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After years of false starts and amid an acute regional energy crunch, large-scale onshore wind power could finally take off in Maine in 2026. Utility regulators in five New England states are considering developers’ proposals to build up to 1.2 gigawatts of onshore wind capacity in Maine’s far north, following a deadline for bids earlier this month.
The coordination between Connecticut, Maine, Massachusetts, Rhode Island, and Vermont — all of which have ambitious clean energy goals — means this procurement is more likely to succeed than those that have fizzled out in years past, said Francis Pullaro, president of clean-energy industry association RENEW Northeast.
“The states have come together, and that’s a pretty impressive accomplishment on their part,” he said. “We’re in a much better position now that we have the states going into the process having conferred.”
Maine’s Public Utilities Commission confirmed that at least one bid was submitted, but declined to share any further details at this time.
New England leaders have for nearly two decades discussed harnessing northern Maine’s robust winds to boost the region’s supply of renewable energy, but the idea has gained more urgency in recent years. Financial challenges and hostility from the Trump administration have dampened the prospects for the offshore wind developments that much of the region was counting on to meet their clean energy goals. At the same time, soaring utility bills and volatile oil and gas prices driven by conflicts in Ukraine and the Middle East have strengthened the case for turning to power generation with no fuel costs.
“It’s becoming more apparent that there is a need for solutions to confront the cost of energy,” said Eliza Donoghue, executive director of the Maine Renewable Energy Association. “Certainly, this is not a silver bullet, but it is a way we can have more renewables injected into the system.”
Maine’s attempts to lean in to wind power began in 2008, with the adoption of a law that set a target of having 3 GW of wind power — some of it offshore — by 2020. Reality fell short of that goal: As of October 2025, the state had about 1.2 GW of land-based wind capacity and no offshore wind, according to the federal Energy Information Administration.
Clean energy boosters have long considered Aroostook County on the Canadian border a promising location for onshore wind development. However, the county is part of a small, local electrical network that is not connected to the New England grid. Any wind projects in the area would require new transmission lines to carry the power produced to the rest of the region.
Attempts to develop projects in remote Aroostook County floundered in 2016 and again in 2023. In both cases, the complications and cost of building transmission infrastructure were major obstacles.
Wind supporters are hoping this time will be different as the multistate collaboration supports much-needed power lines and streamlines bid assessment. All five states have set aggressive emissions-reduction targets: Maine is aiming for 100% clean energy by 2040, for example, and Massachusetts and Rhode Island both want to be carbon-neutral by 2050.
In recent years, they’ve worked together to achieve these goals across the region.
Last March, at the recommendation of the New England States Committee on Electricity, an organization representing the area’s governors on energy matters, grid operator ISO New England issued a request for proposals for transmission infrastructure connecting central Maine to the rest of the grid, shortening the distance power lines would have to travel from wind turbines in Aroostook County. ISO New England received six proposals, which it narrowed down to two after preliminary analysis. The organization will continue its assessments and may announce a preferred proposal in September, after which it will be up to the states to decide whether to proceed.
Also, the Maine Legislature passed a measure in 2023 allowing Maine to partner with other New England states on wind procurements. This move means Maine is sharing bids received in response to the most recent request for proposals with the other participating states, which will then coordinate on selecting a recommended wind farm. A winning bid is slated to be announced by the end of May.
“The fact that we’ve got five of the states signed on and committed to this is pretty important,” Pullaro said.
As power-hungry data centers and rising fuel prices put the squeeze on anxious voters last fall, Virginia Democrats secured a governing trifecta in Richmond partly on a promise to rein in energy costs.
Now, with a 60-day legislative session in the rearview mirror as of March 14, newly elected Gov. Abigail Spanberger and lawmakers in her party look primed to deliver on that pledge in spades.
Democrats, who grew their majority in the House of Delegates last November and have controlled the Senate since 2020, still remain divided on whether and how to continue the tax breaks that have helped make Virginia the data center capital of the world; a special session is scheduled next month to resolve the standoff.
But legislators already have plenty of bragging rights. A slew of bills that would maximize use of the state’s grid, pave the way for more batteries and solar arrays of all sizes, and take other steps to lower energy bills are poised to become law with Spanberger’s signature in the coming weeks.
“I think it was a good session for affordability,” said Sen. Schuyler VanValkenburg, a Democrat who represents a suburban Richmond district. “I think it was a good session for supply.”
In many ways, Virginia is the poster child for the energy upheaval underway across the country. It’s ground zero for the AI boom and the massive computer warehouses needed to support it, which threaten to spike demand at rates not seen in decades. PJM Interconnection, the regional grid manager, is plagued by backlogs and barely capable of bringing new generation sources online. The cost of fossil fuels, together with the ongoing addition and upkeep of poles and wires, is contributing to skyrocketing utility bills.
Amid these pressures, the state hasn’t wavered from a law mandating 100% carbon-free electricity by midcentury — even as the Trump administration has repeatedly threatened to derail Coastal Virginia Offshore Wind, the largest offshore wind farm in the country, and as congressional Republicans have slashed incentives and other inducements for solar and energy efficiency.
All that context was top of mind as lawmakers began their session this year, said Del. Phil Hernandez, a Democrat from Norfolk. “The assignment was crystal clear,” he said. “It really doesn’t matter where you are in Virginia: Electricity prices are salient. People are concerned, rightly, about the upward trajectory.”
Democrats’ strategy for tackling those worries was twofold, said VanValkenburg: to boost solar and storage, and to better utilize existing transmission and distribution infrastructure. “These are the two things we can do that are the cheapest, the fastest to get online, and the fastest way to save ratepayers money,” he said.
VanValkenburg has been on a long quest to speed the deployment of large-scale solar, promoting bills in 2024 and 2025 to ease local solar restrictions; they failed to become law. But the third time might be the charm. His latest attempt, Senate Bill 347, prohibits outright bans on large-scale solar while still leaving ultimate siting decisions up to local governments. It cleared both chambers last month and awaits Spanberger’s signature — though it’s among the few energy measures she hasn’t taken an explicit position on.
“I hope she signs it,” VanValkenburg said. “At the end of the day, this bill doesn’t mandate a single piece of solar. It just creates a better conversation, which I think will get us more solar.”
While that measure would pave the way for adding immense solar farms capable of powering thousands of homes, lawmakers also legalized a much smaller variant: balcony solar. Come January, Virginians should be able to buy and plug in the devices on their balcony or yard in the span of a few hours — avoiding permitting and utility red tape and shaving as much as 15% off their energy bills.
Lawmakers also sought to boost rooftop solar arrays this session, chiefly by increasing targets for these types of installations. The 2020 Virginia Clean Economy Act called on Dominion to get at least 1% of its electricity from renewable energy projects less than 1 megawatt in capacity. A bill sponsored by VanValkenburg, which now sits on the governor’s desk, would increase that number to 5%.
