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The flow has been stop and go for the first few months, but the line shows plenty of potential to boost Massachusetts’ renewable energy supply.
When the New England Clean Energy Connect transmission line started carrying electricity from Canada into Maine in January, supporters hailed the project as a triumph for renewable power. Now, after nearly six months of operations, the early numbers raise questions about whether the project will be able to advance the region’s energy transition as much as advertised.
Energy flow into New England is up just marginally, and there have been roughly 27 days when no power at all traveled along the new line, commonly called NECEC. If current trends hold, New England will receive less hydropower this year over two transmission lines than it did over just one line in 2023 and previous years.
“What we’ve seen so far is not what some people expected to see,” said Joseph LaRusso, manager of the Clean Grid Program at climate nonprofit Acadia Center.
Potentially putting further strain on the supply of Canadian hydropower is the Champlain Hudson Power Express, a transmission line that started sending electricity from Quebec into New York City this month.
NECEC has its origins in a 2016 Massachusetts law that required the state to procure 1.6 gigawatts of offshore wind power and another 1.2 gigawatts of additional renewable energy. The plan was to contract with state-owned Canadian power supplier Hydro-Québec to tap into the region’s abundant hydropower resources and build a new transmission line to carry the electricity south.
The first proposal — a 192-mile project through New Hampshire — was abandoned in 2019 after public outcry about the impact on the state’s forests. The transmission line through Maine faced similar controversy. In 2021, a statewide referendum vote put the project on hold until 2023, when a jury ruled that the development could be restarted.
Two and a half years later, NECEC came online and started carrying the first electrons into New England. It’s certainly a notable achievement in a time when the Trump administration has been doing all it can to stop progress on clean energy, including offshore wind — the cornerstone of the Northeast’s decarbonization plans. And although the results so far have been mixed, some see potential for the line to make a sizable impact on New England’s clean energy future.
When NECEC came online earlier this year, Massachusetts Gov. Maura Healey, a Democrat, and climate advocates touted it as a major win for the state’s renewable energy goals and a way to save residents money on their utility bills. Massachusetts contracted with Hydro-Québec for 9.55 terawatt-hours of hydropower per year, roughly 20% of the state’s annual electricity demand.
The operations have not had the smoothest start. NECEC was completely inactive for several spans — from a half day on April 28 to nearly two weeks at the end of May and beginning of June. The most recent outage was due to “technical difficulties,” Hydro-Québec spokesperson Lynn St-Laurent said in a written statement.
“Once repairs were completed, deliveries resumed,” she said. “With any new transmission infrastructure, a period of optimization and fine-tuning is to be expected.”
Still, most of the time, hydropower has flowed steadily on the new infrastructure. Through the end of April, Hydro-Québec exported about 2.4 terawatt-hours of power on the transmission line.
If the power is (mostly) moving as planned, why are some people still skeptical that the project will deliver the promised benefits? Because so far, it hasn’t done much to add to the total supply of renewable energy in New England.
Before NECEC, New England already imported significant amounts of hydropower on a transmission line known as Phase 2, which runs from Quebec into central Massachusetts. In 2019, the year the Massachusetts regulators approved the contracts between utilities and Hydro-Québec, more than 12 terawatt-hours traveled onto the New England grid over the line.
But starting in 2023, Hydro-Québec started selling less and less energy to New England over Phase 2. For nearly three weeks in early 2025, exports ceased entirely. Through the end of April this year, just over half a terawatt-hour has come south over that line. On paper, it can look a lot like NECEC isn’t allowing more energy into New England but is instead just giving it a new road to travel along.
“We’re not seeing much net new flows coming from our neighbors,” said Dan Dolan, president of the New England Power Generators Association. “We are running pretty close to the net energy flows we had in 2025, which were the lowest amount of imports that New England has ever gotten from Quebec.”
At the same time, Quebec has started importing power over the Phase 2 line, a rare occurrence before 2025. In the first four months of this year, more than 500 gigawatt-hours traveled into Canada on the line. Because New England’s electricity supply relies heavily on natural gas generation, the region is still burning fossil fuels to ship energy north even though it is receiving hydropower for its own use.
