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Illinois legislators passed a major energy bill that creates grid-battery and geothermal incentives and a virtual-power-plant program, during the final hours of a fall veto session Thursday.
Advocates and industry sources describe the legislation as the crucial next step in the state’s clean-energy transition, jump-started by 2017 and 2021 laws that created significant solar and wind incentives. The bill’s passage comes as the Trump administration eviscerates federal support for clean energy and as a debate plays out in state legislatures around the country over how best to rein in soaring electricity rates.
The legislation faced substantial pushback, largely because of concerns about the costs imposed on residential and industrial customers to fund the energy-storage incentives. It also faced stiff competition for legislators’ attention during the six-day veto session, as bills related to a transit-funding emergency, a new stadium, and insurance regulation were also on the table.
The state House passed the bill on the second-to-last day of the October veto session, and the state Senate passed it in the final hours on Oct. 30. Gov. JB Pritzker, a Democrat, has pledged to sign the bill.
The Clean and Reliable Grid Affordability Act, or CRGA, calls for the procurement of 3 gigawatts of energy storage by 2030.
The Illinois Power Agency, which procures electricity on behalf of the state’s two major utilities, ComEd and Ameren, estimates that developing and operating the storage will cost $9.7 billion over 20 years. That money will be collected from utility customers through a new charge on their electricity bills. But under the incentive structure, a portion of the revenue earned by the storage companies will go back to consumers. With this factored in, customers will end up paying an estimated $1 billion for the storage.
Meanwhile, energy storage connected to the grid will save those same customers an estimated $13.4 billion over 20 years, since the influx of electricity into “capacity markets” will suppress prices, the Illinois Power Agency predicted. Capacity markets are run by regional grid operators to make sure enough power is available to meet future demand.
Mark Pruitt, an energy consultant who previously led the Illinois Power Agency, said that getting more electricity into capacity markets is urgent because of the AI data centers springing up in the state.
“Is there a way of demonstrating that we’re going to be able to get a benefit for consumers in all of this?” asked Pruitt. “That was an honest concern by many of the policymakers. When do consumers start to see a benefit, and will they see lower costs? I don’t know that prices are coming down; it’s a question of can you slow their rate of increase.”
The credit structure meant to incentivize storage under the bill is already being used as part of the state’s subsidy program to keep existing nuclear plants online, which got started in 2021. At the time, watchdog groups worried the mechanism would cost households money, but the arrangement has actually benefited consumers.
Energy-storage deployment is central to the virtual-power-plant program created by the bill, wherein homes and businesses with batteries can earn revenue by supplying energy to the grid when needed. The bill also, for the first time, makes geothermal eligible for state renewable-energy incentives. And it lifts a decades-old moratorium on the construction of large nuclear plants. The legislature had revised the moratorium in 2023 to allow small modular nuclear reactors to be built, though this technology is still nascent.
Legislators’ approval of CRGA “is a major step toward strengthening Illinois’ power grid and keeping energy costs in check,” said Hannah Flath, climate communications manager of the Illinois Environmental Council, a group of over 100 environmental organizations working on policy and advocacy. “Battery storage represents the next phase of Illinois’ clean-energy buildout, ensuring that clean power is available around the clock.”
The bill was backed by the Illinois Clean Jobs Coalition, made up of clean energy, environmental, and community groups that were instrumental in crafting and passing the 2021 Climate and Equitable Jobs Act. That law built on 2017’s Future Energy Jobs Act, by increasing incentives for renewables and electric vehicles and creating an ambitious clean-energy workforce training program, among other measures.
In February, legislators introduced two separate storage-related bills, one backed by the Clean Jobs Coalition and the other by storage and solar industry groups. They eventually joined forces, pushing together for CRGA.
Opponents — namely, large energy users — argued that storage development should be left to the open market and that customers shouldn’t have to pay for incentives.
“We want an all-of-the-above energy strategy,” said Phillip Golden, chair of Illinois Industrial Energy Consumers, which represents companies that use lots of electricity. “We think battery storage has a role to play; we think renewables have a role to play. What we’re anti is making ratepayers pay for things they don’t need to. Look to Texas: We’ve seen battery-storage developers invest in projects without state procurements.”
Indeed, Texas has seen rapid growth of battery storage, thanks in part to a lack of regulation. But backers of CRGA said it’s too risky to count on companies to build storage if they don’t have certainty of earning revenue.
The debate played out as northern Illinois residents served by ComEd face a serious spike in electricity prices, driven by the high cost of capacity in the PJM Interconnection regional market. CRGA proponents have said that storage on the grid is crucial to mitigate escalating prices, in part because it facilitates more solar deployment; energy from solar can be held in batteries until it’s needed.
“The only way to protect ratepayers and address energy affordability is by investing in solar and storage, the fastest and cheapest energy sources to deploy,” said Andrew Linhares, a senior manager at the Solar Energy Industries Association who focuses on the Midwest. “Energy costs are already set to increase next summer, and they’ll continue to skyrocket every year until Illinois solves its energy supply-and-demand imbalances.”
CRGA backers sought to dispel the myths that they say swirled leading up to and during the veto session, including the fear that companies could get incentives before they even built storage.
“CRGA does not deliver any benefits to storage projects until those projects are online,” said Stephanie Burgos-Veras, senior manager of equity programs at the Coalition for Community Solar Access, made up of businesses and nonprofits nationwide. “This means ratepayers have no up-front cost for the storage program, and that all projects must actively contribute to the grid through stored power and price suppression before they are eligible for incentives. It is an incredibly safe funding model that ensures families and businesses receive risk-free savings.”
Ultimately, backers of CRGA said the bill’s passage shows that a state-level clean-energy transition can still move forward even without federal support.
“This bill isn’t just a rejection of Trump’s anti-climate policies — it’s proof that local and state action can offset those backward policies,” said Flath. “Illinois consumers, our power grid, and our climate will be better protected from price volatility and increasingly extreme weather events because we’re stepping up to fill the gap where the federal government is failing us.”
Facing a cash crunch of more than $1 billion, Europe’s flagship green-steel project began publicly seeking a financial lifeline earlier this month. This week, the French hydrogen investor Hy24 swooped in to help fund Stegra, the Swedish firm behind the effort.
Construction is 60% complete on the facility, which is located in northern Sweden just below the Arctic Circle. If finished, the plant would be the world’s first large-scale steel mill fueled by clean hydrogen, giving Europe a leg up on both the United States and China in an emerging low-carbon technology.
