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The batteries inside electric vehicles can do a lot more than power a car.
They can back up homes, schools, and businesses during power outages. They can soak up grid power when it’s plentiful and cheap and send it back when it’s scarce and costly. And they could eventually provide enough reliable power to allow utilities to avoid building more power plants or expanding their grids to meet growing demand for electricity — something that would save money for utility customers as a whole.
So far, utilities have had a hard time turning this dream of batteries on wheels into a reality. Plenty have launched these “vehicle-to-everything” (V2X) pilots, but only with mixed success. Broader adoption has been held back by the cost and complexity of getting the required technologies to work smoothly in the real world — and by an absence of well-established utility programs that pay EV owners enough to make it worth their while.
In Massachusetts, a new V2X pilot project is now seeking households, businesses, schools, nonprofits, and municipal governments to test all of these ways that EVs can help the grid. And unlike many V2X tests done by other U.S. utilities, this one will offer two key financial incentives: bidirectional chargers at no cost to participants, and real money to those who commit to letting utilities tap into their EV battery power.
Over the next nine months, the Massachusetts Clean Energy Center, the state’s clean-energy economic development organization, will use most of the pilot’s $6 million in funding to give out up to 100 free bidirectional chargers. This is the technology that allows EV owners to not only pull electrons from the grid but to send power back and get paid for it. Households will get most of this equipment, but a subset of higher-voltage two-way chargers will go to commercial vehicle and electric school bus fleet operators.
Those chargers will be installed by September 2026, said Elijah Sinclair, MassCEC clean transportation program manager. The goal is for the pilot to provide about 1.5 megawatts of distributed energy storage capacity, roughly equivalent to the power use of about 250 homes.
Massachusetts law calls for 900,000 EVs on the road by 2030 in order to meet the state’s decarbonization goals. If a well-designed pilot project unlocks cost-effective ways or even a fraction of those future EV owners to enlist in V2X programs, the payoff could be huge, Sinclair said. EVs tend to stay plugged in far longer than it takes to fully charge up their batteries. Being able to tap into that stored energy expands the value that EVs can provide the grid and allows them to store solar and wind power to use later when the wind isn’t blowing and the sun isn’t shining.
“That could be a really important piece as we seek to get to net-zero by 2050,” Sinclair said. “It still requires a whole lot of infrastructure, and it’s complicated for the utilities. But in the future, it could be serving huge loads across the grid.”
The trick is to move from the experiment stage to a safe, simple, and profitable program for a majority of the state’s EV owners, he said. It’s not something any other state or utility has managed to pull off just yet — but MassCEC and its partners are hoping the upcoming pilot will build the foundation to make that happen.
The idea of pulling power from EV batteries is far from new. Universities and research organizations have been successfully testing V2X for more than two decades, and U.S. utilities have had pilots up and running for years.
Other countries have more fully embraced the technology. Japanese automakers started enabling EVs to provide backup power via vehicle-to-home and vehicle-to-building charging to deal with the power supply emergencies that followed the 2011 Fukushima nuclear power plant disaster. In Europe, vehicle-to-grid (V2G) projects have been turning a profit for commercial and government vehicle fleets for years, and more recently for consumer EVs as well.
In the U.S., by contrast, vehicle-to-grid services have largely been successful in just one niche of the EV market: electric school buses, which happen to sit unused during most of the day. In Massachusetts, the company Highland Electric Fleets and the city of Beverly have been doing V2G with school buses since 2020, and have been earning money for delivering extra power to utility grids over the past few summers.
Transit and commercial vehicles, which must be on the road more frequently and have less idle time to charge, are more challenging to make profitable.
Vehicle-to-home backup power, meanwhile, has been built into the Nissan Leaf for more than a decade, and has been a major marketing draw for the Ford F-150 Lightning electric pickup and other new EV models. But actually engineering and installing the systems to turn a home EV charging system into a backup power system for the grid is a bit more complicated — and costly.
So said Kelly Helfrich, who leads the transportation electrification practice at Resource Innovations, a company specializing in clean-energy program implementation that is co-leading the MassCEC V2X program. She’s worked in the EV space for more than a decade, including a stint at General Motors that covered the automaker’s entry into vehicle-to-grid technology and its eventual development of V2G standards.
Bidirectional chargers are more costly and technically difficult to build compared to simple one-way chargers. That investment may well be worth it for school buses, which have big batteries that can earn lots of money while they’re sitting idle. But for everyday households, it’s harder to see a path to recouping the extra $5,000 to $10,000 in up-front costs that bidirectional equipment can bring, Helfrich said.
Installing free chargers for homeowners, as the MassCEC program is doing, “helps take that cost out of the equation,” she said, “to really test vehicle-to-home at a larger scale than we’d be able to if we were to rely on consumers to take on that expense.”
Successful V2X programs also need to make sure participants get paid for taking part.
On that front, Massachusetts already has an established program that lets EV owners earn money by helping the grid, according to Zach Woogen, executive director of the Vehicle-Grid Integration Council, a group representing EV and charging manufacturers that’s working with utilities and regulators across the country.
ConnectedSolutions is a long-running offering from utilities National Grid and Eversource, which operate in Massachusetts and other New England states. The program pays customers for reducing grid strain during hours of high demand for electricity, usually during hot summer afternoons and evenings.
ConnectedSolutions already pays EV owners who avoid charging during those hours, Woogen said. It also allows customers to earn money for power they send back to the grid from batteries attached to their rooftop solar systems — or, more recently, from EVs in fleets owned by businesses, schools, or governments.
Tapping into the collective flexibility of batteries, EV chargers, rooftop solar, remote-controllable thermostats, and other devices to create “virtual power plants” could unlock gigawatts of capacity across the country. Companies targeting these opportunities have given ConnectedSolutions high marks for its relatively straightforward rules and lucrative payments.
Right now, the program doesn’t allow residential EVs to send power back to the grid, Woogen noted. But it could allow homes to reduce their grid draw by supplying part of their own electricity use during times of peak demand, or explore other opportunities to reward households for making their vehicles available when power demand is highest.
A handful of other utility V2X programs are paying households for their EV battery power. California utility Pacific Gas & Electric has a V2X pilot that pays participants and recently expanded it to support up-front installation costs for General Motors EV-compatible bidirectional chargers. But PG&E’s compensation structure is tied up in a more complicated dynamic pricing pilot program with less certain long-term prospects than the ConnectedSolutions initiative, Woogen said.
Other programs offer easy-to-understand and lucrative payments to customers but don’t take on the high up-front cost of setting up bidirectional charging. Maryland utility Baltimore Gas & Electric launched a program last year that offers up to $1,000 a month for owners of Ford F-150 Lightning electric pickups who let the utility tap their batteries during grid peaks. But few customers have installed the necessary bidirectional charger and control systems, which cost roughly $9,000.
Government incentives can’t keep bankrolling EV owners to install V2X equipment forever, of course. But they’re vital to getting enough customers to sign up so that utilities can test the real-world effects, costs, and benefits of tapping those EV batteries at a scale that really affects the grid.
Incentives also encourage automakers, charging system manufacturers, and software providers to work with utilities on making V2X technologies ready for prime time, Woogen said. “We’re at an early stage of the market — and we don’t yet have that competition to drive down costs for customers.”
The Vehicle-Grid Integration Council’s role in the MassCEC pilot is to organize all these industry participants and to track progress. The first and most fundamental goal, Woogen said, is determining whether bidirectional chargers can “safely and reliably connect with the grid in a way that’s reasonably low-cost and reliable and fast.”