“We’re seeing a heavier natural gas burn on the rest of the generation fleet than I think many of those states had assumed going into this year,” Dolan said.
The main driver behind slowing exports seems to be the drought conditions that have lingered in Quebec for the past few years. During wetter periods, the hydropower industry uses large reservoirs to store water to help it ride out these drier times, said Gilbert Bennett, a senior adviser for WaterPower Canada, a hydropower trade group.
As generators wait for rainier days, their first obligation is to supply domestic customers, he said. That means there will likely be times when Hydro-Québec needs to import electricity over the Phase 2 line to offset some of the hydropower it is contractually obliged to send to Massachusetts over NECEC.
“Electricity flows between Québec and New England are dynamic and vary continuously based on market conditions and system needs on both sides of the border,” St-Laurent said.
Financially, New England customers should not be at risk from these ongoing shifts, LaRusso said. Massachusetts’ contract with Hydro-Québec includes provisions that require the Canadian company to pay financial penalties if it fails to deliver according to its contract.
“To the extent that imports are curtailed, Hydro-Québec is liable to make the electric utilities whole for the cost of replacement power,” LaRusso said.
It is less clear whether NECEC will boost Massachusetts’ renewable energy supply in the long run.
Still, the new transmission line has at times demonstrated its potential to help New England achieve a cleaner energy supply, LaRusso said. He pointed to May 16, a sunny day when solar power reduced demand on the grid and NECEC was going full tilt. Natural gas plants were running at low levels, and most of the power was heading to New York. For a short time, all the region’s power needs could be met by nonfossil fuel resources.
“Hypothetically, [grid operator] ISO New England could’ve turned off its gas generators,” LaRusso said. “It really gets you thinking of the resources available and how they could be managed and shared in the future.”
Bennett is also confident in the long-term outlook. In general, he said, climate change is forecast to create wetter conditions in Quebec. And the region is investing heavily in additional hydropower facilities as well as onshore wind. The years to come, he said, will bring plenty of renewable resources to share with Canada’s southern neighbors.
“Over the long term, we see a bright future,” Bennett said.
In California, Texas, and other places, solar, wind, and batteries hit new highs. Here are the big takeaways from this year’s shoulder season.
As spring gives way to summer, many parts of the U.S. are already feeling the heat. It’s a good moment to take stock of the energy breakthroughs that transpired this past “shoulder season.”
That’s the period of time between the chill of winter and the high temperatures of July and August, when renewable energy systems tend to perform best. With the milder weather and longer daylight hours, total demand stays relatively low while wind and solar ramp up, covering greater shares of grid consumption.
Here are four ways clean energy set new records this spring — and what these feats tell us about where the energy system is headed. While records reflect momentary successes amid ideal conditions, they’re worth noting because they push the boundaries of what’s possible, and lay the groundwork for similar success across broader swaths of the year.
Coal used to make more electricity than any other source in the U.S. Then it fell behind natural gas, and eventually dropped below nuclear. In May, the country’s coal power production slipped behind solar generation, making sunshine the third-biggest source of electricity for the month for the first time.
The U.S. isn’t building more coal plants, though the Trump administration has elected to stop any from closing down, whether or not they can physically operate. Solar, on the other hand, has led the nation in new capacity construction for five years running. When the sun emerges from its wintry slumber, that ever larger fleet shows what it can do.
This upset is all the more striking because, as renewables skeptics love to repeat, solar doesn’t produce all the time. Coal plants can run 24/7, if they aren’t broken or hobbled by uncompetitive operating costs. But even with that structural limitation, solar produced more gigawatt-hours in the daytime than coal did throughout the whole month of May. And this is true not just for a particularly sunny region, or a state with aggressive solar-friendly policies, but across the country.
Solar might not beat coal production for all of 2026, but it’s only a matter of time before it outperforms coal for an entire season, and then eventually for a whole year.