“There is no reason to question the project, whose fundamentals are very good,” Pierre-Etienne Franc, co-founder and CEO of Hy24, told Bloomberg. “If anything, demand for green steel has risen since its launch.”
Franc did not disclose how much money Hy24 invested in Stegra (formerly known as H2 Green Steel), and the company did not respond to Canary Media’s multiple emails requesting comment.
In a press release announcing the start of the new fundraising round on October 13, Stegra CEO Henrik Henriksson said that the investments the company was seeking would represent “approximately 15%” of overall project funding, “comprising a mix of new equity, debt, outsourcing, and selected strategic partnerships.”
“Stegra has a unique position in the green steel landscape with a strong order book, a competitive cost position, and proven execution capabilities,” Henriksson said.
A previous investor from Stegra’s 2023 financing round had also stepped up before Hy24 made its announcement. Just Climate, the British low-carbon venture fund linked to former Vice President Al Gore’s investment company, told the Swedish broadcaster SVT earlier this month that it planned to increase its stake in Stegra. In a statement, Stegra told Canary Media that “several investors have conveyed their commitment to this round,” including the venture funds Altor, FAM, and Kallskär.
But Hy24 is the first new investor to come forward since the latest fundraising began. The investment firm represents “one of the most advanced funding bases for hydrogen in the world,” said Rinaldo Brutoco, the founder of the World Business Academy think tank and a hydrogen investor who has advised European governments on the hydrogen industry.
“They’re the best thing in the hydrogen space in France,” he said. “They invest at the level of ‘let’s build a full-scale plant’ and they operate at the level of ‘let’s build entire industries.’”
That Hy24 is funding Stegra, he said, is a sign the firm is “confident it’s a safe investment.”
“Will Stegra be successful? Absolutely,” Brutoco said. “Have they run into cost overruns? Sure, what new technology hasn’t? But it’s a minor hiccup.”
Still, some big investors are growing skittish. Unnamed sources told the Financial Times this month that Citigroup, one of the project’s core funders, has indicated it wants to stop lending to Stegra because of concerns about the company’s future.
Haunting the project is the ghost of its former sister company, the European battery manufacturer Northvolt, which declared bankruptcy last fall. Both firms were founded with money from Vargas Holding, a Swedish private equity investor focused on climate impacts.
“They’ve got their work cut out,” one lender said of Stegra, according to the FT. “But there is a solid case there, a basis to conduct fundraising, that there wasn’t for Northvolt.”
Amid multiple emergency board meetings, Harald Mix, chair and co-founder of Stegra, agreed to step aside.
Stegra isn’t alone in its troubles. In the U.S., the Trump administration has hampered the nascent green-steel industry by slashing funding to the two regional hubs meant to ramp up production of green hydrogen and changing the terms of grants through the Department of Energy to encourage steelmakers such as Cleveland-Cliffs to double down on coal. In Europe, meanwhile, the Luxembourg-based steel giant ArcelorMittal abandoned plans in June to produce clean steel with green hydrogen and direct reduced iron at two German sites in Bremen and Eisenhüttenstadt.
“[T]here has been slower than expected progress on all aspects of the energy transition, including green hydrogen not yet being a viable fuel source and natural gas-based DRI production not being competitive as an interim solution,” ArcelorMittal said in a statement.
That makes the latest investments in Stegra a cause for optimism, said Anne-Sophie Corbeau, a hydrogen analyst at Columbia University’s Center on Global Energy Policy.
“Some European steel producers have been going backward recently, like Arcelor, so it’s good to see this project moving forward,” she said.
America has some green shoots, too. Hyundai this month confirmed its plans to build a clean steel facility in Louisiana by the end of the decade, with plans to generate green hydrogen by 2034.
“In a time of strong headwinds for industrial decarbonization, continued investor confidence in projects like this is encouraging,” said Ariana Criste, a spokesperson at Industrious Labs, a research group that tracks steel industry decarbonization. “It shows that despite near-term challenges, the fundamentals for clean steel are solid, and each new project or demand signal helps build the technical foundation and market momentum needed to accelerate the transition.”
An update was made on November 2, 2025 to add a statement from Stegra
While the federal policy and regulatory landscapes in 2025 are, to put it mildly, full of uncertainty and outright antagonism — from the cancellation of programs like Solar for All to the rapid drawdown or outright elimination of the Inflation Reduction Act’s incentives for technologies like solar, storage, wind, and electric vehicles — the choice for the industry is either to wait and hope for better political tides in Washington or to adapt and fight to meet the moment.
“It is very easy to get overwhelmed by this moment,” said Amisha Rai, senior vice president of advocacy at Advanced Energy United (United), an industry association representing many of the leading solar, wind, storage, and demand and distributed energy companies. “You could go into the zone of just being flustered and become part of that chaos. Or you can figure out a construct where you can continue leading and focus on a solutions-oriented path.”
The choice for Rai and United was simple. Founded in the aftermath of the 2010 failure of the federal Waxman-Markey cap-and-trade bill, United was built from the start to engage deeply with state policymakers and regional regulators to educate them about the benefits that advanced energy technologies can deliver to citizens and the grid.
United has achieved a long list of legislative and regulatory achievements over its decade-plus of state and regional engagement. Most recently, United championed California’s passage of the “Pathways Initiative” bill, which grants the state’s independent system operator authority to collaborate with other Western states to create an entirely new day-ahead energy trading market for the Western region — a move that is expected to bolster clean energy deployment and save participants upwards of $1.2 billion annually.
Meeting the moment with practical, available solutions
Despite the headwinds from the nation’s capital, United continues to make progress for the industry in state capitals. Recently, the association leveraged its deep experience to develop a playbook that the entire industry can use to further this progress. “The playbook is a way to organize the solutions available to decision-makers and a guide to leaders of any political stripe and in any state about how to think about the urgent challenges they face today,” Rai said.
The challenges are significant. Electricity demand is projected to surge in coming years, driven by data centers, artificial intelligence, electrification, and industrial reshoring. At the same time, energy costs are spiking, supply chain constraints and tariffs are slowing energy infrastructure development, and extreme weather events are straining grid resilience.
State leaders find themselves caught between rising and understandable citizen concerns about energy costs and the urgent need to meet explosive load growth while maintaining grid reliability. Unlike hyperpartisan Washington, state capitals remain a venue for problem-solving. “We have had these conversations with lawmakers that are across the map — rural, urban, Republican, Democrat, Independent,” Rai explained. “The beauty of this playbook is it applies in Texas, and it applies in Pennsylvania, California, Indiana, or Virginia.”