That’s a work in progress, he said. Over the past decade or so, a growing list of charging equipment has been approved for installation by a subset of U.S. utilities working on V2X. New developments are making it possible for EVs themselves to push power back to the grid without a bidirectional charger, although automakers and utilities haven’t gotten to the point of allowing EV customers to use that technology outside of strictly controlled settings.
Utilities have to be sure that hooking high-voltage EV batteries into buildings and the grid is safe before they can let it happen at large scale, Helfrich said. Resource Innovations has longstanding relationships with National Grid and Eversource, and is working with the state’s other investor-owned and municipal utilities as well, she said.
MassCEC has also partnered with an experienced V2X technology partner to select and install the 100 bidirectional chargers. That’s The Mobility House, a German company with technology now in use in large-scale fleet charging projects as well as in Europe’s first mass-market residential V2G program.
“For this project, we’re acting as the technology expert,” said Russell Vare, Mobility House’s vice president of vehicle-grid integration. “That means bringing the right hardware and the software to do both the control for the energy and the aggregation and optimization.”
It also means tracking some far more prosaic data points that are important for V2X, he said. Take the inherently mobile nature of an EV battery — ”Is the car driving around, or is it plugged in?” That’s a big deal when a utility needs to know exactly how much EV battery capacity it can rely on for an upcoming demand peak.
Then there’s the to-be-collected data on how much money it takes to convince customers to use their EV as a backup battery or to allow it to be used to help the grid, Vare said. “How large does that value need to be to encourage them to participate?”
That’s important information for state agencies and utilities to have on hand as they plan out the next phases of their V2X efforts, Woogen said — and it’s an important part of the pilot project. The Vehicle-Grid Integration Council and consultancy Converge Strategies will collect feedback from automakers, charging vendors, utilities, local governments, community members, and the customers who get the 100 bidirectional chargers over the course of the pilot.
That work is meant to inform a guidebook by the end of next year that can inform policymakers and utilities looking at how to build V2X into their clean energy strategy, Helfrich said — not just in Massachusetts but around the country.
“It’s going to be a documentation of everything we designed for this two-year program,” she said — “what went well, what did not go well, and what should be considered in moving these programs to a more mature scale.”
The U.S. hit a major energy-transition milestone last year: For the first time ever, it produced more electricity from wind and solar than from coal.
Over half of U.S. states now get more power from breeze-blown turbines and sun-soaked photovoltaic panels than they do from polluting, planet-warming coal, according to a new report from think tank Ember.
Coal is the most environmentally destructive source of electricity available. For a long time, it was the most widely used power resource in the U.S., too.
Two decades ago, the country got about half of its electricity from coal-fired power plants. Today that number is just 15%. Wind and solar have ascended over the same time period. Together they now produce 17% of U.S. electricity, and solar is set to lead power capacity additions again this year.
Beyond their climate benefits, renewables beat coal on economics. A 2023 report found that all but one U.S. coal plant could be cost-effectively replaced by a combination of solar, wind, and batteries, though that finding relied on Inflation Reduction Act tax credits that some Republican lawmakers want to repeal.
The rise of cheap fossil gas spurred by the fracking boom has also played a key role in phasing out coal. Gas use has soared in the decades that coal has declined; it alone produced nearly 43% of U.S. power last year.
In 2025 the U.S. Energy Information Administration expects that 8.1 gigawatts worth of coal will be retired from the grid — equal to nearly 5% of the nation’s operating coal fleet as of 2024. Over the next five years, 120 coal plants are slated to shutter, helping reduce the carbon intensity of electricity and air pollution for local communities.
In other words, the yearslong decline of coal is set to continue. Unless, that is, the Trump administration’s burgeoning effort to rescue the industry succeeds.
Energy Secretary Chris Wright and Interior Secretary Doug Burgum both said last week that the government is working to halt coal plant closures. And just this week, President Donald Trump wrote on Truth Social that he is authorizing his administration “to immediately begin producing energy with BEAUTIFUL, CLEAN COAL.”
No specific plans have yet been announced.
Speaking to fossil fuel executives and other energy leaders at the CERAWeek conference last week, U.S. Energy Secretary Chris Wright made a bold claim.
“Everywhere wind and solar penetration have increased significantly, prices on the grid went up and stability of the grid went down,” he said.
But that claim is“not borne out by the data at all,” Robbie Orvis, the senior director of modeling and analysis for nonpartisan think tank Energy Innovation, told Canary Media’s Jeff St. John. In fact, a report out Thursday from Orvis and his colleagues found that clean energy is key to keeping U.S. electric bills in check.
The analysis looks at what would happen if congressional Republicans succeed in repealing the Inflation Reduction Act tax credits that have helped supercharge clean energy adoption in the U.S. The result of such a repeal? Dirtier air, more carbon emissions — and higher power bills. The average household’s energy bills would rise $48 per year by 2030 and $68 by 2035. Three other recent studies echo Energy Innovation’s findings, including one released Thursday by Rhodium Group.
The reason bills would rise is straightforward: Cutting IRA incentives would discourage the construction of solar and wind, which have become the cheapest sources of new power generation over the past decade.
Aside from electricity cost, clean energy boasts several other economic advantages over fossil fuels. A 2023 Energy Innovation report found that 99% of the country’s coal plants could be cost-effectively replaced with wind, solar, and batteries. The industry is also a growing employer, with jobs in clean energy expanding at more than twice the rate of the country’s entire job market in 2023. And numerous studies show that curbing fossil fuel use drastically reduces particulate matter and other air pollutants, which in turn helps people avoid health care costs.
Those benefits — specifically lower energy costs and job creation — are why a group of Republican Congress members are pushing to keep IRA incentives in place. Some conservative advocates and business leaders are joining them and making a case that clean energy is the cheapest, quickest way to achieve the “energy dominance” President Donald Trump is looking for.
Two clean energy projects get Trump’s green light
The U.S. Energy Department on Monday sent a $56.8 million loan disbursement to Holtec’s Palisades nuclear plant in Michigan, which will help the company restart the shuttered facility. It’s just a tiny first slice of the up to $1.52 billion loan Holtec could receive, but it indicates the Trump administration supports the Biden-era project even as many others remain in question. The federal Bureau of Land Management also approved a transmission line that will serve a utility-scale solar project in southern California — and went so far as to say the project will support “American Energy Dominance.”
But don’t expect a clean-energy change of heart just yet. Federal funding uncertainty still has dozens of projects in the lurch, including a Louisiana community solar program and a plan to transform a New York City fossil-fuel power plant into a hub for wind, geothermal, and storage.
How the Russia-Ukraine war sped up Europe’s clean transition
It’s been three years since Russia invaded Ukraine and upended Europe’s energy system. In the wake of the invasion, the EU rapidly reduced its reliance on Russian fossil gas by building renewables, shifting to electric heat, and sourcing liquefied natural gas from the U.S., Canary Media’s Julian Spector reports. The continent’s overall gas use fell during that time, with mild winters and higher fuel prices playing a role as well. Analysts say it’s clear the war sped up the transition — and a lot of that gas demand won’t be coming back.
