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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.
A new policy in China could ramp up the nation’s production of green hydrogen for use in airplanes, ships, and other heavy industries, potentially eclipsing output of the fuel in the United States and Europe.
Earlier this month, the National Development and Reform Commission — the high-ranking executive department in charge of economic planning — released what analyst Jian Wu called China’s single “most important low-carbon policy for 2025.”
Until now, China has encouraged provincial governments and state-owned companies to develop hydrogen technology by providing lower electricity prices and loans and by setting production quotas. But unlike the United States and the European Union, the national government in Beijing had no overarching policy to directly subsidize low-carbon hydrogen projects.
While the document published on Oct. 15 does not specify hydrogen by name, the policy change makes Chinese industries that depend on the clean fuel eligible for direct grants.
For the first time ever, the rules outlining which types of industrial projects qualify for national grants list green methanol, carbon capture, sustainable aviation fuel, and zero-carbon industry parks — “paving the way for rapid development of these applications in China,” Wu wrote in his China Hydrogen Bulletin newsletter. Of the hundreds of clean-energy directives China issues at its various levels of government each year, Wu emphasized, the latest policy is “absolutely” the most significant, particularly for heavy industry.
By designating those sectors for direct grants under Beijing’s central budget, “the government is effectively establishing its first national funding mechanism for some of these hydrogen-adjacent technologies,” said Amy Ouyang, a hydrogen associate at the Clean Air Task Force, a Boston-based environmental group.
“China’s hydrogen sector has relied heavily on private capital, so this guidance marks a potential shift toward a more coordinated, state-backed effort to turn policy ambition into on-the-ground deployment,” she said, adding that “the inclusion of these adjacent technologies could reinforce its growing role in China’s broader industrial decarbonization strategy.”
The move comes as the United States turns away from its nascent efforts to develop a clean-hydrogen industry. The landmark 45V federal tax credits meant to spur production and use of clean hydrogen, once slated to last until 2033, are now set to phase out in two years as a result of President Donald Trump’s One Big Beautiful Bill Act. The Trump administration, meanwhile, is poised to use funding meant for hydrogen-based steel projects to bolster production of steel made with fossil fuels instead.
China is already the world’s largest hydrogen market, by far. At about 33 million metric tons of demand per year, the industry is roughly three times the size of the American market. In the United States, 95% of hydrogen is produced with natural gas, primarily through a process that involves using steam heated to temperatures as high as 1,832 degrees Fahrenheit to separate the molecule out of methane. America’s reliance on natural gas is no surprise, given that it has vast reserves and the world’s largest drilling industry.
By contrast, China imports much of its natural gas, so the fuel is used to generate 25% of the country’s hydrogen. A significant share of China’s hydrogen is a byproduct of other industrial processes, such as heating coal to make purified “coke” for steel mills.
Since a portion of that byproduct hydrogen is vented into the atmosphere as waste, the new national grants could include projects that capture and repurpose more of that gas. But China’s world-leading deployments of solar, wind, hydro, and nuclear power plants also generate an ample supply of clean electricity to produce green hydrogen — the version of the fuel made by blasting distilled water with enough electricity to separate hydrogen molecules from the oxygen ones. Already, in July, China agreed to sell a historic debut shipment of green steel made with hydrogen to buyers in Italy.
Despite China’s clean-energy advantage, the U.S. and European Union had, until now, boasted stronger national policies for developing domestic green hydrogen.
While China’s government-owned businesses invested in green hydrogen, “there was nothing at the national level,” like the 45V tax credits in America’s Inflation Reduction Act or the European hydrogen bank, said Anne-Sophie Corbeau, a hydrogen researcher at Columbia University’s Center on Global Energy Policy.
For example, Beijing backed fuel-cell vehicles, but the support came primarily as a reward for reaching manufacturing targets, not as direct subsidies, she said. The central government might give an annual reward of 1.6 billion yuan ($225 million) per city based on progress toward certain deployments of fuel-cell infrastructure, but “if you are underperforming, you may get nothing,” Corbeau said.
“Broadly, that means no state support for industrial applications like what we may have seen in other countries,” she said.
This month’s policy shift will direct Beijing’s funding hose at heavy industries that transition from coal and gas to hydrogen, including “power, steel, nonferrous metals, building materials, petrochemicals, chemicals, and machinery,” said Xinyi Shen, the China team lead at the Centre for Research on Energy and Clean Air, a Finnish research nonprofit.
“This policy sends a strong signal of China’s commitment to accelerating its green transition,” she said. “Given China’s current clean-energy momentum and industrial policy direction, the country may ultimately achieve deeper [emissions] cuts than it has formally committed to.”
