America’s industrial future is taking shape just across the state line from Ortonville, Minnesota.

California-based Antora is commissioning one of the world’s largest battery energy storage projects next to an ethanol refinery operated by POET, the planet’s biggest biofuels producer, near Big Stone City, South Dakota.

Unlike the electrochemical batteries that support small electronics, electric vehicles and the power grid itself, Antora’s thermal battery technology converts electricity to heat and stores it in carbon blocks that remain stable at temperatures four or five times higher than a pizza oven and nearly twice as hot as a cement kiln, one of the toastiest industrial environments around. That’s plenty hot for ethanol plants’ industrial-scale dryers, which run at a few hundred degrees Fahrenheit.

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Less than a year ago, the site was an empty lot. Last week, the system’s more than 200 batteries were “turning on, row by row,” said Antora cofounder and chief operating officer Justin Briggs.

The company’s batteries will closely tie POET’s plant to nearby wind farms and reduce its reliance on the aging, increasingly expensive coal-fired power plant that now supplies its steam alongside an onsite natural gas boiler. They’ll also allow POET to scale up production and inject tens of millions of additional dollars into the regional economy primarily through payments to corn growers, according to Noah Long, Antora’s director for state and regulatory affairs. (POET did not respond to requests for comment for this story.)

In 2024, former President Joe Biden’s Department of Energy gave Antora $14.5 million to expand production of a technology it said “turns low-cost renewable energy into reliable, on-demand heat and power” for industrial plants.

“President Biden is helping to scale up the next generation of clean energy solutions that will advance the nation even further toward our net-zero goals,” then Energy Secretary Jennifer Granholm said at the time. 

Those goals are gone under President Donald Trump and current Energy Secretary Chris Wright, a former fracking executive fond of sharing misinformation about renewable energy, fossil fuels and the costs of climate change. But in the Upper Midwest and elsewhere, there’s still plenty of interest in boosting industrial efficiency among plant owners, utilities, and state officials — in part because some projects create value well beyond the plant fenceline. 

In July, for example, South Dakota utility regulators approved a special rate structure for the Big Stone City batteries to cheaply soak up excess wind power that would likely go to waste otherwise due to lack of demand or available transmission capacity. The tariff, as it’s known in the industry, is backed by a 20-year electric service agreement that includes “protections for other customers.”

“It’s a win for all ratepayers if we can use that wind effectively,” Francesco Aimone, industrial electrification fellow at the Center for Climate and Energy Solutions, told MinnPost.

The tariff is not a sweetheart deal for a big new electricity customer. It’s recognition that “we are a very unique energy customer on the grid [and] what we need is different from what other customers need,” Long said.

Antora’s batteries can store and discharge power over long periods of time, which “allows us to be very selective as to when to charge and when not to charge,” Long added. “So we can be really sure that we’re using the least valuable hours on the grid.”

The system can also respond quickly if grid conditions change, Briggs said. The blocks charge off resistive heating elements — “like your toaster” — that heat up and cool down with little preamble.

Still, innovative industrial efficiency projects, and particularly first-of-a-kind partnerships like Antora and POET’s, often require favorable public policy, regulation and economics to get off the ground. Those that don’t — too many to count — can blame some combination of high upfront costs, the “spark gap” between the price of electricity and natural gas, regulatory uncertainty, inadequate public policy, and the uncomfortable (and unquantifiable) truth that sticking with a ‘good enough’ status quo is easier than going out on a limb.

Industrial energy efficiency’s quiet star of the show: MVR

Minnesota has more than 8,500 manufacturers employing around 323,000 workers, but the sector’s environmental impact is top-heavy, according to a February report prepared by 5 Lakes Energy, a Michigan clean energy consultancy.

Just 37 facilities emit 87% of Minnesota’s industrial greenhouse gas pollution, according to the 5 Lakes report. Flint Hills Resources’ Pine Bend petroleum refinery is the runaway leader, followed by U.S. Steel’s Minntac mine and ore processing plant, two northern Minnesota paper mills, another petroleum refinery, some beet sugar plants and more taconite facilities. Several biofuels plants make the top 50.

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These are big, complex facilities are challenging to retrofit without significant policy support, Elizabeth Boatman, the lead consultant on 5 Lakes’ industrial decarbonization team.

