construction and installation of a final product with a footprint that will likely include more than two dozen containers measuring 11 feet by 9 feet.

Haile, who has taught at VSU for 27 years, is eager for students to dive into lessons about battery configuration, building and maintenance. Collected data will help them assess efficiency, longevity and operational costs.

“So many of us take it for granted that energy powering our homes will be there, and we don’t think about the source,” he said. “Any opportunity we get to help students learn more about this profession, it’s a plus.”

On target for 250 MW by 2025

The VSU pilot project is a small slice of the volume of battery storage the General Assembly expects Dominion to meet to comply with the Virginia Clean Economy Act. 

By next year, that number needs to reach 250 MW. Targets are slated to rise to 1,200 MW by 2030 and then more than double to 2,700 MW by 2035. Dominion is aiming for 65% of the battery projects to be company-owned and the remainder to be power purchase agreements with third-party owners.

“We’re well on our way to meeting that first target,” said Brandon Martin, who manages a business development team that oversees Dominion’s battery projects. “We’ve seen a lot of pricing volatility, but some of that will start to work its way out.”

Thus far, Dominion has petitioned the State Corporation Commission for a total of 180 MW of battery storage projects. Of those, 98 MW are company-owned and the remaining 82 MW have third-party owners with power purchase agreements.

The largest one that regulators have approved is at Dulles International Airport in Northern Virginia’s Loudoun County. 

Once completed in late 2026, it will generate up to 100 MW of solar energy and store up to 50 MW of power, enough clean energy to electrify more than 37,000 Virginia homes at peak output. Dominion broke ground on that project last August.

“In the big picture, battery storage might be in its infancy, but it’s the unsung hero of the renewable energy profile,” Martin said. “It’s critical to be able to store and discharge when the sun isn’t shining and the wind isn’t blowing.”

Meanwhile, the 1.5 MW initiative for VSU is one of three non-lithium-ion battery projects — totaling about 10.5 MW — under review by regulators. Other pioneering projects in the mix are a 5 MW iron-air battery and a 4 MW zinc-hybrid battery that Dominion plans to install at the gas-fired Darbytown Power Station in Henrico County, near Richmond.

If approved, construction on the pair of Darbytown pilots would be operational by late 2026.

Batteries aren’t a one-size-fits-all technology, said Martin, adding that smaller projects are geared for the distribution side of electron delivery.

“Trying out nascent technologies is going to be critical for future deployment,” he said. “Utilities need to know if they’ll perform as anticipated.”

Interim energy storage targets spelled out in the Clean Economy Act allow the utility to innovate with a variety of technologies before scaling up. 

The advantages of experimenting with resources other than lithium is the extended discharge time, availability and durability, Martin said. For instance, an iron-air battery can discharge power for up to 100 hours. While zinc-hybrid batteries have roughly the same discharge time as a lithium-ion model, they’re manufactured with a readily accessible chemical element.

“They don’t compete with the same raw materials,” he said, referencing the high demand for lithium for electric vehicles, cell phones and other electronics. “As you’re thinking about geopolitical concerns and price volatility, these components take that out of the mix.”

Still, Martin continued, promising ideas need a path to commercialization or they will stay on a shelf gathering dust.

“It’s exciting that this space has a number of new entrants,” he said. “Other utilities will be piloting different technologies. By not all choosing the same ones, the energy community can learn what’s successful and where much quicker.

“We want to provide as many solutions as possible at the lowest cost to customers.”

Battery to be shipped from Kentucky

The teams that both Martin and Jackson lead have spent countless hours comparing notes with utility peer groups, technology vendors and experts at the nonprofit Electric Power Research Institute (EPRI) to narrow down their battery choices.

For instance, Dominion has contracted with EnerVenue, a California company, to build the metal-hydrogen battery for the VSU campus.

The company, founded in 2020 by a Stanford University materials science researcher, is borrowing the same technology that the National Aeronautics and Space Administration deployed to power signature — and distant — enterprises such as the Hubble Space Telescope, the Mars Exploration Rovers and the International Space Station.

“This is a proven chemistry that we are commercializing for the grid,” said Brad Dore, EnerVenue’s vice president of global marketing. “The difference is that NASA didn’t have to care about the cost — and we do.”

In a nutshell, here’s how it works. During the energy charging process, the water inside the vessel is split, creating hydrogen gas. At discharge, that gas recombines into water.

Such batteries can discharge for up to 12 hours, said Dore, more than double the capability of a typical lithium-ion battery. 