Still, Shen warned, “green hydrogen remains costly.” But China’s capacity to swiftly scale industries that the government makes a priority has a history of sending prices plunging, as happened with solar panels and batteries. And China’s hydrogen sector “is expanding rapidly,” Ouyang said.
Between 2021 and 2023, she said, roughly 100 to 200 new hydrogen-related companies launched each year in the country. Today, China dominates manufacturing of the most popular type of electrolyzer, the machine used to make green hydrogen, representing roughly 60% of the global market. Thanks to that scale, a Western company buying a Chinese-made electrolyzer would pay one-third the price of a locally made counterpart.
If central government funding accelerates in the next year or two as expected, “China could solidify its leadership in the industry and achieve some of the world’s lowest-cost green hydrogen,” Ouyang said.
That could put the U.S. and Europe at risk of lagging behind China, just as they have with other steps in the clean-energy supply chain, experts say.
Corbeau said the conditions are already there for China to dominate the industry. Once the federal tax credits expire, she said, “nothing much will happen” beyond “a few projects” in America.
She noted that in Europe earlier this year, the regional hydrogen bank’s second offering of a public subsidy for hydrogen tried to limit funding for projects that had too many Chinese components. But “the scheme does not give much money, and some projects told me they are better off with Chinese technology because of the cost advantage,” Corbeau said.
“It’s almost too late already,” she added.
Eavor, an advanced-geothermal startup, says it has significantly reduced drilling times and improved technologies at its nearly online project in Germany — milestones that should help it drive down the costs of harnessing clean energy from the ground.
On Tuesday, the Canadian company released results from two years of drilling activity at its flagship operation in Geretsried, Germany, giving Canary Media an exclusive early look. Eavor said the data validates its initial efforts to deploy novel “closed-loop” geothermal systems in hotter and deeper locations than conventional projects can access.
“Much like wind and solar have come down the cost curve, much like unconventional shale [oil and gas] have come down the cost curve, we now have a technical proof-point that we’ve done that in Europe,” Jeanine Vany, a cofounder and executive vice president of corporate affairs at Eavor, said from the Geothermal Rising conference in Reno, Nevada.
Eavor is part of a fast-growing effort to expand geothermal energy projects beyond traditional hot spots like California’s Salton Sea region or Iceland’s lava fields. The company and other firms — including Fervo Energy, Sage Geosystems, and XGS Energy — are adapting tools and techniques from the oil and gas industry to be able to withstand the harsh conditions found deep underground.
The industry wants to produce abundant amounts of clean electricity and heat virtually anywhere in the world, and it could serve as an ideal, around-the-clock pairing to solar and wind power. But geothermal companies are only just starting to put their novel technologies to the test.
Eavor began drilling in Geretsried in July 2023, shortly after winning a $107 million grant from the European Union’s Innovation Fund. For its first “loop,” the company drilled two vertical wells reaching nearly 2.8 miles below the surface, then created a dozen horizontal wells — like tines of a fork — that each stretch 1.8 miles long. Once in place, the wells are connected underground and sealed off so that they operate like radiators: As water circulates within the system, it collects heat from the rocks and brings it to the surface.
Operations on the first of four loops are nearly complete, and the startup plans begin construction on its second loop in March 2026. All told, the system will supply 8.2 megawatts of electricity to the regional grid and 64 MW of district heating to nearby towns, operating flexibly to provide more heat during chilly winter months and produce more electricity in summer.
In its new paper, Eavor said it encountered significant challenges in drilling its first eight of twelve lateral wells, which took over 100 days to complete — a major expense in an industry where drilling rigs can cost about $100,000 a day to run. But the company said it improved its techniques and adapted its equipment in ways that reduced the drilling time for the remaining four wells by 50%.
For example, Eavor said it successfully deployed an insulated drill pipe technology, which can actively cool drilling tools even as they encounter increasingly hotter conditions underground and helps to increase drilling speed. The adjustments also enabled Eavor to triple the length of time its drill bit could run before wearing out, further reducing downtime during the operation.
On top of cutting drilling time and costs, these improvements should also pave a path to boosting Eavor’s thermal-energy output per loop by about 35%, Vany said.
The Germany project will be the first commercial system of its kind when it starts producing power later this year. But other next-generation approaches — like the enhanced geothermal systems that Fervo is building in Utah and operating in Nevada — are also scaling up.
Enhanced geothermal involves fracturing rocks and pumping down liquids to create artificial reservoirs. The hot rocks directly heat the liquids, which return to the surface to make steam. This approach is relatively more efficient at extracting heat from the ground, but it can also raise the risk of inducing earthquakes or affecting groundwater — though experts say that’s unlikely to happen in well-managed projects. In places that ban fracking, like Germany, closed-loop systems can still move forward.
