Back
Northwest Indiana residents say Nippon Steel’s acquisition of U.S. Steel could bring jobs and growth. But they’re still waiting on Nippon to deliver.
A year ago this month, Japan’s Nippon Steel acquired U.S. Steel, promising to plow $14 billion into America’s legendary but long-declining steel industry.
The hard-fought deal was controversial and highly politicized. But for residents in historic steel communities, like those in northwest Indiana, the foreign investment has come to represent a major opportunity.
Steel mills in the region make the metal that’s used to build the nation’s cars, skyscrapers, appliances, and naval ships. For over a century, the hulking facilities have driven the region’s economy and employed many thousands of workers — while also spewing toxins and planet-warming gases from their coal-fueled furnaces. Today, the jobs are declining even as the pollution continues.
The U.S. Steel buyout and other developments could provide funding needed to not only clean up but also reinvigorate Indiana’s mills, experts say.
Here are four takeaways of where that transformation stands a year into the acquisition.
When Nippon Steel bought U.S. Steel in June 2025, the Japanese firm pledged to build new metalmaking capacity and to modernize the Pittsburgh company’s aging infrastructure, including Gary Works in Indiana, which has been running since 1908.
Nippon Steel isn’t the only foreign manufacturer investing in the U.S. The Korean steelmaker Posco is also in talks to partner with America’s second-largest steel company, Cleveland-Cliffs, which owns the other two mills in northwest Indiana: Burns Harbor Works and Indiana Harbor Works. Posco is separately investing in the nearly $6 billion lower-carbon steel plant that Korean industrial giant Hyundai is building in south Louisiana.
The Trump administration’s high tariffs on steel imports are a key reason why the conglomerates are expanding their presence stateside.
But they’re also looking to capitalize on America’s rising demand for high-value steel that meets the exacting standards for vehicles and electrical equipment, and which represents a more attractive market than the commodity steel that’s flowing out of China.
“The U.S. market is now becoming a proxy battle between three of Asia’s largest steelmakers,” said Roger Smith, a Japan-based expert at the nonprofit advocacy group SteelWatch. He spoke during an April panel that Canary Media convened at the Society of Environmental Journalists’ annual conference, held this year in Chicago.
“This is unprecedented,” Smith added. “The future of the industry may well be decided in Seoul and Tokyo.”
Northwest Indiana’s steel mills certainly need the infusion of funding.
The region’s industry has gradually dwindled over decades because of rising overseas competition, increased automation, and the growth of steel-recycling mills in other parts of the country. At its peak in the 1970s, some 65,000 people worked in the state’s mills. Today, it’s closer to 9,000 people, and the workforce is expected to keep shrinking without further investment, according to an April report by Indiana University.
U.S. Steel and Cleveland-Cliffs have both seen their revenues decline in recent years, and much of the companies’ coal-based capacity is in need of expensive repairs and upgrades.
For activists like Jack Weinberg, the foreign funding represents a chance to rebuild the local industry using modern, lower-carbon methods.
Weinberg is a former steelworker and the green-steel lead for Gary Advocates for Responsible Development in Indiana. He said during the Chicago panel that transitioning away from coal is crucial not only for improving people’s health and addressing climate change — but also for ensuring Indiana’s steel industry can continue operating in a rapidly transforming market.
Today, northwest Indiana is the country’s top producer of high-performance flat-rolled steel.
The region’s “integrated” mills operate in two stages: first, iron ore is heated in coal-fueled blast furnaces to make virgin iron, then the molten metal is processed in a separate furnace to produce steel. The ironmaking step is the main driver of carbon dioxide emissions across the global industry, which accounts for about 9 percent of total annual CO2 emissions.
By making virgin iron, the Gary, Burns Harbor, and Indiana Harbor mills have long held an edge over America’s 150-plus mills that melt down recycled steel scrap in giant electric arc furnaces. While steel recycling is comparatively less carbon-intensive, those facilities’ products haven’t traditionally met the performance standards required by the auto, military, and certain other industries.
Yet the long-standing lines between integrated and steel-recycling mills are starting to blur, in ways that don’t necessarily bode well for northwest Indiana, Weinberg said.
Consider, for example, U.S. Steel’s Big River Steel Works in Arkansas. The sprawling site includes four electric arc furnaces, which use a mix of scrap metal and virgin iron to produce auto-grade steel. For now, that iron comes from Indiana’s Gary Works plant. But in late April, U.S. Steel said it was building a $1.9 billion plant to make iron on-site at Big River Steel, an investment made possible by parent company Nippon Steel.
The Arkansas facility will use natural gas to convert iron ore into iron pellets through the “direct reduction” process. Gas-fueled direct reduction plants can emit about half the CO2 emissions of coal-based blast furnaces. However, companies could produce nearly zero-emission iron if they instead used green hydrogen — which is made with renewable electricity and water — though the concept has been slow to scale up globally.
In Louisiana, Hyundai’s steel mill will include a direct reduction plant that feeds iron into two electric arc furnaces, similar to the setup in traditional integrated mills. The Korean manufacturer initially plans to use natural gas to make iron for its automotive steel but has said it intends to, at some point down the road, switch to green hydrogen.
Weinberg and other northwest Indiana residents hope that the Asian steelmakers will similarly invest in modernizing the region’s aging furnaces. Otherwise, the mills risk becoming uncompetitive and closing down by the 2040s, Gary Advocates for Responsible Development said in a January report. (U.S. Steel, for its part, criticized the group’s findings in statements to the Chicago Tribune.)
“People put up with all the health problems associated with coal-based blast furnaces because they needed the steel and didn’t have any alternative,” Weinberg said. “How long is the country going to put up with this when a cleaner way is available to do the same thing?”
Lisa Vallee, who lives in Whiting near the Indiana Harbor steel mill, said during the panel that shifting to cleaner steel production would be “life-changing” for the region.
Replacing coal-based blast furnaces would curb air and water pollution, while building renewable energy projects, producing green hydrogen, and modernizing steel plants could deliver an economic boost, said Vallee, who is an organizing director for the grassroots group Just Transition Northwest Indiana.
“We have the [steel] facilities, we have a workforce, we have the lake — we have everything we need in northwestern Indiana to create green steel,” she said. “It’s just the investment we need to actually make it happen.”
The 1-GWh battery project in Ohio will help suppress power prices and reduce grid strain from a nearby data center hub. The region could use a lot more systems like it.
Just northeast of Columbus, Ohio, the leafy Main Street of New Albany gives way to lush green fields and agrarian ponds — but soon the countryside transitions into mile after mile of enormous white boxes that emit a low hum. This patch of former farmland has become one of the densest clusters of AI computing in the nation, recently joined by Intel, which is constructing a $28 billion computer-chip factory at the northern end of the industrial bloc.
All of this requires a tremendous amount of electricity, but the area falls within the multistate market managed by PJM Interconnection, which has consistently struggled to bring new power plants online even as demand booms. The resulting power price spike has drawn the ire of both Republican and Democratic governors, who are demanding that PJM and tech giants figure out how to stop data centers from driving up costs for everybody around them. No less than the White House is pushing AI companies to “build, bring, or buy new power supply.”
A huge battery that just began construction in the heart of the New Albany computing cluster could model a way to accomplish that task.
Developer Eolian announced on Wednesday that it’s broken ground on its Flint Grid battery project. The first phase is due online by June of 2027, and will be able to inject 200 megawatts for up to five hours straight into an electrical substation that serves the computing hub. With 1 gigawatt-hour of storage capacity, this battery won’t just be the biggest on the 13-state PJM market; it’ll be the biggest battery east of the Mississippi.
The system will help lower electricity prices by charging up when energy is cheap and abundant and dispatching that stored power onto the grid at times of peak demand — exactly what big batteries have been doing for years in places like California and Texas.
“There are things that have been in progress for a long time, designed to solve these very problems,” said Eolian CEO Aaron Zubaty, in response to the “snowballing narrative” that the grid can’t keep up with demand.
Batteries have set new installation records in the U.S. year after year, swiftly becoming the nation’s top pick for on-demand capacity and beating out new gas plant construction. But construction has clustered in the West, and developers have struggled to make inroads in the Midwest or the densely populated Eastern Seaboard. However, now that those areas face tremendous AI data center growth, they could use the instantaneous power that massive batteries provide.