The Virginia Clean Economy Act could also get a refresh when it comes to batteries. The law was first written to require utilities Dominion Energy and Appalachian Power Co. to deploy a little over 3 gigawatts of short-duration batteries, a mature technology that is widely available. A measure sponsored by Democrat Del. Rip Sullivan of Fairfax would raise the target to nearly 17 gigawatts by 2045, with most coming in data center–heavy Dominion territory. By that same year, the bill requires the utilities to deploy a total of 4.5 gigawatts of long-duration storage; such batteries can discharge energy for 10 hours or more but are still nascent in the commercial sector.
“Storage is really a critical affordability component, especially over the long term,” said Nate Benforado, senior attorney at the Southern Environmental Law Center. “If we can build storage, that is going to obviate the need for a lot of this gas, which is expensive and risky for customers.” Noting the war in the Middle East as the latest global conflict to impact fossil fuel prices, Benforado added, “If we continue to invest in gas infrastructure, expect your bills to go up and up.”
Lawmakers also passed bills to better utilize the state’s existing network of poles, wires, and other electricity delivery infrastructure. Because the grid is built to accommodate the maximum amount of electrons that might ever flow through it — such as on a particularly cold winter morning when people crank up heating systems — about half of it goes unused 99% of the time.
One measure would require Dominion and Appalachian Power to quantify grid utilization across their systems, a first step toward the deployment of batteries, line sensors, and other grid-enhancing technologies to increase energy generation on the system.
Another bill, dubbed the Fast Access to Surplus Transmission, or FAST, Act, would spur the same companies to identify sites where batteries or other technologies could be added to existing solar projects, taking advantage of extra room on the grid at the point of interconnection. Under a first-of-its-kind trial program, the utilities could add a total of 600 megawatts of generation using the surplus capacity.
“We’ve started to see a drastic reduction in costs around energy storage,” said Jim Purekal, a director at Advanced Energy United who heads the group’s legislative work in Virginia. “The more we install these, especially if we use existing grid capacity, the more we’re saving everybody money. And if we’re able to install these projects in tandem with solar and wind, which are your cheapest forms of energy generation, now we’re off to the races.”
Hernandez was a sponsor of the FAST Act, and he is especially proud of its novelty. “Sometimes Virginia is not great at being first to move on a concept,” he said, “but in this case, it worked out.”
He also championed legislation requiring Dominion and Appalachian Power to invest millions in energy-efficiency upgrades for low-income, elderly, and disabled households. Another of his bills would streamline the permitting process for home rooftop solar.
“There were a whole lot more from other members,” Hernandez said. “This moment that we’re in is all about having 1,000 great ideas, because there’s no one thing you can do to fix every problem.”
To wit, over 50 energy and climate bills tracked and supported by the Virginia Conservation Network passed during the two-month session — including those setting the state up to rejoin the Regional Greenhouse Gas Initiative, adopt more community solar farms, study ratemaking reforms, and many others.
Spanberger has yet to sign any of the measures, and many passed with little help from Republicans. But the vast majority of these bills are almost certain to become law, and VanValkenburg is hopeful that they’ll endure with bipartisan support. That’s because the economics of clean energy — especially solar and storage — just keep improving.
“I think these laws are going to be durable from a free-market capitalism perspective,” VanValkenburg said. “But I also just think that those are also the only ways that you’re gonna keep energy bills down.”
The world is in a state of climate emergency, the head of the United Nations declared Sunday, following the release of the latest State of the Global Climate report from the World Meteorological Organization.
“Earth is being pushed beyond its limits while every key climate indicator is flashing red,” said U.N. Secretary-General António Guterres. “Earth’s energy imbalance, the gap between heat absorbed and heat released, is the highest on record. Our planet is trapping heat faster than it can shed it.”
The consequences, he added, “are written into the daily lives of families struggling as droughts and storms drive up food prices, in workers pushed to the brink by extreme heat, in farmers watching crops wither, and in communities and homes swept away by floods.”
The report highlights the significance of record-high concentrations of greenhouse gases in the atmosphere and notes that the effects are visible everywhere, from the 11-year series of hottest-ever years to the way heat is accumulating deep in the oceans. For the first time, it includes a metric called Earth’s energy imbalance as a key climate indicator, measuring the rate at which energy from the sun enters and leaves the planet.
In a stable climate, incoming energy and outgoing energy are about the same. But activities such as burning fossil fuels, growing food and making steel, cement and plastic have upset that balance by pushing levels of heat-trapping carbon dioxide, methane and nitrous oxide in the atmosphere to the highest level in at least 800,000 years. That’s trapping more of the sun’s energy in the Earth’s climate system than ever previously recorded.
“Improved scientific understanding of Earth’s energy imbalance shows the disruption is real and the reality facing our planet and climate right now,” said World Meteorological Organization Secretary-General Celeste Saulo, adding that, “We will live with these consequences for hundreds and thousands of years.”
The new metric shows a more complete picture of how the climate system is responding to human emissions by integrating all the heat accumulating in the oceans and atmosphere, on land and melting ice, said oceanographer Karina von Schuckmann, a senior science adviser with Mercator Ocean International and member of the WMO’s ocean observations panel.
U.S. climate scientist Ko Barrett, deputy secretary-general of the WMO, said Earth’s energy imbalance also helps show how different parts of the climate system are connected and identifies the central role of the oceans in absorbing most of the trapped heat.
The energy balance indicator highlighted by the WMO focuses on the fundamentals of climate change, said independent climate analyst Leon Simons, who co-authored several recent papers on the topic.
“Energy coming in, energy going out,” he said. “Greenhouse gases change how much energy escapes, and the system responds. That’s really what’s driving everything.”
That basic energy measurement is a better starting point than trying to establish temperature change relative to 1850 in international forums, which then quickly start quibbling over what a tenth of a degree means, Simons said. The measurement is also more significant now because there are 20 to 25 years of data from satellite sensors designed to study Earth’s energy balance.
Science basics also help explain one of the report’s most memorable conclusions. The air temperature people experience is only about 1 to 2 percent of all the energy trapped in the Earth’s systems by greenhouse gases. About 90 to 93 percent heats the oceans while about 5 to 6 percent melts ice and heats land.
The WMO report is compiled with input from national weather agencies, international research programs and U.N. partners, drawing on data from satellites, ocean monitoring systems and weather stations worldwide. It reflects contributions from scientists and institutions across nearly 190 countries.
The information reflects the best available global science, despite concerns during the past year about cuts to U.S. climate programs, said Barrett, the WMO deputy and formerly a veteran leader of U.S. federal climate programs across several presidential administrations.
Critical data flows and climate observations have not been disrupted by any of the major contributors to the report, and she noted that Congress has restored “a lot of the funding” previously reported as having been cut. There also has been no decline in demand for accurate climate information, she added.
Guterres said that climate stress is exposing the fact that “our addiction to fossil fuels is destabilizing both the climate and global security.” Accelerating a global transition to renewable energy would “ deliver climate security, energy security and national security,” he said.
“Today’s report should come with a warning label,” he said. “Climate chaos is accelerating and delay is deadly. The way ahead must be grounded in science, common sense and the courage to act.”
See more from Canary Media’s “Chart of the Week” column.
The European Union is once again facing an energy crisis due to its reliance on imported fossil fuels — and is once again poised to lean into renewables to blunt the effects.