But the closed-loop design has trade-offs of its own, said Jeff Tester, a professor of sustainable energy systems at Cornell University and the principal scientist for Cornell’s Earth Source Heat project. Namely, the pipes can limit the transfer of heat from the underground rocks to the fluids inside the pipe, which in turn limits how much energy a system can produce.
“While companies developing closed-loop systems can make them work, the main challenge they face is for fluid temperatures and flow rates to be high enough to pay off economically,” Tester said. “You can get energy out of the ground; it’s just, how much can you sustainably and affordably produce from a single closed-loop well connection?”
Vany said that Eavor’s modeling shows its technology is already in line with the “levelized cost of heat” in Europe, which estimates the average cost of providing a unit of heat over the lifetime of the project. That figure can fluctuate between $50 and $100 per megawatt-hour thermal in the region’s volatile energy market, she said.
“After we’ve drilled those first four loops, we will be at the bottom of the learning curve,” Vany added. “And that’s the purpose of the Geretsried project.”
In the early 2000s, the owners of the Mammoth Pacific geothermal station proposed expanding the plant into an area just east of California’s Yosemite National Park. The project boasted on its website in 2004 that the potential new wells, which would be located in one of the state’s richest heat resources, had been “carefully chosen to reduce or avoid potential environmental impacts.”
By 2009, the company had produced a study on how the development could impact plant life. The power station had been running since the 1980s, so the decades of data on its safe operation seemed to bode well for a swift approval at a moment when, much like today, rising electricity demand and concern over climate change were converging to bolster development of carbon-free power. The prospects looked so good that, in 2010, geothermal giant Ormat Technologies bought the company that owned Mammoth. In 2013 — a decade after the expansion was first conceived — federal regulators gave the project the green light.
Yet that was just the start of Mammoth Pacific’s permitting saga.
An environmental group and local opponents quickly accused regulators of failing to properly consider how the geothermal project could release organic gases into the atmosphere and groundwater, and filed a lawsuit under the California Environmental Quality Act. The litigation took years to resolve. By the time Ormat finally completed the expansion in 2022, the so-called Casa Diablo IV project had been in the works for nearly two decades.
“People in the industry know it took 17 years to expand an existing facility,” said Joel Edwards, the cofounder and chief technology officer at the geothermal startup Zanskar. “And that’s the last facility that’s been built in California.”
Building a new geothermal plant from scratch on an undeveloped site, he said, would presumably “be an even bigger lift.”
A bill that California lawmakers passed almost unanimously last month promised to change that calculus for the geothermal industry. AB 527 would have provided geothermal developers with categorical exemptions to CEQA reviews, clearing the way for companies to carry out the most expensive part of the process — drilling wells to identify viable hot-rock resources — without the costly burden of lawsuits and ecological assessments the state’s landmark environmental law imposes. A companion bill, known as AB 531, gives geothermal energy projects the same special “environmental leadership” status as solar, wind, energy storage, and hydrogen facilities.
But, in a move that has mystified the industry, Gov. Gavin Newsom (D) vetoed AB 527. In his letter explaining the rejection, Newsom said the legislation would have required state regulators to “substantially increase fees on geothermal operators to implement the new requirements imposed by the bill.”
Of more than half a dozen industry executives and analysts that Canary Media spoke to, however, none believed that argument.
“Something doesn’t add up,” said Samuel Roland, a research fellow at the Foundation for American Innovation who has tracked the bill. “It was a political play for him.” The foundation is a right-leaning think tank that advocates for speeding up energy deployments.
While Roland said it’s difficult to determine exactly which groups may have persuaded the governor to block the legislation, “the only people who were objecting were environmentalists,” a dynamic that echoes the fight against Mammoth Pacific’s expansion.
“It does seem like it was a giveaway to environmental groups,” Roland said.
Izzy Gardon, a spokesperson for Newsom, declined to comment. “The Governor’s veto message speaks for itself,” he wrote in an email to Canary Media.
California’s unique geology has made it the destination for the geothermal industry for decades. The Western Hemisphere’s first commercial geothermal power station opened in California in 1960. That plant — The Geysers geothermal complex, located in a valley of the Mayacamas Mountains north of the San Francisco Bay Area — remains the world’s largest electrical station powered by the planet’s heat.
The state has enormous untapped potential — and a growing need for electricity. California has shut down all but one of its nuclear power plants over the past few decades. In recent years, persistent drought has made the state’s hydroelectric stations less dependable. Solar generation has soared, and a growing fleet of batteries has helped steady the supply when sun-soaked days threaten to overwhelm the grid with electrons and dark nights send panels’ production plummeting. But the state remains reliant on natural gas and power imports from neighboring states to meet surging demand. To achieve its carbon-cutting goals and bring down electricity rates that are more than double that of nearby states, California needs to increase its supply of clean, firm generation.