Bird’s-eye view: The Nature Conservancy, Planet, and Microsoft use satellite imagery to map large-scale solar and wind installations around the world. (New York Times, Global Renewables Watch)
Green bank update: A federal judge temporarily blocks the U.S. EPA from taking back $20 billion inBiden-era “green bank” funding this week, though nonprofits won’t yet be able to access that money. (Politico)
Heat-pump road map: California is the first in the nation to create a statewide heat-pump deployment plan, which will help it meet its goal of installing 6 million electric heat pumps by 2030. (Canary Media)
Where renewables beat coal: The U.S. got more of its electricity from wind and solar than from coal last year, with renewables beating out the fossil fuel in 28 states. (Canary Media)
Super Soakers to super batteries: An Alabama entrepreneur who developed the Super Soaker water gun is using proceeds from his inventions to develop a new battery he says doesn’t require the same cooling systems as lithium-ion batteries. (Forbes)
Supersonic charging: Chinese company BYD announces a charging technology it says could“fill up” an EV in just five minutes — a development that could reinvigorate U.S. charger investment. (Axios)
Vermont’s climate battle: Vermont has long built a reputation as a climate leader, but its Democratic lawmakers face an uphill battle to pass more clean energy measures this session as Republican Gov. Phil Scott attempts to roll back parts of the state’s landmark climate law. (Canary Media)
By this time next year, a new satellite will be detecting how much methane is leaking from oil and gas wells, pumps, pipelines and storage tanks around the world — and companies, governments and nonprofit groups will be able to access all of its data via Google Maps.
That’s one way to describe the partnership announced Wednesday by the Environmental Defense Fund and Google. The two have pledged to combine forces on EDF’s MethaneSat initiative, one of the most ambitious efforts yet to discover and measure emissions of a gas with 80 times the global-warming potential of carbon dioxide over a 20-year period.
MethaneSat’s first satellite is scheduled to be launched into orbit next month, Steve Hamburg, EDF chief scientist and MethaneSat project lead, explained in a Monday media briefing. Once in orbit, it will circle the globe 15 times a day, providing the “first truly detailed global picture of methane emissions,” he said. “By the end of 2025, we should have a very clear picture on a global scale from all major oil and gas basins around the world.”
That’s vital data for governments and industry players seeking to reduce human-caused methane emissions that are responsible for roughly a quarter of global warming today. The United Nations has called for a 45 percent cut in methane emissions by 2030, which would reduce climate warming by 0.3 degrees Celsius by 2045.
EDF research has found that roughly half of the world’s human-caused methane emissions can be eliminated by 2030, and that half of that reduction could be accomplished at no net cost. Emissions from agriculture, livestock and landfills are expected to be more difficult to mitigate than those from the oil and gas industries, which either vent or flare fossil gas — which is primarily methane — as an unwanted byproduct of oil production, or lose it through leaks.
That makes targeting oil and gas industry methane emissions “the fastest way that we can slow global warming right now,” Hamburg said. While cutting carbon dioxide emissions remains a pressing challenge, “methane dominates what’s happening in the near term.”
Action on methane leakage is being promised by industry and governments. At the COP28 U.N. climate talks in December, 50 of the world’s largest oil and gas companies pledged to “virtually eliminate” their methane emissions by 2030, Hamburg noted. The European Union in November passed a law that will place “maximum methane intensity values” on fossil gas imports starting in 2030, putting pressure on global suppliers to reduce leaks if they want to continue selling their products in Europe.
In the U.S., the Environmental Protection Agency has proposed rules to impose fines on methane emitters in the oil and gas industry, in keeping with a provision of 2022’s Inflation Reduction Act that penalizes emissions above a certain threshold. And in December, the EPA issued final rules on limiting methane emissions from existing oil and gas operations, including a role for third-party monitors like MethaneSat to report methane “super-emitters” — sources of massive methane leaks — and spur regulatory action.
Accurate and comprehensive measurements are necessary to attain these targets and mandates, Hamburg said. “Achieving real results means that government, civil society and industry need to know how much methane is coming from where, who is responsible for those emissions and how those emissions are changing over time,” he said. “We need the data on a global scale.”
That’s where Google will step in, said Yael Maguire, head of the search giant’s Geo Sustainability team. Over the past two years, Google has been working with EDF and MethaneSat to develop a “dynamic methane map that we will make available to the public later this year,” he said during Monday’s briefing.
EDF and Google researchers will use Google’s cloud-computing resources to analyze MethaneSat data to identify leaks and measure their intensity, Maguire said. Google is also adapting its machine-learning and artificial-intelligence capabilities developed for identifying buildings, trees and other landmarks from space to “build a comprehensive map of oil and gas infrastructure around the world based on visible satellite imagery,” he said — a valuable source of information on an industry that can be resistant to providing asset data to regulators.
“Once those maps are lined up, we expect people will be able to have a far better understanding of the types of machinery that contribute most to methane leaks,” Maguire said. These maps and underlying data will be available later this year on MethaneSat’s website and from Google Earth Engine, the company’s environmental-monitoring platform used by researchers to “detect trends and understand correlations between human activity and its environmental impact.”
The work between Google and EDF on MethaneSat is part of a broader set of methane-emissions monitoring efforts by researchers, governments, nonprofits and companies. At the COP28 climate summit, Bloomberg Philanthropies pledged $40 million to support what Hamburg described as an “independent watchdog effort” to track the progress of emissions-reduction pledges that companies in the oil and gas industry made at the event.
MethaneSat will bring new technology to the table, he said. Its sensors can detect methane at concentrations of 2 to 3 parts per billion, down to resolutions of about 100 meters by 400 meters. That’s a much tighter resolution than the methane detection provided by the European Space Agency’s Copernicus Sentinel satellite, which nonetheless has been able to detect gigantic methane plumes in oil and gas basins in Central Asia and North Africa in the past three years, he said.
At the same time, MethaneSat can scan 200-kilometer-wide swaths of Earth as it passes overhead, he said. That combination of detail and scope will allow it to “see widespread emissions — those that are across large areas and that other satellites can see — as well as spot problems where other satellites aren’t looking.”
This image, taken from a scan using MethaneSat’s sensors in an airplane flying over the Permian Basin, the major oil- and gas-producing region in West Texas and eastern New Mexico, shows the combination of area emissions and point-source emissions that the sensor can capture.
EDF’s work with Google is also enabling the use of MethaneSat data to detect not only the concentration of methane in the atmosphere but also its “flux,” he said — the volumes of methane leaking and their change over time. That’s important information for government regulators seeking to quantify leakage rates to impose penalties or measure industry mitigation efforts, he noted. “We’re telling everyone the information they need to take action, as opposed to scientific information that requires further processing.”
Hamburg pointed to other satellite, aerial and ground-based monitoring technologies that can provide more fine-grained data on which parts of oil and gas infrastructure are the source of individual leaks, so that “any individual company or actor in a specific spot can make a repair.”
This granular monitoring is being provided today by Canadian-based company GHGSat, which can focus its sensors to collect data from a point on the Earth as small as roughly 25 meters square. It will be aided by Carbon Mapper, a joint effort of NASA’s Jet Propulsion Lab, the California Air Resources Board, private satellite company Planet, and universities and nonprofit partners including RMI and Bloomberg Philanthropies. (Canary Media is an independent affiliate of RMI.)
Later this year, Carbon Mapper plans to launch into orbit two satellites that will be able to deliver 30-meter-square resolution of point-source methane emissions.
“What Carbon Mapper is focused on is how to discover and isolate super-emitters,” Riley Duren, CEO of the public-private consortium, told Canary Media in a December interview.
Duren compared Carbon Mapper to “a collection of telephoto lenses, zooming in to give you a single view.” MethaneSat, by comparison, is “regional accounting, wall to wall, all the emissions in the Permian Basin or Uinta Basin,” or other oil- and gas-producing regions, he said.
“This has to be a system of systems,” he added. “No one technology will solve this.”
MethaneSat has spent $88 million on the design, construction and launch planning for its first satellite, Hamburg said. The work is funded by a $100 million grant from the Bezos Earth Fund, the philanthropic organization launched by Amazon CEO Jeff Bezos.