State and local decision-makers understand that they are accountable to constituents who expect the lights to stay on and bills to remain affordable. The advanced energy technologies available today — from large-scale solar, wind, and storage to distributed resources like virtual power plants and advanced efficiency innovations such as smart thermostats and building energy management systems — offer immediate, deployable solutions. Unlike new gas plants and pipelines that take years to build and also risk becoming stranded assets, these technologies can be deployed quickly to meet urgent reliability needs while containing costs.
A three-pillar framework for action
United’s playbook organizes solutions around three core objectives that address the full spectrum of state energy challenges:
Build it: To meet projected load growth, states can accelerate deployment of least-cost energy projects by reforming generation and transmission development processes. This includes streamlining planning, siting, permitting, interconnection, and procurement procedures to build a stable pipeline of projects that will meet growing future residential, business, and industrial needs.
California’s Pathways Initiative exemplifies this approach. The landmark legislation, nearly a decade in the making, enables Western states with vastly different energy portfolios to work together on market expansion, making it easier to boost transmission capacity, get more clean energy projects connected to the grid, and create efficiencies that will benefit affordability and reliability across the region.
United has also been working on improving energy markets in other parts of the country. For instance, the organization has been leading efforts to have PJM Interconnection — the nation’s largest grid operator, serving 13 states and D.C. — make significant reforms to address the massive backlog of projects waiting to connect to its grid, a critical bottleneck preventing clean energy deployment and keeping prices sky high. These regional efforts complement the statewide developments in siting and permitting legislation that United recently helped secure in Michigan and Massachusetts.
Make it flexible: States can maximize existing grid infrastructure by scaling up distributed energy resources, energy waste reduction, virtual power plants, and advanced vehicle and building electrification solutions through state-led programs, plans, and rates. These technologies help grid operators manage costs in real time while preparing the system for increased demand.
Following Winter Storm Uri’s devastating blackouts in 2021, state leaders in Texas recognized the value of flexibility, energy waste reduction, and consumer participation. Recent legislation in Texas has expanded opportunities for those demand-side programs to help shore up the grid. “Texas has showcased that these resources can actually keep the lights on and help strengthen the grid system,” Rai said. “We don’t need to wait 20 years to solve all of our problems. These are solutions that can actually be deployed immediately.”
“We don’t need to wait 20 years to solve all of our problems. These are solutions that can actually be deployed immediately.”
- Amisha Rai, Advanced Energy United
Make it affordable: States can ensure public utilities are planning, optimizing, and delivering the right types of energy investment at the lowest possible cost while identifying least-cost financing avenues for projects both big and small. This includes avoiding investments in infrastructure that may become a stranded asset.
Colorado leads the way in comprehensive energy system planning. The state has implemented country-leading electric distribution system planning that accounts for how distributed resources can play an increasing role in grid reliability, and Colorado has one of the strongest frameworks for containing costs on the gas pipeline system. As a result, the state’s utility regulators are currently reviewing a proposal to save Coloradans $150 million by investing in efficiency, electrification, demand flexibility, and a small liquefied natural gas facility instead of the traditional gas-only solution.
A path forward
The United playbook recognizes a fundamental truth: There is no single answer to America’s energy challenges. The energy system is complex and interconnected, and decision-makers must assess how different technologies combine to keep prices low, secure the economic opportunities represented by data centers and AI, and ensure a resilient and reliable grid.
States are the best place for action and progress, in large part because so much of energy policy lives at legislatures and state agencies. “The urgency right now is making sure that state leaders have a path for action and are not stuck in the chaos and noise of the moment,” Rai said. “This playbook provides a constructive path that works despite the chaos people are seeing at the federal level — a focus on action, not just talk.”
Massachusetts heat-pump owners will spend less to stay warm this winter, thanks to an innovative policy going into effect this weekend.
The state’s three investor-owned electric utilities — Eversource, National Grid, and Unitil — are all offering lower winter rates to the roughly 100,000 households with electric heat pumps, starting on Nov. 1 and running through April.
“It really is what matters to people — it reduces the cost of running a heat pump,” said Larry Chretien, executive director of the Green Energy Consumers Alliance, who is replacing his own gas-fueled heating system with heat pumps this week.
Massachusetts is the first state in which all the major utilities are offering these savings. The rates — ranging from 4.3 cents to 7.5 cents per kilowatt-hour lower than the standard winter price — could trim from $70 to $140 per month off the average bill, utilities estimate. The lower rate applies to all electricity used by participating homes during the winter months.
Households that received heat-pump rebates from state energy-efficiency program Mass Save since 2019 will be automatically enrolled in the new rate. Residents who installed heat pumps earlier or didn’t work with Mass Save can contact their utility to receive the lower rate.
Massachusetts, like other states with ambitious climate goals and cold winters, has made heat-pump adoption a key part of its decarbonization strategy. Today, more than half the homes in the state use natural-gas heating, and another 25% burn heating oil or propane. More than 90,000 homes installed heat pumps from January 2021 to July 2024, but annual adoption rates will need to double over the next five years if the state is to hit its goal of getting the systems into 500,000 homes between 2020 and 2030.
The cost of installing and operating heat pumps has traditionally been a major barrier preventing people from making the switch, particularly in Massachusetts, where electric rates are among the highest in the country. Under current default rates, just 45% of households that transition to air-source heat pumps — the most common version of the appliance — would save money on heating each month, according to a study from climate-policy think tank Switchbox.
Seasonal heat-pump rates change that calculation. Eligible customers will be charged a lower rate on the delivery portion of their bill, while power-supply rates will remain the same. That means that customers who buy power from a third-party supplier or through a municipal community choice program can still participate.
The result should be more savings for more people. Factoring in the discounts, Switchbox estimates roughly two-thirds of households switching to heat pumps would see lower bills, with average monthly savings of $90. The lower cost of operation should make heat pumps a feasible financial choice for more residents, Chretien said.
“This will just put wind in the sails of the heat-pump market,” he said.
Proponents of heat-pump rates say the lower prices are not being subsidized by other customers. Instead, the new approach is a “right-sizing” of currently inflated winter rates.
The delivery portion of a utility bill pays for the poles, wires, transformers, and other infrastructure needed to, well, deliver power. The rate is determined, roughly, by adding up these costs and dividing the total by the number of kilowatt-hours the utility expects customers to use. That number, plus an allowed rate of return for the utility, becomes the final rate.