California has entered the execution phase of its energy transition, when the long-promised potential of solar and batteries has turned into empirical breakthroughs in the power markets. The records came at a dizzying pace this spring.
On the evening of March 29, batteries covered 44% of demand (and 42.8% of the supply mix) in the grid managed by the California Independent System Operator (CAISO), which serves about 80% of the state. That was a mild Sunday, so batteries could meet a higher portion of demand than, say, on a blistering hot workday with everyone’s air conditioning turned on. But the absolute numbers speak for themselves: Batteries discharged over 12 gigawatts at 7 p.m. That’s more than New York City consumes on a hot summer day. Not bad for a battery construction spree that largely transpired over the last five years.
On May 16, batteries held gas plants to a shockingly marginal role in the grid for a four-hour period after 7 p.m. Gas never made it above 3% of demand during that time, according to an analysis by the Institute for Energy Economics and Financial Analysis.
The batteries active in California typically can sustain maximum discharge for four hours. This is visible in the daily pattern of grid activity: Batteries surge around sunset to become the single biggest power source in the CAISO grid. Some of them save their energy for later in the night or the early-morning hours before solar produces again. This dynamic leaves a gap in the middle of the night, when gas shows its value.
One way to extend the clean energy success story would be to build longer-lasting batteries. The first major battery with eight hours of duration came online on June 1 in Southern California, and it will offer a sneak preview into what happens when batteries can serve a longer swath of the day.
In the near term, California is tapping more wind power for nighttime supply. The multi-gigawatt SunZia wind farm in New Mexico started shipping power to California this spring, instantly setting new records for wind power’s contribution in the CAISO grid. The Institute for Energy Economics and Financial Analysis compared the grid activity for May 16 of 2025 and 2026. On that day last year, from midnight to 6 a.m., gas generated 3.6 gigawatts, keeping the system going through the night. This year, for that same time period, gas contributed a paltry 560 megawatts. The cheap wind power rushing in from SunZia was pushing gas out of its last redoubt.
One could say these observations are cherry-picking in favor of clean energy. But such ripe cherries simply didn’t exist a year ago, much less five years. California’s clean energy plants should be able to replicate or beat these records in the fall shoulder months. The more challenging test will be whether solar, wind, and batteries can steal market share from gas in the midst of a heat wave, when the fossil fuel has historically hit its maximum output. This El Niño cycle promises to deliver the requisite conditions for that test.
New York state hasn’t built the kind of batteries California has, but it did set a new solar production record on June 3. Solar of all sizes delivered 5.6 gigawatts, serving a record 29% of demand at noon that day, according to the New York Independent System Operator.
The details are more revealing: Almost all of that generation came from small-scale, customer-sited systems, while utility-scale contributed only 530 megawatts. That’s less than the output of individual solar projects out West.
Even the regions that struggle to build much solar are breaking records for themselves. And where you don’t have wide open desert to build sprawling installations, small ones on rooftops and in yards can add up to a meaningful surge.
This spring, Texas set just about every clean energy record you could ask for, as helpfully documented by data firm Grid Status.
Batteries shipped the most power to the grid on March 13, at 7:30 p.m., with 10.4 gigawatts, which satisfied a record 20% of evening demand at that moment.
Wind and solar served a record 79% of demand (and 76.9% of supply) on the afternoon of March 14; along with baseload nuclear, the zero-carbon power plants limited fossil-fueled power to just 13% of the fuel mix for a five-hour swath of midday.
The Texas grid produced more solar power than ever before on May 13, a stunning 34.4 gigawatts at 12:40 p.m. It produced more wind power than ever before on May 17, nearly 29 gigawatts at 11:50 p.m. The highest combined renewable output came on May 14 at 3:15 p.m., almost 48 gigawatts.
Again, these are mild shoulder months, when Houstonians aren’t sweltering too much yet and when gas plant operators take their machinery offline for maintenance. In these favorable conditions, we’re seeing what happens when a society unleashes the trifecta of solar, wind, and batteries. The solar peaks at midday; the wind often kicks up after sunset. When a particular day gets both sunny and gusty, the two resources alone now cover most of the midday consumption. And batteries are carving deeper into the evening peaks, corroborating the trend that California pioneered.