On paper, it’s easier for smaller or simpler facilities to make improvements that reduce emissions, Boatman said. But the numbers need to make sense and the tradeoffs need to be manageable. They’re often skeptical of investments that take longer than a few years to pay back and reluctant to shut down production lines unless they have redundant capacity elsewhere. It can be less intrusive — and still fruitful — to make upgrades that don’t affect core production processes, like electrifying space heating, Boatman said.

“Smaller facilities function differently from an economic perspective,” she said. “It’s a difference between being able to shut down for a few days or not.”

For production itself, the most appealing investments are those that make existing processes more efficient. 

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5 Lakes Energy estimates that at any given moment, Minnesota factories consume about 4.3 gigawatts of low- and medium-temperature heat energy — a couple large nuclear reactors’ worth. According to Aimone, much of that heat can be captured, upgraded and reused with existing, relatively low-cost technology that can dramatically improve process efficiency and reduce operating costs.

“The cheapest heat is the heat you already have,” Aimone said.

One quiet star of the show is mechanical vapor recompression, a technology that compresses and reheats waste vapor — often steam — and feeds the heat back into the main process. It’s perfectly suited for energy-intensive processes with high steam demand, such as grain drying, ethanol distillation and chemical synthesis, according to Ruth Checknoff, a senior director with the Renewable Thermal Collaborative.

“It’s notable how many MVR systems are already in use in the United States,” Checknoff said.

Tara Schuelke, a director with Hilmar, said on a March webinar hosted by RTC that adding an MVR system at her company’s California dairy would cut its natural gas use by more than 1 million therms per year — roughly the annual consumption of 1,000 Minnesota homes.

Aemetis, a publicly traded biofuels company, is also adding an MVR — also in California — that will be powered in part by an on-site solar array. On an earnings call earlier this month, chairman and CEO Eric McAfee said the combination of reduced natural gas consumption and increased earnings from state and federal incentives for low-carbon fuels will boost Aemetis’s annual cash flow by about $32 million.

Even promising opportunities hinge on policy and permitting 

It’s no accident that these investments are happening in California, home to some of the world’s most ambitious decarbonization policies. 

Among them is a stringent low-carbon fuel standard that rewards environmentally-friendly biofuels producers. That standard is directly relevant to companies like POET, which will likely see a significant drop in carbon intensity at its Big Stone City refinery from Antora’s thermal battery system.

Adding an MVR can reduce ethanol refineries’ carbon intensity by “six to 13 points” while cutting total plant energy consumption by 50%, according to a 2024 presentation from Energy Integration, Inc., a Colorado-based firm that designs energy recovery systems for biofuels producers. 

Plants with MVRs also use significantly less water for cooling, a plus for host communities that draw drinking water from the same sources, Bill Schafer, EII’s CEO, told MinnPost.

But those clear-cut benefits aren’t always enough to get projects over the finish line. 

EII’s presentation called out what at the time appeared to be a promising MVR opportunity at a western Minnesota ethanol plant owned by Granite Falls Energy. The company, which also owns an ethanol plant near Heron Lake, Minnesota, and did not respond to a request for comment for this story, got a $1 million grant from the United States Department of Agriculture to install an MVR that would help it boost ethanol production by up to 8.3 million gallons, reduce electricity consumption by the equivalent of nearly 60 homes each year and save almost $30 million per year, according to EII.

Related: Minnesota taconite mines explore new technology to reduce energy, water use

“Both of those plants are fantastic candidates for MVR technology,” Schafer said. “Our design [for GFE] drastically reduced the amount of natural gas they would consume.”

Those savings would have come from reduced operation of the facility’s steam boiler. Ironically, that would have put GFE out of compliance with a preexisting state air permit that required it to run the boiler enough to destroy a minimum amount of volatile organic compounds created by the facility’s drying process. Installing the MVR would have meant seeking a new permit for the boiler, “and that was scary for them,” Schafer said. 

“The biggest challenge I hear from people in Minnesota is it’s very difficult to work with state permitting,” he said.

It’s not the only one. For Minnesota manufacturers looking beyond waste heat recovery toward electrifying higher-temperature processes, affordable natural gas — which is cheaper in gas-rich North America than in most other parts of the world — is the most widespread sticking point, said Brandon Isakson, managing director for industry at Fresh Energy.

“The ‘spark gap’ is our biggest challenge for sure,” Isakson said in an interview, using the industry term for the price difference for equivalent units of electricity and gas.