The grid infrastructure is built to handle moments of peak demand, typically those hottest of summer days on which millions of air conditioners turn on at once. In the winter, demand usually reaches no more than 80% of the highest summer levels, meaning plenty of capacity is left unused.
In other words, the grid already has the room to accommodate winter demand from heat pumps, so no expensive upgrades are required. Therefore, it would be unfair to ask the heat-pump owner to pay more when they aren’t adding more cost, supporters say.
And while the lower rates can save consumers money, they shouldn’t cut into utilities’ revenue, as the increased use of electricity offsets the decreased price per kilowatt-hour.
“We could see heat-pump rates as leveling the playing field,” said Amanda Sachs, state policy manager for electrification advocacy group Rewiring America.
This winter’s lower rates may be just the beginning for Massachusetts residents. The state energy department in January asked utility regulators to mandate even steeper discounts, ranging from 12 cents to 17 cents per kilowatt-hour, for the heating season starting in November 2026. With these much deeper cuts, 82% of households switching to heat pumps would end up paying less for winter heating, with a median annual savings of $687, according to the Switchbox analysis.
Seasonal heat-pump rates are not meant to be a long-term strategy. The logic underpinning the rates only holds so long as peak demand happens in the summer, and the New England grid is expected to shift to a winter-peaking system in the 2030s. By then, though, utilities should have rolled out advanced meters that will allow more sophisticated and nuanced rate structures to replace current models.
“We’ll be able to be way more accurate about heat-pump usage,” Sachs said.
When Matt Cooper found out in 2020 that the northwest Colorado coal mine where he works would close by the end of the decade, he was pissed.
Questions raced through his mind: Why didn’t the mine’s leaders fight harder to keep it open? And why was the coal industry being singled out? “Is it political?” he wondered.
But coal has been declining in the U.S. for over 20 years, outcompeted by cheap fossil gas and, more recently, even cheaper renewables. Cooper eventually accepted there was nothing he could do — except plan for what’s next.
Now the coal-fired Craig Station is set to shutter in 2028, and the Colowyo mine that feeds it is halting production by the end of the year. For his part, Cooper is choosing to dig for a different kind of energy: geothermal, the renewable heat beneath our feet.
“It works wonderfully well,” said Cooper, a longtime Hamilton, Colorado, resident with a snowy-white goatee and a strong Western accent. Geothermal energy from the shallow earth can be tapped to superefficiently heat and cool individual buildings or even entire neighborhoods. Leveraging his ample experience operating heavy equipment at the mine, Cooper has started a new business, High Altitude Geothermal, to drill for the resource. With the startup’s first projects underway, he’s working alongside his wife, daughter, and two sons, both of whom are also coal miners.
Others in the fossil-fuel industry could follow, finding a foothold in geothermal as clean energy takes off. Colorado plans to decarbonize its economy by 2050, and its remaining six coal plants are shutting down by the end of the decade. The Centennial State’s six active coal mines, which employed roughly 900 workers as of July, will likely shut down along with them.
The northwest corner of the state is the epicenter of the transition. And affected communities stand to lose not only jobs, but big chunks of their tax base. Moffat County, where Cooper lives, will be the hardest hit; Craig Station made up a third of its property taxes in 2022.
In 2019, Colorado created the Office of Just Transition, the first state-level office in the nation dedicated to providing personalized support to coal workers and their families, as well as funding to their communities.
“Small towns have this tendency to be dependent on one or two large employers,” said Wade Buchanan, director at the just-transition office, which helped the Coopers connect to state agencies as they worked on their business concept. “You want to help communities find a way to be more diversified, so that their fortunes are not subject to the fortunes of any single employer.”
Buchanan said he’s thrilled by the Coopers’ venture into geothermal, a tech that the state and federal government are backing with incentives. “They’re trailblazers showing the way for a lot of other people that opportunities exist.”
Cooper still isn’t happy that Colorado’s coal industry is sunsetting. “We produce some of the cleanest coal in the nation,” even if it is a fossil fuel, said Cooper, who plans to keep doing shift work at the coal mine until it closes. President Donald Trump also dubs coal clean, and Cooper reports feeling more aligned with Republicans than Democrats.
He’s clear-eyed that change is inevitable, though, like it or not. “I can’t save the coal industry,” Cooper said.
The Trump administration, meanwhile, has undertaken the Sisyphean task of resuscitating coal in the U.S. by, among other tactics, forcing uneconomic coal plants to keep running past their planned closure dates.
Cooper, who worked at a heat- and power-generating plant when he was in the military, isn’t a fan of most forms of renewable energy. “Windmills are ugly things to me,” he said — a view shared by the U.S. president. He finds batteries unpalatable. And solar panels send jobs overseas, he said.
“When you’re buying solar panels from China, I don’t think that’s the right way to go. If you’re going to buy the things, they ought to be built here,” Cooper said. (Though perhaps not a well-publicized statistic, domestic solar manufacturing employed about 34,000 workers in 2024.)
Geothermal is an up-and-coming energy source Cooper can get behind. Hooked up to heat pumps, it’s the most efficient way to warm and cool buildings.
In a geothermal system, loops of flexible pipe are installed ten to hundreds of feet deep into the ground. At these depths, the earth is a fairly stable 45 to 75 degrees Fahrenheit, funneling a ready source of heat in cold weather to a building’s electrically powered geothermal heat pump. In the summer, the appliances provide air conditioning by dumping a building’s extra warmth underground.
Geothermal heat pumps are extremely efficient. They can deliver the same amount of heating as a fossil-fueled or electric-resistance system using just a fourth or even a sixth of the energy.
“In northwest Colorado, you can pay $700 a month for propane to heat your house, or $400 for natural gas,” said Cooper. “That’s a chunk of change, because our winter up here lasts about five to six months — about half a year where you’re going to be heating your home.” And the cold cuts like a knife: Cooper recalls winters in the area with lows in the minus 50s and 60s Fahrenheit.
Plus, a geothermal heat pump actually “helps the grid out,” Cooper said. The appliances are not only superefficient but also provide warmth steadily, rather than in bursts. That reduces peaks in power demand, keeping electricity more affordable for everyone.
Geothermal systems aren’t yet widespread. Most people don’t know the tech exists, and the up-front cost to install them is typically two to three times the price tag of an air-source heat pump or gas furnace plus a central air conditioner.