No one source of clean energy can run the whole grid on its own, but none has to. The portfolio effect is on stark display as Texas delivers a deregulated version of clean energy abundance.
A yearslong project has finally started producing ammonia with wind power. If the process can be scaled up, it could help ensure farmers have cheap, reliable fertilizer.
In the shadow of a wind turbine on a low rise just outside the western Minnesota town of Morris, a cluster of tanks, pipes, and sheds holds what some believe is the key to a more self-sufficient future for the region’s agriculture and heavy industry.
When the wind is blowing — and it often is, out here — the turbine powers two electrolyzers that cleave hydrogen from water, another system that separates nitrogen out of the air, and a third that binds the two elements to form anhydrous ammonia, a critical input for corn farming. The University of Minnesota West Central Research and Outreach Center commissioned the plant earlier this spring and can produce hundreds of kilograms of homegrown ammonia daily.
As a stable, efficient carrier of hydrogen, the homegrown ammonia could eventually supply raw material for other types of fertilizers, transportation fuels, and high-temperature industrial processes like ironmaking.
“It’s about 100 times cheaper to store and transport ammonia than hydrogen … so this is a gateway for other hydrogen-based industries,” Michael Reese, green ammonia research lead at WCROC, said on a tour of the facility this spring.
“Gateway” is the operative word here. Reese said WCROC plans to add a third electrolyzer to the project in a “future phase,” bringing daily production capacity to about 1 metric ton and annual production between 300 and 400 tons. That sounds impressive, but it’s a rounding error in a highly consolidated industry that produces around 250 million tons of ammonia annually. Minnesota alone imports up to 900,000 tons per year.
That’s a minimum $500 million annual transfer from Minnesota farmers to out-of-state fertilizer suppliers, most of which synthesize the stuff from cheap natural gas at sprawling facilities on the U.S. Gulf Coast, Brandon Isakson, managing director for industry with the St. Paul–based environmental nonprofit Fresh Energy, said in an interview. When prices are high, as they are this year, the outlay can exceed $1 billion, he said.
Anhydrous ammonia and its chemical cousin, ammonium (NH4), join nitrate (NO3) and urea (CO(NH2)2) as the three main nitrogen-derived fertilizers used in modern agriculture — often in combination. All three, along with nonnitrogenous fertilizers like potash and phosphate, are produced in massive “world-scale” plants that put out hundreds to thousands of metric tons daily. They depend on complex global supply chains to reach end users.
Right now, those supply chains are under intense pressure due to the U.S.-Israeli conflict with Iran. About one-third of the world’s urea and one-fifth of its ammonia pass through the Strait of Hormuz, which has been effectively closed to cargo traffic since the beginning of March. While the U.S. has plenty of domestic production capacity, U.S. Department of Agriculture data shows it still imported nearly 40 million tons of various fertilizers in 2025, including nearly 8 million tons of solid and blended urea. Prices for imported urea spiked when the shooting started earlier this year, underscoring domestic farmers’ tenuous relationship with global commodities markets.
Though WCROC has plans to grow the Morris facility, production likely won’t expand there in time to matter for the Hormuz crisis. Nor would it reach the kind of scale that could make a meaningful difference for Minnesota farmers, let alone other hydrogen-hungry industries.
“You’d like to be at 50,000 tons per year to be cost-effective,” Reese said.
But Reese added that he’s optimistic about a not-too-distant future where scaled-up ammonia production facilities dot the Minnesota countryside.
So are others involved with the project. Sameer Parvathikar, senior director of sustainable energy solutions at RTI International, an independent research institute that collaborated with WCROC, said at an April event celebrating the Morris system’s commissioning that it was an important milestone in a multiyear effort to stand up a new, cost-competitive industry from scratch.
“For those of us trying to push this forward from a technology perspective, you realize we have done stuff that actually matters,” he said, noting turnout that included higher-ups in the University of Minnesota system and a North Carolina–based developer looking at commercial applications for an ammonia production pathway that uses clean electricity instead of fossil gas.