Eolian can deliver that in New Albany because the firm got started a decade ago, taking calculated risks that seem to have paid off.
“This isn’t just some random 200 megawatts,” Zubaty said. “This is 200 megawatts at the epicenter of one of the largest industrial buildouts ever seen in our country, and by putting it at this spot, it will actually allow more stuff to get built.”
Zubaty didn’t originally have Ohio top of mind for his clean energy ambitions. By the early 2010s, northern Virginia led the nation in data center density, and Zubaty wanted to develop solar farms near those major energy consumers. But he ran into obstacles finding enough land. Solar development had to contend with northern Virginia’s horse farms and suburban subdivisions, and further west from Dulles airport, you hit the Appalachian Mountains.
“Where do the mountains end? A little bit east of Columbus,” Zubaty said.
Central Ohio was already growing in population and economic vitality, Zubaty noted, anchored by a skilled workforce and The Ohio State University. And it had a lot of open space that could accommodate new growth if the titans of the internet wanted to branch out from northern Virginia.
“We started doing land research, looking at where we could build solar in proximity to the Columbus metro area,” Zubaty recalled. “Lo and behold, we stumbled upon a couple obscurely named LLCs that were buying up a bunch of land at substations, and it was Amazon.”
Amazon Web Services opened its first data center outside New Albany in 2016. That kicked off a frenzy of tech companies buying the larger parcels of land nearby. One smaller tract — with an old house, lots of foliage, and a small pond — got left behind in the land race as data center companies bought all the property around it. The owners agreed to sell to Eolian, which considered the acreage well suited for a battery plant.
Today, that house is gone, and the once-peaceful parcel is fully surrounded by looming warehouses filled with servers. Crucially, it abuts a substation owned by utility AEP that receives power from a high-voltage transmission line and feeds it to a lower-voltage line that loops through the data center region. That potent grid backbone is what makes it possible for the area to host so much computing — and gives the battery a means of charging up.
After securing the land, Eolian got to work on permits, interconnection to the grid, and approval from the Ohio Power Siting Board. At the time, PJM’s power prices were quite low, offering little incentive for companies to build new power plants, even as “we were watching this massive amount of data center development unfold at a really epic scale,” Zubaty said.
By 2025, Eolian was ordering transformers and other long-lead-time equipment, even though it lacked a deal to sell power to one of the many corporate customers operating nearby. In December, Zubaty had sufficient confidence in the project to bid it into PJM’s capacity auction, which would award contracts for power delivered for one year starting on June 1, 2027. The auction hit the maximum possible price, signalling that long-simmering demand had unquestionably outstripped supply in PJM.
That win started a clock ticking to build out the site, because “there’s a massive financial penalty to bidding and then not showing up,” Zubaty said. (Eolian also plans to add a second phase of the same size by 2029.)
Typically, power plant investors want to see decades of revenue commitments in order to finance construction. PJM, though, only offers one year of certainty for that capacity payment.
Eolian took the risk of building in the hopes that further contracts will materialize.
Now, it looks increasingly likely that one of the many hyperscalers in the area could sign a deal that lets it take credit for the battery project’s contributions to PJM capacity. This could offset that customer’s need to buy power at sky-high market rates, but it also may become necessary to operate at all.
Tech giants are under tremendous political pressure to figure out how to meet their electricity needs without burdening the power system overall, especially in PJM territory. The White House’s Ratepayer Protection Pledge has pushed leading AI companies to say they will cover their own energy costs. New York state recently froze data center construction for a year, giving itself time to make rules to prevent the development from driving up electricity costs, and other liberal states are considering similar measures.
Should hyperscalers look for a well-situated battery to help meet their needs, they won’t find many. PJM can’t wind back the clock and ask for more developers to have applied for grid connection and secured land near future AI hubs eight years ago. Nor is there any indication PJM will soon refine its rules to allow the kind of flourishing of batteries seen in Texas’ competitive wholesale market.
But once one developer shows it’s both possible and valuable to build big batteries in the region, the sheer pressure to meet the AI moment may carry more batteries through the impasse.
State lawmakers must decide whether to unlock $194M to fix aging school HVAC and plumbing systems or return it to utilities for a few dollars off monthly bills.
Should California spend nearly $200 million helping public schools install healthier and more efficient heating, ventilation, air-conditioning, and plumbing systems? Or should it send the money back to the state’s biggest utilities so their customers can pay roughly a dollar less on their monthly bills over the course of a single year?
That’s the choice that California lawmakers must make in the coming months.
The funds at stake are part of the California Schools Healthy Air, Plumbing, and Efficiency program, or CalSHAPE, which funds schools’ HVAC and plumbing repairs and upgrades. The state required its three big utilities — Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric — to fill the initiative’s coffers with about $1 billion in fees collected from customers between 2020 and 2023.
Although much of that total has already been doled out, $194 million in CalSHAPE funds has been frozen since 2024 as state leaders debate ways to curb skyrocketing energy bills. Because current law sunsets CalSHAPE at the start of 2027, the leftover money will revert to utilities by year’s end without legislative action.
Clean energy and community advocates are pressing lawmakers to prevent that from happening.
They want leaders to leverage a sprawling budget-negotiating document, known as a budget trailer bill, to extend the looming deadline and to direct the California Energy Commission, which administers CalSHAPE, to disburse the money to schools — many of which have already identified projects they want to pursue. That includes replacing old AC equipment to keep students comfortable as climate change fuels extreme heat, improving air-filtration systems, and swapping fossil-fueled heaters for all-electric heat pumps that can both warm and cool buildings.
“The $200 million or so that’s sitting unused would help about 120,000 students in California electrify their schools, which would reduce their air pollution and give them access to air conditioning,” said Leah Stokes, an associate professor of environmental politics at the University of California, Santa Barbara. That work, she added, is “not optional — it’s to protect kids from extreme weather events, from climate change, from fires, from heat waves.”
Nine members of the state Assembly have signed a letter asking lawmakers who chair key budget committees to extend the CalSHAPE funds. Unless legislation is introduced to alter the current state of affairs, the final decision on whether the $194 million will remain available for schools or be returned to the utilities on Dec. 1 will be made in budget negotiations between lawmakers and Democratic Gov. Gavin Newsom. While a final budget package must be settled by July 1, budget trailer bills that modify state law to implement a broader budget agreement have until Aug. 31, the end of this year’s legislative session, to be completed.
CalSHAPE was created by a law passed in 2020 that aimed to make schools — especially those in underserved areas and “fenceline” communities near polluting facilities — more energy efficient, healthy, and resilient. It has since given out nearly $800 million to more than 1,000 projects, according to a 2025 report from the California Energy Commission.
But the agency abruptly closed further grant applications in mid-2024.
It said it closed the program to ensure that schools had enough time to fully spend their awards before the program’s sunset. But according to a March analysis from a state Senate budget subcommittee, the funding was frozen “in part because legislation and other departmental reports focusing on energy affordability proposed to revert CalSHAPE funds to ratepayers.”
That statement refers to Assembly Bill 3121, introduced in mid-2024 by Assemblymember Cottie Petrie-Norris (D), who chairs the chamber’s Utilities and Energy Committee, in consultation with the Newsom administration. The bill proposed clawing back CalSHAPE funding, along with grants for solar on low-income multifamily buildings and batteries for medically vulnerable households, in an effort to curb the state’s fast-rising electricity rates.
Critics of that plan pointed out that pushing that money back to utilities was likely to yield only $30 to $50 in one-time rebates for customers — an amount they said was too little to validate axing the programs. Those arguments won the day, with AB 3121 failing to advance.
Yet the CalSHAPE funding has remained frozen, and Newsom has continued trying to return the funds to utilities. That’s left schools stuck in limbo. Of the nearly 5,000 schools that received grants to conduct initial assessments — nearly half of which are in underserved communities — only 172 have secured follow-on funding to complete recommended HVAC work, according to the pro-CalSHAPE coalition.
“We’ve been working for two years to try to get this funding revived,” said Keith Butler, deputy superintendent of Torrance Unified School District, in Southern California. His district used $1.6 million in first-phase CalSHAPE funding to deploy carbon dioxide–detecting thermostats and to hire an engineering firm to identify about 300 buildings, serving about 6,000 students, that need to replace decades-old air-conditioning units, he said.