As the war in the Middle East upends global oil and gas markets, European Union energy chief Dan Jørgensen urged member states on Tuesday to build even more renewable energy, faster.
It’s an uncomfortable but familiar position for the EU. Following Russia’s invasion of Ukraine in 2022, the bloc rapidly reduced its reliance on Russian gas imports and swiftly built out new wind and solar power to cushion the blow to the region’s electricity sector.
The results speak for themselves. The European Union more than doubled its solar generation between 2021 and 2025. Wind grew at a more modest 24% over that time period, but it was already providing a higher share of the bloc’s electricity generation. Meanwhile, fossil fuel–generated electricity declined. For the first time ever, in 2025 the EU produced more electricity from wind and solar than it did from fossil fuels.
But the region has not ditched gas entirely. The EU got about 17% of its electricity from gas last year, and it imports almost all the natural gas it burns — 86% in 2024.
That means its energy system is still exposed to the historic disruption caused by the Iran war. The war has shut down liquefied natural gas production in Qatar, the world’s second-largest exporter of the fuel, for the past month. Gas prices globally and in the EU have surged as a result.
This energy shock will be messy and play out in different stages. For Europe, the most immediate and acute effects are being felt in the availability of jet fuel and diesel. But electricity costs will rise too, as nations are forced to buy much-more-expensive natural gas. In certain countries, it will also get dirtier, at least for a time — some EU nations are relying more heavily on coal-fired electricity to get them through the immediate fallout.
But over the longer term, this energy shock is likely to produce the same outcome as the previous one: an even faster transition away from imported fossil fuels and to domestic wind and solar.
The Cow Palace arena, just south of San Francisco, has hosted Dwight Eisenhower, the Beatles, the San Jose Sharks NHL team, and an annual rodeo since it opened in 1941. But an even bigger act is setting up next door: an enormous battery that will perform a starring role in the Bay Area’s energy ecosystem.
Developer Arevon has begun construction of the Cormorant Energy Storage Project, which will occupy an 11-acre vacant lot just southwest of the Cow Palace in Daly City. The battery facility will be large by industry standards, with 250 megawatts of Tesla Megapack containers, capable of discharging for four hours straight, for 1 gigawatt-hour of total stored energy. Bigger batteries have been built, but when Cormorant comes online in about a year, it will be poised to be the country’s largest battery nestled within a major urban area.
Arevon has contracted the battery for 15 years of use by MCE, one of California’s biggest community choice aggregators — entities that purchase electricity on behalf of local residents as an alternative to Wall Street–owned for-profit utilities. The state requires MCE to buy grid capacity commensurate with its members’ usage, and the Cormorant project will fulfill 10% of this annual requirement, known as resource adequacy in California bureaucratese.
MCE has become a major force in the greater Bay Area: It now serves all of Marin and Napa counties, most of Contra Costa, and half of Solano. The aggregator can contract for power plants across California, but it looks for sites within or near its service territory when possible, said Jenna Tenney, MCE’s director of communications and community engagement.
“Having a storage project in a community is going to add to resiliency in that community,” she said. The battery will bring $73 million of property tax revenue to Daly City, she added, and Arevon will donate $1.5 million in community benefits.
Cities need power, but generating it within urban cores is a difficult feat. California effectively stopped building gas-fired power plants, but even if that were an option, sticking a smokestack in San Francisco wouldn’t fly. These days, California expands generation by building large-scale solar plants in wide-open spaces, but those plants need to ship their power over many miles of transmission lines to reach the cities where it gets consumed.
The Cormorant battery provides something new: a dense source of on-demand power that can slip into the urban fabric without any local air pollution, and which absorbs the far-off solar generation at midday to discharge later at night. Arevon CEO Justin Johnson estimated that the battery, fitting on the site of a former drive-in movie theater, could cover the electricity needs of some 321,000 homes for four hours straight.
“It couldn’t keep the whole city going, but it certainly, without a doubt, increases the reliability of the grid in that area in a substantial way,” he said.
Arevon didn’t jump to the highest echelon of energy storage development from nothing. The firm has invested $11 billion in projects and owns 6 gigawatts of solar and battery installations operating across 18 states.
The company launched in 2021 as a spinout of Capital Dynamics, a private equity fund that amassed an early portfolio of energy storage assets. Arevon is owned by the California State Teachers’ Retirement Fund, Dutch pension fund APG, and the Abu Dhabi Investment Authority. Those firms invest for steady, long-term growth, and their patience lends itself to Arevon building and owning batteries for the long haul, instead of building to flip to other buyers.
“When we’re in there developing assets in the community, we can tell them, hey, we’re going to be here a long time,” said Johnson, who stepped up from COO to CEO in March. “You’re incentivized to engineer it well, construct it well, operate it well.”
Arevon focused on the Daly City location because electricity price volatility tends to be highest in proximity to major consumption, Johnson said. Places like that — whether metro areas or large industrial hubs — see the greatest swings from peak to off-peak hours, and having battery facilities to arbitrage between those times should push prices down in the long run. But building within a city comes with obvious trade-offs.
“Siting any infrastructure, whether you’re putting in a Walmart or upgrading an intersection or doing anything in a high-density area, is tough … especially so for power plants or facilities like this,” he noted.
Tough but not impossible, as Arevon proved in San Diego’s Barrio Logan community with its Peregrine project (another entry in a portfolio of projects sporting avian nomenclature), which came online last year. There, the company squeezed 200 megawatts of batteries between a naval shipyard and a light-rail track, in the shadow of the Coronado Bridge. In Daly City, Arevon will need to carve through roughly a mile of streets to run high-voltage cable underground to the nearest substation.
Such projects “reduce your lifespan a little bit” from the stress, Johnson said, but once built, the intrinsic difficulty becomes a sort of strategic moat. If a competitor wanted to open up next door to Cow Palace, well, they probably couldn’t find a viable space.
“Those are assets I’m really proud to own, and I think they’ll become just more and more valuable over time, because they’re hard to replace,” Johnson said.
To achieve that longevity, the batteries need to survive, and that premise is not to be taken for granted, given their location 90 miles north of Moss Landing, where the largest battery fire combusted a little over a year ago. Safety concerns are understandably higher in dense urban areas, so assuring the community that a Moss Landing–style disaster won’t happen here was integral to securing permits.
Arevon’s choice of battery, Tesla’s Megapack 2 XL, addressed the safety question. The containerized storage product is filled with the lithium-ferrous phosphate cells, a battery chemistry known to be significantly less fire-prone than earlier lithium-ion varieties. The older Moss Landing facility packed a huge amount of batteries into a single legacy structure, where they became fuel for an immense conflagration. The Megapack containers, in contrast, will be spread out across the site in a design that will prevent a fire from spreading beyond a single metal box. If one unit ever did catch fire, it would damage only a fraction of 1 percent of the plant’s capacity.
Workers are grading the site and installing “geo piers,” columns of aggregate that extend about 30 feet underground to stabilize the site during earthquakes. This is not an idle threat — the Bay Area just experienced a 4.6 magnitude tremor in the wee hours of Thursday morning. After that work is complete, the 280 Megapacks will take their places so that Cormorant can make its debut.