MethaneSat’s data will be open to analysis from “scientists around the world to validate, to make sure that everybody understands what it can do and what it can’t do,” he added.
Maguire noted that the data from Google Earth Engine, including the MethaneSat data it will make available later this year, is “available to researchers, nonprofits and academic institutions for free.” He noted that oil and gas companies will also be able to access the data to inform their own methane leak mitigation efforts. While Google doesn’t have “any information to share at this point” about if or how it might charge companies for that data, “our goal is to make sure that this information is as broadly accessible as possible.”
As for how regulators might make use of MethaneSat data, Hamburg said the organization is “working with the global community of scientists and talking with governments about how to utilize these data to effectively drive the change they’re looking to drive.” He declined to provide specifics on what those conversations with governments have entailed. “I wouldn’t call them formal talks, but active talks,” he said.
It’s become the animating question in the U.S. electricity industry: How can power-hungry data centers get the energy they need?
The obvious answers have proven insufficient. Solar and wind power projects face yearslong wait times to interconnect to constrained grids. Moves to siphon off existing nuclear power to avoid these grid bottlenecks have proven controversial. And building new fossil gas–fired power plants will not only worsen climate change but may simply be impossible on the timeline that data centers require given current gas turbine backlogs.
But there may be faster and cheaper ways to bring lots of clean energy online to match new data center demand — it just requires some creative thinking.
One idea is to couple new clean power with some of the dirtier, if only rarely used, fossil-fuel power plants already connected to the grid — an approach that, counterintuitively enough, could end up not just faster but cleaner than alternatives.
That’s the proposition think tank RMI lays out in a recent paper describing the potential for so-called “power couples,” which the authors define as lots of new solar, wind, and batteries connected to existing fossil gas–fired “peaker” plants, which basically act as emergency generators for the grid at large, all in service of a data center or other facility that uses large amounts of power.
The biggest data centers now being planned across the country by tech giants like Amazon, Google, Meta, and Microsoft can use hundreds of megawatts to gigawatts of electricity. In some of the country’s biggest data center hot spots, there simply isn’t enough capacity left to connect that much new load right now.
But in the “power couple” structure, those data centers wouldn’t even draw from the grid, explained Uday Varadarajan, a senior principal at RMI’s carbon-free electricity program and co-author of the report. Instead, they’d be connected to clean power behind the “point of interconnection” between peaker plants and the grid at large.
That could also allow new large-scale clean power projects to connect directly to the data center. Some of those solar, wind, and battery developments are already permitted and awaiting grid interconnection — and all of them can be built much faster than new gas-fired power plants, according to industry experts. Allowing some of these projects to avoid the interconnection backlogs and grid upgrade costs would get clean power online much faster.
Of course, few if any data centers can rely solely on the sun and wind to serve their round-the-clock power needs, even with batteries to store some of that power for when demand is highest. That’s where the peaker plant comes in, Varadarajan said.
Peaker plants can serve as a circuit breaker of sorts between the grid on one side and the new data center and all its clean power and batteries on the other side. When there’s not enough clean power for the data center, “we allow the new load to draw from the existing gas plant in a limited way,” he said. The key is making sure the data center doesn’t impinge on when the grid needs that peaking power.
In that sense, the peaker plants are more like gas-fired backups for a largely clean power mix. It’s a natural fit: Peaker plants are designed to fire up only when the grid really needs them, largely during summer heat waves or winter cold snaps when demand for electricity peaks (hence their name).
That leaves a lot of hours when those plants aren’t using their connections to the grid at large — which creates an opening for clean power to use them, Varadarajan said. Developers will probably want to “overbuild” the amount of dedicated solar, wind, and batteries supplying data centers, so they can rely on those resources during more hours of the year. That means the renewables will often generate more than the data center needs at a particular moment, but in the power couple arrangement that extra power wouldn’t go to waste — it’d flow to the grid using the peaker plant’s oft-idle grid connection.
Importantly, from the perspective of a utility or grid operator, this setup is potentially far less disruptive than adding a big new load or trying to interconnect a brand-new source of generation, Varadarajan said. Many U.S. grid operators already have rules to allow sites that have grid connections to add different types of generation capacity or to use a power plant’s existing capacity more frequently.
And because the data centers will have all the power they need behind the interconnection point, power couples won’t have to enter the complicated technical and regulatory realm of projects that both inject and draw power from the grid — a status that can be a significant hangup for battery and “hybrid” battery-solar or battery-wind projects in some regions.
RMI mapped the lower 48 states for suitable power-couple sites, looking for peaker plants with enough available land within a 10-kilometer radius to be able to build solar power that can cover at least 60% of an accompanying data center’s annual electricity needs. But the sites identified in its analysis could add significantly more clean power than that — about 88% of the modeled data centers’ annual power consumption on average.
RMI’s analysis wasn’t limited solely to peaker plants. Of the roughly 160 power plants in its final report, just over 40 were combined cycle gas turbine (CCGT) power plants, a more efficient type of gas-fired power plant. Most CCGTs tend to operate regularly throughout the year to provide “baseload” grid power, but RMI looked at some “load-following” CCGTs, which ramp up and down as grid demand rises and falls, and are therefore idle often enough to supply a power couple’s data center needs.
As for cost, RMI’s analysis found that more than 50 gigawatts of new data center or “other concentrated loads” could be supported by power couple developments at an all-in price of no more than $200 per megawatt-hour. More than 30 gigawatts of that new construction could be powered at less than $100 per megawatt-hour.
Those prices are higher than what data center developers might expect to secure from utilities with low-cost power, ample grid capacity, and an eagerness for the economic development such customers could bring. They’re also higher than recent average prices for solar and wind power purchase agreements in the U.S.
But for the tech giants and data center developers competing for scarce space on crowded grids, price could no longer be as significant as being able to get power quickly. Industry analysts have calculated that Microsoft may be offering more than $100 per megawatt-hour for the power it will get from a deal with Constellation Energy to restart a nuclear reactor at the Three Mile Island site in Pennsylvania — and that’s for power that won’t be delivered until near the end of the decade at the earliest.
Faster routes to getting clean power online could be worth an even greater premium, Varadarajan said — and “a lot of the data centers aren’t particularly price-sensitive to begin with.” So the price ranges for the power couples RMI analyzed are “not completely crazy.”
The price points also vary widely across the sites that RMI modeled. In some cases, they can drop into the $60 per megawatt-hour range, well within striking distance of plain-vanilla power purchase agreements for clean energy — although those lower-cost options also tended to yield less annual clean energy supply.
Even at higher prices, solar and wind power that flows directly to data centers could be attractive for tech companies like Google and Microsoft that are striving to achieve 24/7 clean energy targets. “This is a product that’s giving you bundled capacity, energy, and clean power,” Varadarajan said.
In fact, the concept laid out in RMI’s report looks a bit like what Google and partners Intersect Power and TPG Rise Climate are undertaking in a plan to invest $20 billion through 2030 in newly built wind, solar, and batteries to mostly power new data centers.
Intersect Power CEO Sheldon Kimber has proposed that this is a better way to meet growing demand for industrial-scale electricity, rather than trying to negotiate the complex and sometimes contradictory regulatory and economic hurdles required to add generation and loads to utility grids.
Intersect Power has proposed building its own gas-fired generation instead of relying on existing peaker plants. Whatever the fossil-fuel backup source, Kimber told Canary Media that parts of the country with good solar and wind resources can probably power a big load like a data center with electricity that’s carbon-free about 80% or more of the year.
A power couple also looks something like the “energy parks” concept that think tank Energy Innovation put forth in a December report. Energy parks are combinations of large loads like data centers powered by new solar, wind, and batteries — and some fossil-fuel backup power — all connected to the grid at a single point.