“We were ready to push the button on round 2,” he said — a $6 million investment in replacing those AC units with modern equipment — “and then the plug got pulled.”
The California Energy Commission told Canary Media in an email that it is working with schools to process the nearly $800 million in previously allocated funds, but that “unallocated funding is anticipated to be returned to ratepayers.” The agency declined to comment on pending legislative discussions. Petrie-Norris’ office did not respond to multiple requests for comment.
Returning the unspent $194 million wouldn’t make much of a dent in utility rates. According to the March Senate budget subcommittee analysis, redirecting the funds back to customers “would result in savings of $2 per month for one year for San Diego Gas & Electric ratepayers, $1.25 per month for one year for SoCal Edison ratepayers, and $0.20 per month for one year for Pacific Gas & Electric ratepayers.”
Utilities aren’t obligated to use any unspent money to reduce rates under the law that authorized CalSHAPE, Stokes added. “My fear is that utilities will just do their creative accounting and shuffle things around and take that as profit,” she said.
California isn’t the only state looking to curb energy-efficiency spending to offer short-term utility bill relief. Democratic lawmakers in Maryland, Massachusetts, and Rhode Island, for example, have recently proposed cutting back on energy-efficiency programs to reduce fees on utility customers’ bills. Experts warn that such rollbacks are shortsighted, since lowering energy use through efficiency helps customers save money on their bills and drives down utility costs in the long run.
Efficiency upgrades can also help states meet their climate goals. The California Energy Commission forecasts that the projects funded by CalSHAPE so far will reduce greenhouse gas emissions by 3,300 metric tons, equivalent to taking 770 gasoline-fueled cars off the road for a year.
For example, the Santa Paula Unified School District, in Ventura County, is using $3.9 million in CalSHAPE funds to replace fossil gas–fueled condensers and furnaces at an elementary school with all-electric heat pumps and air-conditioning systems, said Douglas Henning, the district’s facilities and construction manager. “Everything we’re replacing, gas is going away,” he said.
These retrofits have significant health and wellness impacts too, Stokes noted. Students often struggle to concentrate in classrooms that are too hot or cold, and older HVAC systems may not properly filter air pollutants, such as vehicle exhaust or wildfire smoke. Richard Bruns, a scientist at Johns Hopkins University, found that the long-term benefits of school HVAC upgrades — which come in the form of improved health and educational outcomes — outweigh the costs by a factor of 30.
HVAC retrofits can also reduce the burden that schools put on the power grid. Some California school districts are piloting advanced AC control systems to shift when they draw electricity to avoid increasing peak loads on grids during heat waves.
Reducing that strain could lower costs for everyone by reducing the amount of money that utilities have to spend to upgrade their power grids. “Ratepayers will benefit from lower peak demand and lower environmental drag from using less electricity,” the Torrance district’s Butler said.
In an interesting twist, the ongoing dispute over CalSHAPE funding intersects with another controversial energy issue before the California legislature: what to do with the state’s biggest virtual power plant program.
Lawmakers are now haggling over whether to extend funding for that Demand Side Grid Support program or whether to close it down and redirect the funds to utility-managed VPP programs, which have been far less effective at delivering grid relief at an equivalent cost. The Newsom administration has proposed shifting roughly $70 million in interest generated by the CalSHAPE funds to the utility-run programs.
Stokes is among the advocates pushing to redirect that $70 million to the Demand Side Grid Support program, even as she works to retain the $194 million for school retrofits.
In both cases, Stokes said, the choices are to spend money as lawmakers originally intended or to give it back to the state’s politically powerful utilities. “The idea that we would rob from schoolkids to hand another blank check to utilities is to me unacceptable,” she said.
California, Massachusetts, and several other states are home to robust charging networks and strong consumer incentives that make it easy to go electric.
America’s EV industry has suffered a series of bad breaks over the last year and a half.
The end of federal tax credits for electric vehicles sent sales of new EVs off a cliff last fall. A nationwide buildout of chargers has been slow to get rolling. And the Trump administration has been dismantling air pollution regulations that were nudging the country away from gas cars.
But in the absence of a federal push for EVs, several states have been picking up the slack by building strong charging networks, introducing consumer incentives, and adopting other policies that make going electric a sweeter prospect.
A new analysis from the Brookings Institution dives deep on what makes a state an EV oasis, and scores states based on how far they’ve gone to promote vehicle electrification. At the top of its ranking? It’s a tie between California and Massachusetts, both of which scored 11 out of 13 possible points for overall EV readiness.
Massachusetts, New York, and Connecticut, meanwhile, have three major incentives to encourage average drivers to buy EVs: purchase rebates or tax credits, benefits like toll credits or parking perks, and no annual EV registration fees.
What about charging? Massachusetts and New York are the winners here, as they both have robust public charging networks, rebates that help people install chargers, and special utility rates for charging.
And yet Massachusetts still has room for improvement, according to Brookings. For one, EV manufacturers aren’t allowed to service vehicles in the state, which also lacks a plan for building out EV-charging infrastructure. As for California, the state’s annual registration fee for EV owners and lack of special utility rates for charging are weak spots.
At the other end of the spectrum, six states — Indiana, Louisiana, Montana, Ohio, Nebraska, and South Dakota — don’t have a single policy in place that’s getting them ready for an EV future, according to Brookings. Nineteen more have just a few EV-boosting policies on the books. Clearly state action alone won’t be enough to propel the entire U.S. toward a cleaner driving future.
Coal plants forced to stay open aren’t producing much power
The Trump administration has effectively stopped fossil fuel power plants from retiring on its watch, despite the strategy providing little benefit to the power grid and racking up hefty costs.
Six power plants, five burning coal and one burning oil and gas, had been slated to retire by the end of 2025, but were instead ordered to stay running to prevent what the administration called an “energy emergency.” At least one of those coal plants hasn’t operated at all under the emergency order, and another ran for only about two weeks, according to federal data reviewed by Utility Dive.
Altogether, the five coal plants produced just 1.5 million megawatt-hours of power during the first quarter of 2026, down 65% from what they generated during the same period last year. At the same time, the plants have racked up hundreds of millions of dollars in costs that could end up coming out of utility customers’ pockets.
Hyundai is building a massive steel mill in Louisiana. Will its neighbors benefit?
Hyundai’s plans to build a steel and iron plant in Louisiana could drive a clean revolution — or add yet another polluting factory to an area already known as “Cancer Alley.”
Canary Media’s Maria Gallucci recently visited the rural stretch between New Orleans and Baton Rouge where Hyundai is building a massive facility that will produce steel for automaking. At first, the plant will use natural gas to melt iron into steel — already a lower-carbon alternative than the coal that powers aging steel mills in the Midwest. But Hyundai has said it may later power its furnaces with hydrogen made from renewable electricity.
In the nearby city of Donaldsonville, residents and local leaders told Maria they’re skeptical Hyundai will actually follow through. They’re already surrounded by petrochemical facilities and oil refineries, and worry this latest factory won’t be any better for residents’ health or job prospects.
Read Maria’s thorough take on a complex story to learn more about the perils and promises of Hyundai’s green steel plans.
Nuclear ball out: The Trump administration announces $17.5 billion in loans to spur the development of 10 large nuclear reactors, with aims to begin construction by 2030 and get plants up and running in the next decade. (Associated Press)
Pumped-up home sales: A new report finds that installing an all-electric heat-pump heating and cooling system can increase a home’s resale value — as long as the appliance is mentioned in the real estate listing. (Canary Media)
Raising the roof: Warehouse roofs could be the perfect place to build solar arrays that can bring low-cost clean power to communities that can’t install their own panels, but states and utilities first need to do more to promote these community solar projects. (Canary Media)
Slated for takeoff: Jeff Bezos–backed EV startup Slate Auto says it has more than 180,000 reservations for its low-cost, bare-bones electric pickup, and customers now have a chance to preorder a vehicle with a $300 deposit. (Axios)
A data center surprise: The House Energy and Commerce Committee’s top Democrat, Rep. Frank Pallone, unexpectedly calls for a nationwide moratorium on data center development as Congress crafts legislation to protect household utility bills from spiking because of data centers’ massive power demands. (E&E News)
For years, heat pumps have outsold gas furnaces in the U.S. — and now the superefficient appliances are coming for conventional ACs, too.