This analysis and news roundup come from the Canary Media Weekly newsletter. Sign up to get it every Friday.
Renewable energy’s favorite season has arrived.
Spring is when everything comes together for clean power sources. Days get longer, boosting solar generation. Winter’s blustery winds keep blowing, propelling turbines to their max. And melting snow and heavy rains combine to drive hydropower generation.
Previous springs have shown us just what this wild weather is capable of. In the first week of March 2025, Texas’ power grid, known as ERCOT, set all-time records for wind and solar power production as well as battery storage discharge.
Now, just a few weeks into spring, and with plenty more renewable power generation added in the past year, Texas is once again reaching new heights. On March 14, ERCOT reached an all-time high of 28.7 gigawatts of wind power, according to GridStatus.io. Even more impressive is the state’s solar generation, which has already set multiple records so far this year.
And while Texas is the country’s clean power leader, it’s not the only region with renewable power victories to show. Solar records have been achieved across the Southwest Power Pool, PJM Interconnection, the Independent System Operator New England, and the Midcontinent Independent System Operator this spring. ISO-NE also hit a record level for wind power generation, while MISO reached its pinnacle for overall renewables generation.
And in California, batteries stored a ton of that clean energy, and then set record after record for dispatching it throughout March.
A lot of those records were only made possible thanks to the U.S. adding 26.5 GW of utility-scale solar power generation in 2025, and another 5.7 GW of wind generation. A massive 13 GW of grid battery installations last year helped make full use of those renewables.
There’s an added bonus to all these records happening as the weather starts to warm. Most of us are starting to turn down our furnaces and heat pumps, but haven’t yet turned on our air conditioners. That means overall power demand tends to be at its lowest in the spring, and with renewables at their peak, we need far less fossil-fueled power to pick up the difference.
That confluence resulted in something monumental in March 2025: For the first time ever, fossil fuels accounted for less than half of U.S. power production across a whole month, while clean sources generated the rest. Let’s see if the U.S. can repeat that feat this year.
A global energy crisis is in full swing
Continued conflict in the Middle East is highlighting the risks of relying on fossil fuels.
It’s been five weeks since the U.S. and Israel first attacked Iran, sparking a conflict that has largely shut down oil and gas production and transportation in the region. Domestic natural gas supplies have blunted the blow in the U.S., but much of the world is facing a major energy crisis. Thailand has encouraged workers to ditch business suits to curb the use of air conditioning, while Sri Lanka has implemented a four-day workweek to limit fuel use.
The EU’s energy chief this week similarly urged residents to drive and fly less, and pushed countries to speed their transition to clean energy, saying fossil fuels’ price volatility won’t end even with a resolution in the Middle East. That’s been especially clear in the years since Russia’s 2022 invasion of Ukraine, which spurred the EU to cut off Russian gas supplies and turn its attention toward a solar and wind buildout instead.
Residential electricity price hikes aren’t slowing down, report finds
A new report offers a few explanations for why residential electricity prices are on the rise.
Across the U.S., average prices rose by 33% from 2019 through 2025, the Lawrence Berkeley National Laboratory and the Brattle Group found. That’s a big jump, but it tracks with the rising cost of groceries, housing, and other everyday expenses.
Still, that average hides the fact that some parts of the U.S. are experiencing far more dramatic hikes than others. While 29 states actually saw inflation-adjusted retail electricity prices fall from 2019 to 2025, costs spiked in California, Illinois, New England, and some mid-Atlantic states.
The report credits rising fuel costs, growing power distribution expenses, and storm recovery as some of the biggest drivers behind the power price swell. And with utilities requesting rate increases at record levels, researchers anticipate customers won’t see much price relief anytime soon.
Electrify easier: A new study finds many households can adopt energy-efficient, bill-lowering electric appliances and heating without the need for expensive electric panel upgrades. (Canary Media)
Prepare for extinction: The rarely convened Endangered Species Committee rules that federal endangered species protections will no longer apply to oil and gas drilling projects off the Gulf Coast, exposing the Rice’s whale and other creatures to potential harms. (Houston Chronicle, E&E News)
Fossil fuels’ human toll: A Texas refinery explosion last week damaged homes in a neighboring, largely Black town, revealing the human impact of the Trump administration’s push to ramp up fossil fuel production. (Capital B)
Geothermal heats up: Next-generation geothermal projects have the potential to deliver tons of clean power around the clock, but a need for permitting and safety reforms could slow the industry’s progress. (Canary Media)
No resolution: The Ohio trial of two former FirstEnergy executives accused of bribing a former consultant, who went on to become the state’s top energy regulator, ends in a hung jury, with the state vowing to retry the case. (Signal Ohio)
Stuck in limbo: The fate of more than 300 clean energy projects remains unclear after the U.S. Energy Department announced their grants were canceled without officially de-obligating their funding. (Latitude Media)
Chad Shepard has warm feelings about the all-electric Honda Prologue he bought recently. Unlike his first EV, a BMW i3, the SUV is big enough for his two teenage sons and his 80-pound sheepdog. Its 300-mile range is plenty to get him to the homes across the San Francisco Bay Area that he appraises for a living.
And while he hasn’t done the math since he bought it last autumn, he’s pretty certain that he’s saving money on fuel, compared with when he was driving a gas-powered car.
But perhaps the best thing about his new EV is the price he paid: $30,000, well below the sticker price for a new model. “And because it was only a year old, I still had a full 100,000-mile warranty,” he said, which included coverage for its most valuable component — the battery.
Across the U.S., people like Shepard are finding that used EVs are more attractively priced than ever — and are snapping the cars up as a result. It’s a welcome development in what has otherwise been a tough year for an industry that’s key to combatting climate change.
With the oil shock created by the war in Iran, used EVs are likely to become even more attractive to shoppers. Nationally, gas prices have surged to over $4 per gallon on average; in California, the country’s EV capital, they’re nearing $6. Unlike new EVs, used versions have mostly reached priced parity with gas-powered cars, according to new data from Cox Automotive — making the preowned versions the cheapest way for people to ditch increasingly costly-to-fuel gas cars in the near term.
“Affordability is top of mind among Americans, particularly given gas prices today,” said Maximilian Quertermous, co-founder and chief operating officer of Ever, an automotive retail startup focused on electric vehicles. “It’s a great time to buy a used EV overall.”
Used EV sales are climbing even as new EVs sales plummet nationwide.
New EV sales dropped by 28% year over year in the first quarter of 2026, per Cox. That was primarily driven by the loss of federal tax credits under the megabill passed by Republicans in Congress last year.
By contrast, used EV sales increased by 12% over the same period. The reason? Declining prices. The average cost of a used EV is now within about $1,300 of a comparable gas vehicle, Stephanie Valdez Streaty, director of industry insights at Cox Automotive, said during a March forecast call. “That affordability shift has clearly shown up in the data,” she said, “significantly expanding access for mainstream buyers.”