Burning biomass, such as dry wood cleared from California’s forests to help prevent wildfires, could provide one option — but that still generates carbon dioxide, and the demand for wood might encourage logging of healthy trees. Despite the state’s reversal of its plan to shut down Diablo Canyon, its final atomic station, building new nuclear reactors is still banned in California. Hydropower is dogged by water scarcity. That makes geothermal a particularly attractive choice.
It’s not without some drawbacks. Conventional geothermal, which involves drilling down into underground reservoirs warmed by volcanic heat, is limited to easily accessible areas and comes with the challenge of maintaining the subterranean water source over time. Next-generation geothermal companies are rapidly advancing drilling techniques that the oil and gas industry perfected in recent years to go deeper and harvest heat from dry, hot rocks, vastly expanding the locations with potential to generate energy. In a seismically active state, that carries some risk since the version of next-generation geothermal that uses hydraulic fracturing, or fracking, technology to drill could trigger earthquakes.
But every energy source comes with challenges, and neighboring states such as Utah, Nevada, and New Mexico are aggressively pursuing next-generation geothermal projects.
In theory, the best place to develop those first-of-a-kind plants would be California, with its energy-affordability woes and status as a major global economy.
“Utah has low prices, and geothermal is still expensive,” said Thomas Hochman, director of infrastructure and energy policy at the Foundation for American Innovation. “If you want to bring geothermal down to cost parity with other technologies, you have to sell it to Californians. As a result, geothermal scaling runs through California.”
For the most part, however, developers are steering clear of the Golden State. Companies such as Fervo Energy, XGS Energy, and Sage Geosystems — three of the biggest next-generation startups — are based in Houston and are pursuing debut projects in Utah, New Mexico, and Texas itself. Zanskar, a developer using modern prospecting methods to tap conventional geothermal resources, is headquartered in Salt Lake City. States such as Arizona, Colorado, Idaho, and Oregon are “really exciting” as potential next areas for development, Edwards said.
“If California ever fixes CEQA,” he added, “it could be huge.”
The regulatory hurdles represent “the only real barrier” to geothermal taking off in the Golden State, said Wilson Ricks, a Princeton University researcher who focuses on geothermal.
“You can find projects pretty much all across the Western states but very few, if any, in California, despite it being the biggest potential market,” Ricks said.
“It’s stark. People are exploring projects in Texas, which has far, far worse-quality resources than the ones in California,” he added. “That’s because of the regulatory environment there. So the fact that regulatory barriers are going to remain in place doesn’t give me a lot of confidence that California’s going to be leaping ahead on geothermal anytime soon.”
In response to emailed questions, Fervo said it maintains leases near the Salton Sea region, an area with vast geothermal potential. But those parcels aren’t currently under development since the state’s permitting regime makes investing in drilling too risky.
“With the right legislative and permitting reforms, similar to those that were proposed in AB 527, the state could better position in-state resources for development and unlock the enormous economic benefits that come with local clean energy development,” said Sarah Harper, Fervo’s senior policy and regulatory affairs associate.
Not everyone is so bearish. Ormat, the nation’s largest geothermal operator of conventional sites, said the fact that the vetoed bill passed in the Legislature without a single no vote, just a handful of abstentions, shows there’s political support for geothermal “like we haven’t seen in the past.”
“It’s like a revolution for geothermal,” said Marisol Collons, Ormat’s manager of communications and government affairs. “We’re still highly optimistic about the future and ready to kickstart all our next legislative sessions across the country.”
While Fervo lamented that a small number of green groups fought the bill, the company said the fact that there were “more environmental groups in favor than there were ones opposed, or even neutral,” left it feeling hopeful about the possibility of future legislation.
For XGS, a next-generation company whose technology forgoes fracking and minimizes its water usage by keeping the fluid for its operations contained in a closed tube, California remains “the highest-priority market.”
“We feel that California provides a unique combination from both a resource perspective and a market perspective,” said Lucy Darago, chief commercial officer at XGS. “It’s a high-demand market that really needs the attributes that geothermal brings.”
The company backed the bill and said categorical exemptions from CEQA permitting for drilling would have shaved anywhere from six months to two years off its development efforts.
“It’s disappointing, but I’m optimistic that a future iteration of the bill will pass,” Darago said.
The key, she said, is time. Geothermal will grow in California no matter what — of that, Darago said, she’s certain. The question is whether that happens in time to stave off blackouts and slash emissions on the trajectory the state has set for its electrical system.
“The industry is going to happen. It will get there,” she said. “But if it’s going to get there on a timeline that’s meaningful for California’s resource-adequacy challenges and climate goals, we’ll need some of these changes.”
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