Summer is officially here — and more Americans than ever are cooling their homes with heat pumps.
A decade ago, two conventional air-conditioning systems were sold for every one heat pump. Now, heat pumps are on the verge of outselling standard ACs.
In 2025, sales of the appliances were basically tied — and heat pumps even beat air conditioners in September, a first. Through April of this year, the already-slim gap has narrowed further. Compared with the same period last year, heat pump sales are up by about 1%, while AC sales are down by nearly 8%, according to data from the Air-Conditioning, Heating, and Refrigeration Institute, a trade group.
Heat pumps are essentially reversible ACs: The same unit both heats and cools a space. They’ve long been popular in more moderate climates, like the U.S. South, but in recent years their cold-weather performance has improved, and they’ve caught on in more frigid regions, too. Heat pumps have outsold gas furnaces for four years now.
It’s a big deal that more buildings are being outfitted with heat pumps. Heating is one of the largest sources of carbon emissions in the country, and heat pumps, which are two to four times more efficient than fossil-fueled systems, offer a much cleaner way to keep a space warm. The fact that they also cool homes is a climate benefit in its own right, as extreme heat makes air-conditioning a necessity rather than a luxury.
Many states, municipalities, and utilities have incentivized the adoption of the energy-efficient, zero-emissions technology.
Sometimes these incentives come in the form of direct rebates. Other times they manifest in wonkier places, like pro-electric building codes or preferential electricity rates for homes with heat pumps. Some states, like cold and snowy Maine, have even set — and exceeded — explicit adoption targets. (For a few years, the federal government offered incentives for the appliances, too, but President Donald Trump and congressional Republicans repealed those last year.)
All of this goes to explain why the gap is closing between conventional ACs and heat pumps — and why, soon, the efficient two-way tech will overtake the old-school systems.
Earlier this year, the House proposed $1B in cuts to the state’s nation-leading efficiency program. The Senate rejected that idea in a sweeping new energy bill.
The Massachusetts Senate on Wednesday unveiled its long-awaited energy legislation, a wide-ranging bill that touches on dozens of topics from plug-in solar to renewable energy procurement. Sponsors say the measures could save consumers some $14 billion over the next 10 years.
Perhaps most notable, however, is what isn’t in the 150-page bill: The Senate left out an extremely controversial $1 billion cut to the state’s nation-leading energy-efficiency programming found in the House version.
“It’s huge,” said Larry Chretien, executive director of Green Energy Consumers Alliance, an advocacy group in Massachusetts and Rhode Island. “We were very upset when the House did it, and we are equally as happy now that it’s not in the Senate bill.”
The House’s proposed $1 billion cut represents about 22% of the three-year, $4.5 billion budget for Mass Save, the state’s energy-efficiency program, which provides rebates and incentives for insulation, weatherization, and efficient appliances. But the impact would be more severe than those numbers suggest: By the time the bill was implemented, the current energy efficiency plan would be nearly two-thirds complete. The cuts would come almost entirely from the final year’s programming, essentially bringing it to a standstill, advocates said.
Proponents of the cuts argue they are necessary because they offer a direct way to reduce utility bills in Massachusetts, which has some of the highest energy costs in the nation. But climate, consumer, and housing advocates said the cuts would offer only minimal relief to consumers in the short term.
Money spent on Mass Save now yields significant benefits down the road. From 2016 to 2024, Mass Save’s investment of about $8 billion in energy efficiency prevented some $16 billion in increased energy costs, according to an analysis from climate nonprofit Acadia Center. That’s even before public health and environmental benefits are considered.
“This is a program that is cost-effective, and it saves ratepayers money, even if they’ve never used the program,” said Kyle Murray, Acadia Center’s director of state program implementation.
There’s still no guarantee that funding will be preserved. The full Senate is set to debate the bill on July 1. The House and Senate will then have to hammer out the differences between their versions, leaving room for cuts to make it into the final proposal.
However, Democratic Sen. Michael Barrett, chair of the Joint Committee on Telecommunications, Utilities and Energy, and a major voice on climate and energy issues in the legislature, said there is little appetite for any Mass Save cuts among his colleagues.
“The Senate doesn’t want any of it gone,” he told Canary Media. “We think our constituents can tell the difference between a cost and an investment.”
The bill also proposes a range of measures intended to chip away at the thorny problems driving up energy costs in the state.
“This is a process where $100 million here and a $100 million there adds up after a while,” Barrett said. “You have to go after all the sources of overspending and overcharging in these big complex systems.”
One provision would allow individual cities and towns to ban competitive electric suppliers, companies that have often used questionable means to sign up customers for expensive contracts they don’t fully understand. Other measures would authorize the use of plug-in solar systems, allow money from the Regional Greenhouse Gas Initiative’s cap-and-trade auctions to be used for EV incentives, and stop utilities from passing on certain promotional and lobbying costs to customers.
The bill would also phase out the Gas System Enhancement Program, an initiative that allows natural gas companies to recover their costs more quickly for repairing aging and leak-prone gas pipes. These expenses are passed on to consumers over fewer years, which means higher fees on each bill, an approach that doesn’t make sense anymore, Barrett said.
“We don’t think we should have to pay bonuses forever to a system that is supposed to keep us safe for the regular prices,” he said.
This latest bill has its origins in legislation that Democratic Gov. Maura Healey proposed in May 2025. Her package, which she contended would save residents some $10 billion over 10 years, had a hearing in June that year, but went no further.
Many of the ideas it included were revived in the fall, in a bill sponsored by Democratic Rep. Mark Cusack. His bill echoed many of Healey’s proposals but also included provisions he said were needed to rein in soaring energy costs. He proposed reinstating rebates for natural gas heating systems, making the state’s 2030 emissions-reduction target nonbinding, and slashing energy-efficiency spending by $330 million through the end of 2027.
Climate and consumer advocates immediately and adamantly opposed the measure, saying a cut of that size would eviscerate Mass Save without offering consumers any meaningful savings, now or in the future. Still, the bill advanced to the House Ways and Means Committee, where the proposed cut to efficiency programming was tripled in a proposal released in February, much to the dismay of opponents.
The new Senate version, supporters said, takes a deeper dive into some of the less obvious cost drivers, rather than looking for a big, simple answer.
“Everyone wishes there was a switch they could flip to make energy prices get cheap,” Acadia Center’s Murray said. “That’s not how it works.”
The manufacturer is building a $6 billion facility that will use cleaner technology — and potentially green hydrogen. But residents question whether they will benefit.
On a drizzly March day last year at the White House, President Donald J. Trump stood behind a podium to make a “beautiful announcement.” Hyundai, the Korean industrial giant, was investing nearly $6 billion in a new steel plant in Louisiana, which would supply domestic metal to the company’s auto plants in Alabama and Georgia.
Hyundai executives flanked Trump as he spoke, as did top Republican policymakers and Louisiana’s governor, Jeff Landry, who stood out among the sea of navy suits in his cornflower-blue attire. Trump praised his own administration’s tariff policy for driving Hyundai’s investment in U.S. manufacturing, and Hyundai officials touted the jobs they’ll bring to the Bayou State.
But one important detail went unmentioned: The new plant may be the lowest-carbon iron and steel mill the United States has ever built.
Traditional steelmaking is highly polluting, responsible for up to 9% of the world’s greenhouse gas emissions. Unlike the hulking furnaces that launched America’s steel industry in the late 19th century — some of which are still cranking across the Midwest — the Louisiana facility won’t rely on coal to produce the sturdy metal.
Last summer, the company indicated its steel mill would use hydrogen — a carbon-free fuel that can be made cleanly from renewable electricity and water. The project would become a “catalyst for the hydrogen ecosystem” in Louisiana, executives told state leaders, while helping Hyundai meet the growing global demand for sustainably produced steel.
This was good news for anyone who cares about climate, coming at a moment when other U.S. efforts to decarbonize the steel industry had stalled in the face of economic headwinds and the Trump administration’s antipathy toward climate policy. The companies SSAB and Cleveland-Cliffs were each slated to receive $500 million in federal funding for hydrogen-based steelmaking under the Biden administration, but they later abandoned those plans.
A green-hydrogen steel mill would be “a chance to change not just the industrial landscape of Louisiana, in terms of what types of industries are here, but also to advance the broader clean energy transition in the state,” said Kelvin Wells Jr., an industrial organizer with Sierra Club’s Delta Chapter who lives in Baton Rouge, the state capital.