In the U.S., new EVs still outsell used ones. That’s likely to change as the market matures, since the overall used car market is roughly three times as large as the new car market. Right now, EVs make up only about 2% of the used car market, but that share is growing, according to Cox data.
“The trajectory is what stands out,” Valdez Streaty said, “supported by a broader mix of models, more affordable prices, and a significant wave of off-lease EVs.”
These latest data points aren’t coming out of left field, said Scott Case, CEO of Recurrent, a data-science firm specializing in collecting information on used EVs. His company tracked a 35% increase in used EV sales from 2024 to 2025, as well as a consistent downward trend in pricing, with 56% of used EVs selling for $30,000 or less as of January.
“What is different about 2026 is that for the first time ever, there’s actually a big enough used electrical vehicle market,” he said.
In particular, a lot of those used EVs are coming off leases made popular by a “leasing loophole” that allowed automakers and dealers to offer a full $7,500 federal tax credit, without the income qualification and manufacturer restrictions that applied to claiming the credit on direct sales.
More than 1.1 million EVs were leased from January 2023 to September 2025, when the federal tax credit ended. Shepard said he kept a close eye on those trends when planning to buy a bigger EV. “If you track that, you’ll see that [the cars] all go back to the dealer at the same time,” he said. “They have a flood of them, and the price drops a lot.”
And the latest vintages of used EVs offer an impressive value when compared with their gas-powered equivalents, Case said. Recurrent’s latest data indicates that a used EV is a year newer and has nearly 30,000 fewer miles than a similarly priced used gas car.
“When you compare what you’re getting for each of those, this is not an apples to apples — it’s a crappy apple versus a really awesome apple,” he said.
At least 68% of used EVs that Recurrent is tracking are 2022 models or later, which offer newer technology features than the average 6.5-year-old used internal combustion engine vehicle, Case added. Almost all those newer EVs remain under battery and powertrain warranties that tend to offer eight years or 100,000 miles of coverage, he said — and that’s for a class of vehicle that already costs about 40% less to maintain than a conventional car.
If they’re so much better, why are used EVs so cheap? Case outlined several key factors to explain that.
First is the far more rapid pace of improvements from one model year to the next — “more range, faster charging, more technology” — that make newer EVs more valuable than their predecessors. EVs that are even a few years old are seen as less desirable than the latest models, and thus command a lower price, he said. Federal tax credits also pushed down the expectations of what EV should cost, he said.
But many people remain uncertain about buying an EV, Case said. Range anxiety remains one of the chief concerns, he noted. And for used EVs, there’s another layer of uncertainty around “how the battery is holding up.”
Recurrent hopes its research can help disabuse EV buyers of that uncertainty, he said. The company has collected data from more than 50,000 EVs on the road, with more than a billion miles driven. While there’s variability between different manufacturers and EV models, that data shows that used EV batteries are holding up better than expected, he said. That finding is backed by other studies indicating that EV batteries are lasting longer than people thought they would.
These are important factors for low-income customers looking to EVs to cushion themselves from rising fuel costs, said Jason Zimbler, senior director of light-duty vehicles at clean-transportation nonprofit Calstart. “You’re getting a younger car, less road wear, and the battery degradation has been minimal,” he said. “So you’re not putting lemons in the hands of the secondary market.”
And while last year’s Republican-passed megabill killed a $4,000 tax credit for used EVs, along with the bigger rebate for new ones, many buyers can still access state or utility rebates, said Peter Glenn, co-CEO of EV Life, a startup with software used by customers, car dealers, and automakers to find EV incentives.
California’s biggest utilities offer rebates ranging from $1,000 to over $4,000 for income-qualified customers. States including Connecticut, Delaware, Illinois, Massachusetts, New Mexico, New York, and Rhode Island provide rebates in the thousands of dollars range, he said.
Understanding all the price reductions available up front can push used EVs past price parity with gas-powered cars and into the “tipping point” of being cheaper, Glenn said. “You almost need it to tip into obvious savings beyond, so it becomes a total no-brainer.”
Of course, buyers focused on long-term ownership costs can also use a variety of calculators available online that demonstrate how much cheaper it is to fuel and maintain EVs over time, Glenn added. “If you’re charging at home, it can be the equivalent of paying about $1 to $2 per gallon, even in higher-electricity-cost markets.”
Shepard only recently installed a Level 2 charger at home, so he hasn’t had a chance to calculate his fueling savings yet. But he’s glad he doesn’t have to rely on gasoline anymore.
“I just don’t see any need to use fossil fuels to make our cars go when it works just as well with electricity,” he said.
Remell Bryant fed steel coils into the “cold strip” as a way to support her daughter as a single mother.
Valerie Denney worked on the “pickle line,” removing impurities from hot steel, before shifting to a career in public relations.
Jack Weinberg tested metallurgical content until he was laid off, then went on to negotiate international environmental treaties.
Terry Steagall played on the banks of a polluted river near the steel mill as a child, then spent 41 years inside the mill as a machinist, repairing gearboxes, cranes, and line shafts, before retiring in 2023.
Now, the four are collaborating to demand a shift away from coal-based steelmaking and toward cleaner methods for the Northwest Indiana industry in which they once worked. They’re all members of Gary Advocates for Responsible Development (GARD), a grassroots group founded in 2021 by former steelworker Dorreen Carey.
Such a transition could save thousands of jobs, create new economic opportunities, and avoid about $75 million in healthcare costs in the region, according to a report released Thursday by the Indiana University Environmental Resilience Institute and the consultancy 5 Lakes Energy, and commissioned by Indiana Conservation Voters.
Only six integrated mills — facilities that produce both steel and the iron needed to make it — are operating in the United States, and three of them are in Northwest Indiana. With their hulking, polluting blast furnaces, these mills may soon become a thing of the past in the U.S., as steel is increasingly being produced in smaller and cleaner operations, frequently in the Southern states.
The GARD organizers echo the report’s authors and other industry experts in warning that if Indiana’s mills don’t modernize and clean up, they could go the way of the other steel mills that once proliferated in the region, but were shuttered during the steel industry crisis of the late 1970s and ’80s. The region still hasn’t recovered from that era, and further closures could mean thousands of job losses and gutted public coffers. The report notes that Northwest Indiana’s steel mills once had more than 65,000 workers but employ only about 9,000 today. Without modernization, the study estimates, Northwest Indiana steel mill jobs could fall below 5,000 by 2034.
Converting a traditional integrated mill to much-cleaner direct reduced iron (DRI) technology costs billions of dollars, and the Biden-era incentives that could have encouraged companies to make the switch were eliminated by the Trump administration. It’s a hard sell, but GARD considers global steelmaker Nippon Steel’s 2025 acquisition of U.S. Steel’s Gary Works mill, in Gary, Indiana, an opportunity.
Steagall said he “didn’t see a pathway” to green steel until the Japanese company entered the picture.
Nippon plans to allocate $3.1 billion for upgrades to Gary Works. About $300 million of that will go toward relining its largest blast furnace — which will extend its life for about another 20 years. The company could use some of the remaining money to replace the mill’s three other blast furnaces with a DRI plant, GARD proposes in a recent report.