At least some farmers here and elsewhere across the Corn Belt see the potential in local ammonia production, too.
In March, a southern Minnesota farming cooperative said it would partner with a Texas-based infrastructure company, a Minneapolis-based carbon credits registry, and the local power and water utility on a project that could produce most of the ammonia its farmers need within a few years. Located in Blue Earth County, the modular plants could pump out as much as 12,000 tons of ammonia annually, the companies said.
It would be one of the first larger-scale deployments of a “modular, green ammonia system that makes the local production and distribution of a critical raw material cost-competitive and more reliable,” according to Talusag, the company behind the technology.
Talusag says its approach lowers ammonia costs by up to 50% by freeing production from fragile global supply chains and using no raw materials other than abundant sun, air, and water. In theory, its plants can locate anywhere with an adequate power supply, whether that’s the middle of farm country or a remote mine site.
KC Graner, president and CEO of Truman-based Central Farm Service, agrees. He told AgWeek in March that farm prices have fluctuated by more than 300% in recent years. Prices can swing several hundred dollars per ton in a single season.
“Local production gives our member-owners a level of control and predictability they’ve never had before,” he said.
Talusag, Central Farm Service, and CleanCounts — the Minneapolis clean energy credits registry — are among more than a dozen members of the Minnesota Made Ammonia Coalition, which pushes for “policy and practical steps” to leverage the work being done at WCROC into commercial-scale green ammonia production.
The coalition’s top priority this year was securing an $8 million legislative grant that the Blue Earth County project’s backers said was needed to move forward. That didn’t happen, leaving its near-term fate uncertain. Tristan Peitz, Talusag’s head of business development, told the House Finance and Policy Committee in April that the facility would have ammonia ready for use in 2028 if it began construction in 2027.
Talusag already operates one green ammonia facility in the Upper Midwest, near the central Iowa town of Boone. Commissioned last spring in partnership with Iowa-based farming cooperative Landus and capable of producing 1 to 2 tons daily, it’s North America’s first “commercial, modular” green ammonia plant, Talusag cofounder and CEO Hiro Iwanaga said at the time. The company is building a plant in Eagle Creek, Iowa, about 50 miles north, that can put out 20 tons daily.
The Boone facility is registered with CleanCounts, which issues a bit more than 40 percent of all renewable energy certificates in North America, chief commercial officer Rob Davis said in an interview. Each certificate, or REC, equals 1 megawatt-hour of electricity, roughly what a typical Minnesota home consumes each month.
To qualify for the federal clean hydrogen tax credit today, producers have to prove that they procured enough renewable power to offset their energy consumption each year. Beginning in 2030, they’ll need to show the power was generated in the same hour it was consumed — a much stricter standard.
“You need a tech-forward registry to be able to meet these requirements,” Davis said.
CleanCounts has dozens of software developers working on a system that can accurately match hour-by-hour output from solar and wind farms across “the vast majority of corn country” by later this year, Davis said.
It’s a big job that’s worth the effort for CleanCounts, which Davis said earns 1 cent when a REC is created and another cent when it’s retired, or claimed by the end user. For cooperatives like Landus and Central Farm Service, the RECs themselves are worth buying because they lower the carbon intensity score, or CI, of their harvests. Biofuels produced from low-CI feedstocks have an easier time qualifying for the federal clean fuels tax credit, state incentives like Minnesota’s sustainable aviation fuel tax credit, and state blending mandates like California’s low-carbon fuel standard.
Lower CI is the impetus for other emissions-reducing investments across the agriculture sector, from pipelines to divert carbon dioxide captured during biofuels production to thermal batteries to replace gas- or coal-powered equipment at ethanol plants. In May, a POET ethanol plant on the Minnesota–South Dakota border commissioned a thermal battery system that charges off the area’s wind-rich power grid, significantly reducing the plant’s reliance on fossil fuels.