But whether Hyundai will fulfill its hydrogen ambitions remains an open question.
In permit fillings, the company stated the steel mill will use natural gas when it starts operating in 2029, and Hyundai confirmed this plan to Canary Media. The firm also said it will capture and store the carbon dioxide emissions the plant produces from the get-go. The combined approach can slash the carbon footprint of coal-based steelmaking by as much as two-thirds — but it’s still more polluting than using hydrogen from renewables, and is sure to face opposition from carbon-capture’s critics.
Asked when the company will transition to using green hydrogen, a representative said, “It is difficult to pinpoint when hydrogen will become economically viable.”
Meanwhile, residents in Ascension Parish, where the facility is being built, have their own questions about the project. Their community is already stacked with petrochemical plants and oil refineries that have turned the rural region between Baton Rouge and New Orleans into “Cancer Alley.” They hope the steel mill will offer an alternative to those dirty facilities, and they want assurances that the steelmaker will deliver on its promises. So far, locals say the company hasn’t responded to their requests for talks.
As Hyundai begins transforming the grounds of a former sugarcane plantation into an industrial site, community members and climate advocates are watching the project closely to see what happens next.
That’s why he joined the grassroots group Good Neighbors Louisiana. The coalition is pushing Hyundai to crystallize its plans — for curbing pollution, using green hydrogen, and protecting workers — in a legally binding “community benefits agreement,” and it is calling on the state to conduct an environmental justice analysis. Not long after my visit, the group claimed a win: Hyundai said it would switch nine gas-fired heaters in parts of its operation to cleaner electrified equipment; the change will “reduce emissions of pollutants,” the company explained by email.
“We can’t stop people coming in — we don’t have the might. So you have to have a plan B,” Price told me inside the small, hushed library. “If they’re going to come in, then we want them to make sound commitments to us. We want the best that we can get.”
Donaldsonville is surrounded by emerald fields of sugarcane and rice paddies dotted with orange crawfish traps. But signs of its modern industrial identity are impossible to miss. Driving west over the Sunshine Bridge earlier that day, I saw silver spires and grayish plumes rising from CF Industries’ ammonia-production plant. It’s the biggest fertilizer factory in the world — and also Louisiana’s largest source of planet-warming emissions and toxic air and water pollution. The imposing complex sits within sight of a primary school and the local Walmart.
As I headed toward the rural village of Modeste, the factory shrank into the distance, replaced by farmland owned by the descendants of slaves and sharecroppers. Hyundai, CF Industries, and other firms are collectively planning to develop a 17,000-acre industrial hub, called the RiverPlex MegaPark, in this area.
I pulled over my rental car — a Hyundai Kona, as it happened — when I came across the temporary sign for Hyundai America. Stepping into the broiling sun, I took in the preliminary site work: leveled ground, piles of dirt, fleets of excavators and dump trucks. At full tilt, Hyundai’s steel mill is expected to churn out 2.7 million metric tons of metal per year on its 1,700-acre property. Posco, another major Korean steelmaker, is set to invest $582 million and take a 20% stake in the operation.
Details about Hyundai’s work and the bigger industrial park are hard to come by, especially for the Modeste residents who fear being displaced.
At least 10 elected leaders in Ascension have signed nondisclosure agreements with Louisiana Economic Development, a state agency. The practice reportedly allowed state officials to privately negotiate a sweeping $2.6 billion incentive deal for Hyundai’s project. The level of secrecy is becoming commonplace in Gov. Landry’s Louisiana, though local environmental groups are suing to stop it. The state agency defended its use of nondisclosure agreements, calling them a “standard part of economic development projects” across the country.
“By engaging local elected officials early while protecting sensitive business information during negotiations, Louisiana is able to compete for transformational projects that create opportunity, grow wages, and strengthen communities across the state,” a spokesperson for Louisiana Economic Development said by email.
Ashley Gaignard, a Donaldsonville resident and president of Rural Roots Louisiana, questioned why project details have been kept secret if they’re in the public’s best interest. “I would love to see my community thrive,” she said. “I just don’t want to do it at the cost of risking our water, our air, our lives.”
Deletrick Dickerson, who lives in the parish, said that while he’s wary of the larger RiverPlex expansion, Hyundai’s steel mill in particular could have a “phenomenal” impact if it employs people within the predominantly Black, economically distressed towns that trace the western bank of the Mississippi.
Dickerson works at the Atalco alumina refinery in neighboring St. James Parish and is a safety representative for his United Steelworkers local union. He also advocates for the union on other urgent political matters. He and I met after my drive to Modeste near the state Capitol building, in Baton Rouge, where he had spent the previous night rallying against a congressional redistricting bill that would eliminate one of Louisiana’s two majority-Black districts. The measure passed at 4:30 a.m.
The Hyundai project is another kind of fight for communities, he said later that afternoon, warding off fatigue. “We just want everything to be on the up-and-up.”
Hyundai-Posco Louisiana Steel, the U.S.-based subsidiary of Hyundai Steel, addressed the community’s environmental and labor concerns in an email to Canary Media.
The steelmaker is using advanced technologies “to minimize emissions of harmful and toxic substances. The project is designed to comply with all applicable environmental regulations and permit requirements,” a representative said. The company plans to “prioritize hiring local residents to the greatest extent possible. Safety will be our top priority, and HPLS will be prepared and operated with the highest safety standards.”
For all the uncertainty surrounding Hyundai’s hydrogen future, one thing is clear: It won’t be like the aging steel mills that operate from Illinois east to Pennsylvania.
Those facilities consume lots of coal in scorching-hot blast furnaces to turn raw iron ore into iron. The molten metal is then transported into a basic oxygen furnace, which removes impurities to make steel. The mills produce most of the high-performance steel that U.S. auto manufacturers need for car bodies and engine parts. They are also responsible for the vast majority of carbon emissions and toxic air pollution associated with steelmaking.
The Louisiana plant will be the first new U.S. steel mill to combine two alternative furnace technologies into one relatively lower-carbon facility.
To produce the iron, the company will install a direct reduction furnace, which can use natural gas or hydrogen, or a combination of the two. Three such facilities already operate in the United States — all of them fueled by gas — including Nucor’s sprawling operation near the community of Romeville, Louisiana, across the river from where Hyundai’s steel mill is being built. At the Nucor site, an impossibly long conveyor belt travels overhead to move the iron onto river barges that ship the metal to other states.
Hyundai’s project, by contrast, will feed iron directly into two electric arc furnaces. Over 150 of these power-hungry furnaces exist nationwide. But they primarily melt down scrap metal, with some virgin iron, into shiny new steel. Hyundai will mostly supply its own iron for the electric arc furnaces, enabling it to form steel sheets with the right qualities for vehicle production.
Hyundai has been making steel in South Korea since the 1950s. But with the Trump administration’s tariffs raising the cost of importing steel and cars, the manufacturer has opted to boost its U.S. production in both sectors. Building a new coal-fueled blast furnace in the United States makes little economic sense, given the expense of using coal and complying with environmental regulations. And there’s no need to — not when Louisiana can offer plentiful supplies of cheaper natural gas.
Eventually, the company intends to sell its Louisiana-made steel to other automakers in the U.S. and internationally. The global market is increasingly calling for lower-carbon steel, through policies like the European Union’s carbon border tax and because of broader consumer interest. Hyundai itself is facing pressure to decarbonize under South Korea’s carbon-neutrality targets.
“This project is not just about producing steel — it’s about producing a better future,” Hyeongjin Kim of Hyundai Steel told Louisiana leaders last year in Baton Rouge.
In May, Hyundai signed a $650 million supply contract with the Italian company Danieli for the two electric arc furnaces and other key steel-manufacturing equipment. The deal also includes an Energiron direct reduction plant, jointly developed by Danieli and the Italian firm Tenova, which is similar to the one Nucor operates in Louisiana.
“This is state-of-the-art, latest technology,” Andrea Diasparro, Danieli’s group sales director and a member of its executive board, said by phone from his office in Buttrio, Italy.
He added that the equipment is designed to limit energy consumption across Hyundai’s operation. The direct reduction furnace has built-in capabilities to capture carbon dioxide emissions, which Hyundai said it will utilize during its initial operations. The plant is also designed to seamlessly transition from using gas to hydrogen to produce the iron.