It would cost about $3.6 billion to transition Gary Works to cleaner steelmaking, according to the Indiana University report. Modernizing the area’s other two mills, both owned by Cleveland-Cliffs, would cost $2.8 billion to $3 billion each. That’s in line with what the companies have indicated they will spend to maintain those operations.
In a February earnings call, Cleveland-Cliffs announced that it is planning to reline an Indiana blast furnace next year. The company had in fact proposed a DRI conversion at one of its Ohio mills, but backed off the plan after Trump took office in 2025.
Advocates note that the crucial technologies needed for green steel — DRI and electric furnaces — already exist at commercial scale, and efforts are gaining steam globally to combine the two. Many existing DRI plants use natural gas, which results in much lower emissions than the coal that fuels blast furnaces. But using green hydrogen — produced by splitting water atoms using renewable electricity — would slash emissions even further.
The national climate research groups RMI and Industrious Labs are also touting the feasibility of greening the nation’s integrated steel mills. An RMI analysis shows that such overhauls cost roughly the same as relining and upgrading existing infrastructure.
The biggest challenge may be convincing company leaders to make a major change in an industry that “has never been known to move quickly,” as Steagall put it.
In an integrated steel mill like Gary Works, iron is added to a blast furnace, where it undergoes chemical reactions involving limestone and coke — a baked-down, concentrated form of coal. Molten iron is then converted to “primary steel” in a separate stage. This process results in the type of high-quality, flat-rolled steel suitable for automobiles and buildings.
But it is highly polluting, with about 2 million metric tons of carbon dioxide released for each ton of steel produced globally, along with high levels of particulate matter, sulfur dioxide, nitrogen oxides, and other pollutants.
The fortunes of Gary Works and other integrated steel mills declined starting in the late 1970s because of slowing demand and competition from abroad, including from “mini-mills,” which use electric arc furnaces to make steel — mostly from scrap metal — without producing any iron on-site. Integrated mills in Indiana, Illinois, Ohio, and Pennsylvania downsized their operations and then closed over several decades, transforming thriving cities into Rust Belt relics. Nationwide, steel sector employment fell from about 512,000 in 1974, according to a study by the National Bureau of Economic Research, to about 85,000 today, according to Federal Reserve Economic Data.
“Republic Steel, Bethlehem Steel, J&L Steel, they all shut down or were liquidated,” said Weinberg, who worked for eight years in Gary Works’ sheet and tin division.
Though the Gary Works mill survived, its workforce was greatly reduced – from more than 30,000 people at its peak in the 1970s to about 4,300 people today. By the 2010s, the city was notorious for its abandoned buildings and urban decay.
As GARD organizers see it, without investments in clean steel, Gary’s fortunes could fall further. The plant’s market niche — high-quality primary steel — is vulnerable to competition from the electric arc furnaces that make at least 60% of the country’s steel today.
Facilities using electric arc furnaces have typically not produced the highest-quality steel, mainly owing to their reliance on recycled steel scrap. But they do still require at least some virgin iron to produce steel, which can come from integrated mills or from on-site DRI facilities. Automakers typically demand steel made in integrated mills, but electric arc furnaces could increasingly compete for that market as their steel quality improves.
Big River Steel, along the Mississippi River in Osceola, Arkansas, is a prime example. Its electric arc furnace uses iron from Gary Works to make high-quality steel. U.S. Steel acquired the mill in 2021, and now it’s part of Nippon’s portfolio. Nippon announced in November that it will build a DRI plant at Big River, which would potentially displace the metal it currently sources from Indiana.
So, such electric arc furnace operations could become competitors, rather than customers, of integrated mills like Gary Works. And they could gain a market advantage if automakers and other industries demand a cleaner supply chain, as GARD and other decarbonization advocates predict.
Nippon lags behind most of its peers globally in its readiness for greening operations, according to a scorecard released March 30 by the international climate advocacy organization SteelWatch. The organization analyzed the decarbonization progress and potential of 18 major steel companies in 29 countries and found that Nippon ranked 17th; U.S. Steel, which was ranked before the acquisition, came in eighth; and Cleveland-Cliffs was sixth. While U.S. Steel could help facilitate Nippon’s decarbonization, SteelWatch said, the plan to reline rather than convert the Gary Works blast furnace represents a “backward trajectory.”
There’s a strong public health argument for greening the mills.
Emissions from blast furnaces are linked to an increase in various cancers, asthma, pulmonary disease, and other ailments. Industrious Labs found that in 2022, Gary Works emitted 182 tons of 24 different toxic chemicals. The health impacts are also a clear environmental injustice: 97% of those living within a three-mile radius of Gary Works are people of color, and almost two-thirds are low-income, according to Industrious Labs’ analysis.
Indiana University’s report found that Gary Works annually emits eight times more carbon monoxide and 50% more particulate matter than the state’s largest coal plant; and the region’s three primary steel mills account for not only the $75 million in healthcare costs but also 27,8000 work days and 26,700 school days lost to illness each year.
GARD member Natalie Ammons did not work in the mills, but her husband did. And she blames the Gary Works blast furnace for his early death from cancer.
Her family’s health problems have continued. Two of Ammons’ granddaughters, both of whom live near the mill, rely on breathing machines that look like scuba apparatus, she said. Modeling done by Industrious Labs using federal algorithms shows up to 114 premature deaths and over 31,000 asthma attacks linked to pollution from Gary Works each year.
Bryant retired from Cleveland-Cliffs Indiana Harbor refinery about four years ago, because she had developed a nodule on her thyroid that impeded her breathing. She attributes it to her exposure to pollution there.
“I was always super healthy. It is odd that happened shortly after I worked a lot of overtime in the lime plant,” she said.
Steagall cites examples like these in calling for Nippon to be “a good corporate citizen” for its American neighbors.
“They’ve got to make their mind up,” he said. “Do they want to be the king of steel or the king of death?”
Nippon has not responded to GARD’s proposals and requests for dialogue nor to a request for comment for this story.
The United Steelworkers union, which the GARD members once belonged to, has similarly not engaged with them. While GARD notes that unions are often reluctant to consider any changes that could disrupt the job market, it warns that the shift to mills in the South with electric arc furnaces could be disastrous for the union — as those plants are typically not unionized. (United Steelworkers did not respond to a request for comment.)
At a recent symposium at Purdue University Northwest, students and faculty clamored to hear more about GARD’s vision for the industry’s future. After the event, the GARD members gathered around a table and reminisced about the jobs they used to do. Their eyes lit up describing the complexities of the steelmaking process.
The metal “runs through a big acid bath, then we cut it to specification,” Denney said of the pickle line where she had worked. “At the end, they oil it, and you have this beautiful, very shiny, gorgeous steel.”
Gary itself could be similarly transformed, through clean steel, she imagines.
“People are used to Gary being kind of a throwaway city,” she said. “It’s all bad. There’s an opportunity for it to be all good now for the first time in a while. Nippon could be part of this change. It could be part of changing Gary forever.”
Maria Gallucci contributed reporting for this article.