The spark gap varies from state to state, but Aimone said it’s about 4 to 1 in Minnesota. Isakson said the gap could be even wider for big industrial customers that buy discounted gas directly from pipeline companies, rather than the local retail distribution utilities that serve residential and smaller commercial customers. According to the U.S. Energy Information Administration, pipeline companies delivered about 51% of industrial gas purchases in 2018, the most recent data year.

Utilities play important role in industrial energy saving projects

Isakson said he’s heard more talk of hedging gas-price volatility since the late-February outbreak of hostilities in the Middle East, along with tentative signs that some industrial companies are rethinking what it means to depend on out-of-state or out-of-country fuel supplies. In the longer run, many commodity experts expect U.S. natural gas prices to reset higher as large-scale data centers compete with existing industrial customers for pipeline gas and more liquified natural gas export terminals come online on the Gulf Coast.

“The most forward-looking companies will project [those trends] far enough out” and may conclude that it makes sense to shift off gas over time, Isakson said. 

But with the math unlikely to shift dramatically against natural gas anytime soon, individual industrial firms’ investment decisions remain dependent on utility programs, state regulation, and public policy decisions made in St. Paul and Washington. For serious industrial facilities like POET’s Big Stone City refinery, special utility tariffs like the one South Dakota regulators approved last year will be critical — perhaps along with other regulatory changes proponents say would more accurately reflect thermal batteries’ value for the electric grid.

Minnesota utilities contacted by MinnPost say they’re broadly on board with the idea of industrial efficiency and beneficial electrification. Many, including gas-only utilities like CenterPoint Energy’s Minnesota subsidiary, work closely with individual industrial customers to develop customized programs. 

A spokesperson for Xcel Energy, Minnesota’s largest investor-owned utility, told MinnPost the company’s energy efficiency rebates for large commercial and industrial customers helped save more than 300,000 dekatherms of natural gas in 2025 — about 3,000 Minnesota homes’ worth.

For CenterPoint, a relatively new Minnesota law known as the Natural Gas Innovation Act gives it more flexibility to help customers achieve more ambitious goals, Emma Ingebretsen, CenterPoint’s manager for decarbonization projects, said in an interview. 

“[This is] a new regulatory mechanism that allows us to help customers with decarbonization opportunities above and beyond what we’re able to do with traditional energy efficiency programs,” she said.

Minnesota utilities aren’t simply copy-pasting each other’s strategies, however.

Otter Tail Power, the Fergus Falls-based utility that serves POET’s Big Stone City refinery and more than 100,000 other customers in western Minnesota and the eastern Dakotas, proactively sought and received approval for thermal energy storage tariffs in Minnesota and North Dakota despite having no active projects in those states, spokesperson Stephanie Hoff told MinnPost. 

Xcel Energy, Minnesota’s largest investor-owned utility, appears more hesitant. When the Minnesota Public Utilities Commission asked stakeholders to weigh in on whether it should order Xcel to propose its own thermal battery tariff, Xcel said such a broad framework is not yet warranted for what it called an “emerging technology.” Otter Tail developed its own tariff for a single customer — POET’s Big Stone facility — with “a site-specific reliability issue” caused by an increasingly unreliable steam supplier in the coal plant next door, Xcel said. 

(Asked whether the setup at Big Stone could translate to other ethanol plants, Antora’s Briggs said it could — and to other industrial facilities, like pulp and paper, chemicals and data centers. “This was not sort of a unique situation…it comes down to the product that we’re offering: reliable energy around the clock,” he said.)

The idea of a broad thermal battery tariff has unusually wide support, however, from consumer advocates, environmental groups and industrial companies, all of which filed briefs pushing for Xcel to propose one.

“There’s not many times those three groups are on the same side of the issue,” Sydnie Lieb, a deputy commissioner with the Minnesota Department of Commerce, told MinnPost in an interview. 

Lieb’s department is among those arguing for the Xcel tariff, in part because thermal batteries that soak up excess renewable energy are “a unique opportunity for improved grid utilization, which is better for ratepayers,” Lieb said. The commission could decide on the Xcel thermal battery tariff question this summer, she added.

Whether that decision changes the math for any of Xcel’s industrial customers is a question for another day.

Editor’s note: This story is the first in a four-part series on clean energy innovations within Minnesota’s industrial sector. The series is underwritten by Fresh Energy, which like all MinnPost funders does not weigh in on editorial decisions.