He emphasized that the charging process is stable, repeatable and doesn’t cause the degradation common with battery chemistries such as lithium-ion. The other plus, he added, is that the metal, which is 99% nickel, means most of the battery is recyclable when it does finally wear out.

Once Dominion partnered with VSU, the utility collaborated with EPRI researchers to sort through technologies and manufacturers, as well as basics such as cost and land footprint.

“They did a lot of the legwork for us,” Jackson said about matching a battery with the 6,000-seat Multi-Purpose Center, which attracts audiences from the university and the community.

Fortunately, the battery won’t have to be shipped from California because EnerVenue announced a year ago that it is constructing an energy storage factory in Shelby County, in north central Kentucky. That will translate to a much shorter trip to the Petersburg campus three years from now. 

In the meantime, Haile and fellow faculty members are creating a power storage curriculum.

The professor is already anticipating the new battery could be a springboard to attract more on-campus energy storage projects as the technology evolves.

“The potential is huge,” he said. “Our mission here is access and opportunity, so to be able to show our students what the future is, that’s a big deal.”

Dominion battery pilot to provide hands-on training at historically Black university in Virginia 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.

Just about every week, Shawn Grant, who works for Salt Lake City-based Rocky Mountain Power, gets an inquiry from another utility looking for information about the company’s Wattsmart battery program.

“We want to do something. … How did you guys do it?’” Grant, the company’s customer innovation manager, says he’s often asked. “We’re always fielding those questions.” 

The program pays customers with solar who opt to install battery storage systems for the ability to use that stored electricity to help balance flows on the electric grid.

For customers, the benefits come in the form of lower electric bills and backup power in case of an outage. For Rocky Mountain Power, which has 1.2 million customers in Utah, Wyoming and Idaho, the program allows the company to harness the collective power stored in those distributed batteries to shave electric demand when it spikes rather than calling for more generation from a traditional power plant, among other uses.

“We’re using every battery every day to reduce demand on the grid,” Grant said. 

The concept is known as a virtual power plant, and grid operators, utilities, state regulators and lawmakers across the country are increasingly exploring the possibilities. They are seen as a cost-effective way to aid an electric grid that in many parts of the country is increasingly embattled by power plant retirements as well as difficulties building new, cleaner generation and the transmission lines they need — all at a time when huge projected electric demand increases loom.

“We’re now in this load-growth era,” said Robin Dutta, acting executive director at the Chesapeake Solar and Storage Association, a solar and storage industry group focused on Maryland, Virginia and Washington, D.C. “When you’re mitigating peak demand growth at the source, that’s perhaps the most cost effective way to modernize the grid.”

‘Faster, better, cheaper’   

Nearly 800,000 American homes installed a new solar or solar and energy storage system in 2023, according to the Solar Energy Industry Association. That growth set a record, with about 6.8 gigawatts installed, a 12% increase from 2022. Electric vehicles, another potential grid resource as a store of energy, also broke a sales record last year, despite consumer uptake being slower than some expected.

“These are devices that people are buying anyway because they’re faster, better, cheaper and virtual power plants allows everybody to leverage these devices while putting some money back in the pockets of people that bought the thing in the first place,”said Brian Turner, a director at Advanced Energy United, a clean energy trade group

The U.S. Department of Energy found in a report last year that large-scale deployment of virtual power plants “could help address demand increases and rising peaks at lower cost than conventional resources, reducing the energy costs for Americans — one in six of whom are already behind on electricity bills.”

They’re not a new concept, the DOE noted, adding that most existing virtual power plants are so-called demand response programs. In Virginia, for example, the commonwealth for years has run a program that enrolls hundreds of public facilities (airports, universities, K-12 schools, municipal buildings, water treatment plants and others) that agree to reduce or shift their electric demand to relieve strain on the grid. The DOE report says deploying 80 to 160 gigawatts of virtual power plants by 2030 could save about $10 billion in annual grid costs and would “direct grid spending back to electricity consumers.” At that scale, virtual power plants could meet between 10 and 20% of peak electric demand. The Rocky Mountain Institute, a research nonprofit focused on sustainability, called virtual power plants “a valuable and largely overlooked resource for advancing key grid objectives,” including reliability, affordability, decarbonization and electrification, among others.  