A clarification was made on April 2, 2026: This story has been updated to clarify that direct reduced iron plants and electric furnaces exist separately at commercial scale.
If the war in the Middle East has proved anything over the last month, it’s that fossil fuel prices are extraordinarily unstable. But global conflict isn’t the only catalyst that can send the cost of oil and natural gas reeling. Factors such as extreme weather, policy changes, and pipeline outages can also set off a price roller coaster.
In North Carolina, all this volatility is prompting calls for change. Advocates want the state to join the handful of others that require electric utilities to absorb a fraction of fossil fuel prices — rather than saddling customers with all of them, as the companies do now.
The point of the policy, called fuel-cost sharing, is twofold. It can bring utility bills down for average consumers, who are increasingly angry about ballooning expenses. And it can aid the clean energy transition: If the state’s predominant utility, Duke Energy, knows that its shareholders will take a hit when fuel prices rise, the company may scale back its dependence on polluting gas plants and instead rely more on emissions-free, fuel-free forms of energy, like wind, solar, and batteries.
The notion of fuel-cost sharing is still very much in its nascence here, where Duke wields incredible power over the Republican-controlled legislature, and neither lawmakers nor regulators have pushed the company to invest in cheap, clean energy.
But proponents of the idea say the conversation is still worth having.
“Fuel dependence creates vulnerability — whether it’s gasoline for your car or natural gas for your power plants,” said Josh Brooks, chief of policy strategy and innovation for the North Carolina Sustainable Energy Association. “Tying costs to volatile commodities means a lot of risk exposure for ratepayers. That’s an issue both regulators and policymakers should take up.”
North Carolina is far from unique. Most states with vertically integrated utilities allow them to pass 100% of fuel costs to their customers. Utility shareholders don’t earn a return on those outlays in the same way they profit from building new power plants, but they’re insulated from the wild price swings inherent in the global fossil fuel market. Consumers are not.
Ratepayers, for instance, bore the full brunt of spiking gas prices after Russia invaded Ukraine in 2022. Confusingly for customers, Duke doesn’t specify these fuel charges on their bills; instead, the charges are incorporated into a nondescript line item, leaving consumers to ferret out on their own what they’re paying for fossil fuels.
The lack of clarity around fuel costs adds to customers’ outrage about rising bills. One example of the widespread frustration: A Change.org petition calling for Duke to submit to an independent audit and refund its customers for any improper charges has drawn more than 73,000 signatures so far.
“Unexpected and unexplainable increases in Duke Energy bills have become a major concern for many families,” the petition begins. “When bills rise without reasonable justification or transparency, it impacts our ability to plan and manage our household finances effectively.”
The average household Duke bill has risen by nearly 45% since 2020, according to an analysis from the Energy and Policy Institute, because of a confluence of factors. The cost of natural gas is a major one.
Research from the Environmental Defense Fund shows that fuel costs accounted for 67% of rate increases from 2017 to 2024 in Duke’s central North Carolina territory, and for 46% of the hikes in the rest of the state. While fuel costs did dip last year, they’re still about double what they were in 2017.
“Fuel costs have stayed high since the 2021-22 price spike,” Will Scott, the environmental group’s North Carolina policy director, said in a written response to Canary Media. “At the same time, Duke has become more natural gas reliant, with even more new gas plants on the way.”
Indeed, with the state’s 2030 climate goal gone, and the Trump administration aggressively propping up coal and gas, Duke has every incentive to pursue a massive buildout of fossil fuel infrastructure: Shareholders will profit from the plants and suffer no adverse consequence if gas prices continue to rise.
As Jeremy Kalin, a fuel-cost sharing expert and clean energy finance lawyer, put it, “The utilities are the ones that have all the power, all the visibility, all the expertise — and none of the risk.”
Fuel-cost sharing would shift the balance. In a February report, clean energy think tank Rocky Mountain Institute evaluated one way that North Carolina could structure such a policy: Duke would tell regulators how much it expected to spend on fuel over the course of a year. If the utility went over that estimate, investors would cover 10% of the extra cost — up to a small cap. If fuel ended up costing less than expected, investors would get to pocket 10% of the savings.
The policy, said Oliver Tully, RMI’s carbon-free electricity manager and one of the report’s authors, would “reduce some of the risk exposure that customers have — and essentially give utilities some skin in the game.”
With the 10% sharing scenario in place from 2020 to 2024, RMI concluded, Duke’s roughly 3.8 million customers in North Carolina could have saved a total of $100 million in 2021, 2022, and 2023 — a small but meaningful fraction of the fuel cost increases that followed the pandemic and the invasion of Ukraine. Duke investors, meanwhile, would have gained an extra $9.9 million in 2020 and $1 million in 2024. The net benefit to customers over the study period: $89 million.
Tens of millions in consumer savings is meaningful in and of itself, Tully and other experts stress. But the policy also gives utilities an incentive to reduce their fuel expenses, both in the long term by building fewer gas plants and in the near term by relying less on coal and gas during periods of high demand.
“They have a lot more control, especially compared to ratepayers, over overall fuel costs,” Tully said. “They can decide how much gas-fired generation to build or control. They can choose to invest in resources that don’t have fuel costs, like renewables.”
Ideally, Tully and other experts say, the cost-sharing policy would create a win-win situation that aligns Duke’s incentives with its customers’. Both investors and customers pay more when fuel costs are high and save when fuel costs are low.
“The goal is to get shareholders and customers on the same rope,” Kalin said, “pulling in the same direction.”
Nine states have implemented some form of fuel-cost sharing, according to RMI. Five are in the Northwest, including ruby-red Idaho and Wyoming. Last year, lawmakers in Nevada authorized regulators to study the policy, and Virginia just enacted a law doing the same.
Despite its advantages for customers and even shareholders, the cost-sharing policy’s prospects in North Carolina are uncertain.
The North Carolina Sustainable Energy Association pushed for a study of fuel-cost sharing last year at the North Carolina Utilities Commission as part of its annual deliberation on the fuel charge itself. But regulators rejected the idea, saying they lacked the authority to order such an analysis — at least in the context of a fuel proceeding.
“The commission has historically had a pretty conservative view of its statutory authority,” the association’s Brooks said.
Still, his group plans to raise the issue as part of Duke’s active bid to regulators to increase residential rates by 18% over two years. Proponents will also look for ways to advance the policy during the state legislative session that begins next month, even while expecting that lawmakers will focus their time on other matters.
“That’s not going to stop folks from advocating for some kind of change,” Brooks said.
Geothermal energy is on the cusp of a renaissance in the United States. But outdated and piecemeal rules could delay development of the around-the-clock, carbon-free energy source.
Next-generation geothermal is something of a golden child, backed by everyone from climate advocates to leaders in the drilling-obsessed Trump administration. Investors are pouring billions of dollars into the sector. A huge, first-of-a-kind project in Utah will start delivering power this fall, marking a milestone for this new wave of geothermal technologies — and fueling hopes that the energy source can help the U.S. keep pace with skyrocketing demand.
But companies won’t be able to quickly build dozens more of these power plants without updated regulations and standards for developing geothermal projects, industry insiders and experts say.