“No additional equipment has to be implemented for the plant to be hydrogen-ready, in the case that hydrogen is available at a reasonable price,” he said.
The question of when Hyundai will use green hydrogen, if ever, weighs heavily on Angelle Bradford Rosenberg, a medical scientist who leads the Sierra Club’s Delta Chapter. She met with me, her colleague Wells, and Dickerson — all members of the Good Neighbors Louisiana coalition — at a bar in downtown Baton Rouge the afternoon after the combative redistricting hearing.
“There’s no mechanism in Louisiana for watchdogging that sort of thing,” Bradford Rosenberg said. “We need those commitments from corporations in the beginning, because we cannot trust that it will come later.”
Hyundai outlined its hydrogen ambitions last year during meetings with Louisiana’s Clean Hydrogen Task Force, as part of an 18-month initiative created under former Gov. John Bel Edwards, a Democrat. The group included legislators and industry experts, who made policy recommendations for boosting production of the lower-carbon fuel within the state.
Louisiana makes millions of tons of conventional hydrogen every year for use in the chemicals sector, through a dirty and energy-intensive method that breaks the hydrogen-carbon bond in methane from natural gas.
The industry has plans to clean up by capturing its CO2 emissions and storing them permanently underground — producing so-called blue hydrogen — with a few such projects underway. In meetings, Hyundai gave the impression that it would start by using blue hydrogen in its ironmaking furnace. It would have a convenient source: CF Industries is developing a $4 billion blue ammonia plant next door that could also make hydrogen and bury emissions beneath Ascension Parish.
Whether this is a good idea depends on who you ask. The Sierra Club and local groups like Rural Roots and Louisiana Bucket Brigade — and, increasingly, Republican state policymakers — are vehemently opposed to injecting CO2 into underground wells, given their concerns about public safety risks and potential emission leaks. Critics also don’t like that it prolongs industry’s reliance on fossil fuels, and all the harmful emissions that entails.
On the flip side, the nonprofit Clean Air Task Force generally considers carbon capture and storage, or CCS, to be a “safe, permanent, and essential pathway” to curbing industrial emissions. By including CCS in its initial plans, the Hyundai steel mill could help create the supply chains and infrastructure needed to develop blue hydrogen, eventually driving down the costs for hydrogen made with renewables.
“We really see CCS-enabled hydrogen as a way to jump-start the economy and lead us into electrolytic [green] hydrogen in the future,” Lindsay Cooper Phillips, the senior Gulf Coast policy manager for the Clean Air Task Force, told me over coffee in Baton Rouge. “It’s challenging for someone like Hyundai to just start off there.”
Hyundai has indicated that it could later switch to using green hydrogen, which is made by running electrolyzers — powered by renewable electricity — to split water into hydrogen and oxygen. This is considered the cleanest form of the fuel, because it doesn’t directly emit carbon. It also eliminates the harmful air pollution that comes with burning natural gas, including smog-producing compounds and fine particulates, which can damage people’s hearts and lungs.
A handful of global steelmakers have started using hydrogen in their operations. But the world’s first commercial-scale green steel mills are only just being built, both of them in northern Sweden. SSAB and Stegra are aiming to fire up their respective facilities before the end of the decade, despite significant challenges with project funding and delays.
Globally, the limited supply of green hydrogen and sky-high cost of producing it have stalled progress on green steel — problems exacerbated in the United States by politics. Over the last year and a half, the Trump administration has weakened or paralyzed federal funding for new clean hydrogen projects. Gov. Landry has done little to advance the low-carbon hydrogen efforts started by his predecessor, and the state has barely installed any renewable energy to date.
So it’s perhaps unsurprising, if not deeply disappointing for advocates like Bradford Rosenberg, that Hyundai said it will use natural gas when it fires up its steel mill in 2029.
“The production of green hydrogen has not yet reached the scale, nor cost, necessary for feasible implementation to replace natural gas,” Hyundai said in its December air-pollution permit application to the Louisiana Department of Environmental Quality.
In its filing, the company said it would use green hydrogen when there’s enough supply to meet its demand. But it hasn’t disclosed a timeline for when it plans to shift away from gas. “As hydrogen becomes more viable, we have also considered a phased transition to blue and green hydrogen,” Hyundai-Posco Louisiana Steel said by email.
Experts question whether the company will want to make such carbon-cutting investments after its gas-fueled plant is already up and running.
“Hyundai has the ambition, and we really want to see it put into practice,” Cooper Phillips said.
As Hyundai sorts out what will happen inside its steel mill, the world outside is preparing for the plant’s arrival.
Earlier this year, the River Parishes Community College broke ground in Donaldsonville on the Hyundai Training Center, which will offer a two-year program to prepare people for jobs in the steel industry. Landry and Bo-ryong Lee, Hyundai Steel’s president and CEO, were among those tossing shovels of dirt at the February ceremony. Korean investors have purchased hotels and apartments in downtown Donaldsonville to house future steelworkers, and the first Korean barbecue joints are opening up.
About a dozen miles down the river, in St. James Parish, the industrial gas supplier Air Liquide is building a second air-separation unit to serve Hyundai’s steel mill.
During my visit to the area, I stopped by to see its existing facility, which sucks outside air through an enormous filter and distills the molecules into high-purity oxygen, nitrogen, and argon. The Paris-based company is about to start construction on a $350 million additional unit and infrastructure that will mainly supply oxygen by pipeline to Hyundai’s new electric arc furnaces. Injecting oxygen makes chemical reactions more efficient, reducing the amount of electricity needed and lowering emissions.
“Hyundai wants to put the steel plant in badly, so we’re working at a fast pace. We’re going to support their needs,” Nick Frasier, the plant manager, told me as we toured the plant by car, rolling past towering columns and snaking pipes. He said the new unit is expected to come online in 2028.
Air Liquide is also one of the world’s largest producers of hydrogen. The company today primarily makes conventional hydrogen from natural gas, though it is building several large-scale green hydrogen plants at sites in Canada, Europe, and Asia.
Matthieu Giard, a group vice president for Air Liquide, said the company “would be more than happy” to partner with Hyundai if the steelmaker decides to use hydrogen in its Louisiana steel mill. “That could be another project for us tomorrow,” he said by phone from his office in Houston.
But Louisiana will need to first see a massive buildout of renewable energy if Hyundai is going to make that switch.
Producing enough green hydrogen to supply the steel mill could require at least 3 gigawatts of renewable generation capacity to run electrolyzers, the Clean Air Task Force estimated. That’s more than all of the solar power installed in Louisiana, which makes up most of the state’s clean energy capacity. Natural gas power plants provide the majority of the state’s total electricity generation, along with a smaller share from nuclear facilities.
Entergy Louisiana, the state’s largest utility and Hyundai’s electricity provider, is planning to add up to 3 GW of solar power to its portfolio in the coming years. And developers are advancing plans to build the state’s first three onshore wind farms. However, earlier efforts to install gigawatts’ worth of turbines in the Gulf of Mexico have screeched to a halt amid the Trump administration’s attacks on offshore wind development.
Clean energy advocates in the state say they’re trying to position Louisiana’s industrial growth as a key reason for policymakers to support more wind and solar development — particularly given that renewables are now cheaper and faster to build than gas and nuclear plants. Hyundai itself spoke out about its coming clean-energy needs during an off-the-record panel in April at the Powering Louisiana Forum.
If built as promised, Hyundai’s green steel mill could be the start of that broader transformation for both the state and U.S. steelmaking.
When I sat down with Bradford Rosenberg, Wells, and Dickerson in Baton Rouge, the three of them wavered between excitement about what the project could deliver and skepticism about whether Louisiana was being sold yet another dream too good to be true. As they see it, the work of their grassroots coalition is to not only pressure Hyundai but also counter the growing disillusionment in surrounding communities and even within themselves, and to hold on firmly to a vision of what could be.
“The Hyundai plant is huge for the United States and for us,” Bradford Rosenberg said. “We want to make sure we get it right.”
The unicorn startup launched its first move outside its home state of Texas, pitching low-cost energy and backup power in northern Illinois.