But the higher costs in northwest Colorado are partly due to far-flung geothermal drillers having to haul their equipment across the Rocky Mountains, said Cooper, who’s been spinning up the startup in his off-time. “I think I can keep my costs of mobilization down, and so that makes the product more affordable.”
His geothermal drilling business will be the first in Moffat County and neighboring Routt and Rio Blanco counties — a region home to more than three-quarters of the roughly 1,700 workers that make up Colorado’s coal industry and its supply chain. The state is backing High Altitude Geothermal, providing four years of tax relief and a $40,000 grant for operations through the economic development program Rural Jump-Start.
For now, the startup consists of Cooper and his family members. His wife, Kristine, is helping with administrative work. His daughter, Anna, handles operations. His sons, Matthew and Nathan, are drilling alongside him. Anna is also certified to do that work, so she can step in when the need arises. But as business picks up, Cooper aims to expand to a second crew and hire more people — especially other miners in the area.
“Hiring displaced coal workers was part of Matt’s ‘why’ for starting this business,” Kristine said. “He wanted to be part of the solution for the employment of these individuals.”
Going into geothermal energy “felt so right,” Anna said. “It’s a wonderful resource that everyone has access to. It’s there all the time.” And it’s a boost to the local economy. “It’s really exciting … when you have something that’s so powerful.”
High Altitude Geothermal has already secured its first contracts: retrofits of two homes in Moffat County. The Coopers are also bidding on two large-scale commercial projects in the municipalities of Steamboat Springs and Gunnison. They’re building a future with geothermal energy, regardless of the federal push for coal.
“There’s some people that are holding out that somehow Trump will be able to make coal viable again and make the power plants stay open,” Cooper said. “Maybe they’ll be right. … I have no idea. But my intuition is that this ball is rolling, and I don’t see it stopping.”
“So you better just try to figure out what’s next for you.”
Hyundai Motor Group says its plan to invest $6 billion in a low-carbon steel plant in Louisiana “remains unchanged,” despite the Trump administration’s cuts to tax credits for the green hydrogen needed to produce clean iron and a recent immigration raid on a factory the automaker is building in Georgia.
In a statement last week to NPR’s Gulf States Newsroom, Hyundai said the company’s investment “is centered on creating thousands of high-quality American jobs.” The South Korean car manufacturer did not respond to Canary Media’s request for comment.
The Louisiana facility, set to come online in 2029, has emerged as the United States’ leading green-steel initiative.
“This is going to be the flagship project when it comes to green steel,” said Matthew Groch, senior director of decarbonization at the environmental group Mighty Earth.
Days before President Donald Trump returned to office in January, Swedish steel company SSAB quietly pulled out of talks with the Department of Energy for a $500 million grant to support a green-steel project in Mississippi. In June, Cleveland-Cliffs backed away from its plans to replace the blast furnaces at its Middletown Works facility in Ohio with cleaner, hydrogen-ready technology, also with $500 million in financing from the federal government.
Between those two decisions, however, Hyundai bucked the trend, announcing plans in March for its Louisiana steel plant.
Designed to use direct reduced iron, a cleaner method of making iron that relies on natural gas or hydrogen instead of the coal that fuels a blast furnace, the Hyundai facility is slated to produce 2.7 million metric tons of steel each year, including“low-carbon steel sheets using the abundant supply of steel scrap in the U.S.”
Hyundai’s initial press release did not explicitly mention direct reduced iron or hydrogen. But a Korean newspaper article noted at the time that the project would include direct reduced iron, and the 3.6 million tons of iron ore the Louisiana government said the plant would import each year will require some kind of processing. Since then, the company has clarified its plans at state regulatory hearings, Groch said.
At a Louisiana Clean Hydrogen Task Force meeting in June, Hyundai laid out its vision for bringing the plant online in about four years using what’s called blue hydrogen, a version of the fuel made with natural gas and equipped with carbon-capture technology to prevent the emissions from entering the atmosphere. But by 2034, Groch said, Hyundai intends to start producing green hydrogen — made with renewable energy — at the facility to power the process.
A clean industrial plant would likely be welcomed in Ascension Parish, roughly an hour west of New Orleans in the heart of the Bayou State’s so-called Cancer Alley. A new survey, shared with Canary Media, shows 60% of residents in the area favor investment in green hydrogen for steelmaking. The poll, commissioned by the Sierra Club’s Delta Chapter and conducted by JMC Analytics, “makes clear that steel manufacturing at this scale presents a unique set of opportunities for Louisianans,” said Angelle Bradford Rosenberg, the chair of the Sierra Club affiliate’s board.
“Residents are aware that the technology exists to make steel that is clean and has low impact on communities — they want Hyundai to make good on their promises,” Bradford Rosenberg said in a statement. “This poll shows that communities want industry to prioritize clean energy, and provide steel using renewable energy.”
For much of the past decade, Hyundai has focused on growing its presence in the U.S. market, particularly as competition from cheap Chinese electric vehicles mounts in Asia and Europe. The steel plant is part of a broader $26 billion investment that includes the EV-battery plant in Georgia where Immigration and Customs Enforcement arrested and shackled hundreds of South Korean workers in a high-profile raid in September.
Signs are emerging of Hyundai’s broader ambitions. First, there’s the location of the plant in Ascension Parish. That industrial corridor hosts the Louisiana stretch of an ammonia pipeline system that extends from the Gulf state all the way north to Indiana. Hydrogen is notoriously tricky to ship because the world’s smallest molecule is prone to dangerous leaking. Transformed into ammonia, however, hydrogen becomes a liquid that can be easily transported via a pipeline.
“They could eventually be selling green hydrogen as far as Indiana,” Groch said of Hyundai. “That’s why they’re building it there.”
Then, there’s the potential to supply rivals.
Last September, General Motors inked a partnership with Hyundai to work together on new car models and establish a shared supply chain that circumvents China. In June, news broke that GM abandoned the Chinese steel company supplying its Korean factories in favor of a new deal with Hyundai.
In August, however, GM signed an unusual three-year deal to buy steel for its American plants from Cleveland-Cliffs. Typically, such deals are structured to last a year. But the expiration date of this one coincides with when Hyundai expects to start selling steel made in Louisiana in the U.S.
“Hyundai has played this incredibly well,” Groch said.
Maine and Connecticut are considering working together to build renewable-energy projects faster, a strategy that could be repeated throughout the region as states with ambitious emissions-reduction goals race to take advantage of federal tax credits before they disappear.