Today, permitting requirements are fragmented and can vary at the state and local levels, a reflection of the modest role geothermal has historically played in America’s energy sector. However, next-generation technologies are promising to unleash development in areas where harnessing Earth’s heat was previously too difficult or too expensive.
So companies are calling for a more standardized approach to permitting, instead of the bespoke, project-by-project reality they currently face. That will require lawmakers to act, but also the industry itself to develop better systems for defining projects and sharing data.
Meanwhile, pressure is growing within and outside the industry to create more safeguards for preventing accidents and high-profile mistakes that could harm communities and the environment — and could damage the industry’s reputation before it can truly launch.
“We want geothermal to advance as a clean energy solution that can be available anytime that is needed, anywhere that it is needed,” said Angela Seligman, a senior geoscientist at the nonprofit Clean Air Task Force. “But we also want it to stay as a source of clean energy, and we want the good actors … to be the ones who build new projects.”
Here are just a few of the ideas gaining traction for safely accelerating geothermal projects.
An obvious but essential step for creating rules is to establish exactly how next-generation technologies work and what their impacts might be.
The emerging industry has an ever-expanding vocabulary to describe its tools and techniques, but there’s still little consensus about what those terms all mean, said Jamie Beard, executive director of Project InnerSpace, a geothermal research and advocacy organization.
For example, Fervo Energy’s flagship, 500-megawatt Cape Station project is an “enhanced geothermal system” that uses hydraulic fracturing techniques gleaned from the oil and gas industry. Other developers might take a similar approach but use different words to describe it. The same goes for “advanced” and “closed loop” geothermal systems, which broadly include projects that circulate fluids in sealed underground pipes but can still involve intensive drilling methods and encompass a variety of materials.
“Right now, everybody’s kind of calling themselves what they want,” Beard said. “You can’t standardize, and you also can’t build trust about a technology” in this way, she added.
Last month, Project InnerSpace unveiled an initiative to start defining projects in more concrete terms. The Geothermal Resources Management System, which is modeled on the petroleum industry’s system, aims to establish a global framework for classifying and evaluating geothermal reserves. The main idea is to give banks and insurers more clarity and confidence in potential projects. But it would also support larger efforts to establish industry protocols for things like limiting groundwater contamination and avoiding industrial accidents, Beard said.
In the U.S., new bipartisan legislation to accelerate geothermal development is also geared toward creating more public transparency from the sector.
Sens. John Hickenlooper (D-Colorado) and Steve Daines (R-Montana) recently introduced the GEO Power Act, which would require the Department of Energy to help fund geothermal projects in states with limited or no existing geothermal power generation. It also prioritizes data sharing within the industry to “de-risk” future projects and to help regulators, communities, and business partners better understand and address potential impacts, according to the office of Sen. Hickenlooper.
Perhaps no risk looms as large over the next-generation geothermal universe as human-caused earthquakes.
The mistakes made on earlier enhanced geothermal systems are notorious. In France, Switzerland, and South Korea, the process of injecting water at high pressure to fracture rocks underground triggered seismic activity that was strong enough to damage buildings, rattle surrounding cities, and create public backlash.
In response to such events, in 2012, the U.S. Department of Energy revised its induced seismicity protocol, which describes a “traffic light” system for the real-time monitoring and measuring of vibrations caused by geothermal development. Any U.S. geothermal project that receives federal funding — which is virtually all of them today — is required to set up seismicity monitoring stations and follow the DOE’s guidance.
But as the industry matures, projects will likely no longer need government support, meaning they won’t have to follow the system of red, amber, and green lights in their operations. Seligman said that the Clean Air Task Force is pushing for the federal government to require all geothermal projects to adhere to the protocol.
“We want to be really careful about induced seismicity, so that it’s not something that will hinder the advancement of the geothermal industry,” she said.
The startups Eavor Technologies and XGS Energy told Canary Media they would have no issue adhering to a universal protocol. Both firms claim their systems are designed to mitigate such risks from the start. They say their closed-loop technologies don’t require fracking or injecting and withdrawing fluids from the ground — the main drivers of seismicity in geothermal wells.
“Maintaining public trust is vital for the entire geothermal sector,” said Neil Ethier, Eavor’s vice president of commercial and business development. In December, the Canadian startup began delivering power to the grid from its flagship operation in Germany, which is slated to produce over 8 MW of electricity and 64 MW of district heating when fully completed.
XGS is developing a 150-MW closed-loop system in New Mexico that’s expected to provide clean power for Meta’s data centers by 2029. Last week, the Houston-based firm said it was partnering with oil-and-gas services giant Baker Hughes on the exploration and engineering phases of the geothermal project.
Lucy Darago, the chief commercial officer for XGS, said that blanket requirements run the risk of adding “superfluous” rules for companies like hers, and that regulators should instead adopt measures that are “fit to purpose” and reflect the nuances in next-generation systems. She said that XGS is active in ongoing discussions with policymakers in states such as Colorado and New Mexico, which are revising permitting structures to accelerate geothermal development.
“Should we be required to drill a monitoring well and maintain a seismic program that could add millions of dollars to overall project costs?” Darago asked. “We probably will, especially for early projects. But should that be a perpetual part of our regulatory regime? I think that’s an open question, and one that we’d ultimately like our regulators to decide.”
As state and federal agencies work to revise rules for geothermal projects, industry leaders in the U.S. and other countries are also looking to show a token of good faith by proactively committing to certain standards.
Last fall, for instance, Fervo released the Geothermal Sustainable Development Pact, a voluntary framework meant to guide the industry’s growth. The 37-point plan includes steps like adopting DOE’s protocol for reducing seismic risk, prioritizing efficient water use, minimizing land disruption, and engaging with communities.
“As geothermal scales to meet rising energy demand, we have a responsibility to raise the bar on how these multi-decade projects are developed, and not just exclusively focus on the technology itself,” Tim Latimer, Fervo’s CEO and co-founder, said by email.
“Geothermal benefits from decades of lessons across energy: what worked in oil and gas, what worked in renewables, and where both fell short,” he added. “We don’t see it as an either-or situation. It’s not growth or responsibility. It’s both.”
No other companies have signed Fervo’s pact so far, though Latimer said the startup is inviting others across the industry to adopt and build on its principles. The environmental groups Sierra Club and NW Energy Coalition, an alliance of over 100 organizations and businesses in the Pacific Northwest, have said they fully endorse the pact.
“I think everybody will benefit from it, especially at this early stage of an exciting new era,” said Fred Heutte, a senior policy associate for the NW Energy Coalition.
He said that in his home state of Oregon, the startups Mazama Energy and Quaise Energy are working to build novel geothermal projects near the Newberry Volcano. Oregon currently has one large-scale conventional geothermal project — the 33-MW Neal Hot Springs plant — but most states have no geothermal development at all, given the industry’s traditional limitations.
With next-generation systems, “there’s going to be a lot more places that will be looked at for geothermal development … and that’s going to raise issues about land impact, community impact,” Heutte said. “I think the industry is well aware of the risks of problems like that and is trying to get out in front of it.”
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