For clean energy developers, the ability to secure a major customer and avoid grid interconnection wait times and grid upgrade cost uncertainties takes away a lot of risk, said Eric Gimon, Energy Innovation policy adviser and a co-author of the group’s recent report. “You still need permits — but you’re not waiting for years to learn if you can interconnect or not. And you’ve got a committed buyer” for the newly built power.
That’s not to say that current regulations make these kinds of projects easy. It’s probably simplest in Texas, where a deregulated energy regime has allowed clean energy and batteries to thrive. That’s where Google and Intersect Power are planning their first projects.
The situation is more mixed in other parts of the country, depending on the rules that apply. For example, RMI has tracked gigawatts of new generation added to existing power plants’ grid connections under so-called “surplus interconnection service” rules across the territories of the Midcontinent Independent System Operator and Southwest Power Pool, two entities that manage transmission grids and energy markets across a swath of Midwestern and Great Plains states.
But PJM Interconnection, which manages the transmission grid and energy markets providing power to about 65 million people from Washington, D.C., and 13 states from Virginia to Illinois, has only recently started amending its regulatory regimes to allow this surplus interconnection option in ways that energy developers say they can work with.
In many parts of the country where utilities retain monopolies over the right to build generation, operate power grids, and sell electricity to all customers in their service territories, pathways for other companies to build and own clean energy remain largely untested.
But those “vertically integrated” utility territories could also be a key venue for energy parks, according to Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative.
Peskoe co-wrote a recent paper laying out the risk that utilities may build power plants and expand their grids to serve gigawatts of new data center demand and then pass on a disproportionate share of those costs to ratepayers.
Energy parks could help insulate everyday customers from these potential rate hikes, he wrote, since only the companies building the data center and the new generation would be responsible for the costs involved. But for that to happen, state lawmakers will have to make these arrangements legal.
Or utilities could build power couples themselves. RMI’s analysis finds that opportunities exist in the deregulated market of Texas and the backed-up grids managed by PJM but also across much of the Southeastern U.S. where utilities largely retain monopoly status over generation, grids, and retail customers. Those utilities face massive demand growth from prospective data centers — and pressure from tech companies to find cleaner options than gas-fired power plants.
The technical potential for using existing grid connections to boost clean power capacity is enormous. A report from think tank GridLab and the University of California, Berkeley found surplus interconnection sites across the country that could support nearly 700 gigawatts of new generation.
To be sure, that’s a theoretical maximum that’s almost certain to remain unrealized due to real-world constraints and basic energy economics. “But a screaming success would be that we could unlock 10% of that opportunity” over the next decade, said Ric O’Connell, GridLab’s founding executive director.
That won’t be simple to achieve. One early hurdle is setting up the contractual structures between existing power plant owners and the developers of data centers and clean energy, O’Connell said. Even when those are done, conflicts could arise between power-couple project partners and incumbent generators, transmission grid owners, and utilities.
“There’s a lot of regulatory risk behind this approach that I hope can be mitigated because the benefits are really strong,” he said.
Varadarajan agreed that power couples are “not an easy transaction to do. I’m not saying it won’t be complicated.” But as reports like those from RMI, GridLab, and Energy Innovation indicate, “this is a good opportunity for everyone to take a look at what they’ve got and use their interconnection rights to the greatest value.”
California has big heat-pump dreams. Now, it’s got a road map to realize them.
Last week, the California Heat Pump Partnership announced the nation’s first statewide blueprint to achieve the state’s ambitious goals for deploying heat pumps, a critical tech for decarbonizing buildings and improving public health. The plan draws on recommendations from the public-private partnership’s members, which include government agencies, heat pump manufacturers, retailers, utilities, and other stakeholders.
“We hope it serves as a national model,” said Terra Weeks, director of the partnership.
In 2022, California Gov. Gavin Newsom (D) set a goal for the world’s fifth-largest economy to deploy 6 million heat pump units by 2030. That includes heat pumps for building heating and air-conditioning needs as well as for water heating. An estimated 1.9 million have been installed so far, according to the blueprint report.
The state is not on track to hit that 2030 benchmark. Even with current policies and incentives, California would fall 2 million heat pumps short, the report says.
Heat pump units are outselling gas furnaces nationally, but of the roughly 1 million units of HVAC equipment sold annually in California, just one in five are heat pumps. Of about 800,000 water heaters sold each year, only 3% to 5% are heat pump models. The state is one of nine committed to making heat pumps at least 65% of residential HVAC sales by 2030.
Looking beyond the 2030 target, the Golden State ultimately needs to deploy an estimated 23 million heat pumps to decarbonize its residential and commercial sectors by 2045, when California aims to be carbon neutral.
Heat pumps face considerable challenges to mass adoption in the state. Many Californians aren’t aware of the appliance’s benefits, according to the report. Heat pumps are typically more expensive up front than gas furnaces and can cost more to run in states like California where electricity prices are high relative to those of gas. Plus, many contractors aren’t prioritizing heat pumps, citing a lack of market confidence, the report notes.
The blueprint lays out a raft of solutions to make heat pumps more desirable and affordable. Building customer demand and contractor support is key to making them “the easy and obvious choice,” as the report puts it.
To create buzz for the appliances, the partnership is launching a “heat pump week” with interactive experiences next spring. The group will also start a broader marketing campaign this fall, which will include spotlighting contractors who already install heat pumps.
To reduce up-front costs, the coalition supports expanding heat pump financing tools, like the low-interest loans from the State Treasurer’s Office GoGreen Home program. Weeks also underscored the need for incentives that are easy for contractors and customers to access, such as instant, “point-of-sale” rebates for heat pumps.
Applying lessons from existing incentive initiatives like TECH Clean California, the partnership recommends that program architects get input from contractors and manufacturers on how to design incentives and ensure funds follow predictable timelines, rather than abruptly run out.
“The current start-and-stop dynamics that we’re seeing with many incentive programs today … can deter both customers and contractors from opting for heat pumps,” Weeks said. “There’s really broad consensus from our members that there is a distinct need to just make sure that those incentives don’t disappear.”
The group also endorses streamlining the permitting process for heat pump installations, a measure currently before the state Legislature.
The blueprint points out that focusing on particular markets could help supercharge heat pump adoption. Residents in the San Francisco Bay Area, for example, must start replacing their broken gas-fueled furnaces and water heaters with zero-emissions electric equipment starting in 2027 to comply with air quality rules.
Consumers in hotter areas, like inland California, will also save more on cooling costs than other customers when they replace older, less-efficient central ACs with heat pumps, making them potentially prime early adopters.
If heat pumps went from their current 23% of market share for AC replacements to 80%, installations would add up to roughly 1.7 million additional units over six years, per the report.
A linchpin of the blueprint is a workforce advisory council of installers, trade associations, workforce educators, and other stakeholders who can help guide the partnership’s marketing efforts and policy recommendations.
“We need to be designing regulations and programs with contractors so that they work for contractors,” Weeks said. “And if we make it easy and profitable for contractors, we win.”
The sweeping tactics laid out in the report will require substantial funding, potentially in the billions of dollars. But exactly how much will be up for debate, Weeks said. Funds could come from a variety of sources, including cap-and-trade revenues, utility ratepayer programs, and state tax dollars, she said. The report recommends minimizing the use of ratepayer funding; California is looking to cut costs to utility customers as the state’s electricity bills skyrocket.
Last Monday, California paused its $290 million home energy rebate program, part of an $8.8-billion federally funded initiative for heat pumps and other home energy upgrades, because state officials couldn’t access funds.