“They’re trying to collaborate, trying to coordinate,” said Francis Pullaro, president of clean-energy trade association Renew Northeast. “This is a preview of what’s to come.”
The next eight months are crucial for commercial-scale clean-energy developments nationwide. The tax credits included in former President Joe Biden’s 2022 Inflation Reduction Act spurred massive investment in the sector, with more than $360 billion in projects already announced as of June 2024. Now the Trump administration is phasing out the incentives for wind and solar farms, requiring them to begin construction by July 4, 2026, or be placed in service by the end of 2027 in order to qualify for the tax credits. Across the country, states are responding by streamlining permitting processes and fast-tracking clean-energy procurements to get projects going in time.
Maine and Connecticut — which both aim to get all of their power from clean sources by 2040 — have been among the states looking for ways to get projects in under the deadline. In July, Maine asked for proposals for up to 1,600 gigawatt-hours of renewable energy, giving developers just two weeks to submit their bids; regulators selected one hydropower and four solar developments in September.
It was Connecticut’s call for collaborators that sparked the emerging partnership between the states.
Connecticut released a request for proposals for solar and onshore wind projects in September, with a deadline of Oct. 10. The initial timeline calls for bids to be selected in November, and final contracts to be submitted by the end of the year. The call for proposals included provisions to allow other states to participate. Each state would make its own evaluations; if another state decided to select a project, it would coordinate with Connecticut on finalizing the terms of the deal.
Maine’s newly created Department of Energy Resources saw potential in this opportunity and reached out to the state’s utility commission, which voted to join Connecticut’s procurement. This move does not mean Maine will necessarily choose the same projects as its New England neighbor, just that it will have the opportunity to assess the same bids against its own criteria and needs.
The hope is that, by pooling demand and sharing information, both states will emerge with more efficient and viable projects at lower prices for residents.
“It makes a lot of sense for a state like Maine to piggyback on their efforts and hopefully enter into contracts for a share of the capacity that gets bid in cost-effectively,” said Jamie Dickerson, senior director of climate and clean-energy programs at Acadia Center, an advocacy group.
Both Connecticut and Maine have previously attempted to collaborate with other states on renewable-energy procurements, though not on quite as tight a timeline.
In 2022, Massachusetts agreed to buy 40% of the power produced by a planned onshore wind farm in northern Maine, though that development stalled when a deal for an associated transmission line fell through. In 2023, Connecticut, Massachusetts, and Rhode Island announced a three-state offshore wind solicitation; in the end, Connecticut declined to choose any of the bidders, although the two other participating states contracted nearly 2.9 GW of capacity.
Whether this latest endeavor yields any joint procurements remains to be seen, but Pullaro is confident that it will not be the last cooperative effort among New England states as the tax-credit deadline looms.
“The states are having a lot of conversations,” he said.
This story originally appeared in New York Focus, a nonprofit news publication investigating power in New York. Sign up for its newsletter here.
New York is violating its climate law — and doesn’t get a pass because implementing the law is “complicated,” a judge found Friday.
The 2019 law, which remains one of the most ambitious in the country, gave the state Department of Environmental Conservation until the start of 2024 to issue regulations that would “ensure” New York meets its binding greenhouse gas emissions targets. More than a year and half later, it has not — a fact that Ulster County Supreme Court Judge Julian Schreibman said was “undisputed” in the case.
Schreibman gave the DEC until Feb. 6 to issue regulations that comply with the law, called the Climate Leadership and Community Protection Act.
“While DEC notes that it has taken other, commendable regulatory steps to reduce greenhouse gas emissions, it candidly concedes that the impact of those regulations would fall far short” of the targets set out in the law, which requires the state cut emissions 40% from 1990 levels by 2030 and 85% by 2050, Schreibman wrote.
Climate groups brought the case in March after Gov. Kathy Hochul (D) slammed the brakes on what was expected to be her signature policy to implement the climate law: an emissions-pricing program known as cap-and-invest. Internal emails reported by Politico show that the DEC and the New York State Energy Research and Development Authority had completed draft cap-and-invest rules at the beginning of this year, before Hochul’s abrupt about-face.
The DEC argued in court that issuing the regulations was “infeasible” because it “would require imposing extraordinary and damaging costs upon New Yorkers.” (Hochul in August said much the same about her own reasons for shelving cap-and-invest.)
The judge dismissed that argument.
“It is undoubtedly true that the task placed before the DEC is very complicated indeed,” he wrote. “But as a legal argument, this is unavailing.”
Schreibman said there were two possible paths forward: Either the legislature can step in and change the law, or the DEC must act on it. He set his deadline in February, a month into the next legislative session, to give state lawmakers a chance to weigh in. If the legislature leaves the climate law intact, he said, he is “highly unlikely” to grant the DEC an extension.
The ruling does not explicitly require the state to move ahead with cap-and-invest; the policy is not named in the climate law, and Schreibman said the content of the DEC’s regulations is not up to him. But the law does require the regulations to reflect the findings of its 2022 scoping plan, which envisioned cap-and-invest as its core measure to achieve the emissions targets. State agencies spent two years working on the rules to establish that program before Hochul put them on ice. It’s not yet clear whether the DEC could find a substitute by February.
Hochul said Monday that her administration plans to appeal the decision, which could lead the case to drag on for months longer, if not more.
Reacting to the ruling on Friday evening, she said she would do what was necessary to keep New York’s energy supply reliable and affordable and keep the state attractive to business.
“New York has been, and will continue to be, a leader in climate action, but the judge’s decision fails to factor in the realities of today that include a federal government hostile to clean energy projects, the continuing impacts of post-COVID high inflation, and potential energy shortages expected downstate as soon as next year,” Hochul said in an emailed statement. “We plan to review all our options, including working with the Legislature to modify the CLCPA and appeal, in order to protect New Yorkers from higher costs.”
Headlines often paint a picture that America’s energy transition is off track, suggesting that the U.S. is no longer an attractive market for energy project investment.
But DNV’s Energy Transition Outlook and Energy Industry Insights surveys tell a different story, revealing unique perspectives from business leaders involved in North American energy projects.
Enduring optimism:
Business leaders remain confident in a long-term future for a decarbonized energy system. The coming years will see a renewed focus on an all-inclusive approach to how energy is produced, moved, stored, and used.
Pace of change:
The energy transition is seen as slowing, not stopping. Policy shifts and global geopolitical tensions impacting supply chains are the main factors contributing to the slowdown.