PJM Interconnection, which serves 67 million people across 13 states from the mid-Atlantic to the Midwest, has become a poster child for how not to keep up with soaring energy demand. Startup Base Power is taking a whack at that problem by installing a network of unusually large home batteries in one corner of that regional grid.
Starting today, the first 2,000 customers in Illinois utility ComEd’s territory who sign up with Base Power can get a 40-kilowatt-hour home backup battery for just $95 up front. Subsequent customers will pay $295, still a mere sliver of the $10,000 or more that a backup-capable home battery normally costs. All these customers will then buy retail electricity from Base Power at a 25% discount to the prevailing ComEd rate, which was 10.4 cents per kilowatt-hour this summer. Customers sign a 12-year battery agreement, but can pay a $500 deinstallation fee if they want out early.
This business model gives customers in Chicagoland more options for cheap and resilient power while also giving Base Power the rights to operate the battery fleet in response to broader market dynamics. Base Power will be adding capacity in the northwesternmost territory of the constrained regional grid, but its unique model allows it to avoid PJM’s ossified procedures for expanding large-scale grid production.
“We are deploying capacity behind the meter at the residential home, where an interconnection already exists, so we don’t wait in the interconnection queue,” said Base Power’s founder and CEO Zach Dell. “There’s some work around that, but it’s certainly less onerous and much faster than the large-load interconnection queue.”
PJM famously hosts the densest corridor of data centers, in northern Virginia, but the AI buildout has taken off in Indiana, Ohio, and Pennsylvania as well. While hyperscalers stare down yearslong waitlists for new gas turbines to meet their colossal power needs, Base Power can install miniature power plants every day, which add up over time.
The Illinois offering is even cheaper than Base Power’s prices in its home state of Texas, where it has installed more than 500 megawatt-hours of storage since it launched in 2024. Base Power operates most of that in the Texas’ freewheeling, competitive energy market, but it also is working with a cooperative utility to install 100 megawatts of instant discharge capacity at customer homes over the next two years.
Base Power’s two-part pitch of customer benefit and aggregated grid resource has made it arguably the most effective fundraiser in the residential battery space — it netted a billion-dollar raise last fall from mainstream VCs like Andreessen Horowitz and Valor Equity Partners, an early backer of Tesla and SpaceX. Base Power needs that cash to fuel its vertically integrated model: It designs, manufactures, markets, installs, owns, and operates all the batteries in-house.
After a few years of tremendous growth, though, the question had remained whether this model would work outside the particularities of the Texas market. Now, Base Power is staking a claim on a new state that provides access to the country’s biggest regional power market.
Several layers of policy and regulation made Illinois the right entry point for Base Power in PJM. The state allows retail competition, so Base Power can sell power directly to customers. However, it still has to get permission from a wires utility to hook up the batteries to the distribution grid, and ComEd stood out as a partner.
“ComEd, they’re an innovative utility,” said Travis Kavulla, Base Power’s head of policy, who on Monday was tapped to run the Bonneville Power Authority, a New Deal–era federal power agency. “They’ve done things that other utilities have not done.”
In particular, ComEd has rules that compensate homes at market rates for discharging power to offset high capacity prices in PJM. These rules emerged from a recent revision to the long-standing net-metering policy, which originally paid homes for shipping excess rooftop solar to the grid; now, the policy also allows stand-alone batteries to export power and participate in the market.
Base Power will also tap into a new Illinois policy to encourage virtual power plants that was created by the Clean and Reliable Grid Affordability Act, which became law in January. Starting this summer, battery customers can receive a rebate if they install a battery and agree to discharge it to the grid for multiple hours during the evening peak on a certain number of summer nights. It’s a simple way to ensure that the batteries make themselves useful, and Base Power will apply that rebate to support its very low pricing.
All this means that Base Power will not rely on specific PJM programs to make money in Illinois. The grid operator is working on a new mechanism for distributed energy resources to play a broader role in capacity markets, in response to the Federal Energy Regulatory Commission’s Order 2222. That process will have its first auction next month, to pay for capacity in 2028 and 2029, Kavulla noted.
“Our approach is not something that has to wait on that. It’s more ready to go to market if you’re configuring it on the retail side through a competitive retailer, in the way we’re doing it,” he said.
Down the road, the startup could tap another source of revenue by selling aggregated capacity to hyperscalers that need power for new data centers. Google signed a bilateral deal with demand-response provider Voltus to do just that in PJM. Sunrun, Tesla, and Renew Home just announced a national strategy to tap existing home batteries and smart thermostats to sell capacity to data center customers. Dell confirmed that Base Power is in talks with data center clients, but said his Illinois strategy does not depend on that kind of deal.
Whether or not Base Power deals directly with data centers, the households in Illinois are feeling upward pressure on their energy bills as the region struggles to supply the AI arms race. Some governors have threatened to exit PJM if the capacity costs keep rising, though that would take years of thorny wrangling to execute. If other PJM states want to do something to help customers short of the nuclear option, they could look to the ComEd policy that rewards households for peak exports.
“One of our takeaways here is that if you’re a state in PJM, this is something that you can kind of cause your utilities to do,” Kavulla said.
The clean energy giants are uniting their home batteries and smart thermostats to help tech giants power booming, AI-driven data centers without crushing the grid.
The leading U.S. providers of rooftop solar, home batteries, and grid-responsive smart thermostats have combined forces to create what could be the country’s biggest virtual power plant — or, more precisely, a lot of VPPs in data center hot spots.
On Wednesday, Sunrun, Tesla, and Renew Home announced an agreement to “deliver more than 16 gigawatts of flexible energy capacity” to tech giants and utilities around the United States. Those gigawatts will be produced by hundreds of thousands of home battery systems managed by Sunrun and Tesla, as well as more than 8 million smart thermostats and devices managed by Renew Home.
These batteries and smart thermostats are already installed in homes and businesses across the country, Paul Dickson, Sunrun’s president and chief revenue officer, told Canary Media. Some are enrolled in utility or grid programs that call on batteries to discharge, or thermostats to turn down energy use, during the handful of hours per year when grid demand is at its peak, he said.
But he noted, “Most of the constructs for these distributed power plants are tapping into the resources a fraction of the time they could be realized.” This new partnership is meant to “further legitimize these devices as core dispatchable, capable resources.”
Wednesday’s announcement is just the latest — and biggest — proposal for solving the country’s rising energy costs and grid congestion challenges through the power of distributed energy.
The aggregated energy-injecting and load-shifting capacity of batteries, smart thermostats, electric vehicle chargers, and remote-controllable appliances such as water heaters could add 80 gigawatts to 160 gigawatts by 2030, or roughly three to five times what’s now available across the country, according to analysis from the U.S. Department of Energy. VPP deployment at that scale could save U.S. utility customers about $10 billion in annual grid costs, the DOE estimated.
To make that happen, VPP companies need to coordinate with — and convince — utilities, regional grid operators, and state and federal regulators that distributed energy resources can do the work of traditional power plants. That’s easier said than done. The grid has been designed to deliver electricity from central power plants, not to rely on thousands of customer-owned devices turning on and off in unison to keep supply and demand in balance.
But traditional ways of managing the grid are falling short in the face of booming demand from the massive data centers that tech giants like Amazon, Google, Meta, Microsoft, and Oracle are building to fulfill their artificial intelligence ambitions. Some states are already seeing big spikes in energy costs due to data center growth. Across the country, lawmakers and regulators are demanding that developers of these facilities find ways to finance their own energy resources to avoid pushing more costs onto everyday consumers.
That’s putting pressure on tech giants to pursue novel approaches, from shifting when they use power, in order to avoid stressing the grid during times of peak demand, to investing in VPPs that can do the same work.
Home batteries and thermostats obviously can’t power data centers around the clock, Dickson said. But they can “solve elegantly for your peak-capacity needs, which is the bottleneck for data centers getting connected,” he said. “We want to provide for getting more data centers online in a way that doesn’t strain the grid or cause costs for customers to rise.”
Sunrun, Tesla, and Renew Home have a lot of existing customers to work with. Sunrun and Tesla already operate hundreds of megawatts of battery-based VPP capacity, including large-scale aggregations in California, New England, Texas, and Puerto Rico. And Renew Home — a spinoff of Google Nest’s smart-thermostat energy-shifting service Nest Renew and California startup OhmConnect — has partnered with major energy retailer NRG Energy to aggregate a gigawatt of flexible capacity in Texas, and is working with utilities in Arizona and other states.