However, many states are starting to take notice of the potential:

• Maryland’s legislature just passed a bill that, among other provisions, requires utilities to create a pilot program to compensate owners of distributed energy resources like solar and battery storage for services they provide to the grid. “Ratepayers and consumers who invest in clean energy systems should see financial benefits when they provide meaningful grid services,” said Del. David Fraser-Hidalgo, a Democrat from Montgomery County who carried the House version of the bill. “Our DRIVE Act does just that; pairing battery storage with renewable generation will help Maryland achieve its clean energy goals, reduce our dependence on fossil fuels and mitigate the negative impacts of climate change.”
• Michigan, afflicted by expensive electric prices and high outage rates, has pending legislation, part of a package of pro-solar bills, that would create a virtual power plant program.
• In North Carolina, the state’s Utilities Commission has approved a Duke Energy pilot, called the PowerPair program, that it had directed the company to propose that will give customers incentives to install solar and storage. One group of customers will turn over control of the batteries to the utility and the other will participate in a test of “time-of-use rates,” which aim to shift customers’ usage to periods of lower demand, like running a dishwasher overnight, Utility Dive reported.
• In the summer of 2022, the New England Independent System Operator, which manages the electric grid for Maine, Vermont, New Hampshire, Massachusetts, Rhode Island and Connecticut, became the first such organization to use a virtual power plant, Politico’s E&E News reported. Sunrun, one of the nation’s largest solar installers, said it linked an estimated 5,000 small solar and battery systems to share 1.8 gigawatt hours of energy. In the summer of 2022, during a heat wave that sent temperatures soaring across New England states, residential and other non-utility solar installations reduced demand on the system by about 4,000 megawatts.
• The Pennsylvania Public Utility Commission announced in February that it was seeking comment on proposed rules related to use of distributed energy resources and virtual power plants. “Distributed resources provide the possibility for those who were traditionally consumers to play an active role in ensuring electric reliability and resiliency for themselves and their neighbors, and often in a less expensive way than traditional large generation that requires delivery infrastructure,” the commission’s chair and vice chair said in a joint statement. 
• Arizona Public Service, the largest electric utility in the state, counts 75,000 smart residential thermostats in its Cool Reward program, which provided nearly 110 megawatts of capacity during the summer of 2022. 
• A Colorado utility regulator is pushing for Xcel Energy to get a 50 megawatt virtual power plant up and running by the end of 2024, Utility Dive reported. The company, the state’s largest utility, already has a program called Renewable Battery Connect that allows it to discharge participating customers’ batteries during peak periods in exchange for financial incentives.
• In November, Puget Sound Energy, Washington’s largest utility, and AutoGrid, a California software company that provides distributed energy management systems, announced that they were expanding their partnership to develop a virtual power plant. “PSE’s VPP will reduce costs and help maintain reliable energy supply to its more than 1 million residential and business customers. Additionally, the VPP solution allows participating customers to receive monetary incentives for sharing assets with the grid and/or curtailing usage, something that’s financially beneficial for the community as well as helping the utility efficiently manage increasing electricity demand,” the companies said in a news release.

Why it matters

Experts who study and run the nation’s electric grid are worried about the pace of the energy transition. Old coal and gas plant retirements are accelerating, driven by economics, state clean energy policies and utilities’ own decarbonization goals. At the same time, massive backlogs in the queues to connect new power resources — overwhelmingly wind, solar and battery projects — in the regional transmission organizations that run the grid in much of the country mean big delays in replacing that retiring power generation. And after roughly a decade of flat electric demand, load growth is projected by many experts to explode as a result of transportation, industrial and home heating electrification, as well as a surge in data center development, among other factors. Throw in the fact that the construction of new transmission lines, essential to get excess power to where it might be urgently needed, has also stagnated and a problematic picture emerges. 

“Most utilities in the country are planning on pretty significant load growth,” said Turner from Advanced Energy United. ”They could plan to build a new peaker plant or they could plan to ‘build’ VPPs.”

That’s where utility incentives come into play.

Generally speaking, Turner said, utilities that operate transmission and distribution systems are more friendly to the idea. Companies that also own their own generation,  – and make a sizable chunk of their income from guaranteed profits on building new plants – , might not like the idea of a program that erodes the business case for a pricey new facility. 

“That’s why we have utility commissions,” Turner said. “They exist to say to the utility that virtual power plants are a cheaper option for the ratepayer and therefore you should implement it.”

However, even companies that might have resisted the idea are facing such dire electric-demand growth scenarios that virtual power plants may be attractive ways to get more flexibility out of the grid more quickly than building new generation.

“This is a way to get the capacity online faster and oftentimes cheaper,” Turner said. “Meeting that load growth is a real challenge in a lot of places.” 

‘Valuable and largely overlooked’: Interest in virtual power plants grows 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.