But Weeks remains sanguine; California runs several home-grown programs, including the $500 million Equitable Building Decarbonization program to put heat pumps in reach for thousands of low-income households.
“While the step back from the federal government on funding programs is regrettable,” Weeks said, “leadership states like California will find ways to help people make the right choice to buy heat pumps.”
Republicans are looking to roll back key electric-vehicle incentives passed under the Biden administration. Doing so would kneecap the EV transition for years to come.
Under current policies, the number of light-duty EVs sold annually is forecast to climb to 7 million by 2030, according to a new analysis from the REPEAT Project at Princeton University. But if those policies — specifically the consumer EV tax credit and tailpipe emissions rules — are repealed, that figure is forecast to be 40% lower in 2030, at around 4.2 million.
Despite Detroit’s pleas, the Trump administration and congressional Republicans are seeking to eliminate the $7,500 EV tax credit as well as vehicle efficiency rules that incentivize automakers to stop making gas-fueled cars.
It would be a blow to a U.S. EV industry that’s already coming off a year of mixed success. On the one hand, consumers bought a record number of EVs in 2024 as models from automakers other than Tesla caught on. On the other hand, sales grew by just 7% compared with the year prior — a sluggish rate compared to the nearly 50% leap that occurred in 2023 — and automakers began walking back from their EV commitments even prior to President Donald Trump’s election.
Should Republicans succeed in repealing the tax credits and efficiency rules, it would further slow EV adoption — and in the process destroy jobs at EV and battery factories. The REPEAT Project analysis found that eliminating these policies would threaten plans to expand U.S. EV factories and potentially lead to the cancellation or closure of half of existing EV factory capacity. The moves would have a similar effect on the burgeoning battery belt.
More than 80% of announced investments in U.S. EV manufacturing are located in congressional districts represented by Republicans, according to a January report from the Environmental Defense Fund and WSP USA.
Beyond the economic ramifications of the potential repeal, the climate consequences are dire. Gas-powered vehicles are one of the largest sources of planet-warming carbon emissions in the U.S.; they also cause a significant amount of smog-forming pollution that can contribute to respiratory diseases like asthma. Slowing down the transition to electric vehicles would only serve to exacerbate these problems.
It is easy to overlook the low-rise, cream-colored building on Chicago’s Motor Row, a historic district that was a hub for auto dealers in the early 1900s.
Yet the newly purchased headquarters for Bronzeville Community Development Partnership at 2416 S. Michigan Ave. plays both a symbolic and substantive role in fulfilling the organization’s mission of promoting clean energy and community-driven development in this predominantly Black, environmental-justice neighborhood on Chicago’s South Side.
“We want to be able to tell the story of the Great Migration and how we are replicating that age of innovation here in the 21st century, with the transition away from fossil fuels to beneficial electrification,” said Billy Davis, general manager for JitneyEV + EVCharge, one of the partnership’s initiatives. “Not just in commerce and transportation but culturally in the arts as well.”
Since its foundation in 1989 as the Abraham Lincoln Center Business Council, BCDP has strived to promote sustainable economic development in Bronzeville.
The Bronzeville Microgrid, which the organization developed in collaboration with utility ComEd, is one of BCDP’s main clean energy initiatives. As Chicago’s first neighborhood-scale system of its kind, the microgrid services more than 1,000 buildings with solar panels, batteries, and fossil gas–fired generators.
Another major initiative, through the JitneyEV + EVCharge program, is to expand EV adoption among Black and Brown drivers to reduce carbon emissions and other pollution, which have been disproportionately concentrated in environmental justice communities.
BCDP also advocates for the construction of public charging stations throughout the city’s South and West sides, where many communities lack access to such infrastructure.
This work, in addition to sustainability-focused development and cultural tourism projects, reflects a holistic approach to mitigating the adverse effects of disinvestment and climate change in environmental justice communities.
“What happens when a community transforms infrastructure, heritage, and innovation from vision to reality? In Bronzeville, 2024 was the year we proved that sustainable development isn’t just a concept—it’s a lived experience,” wrote Paula Robinson, president of BCDP and managing member of Bronzeville Partners LLC, in a January social media post. “This year, we didn’t just talk about change. We powered it—literally and metaphorically.”
BCDP moved into its current headquarters in June 2024 after purchasing the building with a grant from the state of Illinois, which included funding for a solar array and EV charging infrastructure. The organization also received a City of Chicago Climate Infrastructure Fund grant for energy-efficiency improvements to the building. JitneyEV + EVCharge was awarded a grant from that fund for purchasing EVs and installing charging infrastructure, according to Davis.
The complex, which is still being fitted out, includes a garage for JitneyEV; a visitor center and community meeting space; and spaces for the Urban Innovation Center, Innovation Metropolis, Bronzeville Studio, and the Bronzeville-Black Metropolis National Heritage Area, all of which are affiliates of the larger BCDP collective.
Owning the building allows BCDP to bring the various aspects of its work under a single umbrella and eliminates vulnerability to the whims of a landlord. At the same time, the building serves as a tangible symbol of the organization’s focus on self-sufficiency and self-determination, which is especially relevant in the present political environment.
In Motor Row’s heyday in the early 20th century, Chicago was home to multiple electric vehicle companies. And modern app-based rideshare services operate much like jitneys — taxi-like services that flourished in African American communities that conventional taxicabs often refused to serve. BCDP has married the two histories in its JitneyEV + EVCharge program, which aims to provide the community with an all-electric rideshare service and expand access to public EV charging stations.
BCDP recently purchased its first electric vehicle for the rideshare service and plans to purchase an electric passenger van in the future. BCDP also intends to install a public DC fast charging station on the outside of its new headquarters and a Level 2 charger inside the building’s garage for its own vehicles, according to Davis.
“The building that we are in, the building that we own, was once home to electric automobile manufacturing companies at the turn of the 20th century,” Davis said, adding that it housed showrooms for Detroit Electric, Chalmers Motor Co., and Cadillac.
“So, it just resonates somewhat, that we are returning home, so to speak,” Davis said.
Once it is fully operational, JitneyEV’s rideshare service will be especially useful in helping to fill in gaps in public transit in Bronzeville, which like much of the city’s South and West sides, is underserved by public transportation.
BCDP is also adding its input into initiatives like the Chicago Transit Authority Better Streets for Buses plan, which aims to expand clean transportation options and develop safer streets in communities of color.
”If you’re gonna electrify your bus fleet, why would you launch the 20 or 30 new electric buses anywhere other than in a Justice40 community where the air quality is poorest, where the need for a clean energy transportation solution is greatest?” Davis said, referring to the Biden administration program that aimed to ensure that Black, Brown, and Indigenous communities would receive a substantial proportion of allotted federal funds and other resources.
In 2024, BCDP participated in the National Renewable Energy Laboratory’s Clean Energy to Communities program, which supports community-led projects. BCDP also collaborated with NREL, Argonne National Laboratory, and local universities to launch the EV Institute, according to Davis.
The EV Institute, still under development, has been tasked with empowering the community to implement mobility and transportation equity. For example, there are plans to provide in-person and online education about the benefits of electric vehicles, according to Davis.
This holistic view reflects BCDP’s forward-thinking approach to electrifying transportation, said Julia Hage, manager of the transportation team at the Center for Neighborhood Technology in Chicago, which works with BCDP on its clean energy and community development initiatives.
Like many environmental justice community organizations, BCDP is taking the lead on its own initiatives around economic development, resiliency, and climate mitigation, Hage said.
While welcoming technical assistance and financial resources from outside organizations, environmental justice–based community organizations are nonetheless taking a more assertive approach toward self-determination. The Center for Neighborhood Technology has embraced its supporting role in empowering environmental justice communities to take their rightful seats at the clean energy transition table, Hage said.