“All of the above” solutions:
North America needs more of all forms of energy production to meet growing demand. This includes projects that combine fossil fuels and renewables.
Grid modernization:
Urgent investment in the grid is needed. Connecting renewables, managing distributed energy resources, and meeting demand will be impossible without modernized transmission.
Smarter energy use:
Across America, consumers are reshaping the energy system by converting their homes and businesses into mini power plants featuring rooftop solar, electric vehicles, and battery storage. Advanced digital technology can use these distributed energy resources to help balance the grid.
The answer is yes — if the solutions are as broad as possible.
America needs an “all of the above” approach to meet the increasing demand for energy. The key is to think in systems, not in silos. This means an interconnected energy system that puts everything on the table — solar, wind, oil and natural gas, low-carbon and renewable products, battery storage, energy efficiency, virtual power plants (VPPs), and carbon capture, utilization, and storage (CCUS) can all contribute to a reliable, lower-carbon, and affordable energy transition.
In our 2023 Energy Transition Outlook for North America, we estimated a $12 trillion opportunity. Things have changed. Today, DNV continues to see the energy transition in the U.S. and Canada offering significant financial opportunities. However, the size of the prize is different, as regional policy shifts, ongoing geopolitical tensions, and supply chain issues have affected the economics and pace of delivering energy projects.
We will explore this in-depth in our upcoming 2025 Energy Transition Outlook for North America report, but as a preview, here are a few key insights for the major players:
Renewable developers:
Pairing renewable power generation, battery storage, and natural gas–fired power generation is an attractive opportunity to use existing infrastructure to bring lower-emission energy online faster and more affordably.
Utilities:
Virtual power Plants (VPPs) offer a way to reduce peak demand, cut energy bills, make it easier to bring more renewable power online, and — critically — boost energy efficiency.
Investors:
Financing structures are evolving as North America pursues an “all of the above” approach to energy and infrastructure creates exciting opportunities for divestment and opportunities of assets.
Oil and gas companies:
Fossil fuels — especially natural gas — will continue to play a role in the energy mix. Decarbonizing fossil fuel production with low-emission hydrogen and carbon capture, utilization, and storage (CCUS), while blending in renewable feedstock, is critical.
Even as incentives are phased out, market forces are making solar and solar-plus- storage projects the optimal choice for new power generation. But solar isn’t the only option. Here’s what winning companies will act now to invest in:
• Energy efficiency
• Energy storage
• Hybrid power generation
• Fossil fuel decarbonization
• Digital trust
For more than 125 years, DNV has helped businesses progress winning energy projects in the US and Canada that contribute to energy security, affordability, and reliability. DNV helps clients confidently navigate complex projects and ensure they are bankable and successful.
DNV’s proven impact
Energy efficiency:
DNV has delivered over 2 million megawatt-hours and 40 million therms in energy savings, significantly reducing costs and emissions for utilities and millions of users.
Clean energy capacity:
DNV supported 400 gigawatts of clean energy capacity and oversaw more than $1 billion in energy spending, accelerating renewable deployment and grid modernization.
Oil and gas:
DNV has a long history of supporting safe oil and gas operations. The vast majority of oil and gas pipelines are built to our standards, and we lead the industry in validating the materials used in technologies essential for offshore oil and gas development.
Research and technology centers:
We operate state-of-the-art technology centers and testing facilities around the world. At these facilities, dedicated experts research and develop solutions for some of the most challenging issues facing the energy sector.
Advanced digital solutions:
We are a world-leading provider of software and digital solutions for managing risk and improving performance of power generation assets, transmission lines, pipelines, processing plants, offshore structures, ships, and more.
Your partner for energy systems thinking
DNV ensures integrated planning across all energy types, sectors, and regions. DNV’s North American team deeply understands the entire energy system, including specific regional markets and regulatory frameworks. This local expertise is powerfully backed by a global network of experts, ready to be mobilized anywhere in the world, with access to world-class technology centers and cutting-edge digital tools.
Learn more in the Global Energy Transition Outlook 2025 report.
An Indiana utility has come up with an unusual plan for meeting growing power demand from data centers.
Northern Indiana Public Service Co. is launching a spinoff company, GenCo, that is exempt from many of the regulatory proceedings typically required before power plants can be built in the state. The utility, also known as NIPSCO, says that this will allow the new entity to quickly provide the copious amounts of energy that data centers need without pushing excessive costs onto other consumers.
But the move is raising alarm bells for watchdog groups and other critics, who argue that rather than protect consumers, the plan will mainly enrich the utility’s parent company while interfering with market competition and undercutting important regulatory safeguards. It could also set back the state’s clean-energy transition, advocates say.
As regulators around the country wrestle with how to get a lot of power online quickly to serve “hyperscaler” AI data centers, other utilities may be looking at NIPSCO’s “unique arrangement” as “a model for how to maximize profits while meeting new data-center demand,” said Emily Piontek, a regulatory associate at the nonprofit Clean Grid Alliance.
Indiana is attractive to huge data centers because of its cheap land, ample water, special state tax breaks on equipment and energy, and access to both the PJM Interconnection and Midcontinent Independent System Operator regional electric grids. The State Utility Forecasting Group at Purdue University recently predicted that data centers will almost double Indiana’s energy demand by 2035.
NIPSCO highlighted that boom to the Indiana Utility Regulatory Commission during the case proceedings to create GenCo. Vincent Parisi, president and CEO of both NIPSCO and GenCo, told regulators about the sheer number of requests the utility has gotten from potential “megaload” customers, generally data centers, seeking hundreds or even thousands of megawatts of electricity.
But it’s a competitive business, with other states and municipalities courting the same data centers. NIPSCO says that providing new power quickly, through GenCo, will be key to securing the deals.
The regulatory commission agreed with this reasoning, writing in its September order approving the GenCo plan, “The evidence shows that megaload customers are sophisticated and have many choices available to them when determining where to make developments.” The commission added that relinquishing its jurisdiction over aspects of GenCo “will enable NIPSCO to support Indiana’s efforts to compete with other states to attract this economic development.”
Nationwide, regulators and advocates have grappled with concerns that residential customers could pick up too much of the tab for new generation built to power data centers, especially if the computing warehouses don’t materialize or don’t use as much power as predicted.
NIPSCO says GenCo will protect customers from such costs since it will be responsible for providing the data centers with power. That means those expenses won’t be rolled into the rates paid by other NIPSCO consumers, the utility says.