Like POET’s battery, and unlike traditional fossil-fueled ammonia factories, green ammonia plants easily flex their output to match variable wind and solar production on the power grid. The WCROC plant can go from 10% to 100% production in about two hours, according to Reese.
Flexible sources of demand on the grid could help Minnesota and surrounding states use renewable power more efficiently. Federal data shows the region’s grid operator curtailed nearly 6 gigawatts of wind power on blustery days — equivalent to six large nuclear reactors — for lack of local demand and transmission capacity.
Minnesota alone would need about 5 gigawatts to produce all its ammonia locally with current technology, according to a 2024 analysis by RMI, an environmental nonprofit. That’s a lot, but maybe not too much. Davis said some projections have curtailment doubling across the region by 2035.
Beth Soholt, executive director for Clean Grid Alliance, a Minneapolis-based nonprofit advocating for clean energy development across the Midwest, said that’s one reason why the region’s policymakers, electric utility leaders, and economic development boosters were enthusiastic about localized green ammonia production just a few years ago.
“Ammonia was the low-hanging fruit, people thought … and you hear every day how expensive the farming inputs are,” Soholt said.
Former President Joe Biden signed legislation authorizing generous tax credits for clean hydrogen production and approved seven regional “hydrogen hubs” to scale and match supply and demand for the stuff. Minnesota was one of several states in the Heartland Hub, where the administration saw abundant wind power supporting a thriving low-carbon fertilizer industry.
The Trump administration has been much less supportive. It ultimately spared the Heartland Hub and four others after earlier moving to dismantle the program, albeit with a shift in focus toward fossil-based production methods. In the meantime, green ammonia boosters’ enthusiasm has been tempered by what Soholt said were “sticky” questions about the cost of electricity and other inputs.
“It just comes down to economics — do these [facilities] pencil out?” she said. “But people have done a lot of work on them.”
For many rural communities and the electric utilities serving them, hope for a green ammonia boom has been replaced by hype around another seemingly endless source of power demand: data centers. Huge computing facilities like the ones Google has proposed near Rochester and Duluth can consume hundreds of megawatts of electricity, many times more than the WCROC and Talusag ammonia plants draw.
Data center loads are less flexible than ammonia plants, however, and they’re attracting increasingly stiff pushback from rural residents concerned about noise, air pollution and other quality-of-life impacts. In addition to being better at soaking up excess renewable power, ammonia plants may be better neighbors, Davis said.
“People are beginning to realize it’s a lot harder to build data centers near wind farms … but there are a lot of farmers growing a lot of corn out near wind turbines, and they definitely need fertilizer,” he said.
While farmers will claim the first batches of homegrown Minnesota ammonia, they’re not the only potential customers. At scale, the industry could provide secure, local supply of a critical input for advanced steelmaking.
Today, most steel plants in the United States use high-grade coal to purify iron in giant, superhot blast furnaces. But those facilities are aging, and eye-watering construction costs mean the U.S. is unlikely to build a new one. So steelmakers are looking ahead to direct reduction, a newer, more flexible process that doesn’t require coal. Most present-day direction reduction plants use natural gas as the reducing agent, but experts say the process can be adapted to run on pure hydrogen.
That could happen here in Minnesota — eventually. Mesabi Metallics, the company behind Minnesota’s first new iron mine in 50 years, says making direct-reduced iron is part of its long-term vision for integrated “green” steelmaking. It’s focused on getting its Iron Range mine open later this year and hasn’t given a firm timeline for a direct-reduction plant, but the prospect is tantalizing for Iron Range boosters hoping to keep the region’s primary industry competitive well into the future.
Reese said that would mark a more sustainable return to form for a state whose early economy was closely tied to the land.
“We have an opportunity here in Minnesota to follow the model we followed in the late 1800s — to take these natural resources and transform these industries,” he said.
Editor’s note: This story is the second in a four-part series on clean energy innovations within Minnesota’s industrial sector. The series is underwritten by Fresh Energy, which like all MinnPost funders does not weigh in on editorial decisions.