“Oftentimes with these different progressions of technology and transportation, the communities are left behind because they’re not included in these conversations,” Hage said. “A lot of harm has been done to communities because of top-down planning decisions.”
Beyond collaborating with BCDP on transportation electrification, Hage said her organization is pulling the group into transportation equity work, too.
This approach was evident in a recent “EV 101” information session that the Center for Neighborhood Technology conducted to educate community-based organizations on how to promote electric vehicle adoption, in which BCDP acted as both a participant and a subject-matter expert.
“[BCDP was] able to also provide information to other CBOs, which I thought was a really cool benefit of having a cohort of community-based orgs,” Hage said. “No matter where they were in their journey of electrification or clean transportation, they could share with each other things that they knew from their experience.”
While the Center for Neighborhood Technology and BCDP have multiple sources of funding outside the federal government, the sudden inability to rely on federal funding has made it harder for them to carry out their mission.
“That’s part of our story now, too. We’re going to continue this decarbonization even in the face of all these cutbacks,” Davis said. “We have community engagement programs that are now on hold that we were relying on for this year and the summer. That won’t happen, at least not in a timely manner, but we’re going to do this anyway because we’re using mostly city and state funds.”
The federal government’s abrupt cancellation of promised funds has had a profound impact on the broader environmental justice community that the Center for Neighborhood Technology and BCDP are a part of. In the resulting atmosphere of uncertainty, many of these organizations are questioning any future reliance on the federal government, Hage said.
“The really alarming thing is, we’re seeing these full-on pauses and stop-work orders; resources that have been already allocated are being told to stop,” Hage said. “Some speculate like, ‘Oh, it’s just to confuse us. It’s just to make us scramble. They’ll have to go back on this. There’s no way.’ And there’s other folks who are kind of like, ‘We can’t even trust this money anymore.’ We’re still just kind of on edge, like, ‘Hey, is this going to happen?’”
One potential strategy is to advocate for state and local clean energy regulations and carbon-free transportation initiatives, along with increased emphasis and reliance on state-level organizations, such as the Illinois Environmental Protection Agency, Hage said.
“I am sure organizations right now don’t want to find themselves in this situation,” Hage said. “And I’m sure that they will want to redirect their focus on ‘What are grants that won’t be suddenly paused or suddenly taken away from us?’ And that’s why I think the focus on state and local resources is in conversation. Though, a lot of state money comes from the federal government. So, it’s kind of about ‘How do we best utilize this money while we have it?’”
The federal government’s purge of environmental justice data makes it harder to direct resources to where they are most needed. Nonetheless, BCDP and other environmental justice–focused organizations are determined to continue moving forward while acknowledging the significance of the challenges ahead.
“The freezing of federal grants and loans previously appropriated by Congress has been disruptive and is being challenged in court as unlawful overreach. The ultimate impact, therefore, is not yet fully known,” Davis said in an email.
“However, we remain undaunted in our work advancing renewable energy and clean transportation as economic and workforce development opportunities that make our communities healthier, safer, more livable and sustainable.”
A wave of new reports and data out this week showed just how good of a year 2024 was for U.S. clean energy, especially solar and batteries. Here are a few highlights:
2025 could be another big year. The U.S. Energy Information Administration predicts solar will once again lead power plant construction and that energy storage deployment will shatter last year’s record.
But those predictions come with two major caveats: The White House and Congress.
The Trump administration has already taken direct aim at offshore wind construction and at loans that were set to support battery factories and other clean energy projects. Developers fear Congress will roll back Inflation Reduction Act investment and production tax credits, which are a major reason why clean energy deployment and manufacturing surged in the past year.
House Republicans’ budget talks haven’t yet targeted those particular incentives, and 21 GOP Congress members this week called for preserving them. Still, the IRA’s precarious position is making it hard for clean energy developers to plan ahead. As Morningstar analyst Brett Castelli put it to Heatmap, “all businesses like certainty” — and Congress and the Trump administration aren’t providing much of that these days.
Here are two more big stories from this week:
A lot is going on at the U.S. Environmental Protection Agency this week. For starters, EPA Administrator Lee Zeldin said he terminated $20 billion in federal “green bank” funds for climate nonprofits, Canary Media’s Jeff St. John reports. A judge seemed skeptical of Zeldin’s allegations of “misconduct, conflicts of interest, and potential fraud” in a Wednesday hearing.
Zeldin also announced Wednesday that he’s targeting dozens of climate and environmental regulations for rollback. Power plant and tailpipe emissions rules are among those on the chopping block, though experts say it could take years — and willing courts — for Zeldin to achieve his deregulatory dreams.
The EPA has also canceled more than 400 grants across “unnecessary programs,” Zeldin said, though he wouldn’t specify further. It all comes on top of plans to shutter the EPA’s environmental justice offices, just days after Zeldin recalled workers in those offices from administrative leave.
Energy industry leaders met this week in Houston for the annual CERAWeek conference, which turned into a celebration of all things fossil fuels. U.S. Energy Secretary Chris Wright kicked things off with a promise that the Trump administration will “end the Biden administration’s irrational, quasi-religious” climate policies, while fossil fuel executives praised President Donald Trump’s deregulatory push and announced they are stepping back from clean energy promises.
But it wasn’t all love for Trump policies. Some fossil fuel leaders quietly aired their grievances with the president’s trade fights, saying they’re driving up costs even as he tries to boost the industry.
The latest on tariffs: Ontario’s premier lifts a 25% surcharge on Canadian power exported to Michigan, Minnesota, and New York, but President Trump’s tariffs on steel and aluminum imports from the country and beyond still went into effect Wednesday. (CNN)
Climate suits safe for now: The U.S. Supreme Court declines to hear an argument by 19 Republican attorneys general seeking to limit states’ abilities to sue fossil fuel companies for climate damages. (New York Times)
It’s all about timing: Time-of-use electricity rates, which charge customers more during times of high power demand and less when it’s low, could make heat pumps more financially worthwhile in areas where fossil gas is cheaper than electricity. (Canary Media)
Dive deeper: A time-of-use rate pilot program helped Chicago-area utility customers save money, and it will soon let more residents opt in. (Canary Media)
Power plant preparations: Several states are devising tax incentives and loosening regulations to encourage power plant construction and prepare for rising electricity demand stemming from data center expansions. (Associated Press)
Sunshine State: Florida built 3 GW of utility-scale solar last year, second only to Texas, even as the state’s Republican leadership continued to fight climate action. (Canary Media)
Reliving EV history: A Chicago-area environmental justice community is reigniting its 100-year history as an electric vehicle hub by building a charging network it hopes can get more Black and Brown drivers into EVs. (Canary Media)
Smells like clean energy: A startup is adapting fusion technology to blast through rock that would destroy conventional drill bits, letting it get deeper into the Earth to unlock hotter geothermal power — and the result smells like toasted marshmallows. (Canary Media)
One recent day in a warehouse south of downtown Houston, I got a peek at something that just might revolutionize the clean energy transition: a molten orange puddle of instantly liquefied rock.
Moments before, an attendant loaded a slug of basalt under a metal-frame structure that looked like something a supervillain might point at a tied-up James Bond, and I was ushered behind a protective barrier. An order went out, the contraption began to whir, and we turned our focus to a TV screen, where the solid rock erupted in a blast of white light that overwhelmed the livestream camera.