But Citizens Action Coalition, the state’s main consumer-advocacy group, argues that the GenCo structure doesn’t really insulate customers from the risks of the data-center market.
If GenCo were to lose money, that could affect the finances and credit rating of parent company NiSource and hence impact NIPSCO’s customers, said Citizens Action Coalition Executive Director Kerwin Olson. And he worries some costs of data-center power infrastructure could still be passed on to residential customers, hidden in an opaque process created specifically for GenCo.
In September, the state regulatory commission exempted GenCo from a host of usual procedures. Chief among them is that GenCo does not have to file a detailed plan when it wants to build or acquire new generation. The commission did not set any minimum standards or requirements regarding how power will be provided to data centers, as advocates had hoped. Instead, the commission will review each proposed contract between NIPSCO and a data center, and the related power purchase agreement between NIPSCO and GenCo.
The Citizens Action Coalition called this case-by-case review process unfair and inefficient, making it too difficult for stakeholders to monitor the situation and submit public comments to the commission.
“Every single time a data center comes online, there’s another case; there’s no minimum criteria or boxes that need to be checked,” said Olson. “I know they’re claiming costs won’t be passed on to ratepayers, but we’ve been around the block. When you have what will likely be confidential special contracts, everything redacted, it’s going to be really challenging for stakeholders to dive into the details to ensure that none of these costs are being passed on.”
NIPSCO declined to answer questions but referred Canary Media to a press release quoting Lloyd Yates, NiSource president and CEO, regarding the regulatory commission’s decision.
“This is an important step forward to position Northern Indiana at the center of a fast-growing, economically essential industry,” Yates said.
The Citizens Action Coalition and the Indiana Office of Utility Consumer Counselor, a state agency tasked with protecting consumers, notified the commission that they plan to appeal the approval of GenCo.
Another major concern of critics is that GenCo will have an unfair competitive advantage over other power producers.
Indiana has a regulated energy market, wherein utilities have the right to serve as monopoly producers and distributors of energy, but regulators must approve how much capacity they build or buy and what they charge customers for the power.
GenCo is largely exempt from this structure, acting more akin to a power producer in a state like Illinois, with a deregulated market. But in Illinois, power producers compete to sell their energy to utilities, whereas GenCo has a guaranteed customer in the form of NIPSCO, and the two sister companies — which share the same parent — set the price NIPSCO will pay GenCo for power.
“The utility affiliate is being treated like an unregulated independent power producer while retaining the guarantee of a monopoly market enjoyed by regulated utilities,” Piontek said. “Essentially, the arrangement insulates GenCo from market forces, and [it] is not subjected to rate regulation. It’s going to be a very profitable arrangement for the parent company and its shareholders … by providing the affiliate with an unearned competitive advantage.”
The Clean Grid Alliance — made up of renewable-energy developers, environmental groups, and other stakeholders — and Takanock, a data-center developer, told regulators in a joint brief that GenCo “turns the federal paradigm which encourages competition … on its head by proposing that GenCo, and only GenCo, provides generation services to NIPSCO to serve its megaload customers.”
In testimony, Takanock founder and CEO Kenneth Davies told regulators about problems his company has had trying to acquire power from NIPSCO for a planned data center. Davies described the NIPSCO-GenCo relationship as “anticompetitive,” and lamented that NIPSCO will not allow new data-center customers to buy power on the open market themselves, as some existing industrial customers are allowed to do. Davies said NIPSCO seems to be “picking and choosing” which data centers to prioritize, and he is worried Takanock could be treated unfairly, since confidential contracts would make it difficult to compare the arrangements other data centers are getting.
Davies and other stakeholders say there are ways for NIPSCO to protect customers from data-center costs without creating a new market entity with an unfair edge.
Takanock and the Clean Grid Alliance, in their filing, criticize GenCo for failing to explore the more common method of pricing tariffs designed specifically for data centers. That’s where a utility makes an agreement with state regulators to treat data centers differently from other customers, ensuring they pay their fair share of costs. Davies described Wyoming regulators’ creation of such a special tariff to serve a Microsoft data center. Davies was Microsoft’s director of renewable-energy strategy and research at the time.
In another example, Citizens Action Coalition reached an agreement last year with utility Indiana Michigan Power and three new data centers, requiring long contracts, exit fees, and other protections to ensure the centers pay the full costs of infrastructure built to serve them, even if they don’t use as much power or operate for as long as expected. The agreement also requires the data centers to pay millions of dollars to support low-income electricity customers with benefits like weatherization.
Advocates point out that Indiana already has a law on the books meant to help utilities more quickly get power online to supply data centers, without sacrificing transparency or relying on a new entity like GenCo. HB 1007, enacted in May, gives utilities an expedited approval process for new generation if they provide information about the impacts on customers, predicted load growth for the next five years, and the potential of grid-enhancing tech to avoid investments in new power plants, among other things.
“NIPSCO decided to ignore 1007 and create what we think is a shell game, a scam, with this unregulated affiliate doing Lord knows what,” said Olson.
The creation of GenCo will likely undermine the clean-energy transition in northern Indiana, advocates say. NIPSCO has already made clear its plans to build lots of natural-gas-fired generation to power data centers, and if this is carried out through GenCo, stakeholders will have little opportunity to weigh in on the implications.
This is a disappointing shift for environmental groups that had praised NIPSCO for plans it announced in 2018 to retire all coal plants within a decade and build out renewables, reducing carbon emissions by 90%.
By contrast, NIPSCO’s 2024 Integrated Resource Plan says that if contracts with data centers are in place, the utility will build over 1,700 megawatts of gas generation by 2030 and another over 2,000 MW by 2035. Already, NIPSCO is seeking an air permit to build 2,300 MW of gas-fired generation at the site of a retiring coal plant, in order to serve data centers.
“GenCo is certainly a concern for the climate, demonstrating that NIPSCO has done a complete strategy reversal on sustainability,” said Ben Inskeep, program director at Citizens Action Coalition. He said the utility’s 2018 resource plan “was groundbreaking for leading the way on a clean-energy transition. Now, they are pursuing a strategy that appears to be 100% natural gas for new data centers, with no additional clean energy to serve the additional load.”
If NIPSCO had to turn to the open market to procure the power that data centers need, Piontek noted, more renewables would likely get built along with the gas-fired generation.
“Clean-energy resources like wind, solar, and energy storage outcompete other resources in speed-to-market and remain the most cost-effective resources available, making them an attractive option for bringing data centers online in Indiana,” Piontek said.
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