Lots of companies are promising similar solutions. Voltus, a major U.S. demand-response and VPP aggregator, launched its “bring-your-own-capacity plan” last year, targeting tech giants struggling to interconnect to overburdened power grids. Earlier this month, Voltus and Google announced plans to develop 100 megawatts of this distributed capacity as part of the tech giant’s broader efforts to finance new energy resources for its expanding data center footprint.
Data centers want to “lock in that capacity, which is important to them,” Voltus’ CEO Dana Guernsey told Canary Media in early June. “They’re giving us the right signals to build, which we can take to our customers to save them money. And it’s not putting the cost on the ratepayers.”
The more data centers are willing to pay for VPP capacity, the more companies can offer customers to participate in them, Dickson said. Sunrun and Renew Home have paid out nearly $70 million to customers participating in existing grid-services programs, he added.
Low-income households could particularly stand to benefit if these programs prioritize these customers, according to a recent study by consultancy Brattle Group for the Natural Resources Defense Council. It found that if programs directed energy efficiency and VPP investments from data centers to lower-income customers in four cities — Atlanta; Memphis, Tennessee; Kansas City, Missouri; and Columbus, Ohio — participating households could save from $50 to more than $1,000 per year on their utility bills.
It’s not yet clear how Sunrun, Tesla, and Renew Home might deliver additional savings to customers at large. The companies didn’t disclose which existing or in-development VPP programs or data center opportunities they’re jointly pursuing.
But they are staking claims in key markets, including northern Virginia’s “Data Center Alley,” where massive data center expansions are pushing the grid to its limit, driving lawmakers and regulators to explore policies to limit cost and environmental impacts. Sunrun, Tesla, and Renew Home claimed they collectively have “more than 300 megawatts of capacity readily available for immediate deployment” in the region, which they expect will grow to at least 500 megawatts by 2030.
Sunrun, Tesla, and Renew Home also intend to provide VPP capacity to PJM Interconnection, the country’s biggest energy market, where power costs are spiking because of new data centers and PJM’s inability to bring new generation resources online. Specifically, the companies plan to commit capacity to PJM’s upcoming reliability backstop procurement, which is being designed to encourage data center developers to pay for new resources to match their grid impacts.
Renew Home has a lot of smart thermostat–equipped customers in the 13 states and Washington, D.C., region who are served by PJM but aren’t yet enlisted in VPP programs, CEO Ben Brown told Canary Media. “We have over a gigawatt of capacity in the ground, installed, flexing every day, providing savings for customers every day,” he said.
Last year, Renew Home ran tests of the potential grid relief those thermostats could provide, and found that customers were able to reduce summertime peak demand by about 380 megawatts over three consecutive afternoons, he said. That represented a little less than half its available “fleet” of customers, he added.
Dickson highlighted other parts of the country where the three companies have capacity to spare. According to the partners’ calculations, they can collectively relieve grid stresses for roughly two hours at a time by about 4.7 gigawatts in California, about 1.7 gigawatts in Texas, and about 1 gigawatt across Illinois and Ohio.
The number of home batteries and smart thermostats available for future service could expand if data centers are willing to pay more for these services, Dickson said. “Unlike a traditional power plant, this number grows every single day.”
A new report finds that mentioning all-electric heat pumps in real estate listings delivers a sales premium. But most agents don’t note the appliance.
Would you pay more for a home with a heat pump?
You can bet I would.
I’d gladly fork over more money to bypass a gas or oil furnace, which — unlike an all-electric heat pump — spews toxic combustion by-products, runs the risk of poisoning my family with carbon monoxide, and contributes to climate change. And while heat pumps, which provide both heating and cooling, typically cost more upfront than conventional furnaces, they’re two to four times as efficient, and so could save me money in the long run.
Apparently, I’m not alone in prizing the comfort, safety, and economic benefits of these appliances.
Heat pumps give home values a boost, according to a new report by the nonprofit Smart Energy Consumer Collaborative, which studies consumer behaviors, interests, and concerns in the energy transition; 257, a customer-intelligence platform that profiles U.S. residential property characteristics for contractors, utilities, and others; and the trade group the National Association of Realtors. Their analysis showed that homeowners who install a heat pump can recoup up to a quarter of its cost just by mentioning it in real estate listings when they’re ready to sell.
While some homeowners may invest in a heat pump for its environmental bona fides, for most people, economics trumps all, said Scott Rosenberg, a co-founder and CEO of 257. “A homeowner who puts a garage on, redoes their bathroom, improves their kitchen, always thinks, ‘Am I going to get this value back?’”
By analyzing more than half a million sales of U.S. homes with ducted heat pumps from 2024 to 2025, the authors found that those with real estate listings mentioning the heat pump typically enjoyed a sales price boost of 0.6% to 1% over homes that didn’t advertise their efficient appliance. This modest lift translates to $2,300 to $3,900 per home, given a median sales price of $399,000.
“Just shy of $4K doesn’t sound like a lot of money on a home sale,” Rosenberg said. “But it’s actually a meaningful piece of the investment that you made to get the heat pump in the first place.”
In 2026, a ducted heat-pump system costs on average about $15,400, per energy marketplace EnergySage — though prices vary wildly depending on the region, a home’s size and electrical service, and local contractors, to name a few variables. A comparable gas furnace plus central AC system can cost half that, according to home services platform Angi. Mentioning a home’s heat pump in the sale listing, assuming the appliance cost around the average price, can recoup about 15% to 25% of the outlay.
Now, every home is different, and people willingly pay premiums for a wide variety of attributes, such as the floor plan, the views, and neighborhood vibes.
But Rosenberg is confident that when it comes to real estate listings, the heat-pump price bump is real, because of the approach his team used and the sheer amount of data they analyzed. 257 used a machine learning technique to cluster homes across hundreds of attributes to identify those that are nearly identical, he said. Then within those clusters, sales prices were contrasted for those homes where the heat pump was or wasn’t mentioned in the listing.
Yueming “Lucy” Qiu, an economics professor at the University of Maryland, called the report “very valuable” for helping to gauge the premium that people place on heat pumps. “I’m actually very happy that this came out,” said Qiu, who investigated the matter years ago at a smaller geographic scale.
In 2020, Qiu and her colleagues published a peer-reviewed study in Nature Energy that looked at home sales across 23 states from 2000 to 2018 for whether the presence of a heat pump improved the property’s sale prices.
Notably, to control for differences between homes that could influence price, her team looked at individual abodes that sold both before and after a heat pump was installed. They then compared the differences in sales prices (adjusted for inflation) with those for homes that hadn’t gotten a heat-pump makeover. Residences with heat pumps sold for a 4% to 7%, or $10,400 to $17,000, premium on the $240,000 average home price.
That’s a much bigger boost than the latest report identifies, but that’s because the groups investigated different questions. Qiu’s team asked, What’s the value of a heat pump? Whereas 257 asked, Once a home has a heat pump, what difference does highlighting it in the real estate listing make?
“We weren’t trying to make the case for energy efficiency, but rather to study whether it’s valued once it’s there,” Rosenberg said.
Qiu would love to see a follow-up study in which Rosenberg and colleagues analyze a subsample of homes with the methods she used in her paper. “Just as a robust check to see if, using similar methods, they find a similar magnitude [to what] we do,” she said.
Homebuyers are asking real estate agents more frequently about energy-efficient upgrades — not only for environmental reasons “but also to control and maintain their monthly costs, like their utility bills,” said Matt Christopherson, director of business and consumer research at the National Association of Realtors.
Yet Realtors often struggle to convey the benefits of energy-efficient features to clients, according to the recent report, which looked at a range of technologies. More than half of Realtors surveyed said they were “not too confident” or “not confident at all” in their ability to explain the benefits of heat pumps.
Real estate agents are the ones writing the listings, Rosenberg pointed out. In homes with a heat pump, it was mentioned in the listing just 8% of the time.
If real estate agents become more aware that potential buyers are willing to pay more for homes with heat pumps, and they lean into promoting the appliances, Rosenberg believes “that’ll have a virtuous-cycle effect of reinforcing and signaling to buyers that this is something they should pay attention to.”
Of course, some of us are already keeping our eyes peeled for listings that give heat pumps and other clean energy perks a shoutout.
.svg)