One mustn’t believe everything that appears on a screen, but then Carlos Araque, CEO and co-founder of advanced geothermal startup Quaise Energy, led us back to the rig, and there was the freshly blasted rock. A minute ago, it hit as much as 2,000 degrees Celsius, but the molten goop had already solidified into a crown of shiny obsidian. Heat radiated from it, warming my hand as I hovered it a few inches away. The air smelled like toasted marshmallows, if the marshmallows were made of stone.
The flashy demonstration was just one example of how startups are looking to revolutionize geothermal energy production. The U.S. built its biggest geothermal power-plant complex in 1960, but construction has stagnated for decades. Geothermal serves a mere 0.4% of U.S. electricity generation; its nearly 4 gigawatts of capacity amounts to roughly the solar and battery capacity Texas installs in four months these days.
The way out of this decades-long malaise may simply be down. The more subterranean heat a geothermal plant can access, the more energy it can generate, and the Earth gets hotter closer to the core. But the intense conditions below a few miles deep rapidly wreck conventional drill bits.
Araque figured that if he could build a strong enough drill bit, it could harness this super-deep heat and deliver cheap, clean, and abundant geothermal power, pretty much anywhere.
So he left a career in oilfield drilling and formed Quaise in 2018 to do exactly that. Or, more precisely, the company adapted the gyrotron, a tool honed by the nuclear fusion industry that emits millimeter waves, which fall on the electromagnetic spectrum between microwaves and infrared waves. Fusion researchers use them to heat plasma to unfathomably high temperatures. But these waves exert a dramatic effect on rock, so Quaise leadership repurposed them to bore through depths that would demolish conventional drill bits, and perhaps unlock a new golden age of geothermal.
Araque likened the technology to the familiar microwave oven, which heats food by zapping it with a particular band of electromagnetic waves that excites water molecules.
“Translate that into rock,” he said. “Well, rocks love millimeter waves. You put millimeter waves into rock, they soak it up, they light up instantly.”
He first pitched me on his super-powered drill bit six years ago. At the time, it all sounded like science fiction, something that Massachusetts Institute of Technology researchers might study and venture capitalists might take a flyer on but that wouldn’t materialize as real technology.
In fact, Quaise did spin out of an MIT lab, and it did raise venture capital for the idea — more than $100 million to date from Prelude Ventures, Mitsubishi, and others. Seven years into the project, however, here I was, smelling the deep, toasty scent of freshly bruleed rock. Deep geothermal energy suddenly seemed a little less like sci-fi and a little more plausible.
Still, Quaise has plenty more work to do before it can deliver its transformative promise — and that starts with getting out of the lab and into the field.
By the time I visited in late January, Quaise had been melting rock outside of the lab but on its own property for weeks. I personally witnessed rock-melting in two places: in the hangar, with a drill rig pointing the millimeter-wave beam at a target rock, and in the yard, where a contraption mounted on tank treads blasted into a rock sample placed in a concrete receptacle on the ground.
“This is the first demonstration of capability, outside, at full scale,” Araque said of the installation.
These tests are necessary to calibrate the novel combination of millimeter-wave emitter and conventional oil-drilling rig. (The Quaise founders know their way around that world, having come from drilling powerhouse Schlumberger.) Quaise proved it can transmit the waves while moving the device, something that the nuclear fusion folks never needed to test. The company’s “articulated wave guide” also showed it can achieve a consistent round shape for its borehole, at least over short distances.
The tests so far amount to the karate demonstration where someone chops through a stack of two-by-fours: Most impressive but not a commercially viable way to chop wood. The next step is obvious — Quaise needs to get out and drill into the earth. That’s coming soon.
Quaise obtained a test site in north Houston where it can drill up to 100 feet underground. The 100-kilowatt gyrotron system I saw firing up in the warehouse has already been moved to this field site, where Quaise is connecting it to a full-scale drilling rig owned by partner Nabors Industries; its mast will soar over 182 feet tall. Drilling should begin in April, cutting into an existing well stuffed with rock samples — outdoors but still a controlled environment.
Soon after, Quaise will swap that out for a new 1-megawatt system, delivering 10 times the power to speed up subsurface boring and maintain an 8-inch-diameter hole, bigger than the initial test holes. That device will use a comparable amount of power as is used by conventional drilling rigs, Araque noted.
Drilling 100 feet down is a start but far from sufficient. The company also secured a quarry site near Austin that provides the opportunity to drill nearly 500 feet through pure granite. Once the technology graduates to drilling thousands of feet, Quaise plans to piggyback on the existing drilling industry with its “BYOG” approach.
“Bring a gyrotron, bring the waveguide, bring the power supply, plug it into the drilling rig,” Araque said. “There’s thousands of drilling rigs in the world. You just go and plug and play into them.”
If and when the time comes to drill for actual power plants, Quaise aims to ride conventional drilling technologies as far as they’ll go. The plan is to hire traditional rigs to burrow through the first 2 to 3 kilometers of subsurface (up to nearly 2 miles) until the drill hits what’s known as basement rock.
After hitting basement rock, Quaise will swap drill bits for its millimeter-wave drill and blast to about 5 miles deep in favorable locations — even that far down, some places have easier access to heat than others. Operators will pump nitrogen gas into the hole to flush out the dust from vaporized rock as the drill moves ever deeper.
Quaise leaders did not disclose a timeline for the company’s first commercial deep drilling. At that point, Quaise will need to build an actual power plant and navigate the myriad permitting and transmission-connection hurdles that face renewables developers broadly. The company is running this development process in-house and already has multiple geothermal leases secured, a spokesperson noted.
In the meantime, a handful of other startups are making headway on commercial-scale geothermal plants, albeit with different approaches.
Fervo Energy has applied fracking technologies to geothermal drilling to make the process more efficient; after a successful 3.5-megawatt trial project in Nevada, the company began drilling the 400-megawatt Cape Station plant in Utah.
Closer in principle to Quaise, a Canadian startup called Eavor is developing ways to drill deeper than was economically practical before. Instead of reinventing the drill itself, Eavor defends it with insulation and “shock cooling” to avoid crumbling in deep, high-temperature rock.
“Most oil and gas directional drilling tools are rated for 180C temperatures, [but Eavor’s] insulated drilling pipe has a cooling effect on the tools making them work at even higher temperatures just by insulating the pipe,” a company spokesperson said in an email.
Eavor notched a big win in 2023, when it drilled a test well in New Mexico to depths of 3.4 miles and through rock as hot as 250 degrees Celsius. Now it’s drilling a closed-loop project in Germany to generate 8.2 megawatts of electricity and 64 megawatts of heating.
Taken together, geothermal innovators like Quaise, along with the somewhat less science-fictiony enhanced geothermal startups like Fervo and Eavor, could produce the “clean firm” power that energy modelers say is necessary to balance out cheap wind and solar in the quest to decarbonize the electrical grid.
“Advanced geothermal technologies could unlock a terawatt-scale resource that can deliver clean energy on demand,” said Jesse Jenkins, an authority on net-zero modeling and assistant professor at Princeton University. “That would be an enormously valuable tool to have in our toolbox.”
Quaise could in theory supply those other geothermal innovators with a better type of drill to extend their range. But Araque insisted Quaise wants to be in the power generation business, not the widget business.
The company also has to manage an evident chokepoint in its development: those highly specialized gyrotrons. Quaise owns four, Araque said; the global gyrotron supply chain currently can’t handle an order for 10 more. That’s not an issue while Quaise works its way up to deep subsurface drilling, but the growth trajectory of the gyrotron suppliers could limit how much power-plant drilling the company can perform simultaneously in the future.
The work to extend from boring a few inches of rock to miles of it should not be underestimated, but Quaise has already crossed the more daunting chasm from never melting rock with an energy beam to doing so daily.
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