Editor’s note: This story was updated on June 9, 2026, to clarify the service provided by CleanCounts, which issues and tracks energy attribute certificates such as renewable energy credits.
This article first appeared on MinnPost and is republished here under a Creative Commons Attribution-NoDerivatives 4.0 International License.
It’s the first time that’s happened across an entire month, and it comes despite the Trump administration’s efforts to reinvigorate coal and hamper solar.
The U.S. just hit a big milestone: It got more power from solar panels than from coal plants in May.
It’s the first time that has ever happened across an entire month, and all the more notable given the Trump administration’s all-out push to revive the moribund U.S. coal industry.
Solar produced 12.8% of the nation’s electricity in May, a sun-soaked month that’s often among the best-performing for the clean energy source, per new data from think tank Ember. Coal power made up just 12.2%, a near all-time low, while natural gas dominated the mix at 37%.
For years, the power sector was the single biggest source of planet-warming pollution in the U.S., which is itself responsible for more historical greenhouse gas emissions than any other nation. America’s heavy reliance on coal, an especially dirty fossil fuel, drove those dubious distinctions.
In the late 2000s, facing hotter competition from increasingly abundant natural gas and a burgeoning renewable energy sector, coal-fired electricity output peaked in the U.S. It’s been all downhill from there for coal, which slipped from providing nearly half the country’s electricity needs two decades ago to just 17% last year. Emissions from the power sector have fallen accordingly, and now it’s the second-largest source in the U.S., after transportation.
President Donald Trump, who has insisted that the words “beautiful, clean” precede “coal” in all instances, is trying his best to stem the sector’s terminal decline. His administration has issued a slew of controversial emergency orders requiring aging coal plants to stay online — even those that are broken or otherwise unable to run. Earlier this month, it announced it would plow $700 million into the industry, both to patch up old plants and to build two new ones.
Coal actually did produce a bit more electricity last year than in 2024, but mostly because a combination of high power demand and elevated natural gas prices made the fuel momentarily more attractive.
Still, that doesn’t reverse the long-term trend. Every year, gigawatts of new clean energy come online in the U.S., because it’s cheap and comparatively easy to build. For several years running, over 90% of new electricity capacity built in the U.S. has been in the form of solar, wind, or batteries.
Meanwhile, the last new coal plant in the U.S. was completed back in 2013.
Take those two facts together, and it’s clear that solar is going to outperform coal many more times in the near future, and by wider and wider margins each time.
A worker shortage threatens to hold up America’s buildout of geothermal networks. These groups have a plan to address the problem, starting in Massachusetts.
Geothermal networks are taking off across the U.S., with roughly 30 such projects in various stages in Massachusetts, Colorado, and elsewhere.
These systems — which use electric heat pumps and thermal energy from underground to warm and cool buildings — are key to weaning communities off polluting fossil-fueled appliances and reining in home utility bills, supporters say.
But the buildout faces a major roadblock: There just aren’t enough qualified workers to drill the thousands of boreholes needed for the anticipated networks. The United States now has about 19,500 professional drillers working outside the oil and gas industry, according to the federal Bureau of Labor Statistics. This workforce would need to triple in size to meet the U.S. Department of Energy’s target, announced in 2022 under the Biden administration, of installing 17,500 geothermal networks by 2050, said Brock Yordy, president and co-founder of the Geothermal Drillers Association.
“This work is absolutely essential in New England and anywhere there are legacy heating systems that are fossil-fueled,” said Lawrence McKenna, chair of the Department of Environment, Society, and Sustainability at Framingham State University in Massachusetts. “But we don’t have the personnel to man the equipment.”
An initiative led by the nonprofit Home Energy Efficiency Team, or HEET, and the Geothermal Drillers Association aims to turn this obstacle into an opportunity. As many states attempt to reduce their carbon emissions, the natural gas industry is likely to slow down, leaving many experienced workers unemployed. At the same time, young people are entering a job market that, well, “sucks,” said McKenna. The anticipated growth of geothermal networks could create jobs that repurpose gas workers’ existing skills, pay well, and lead to career paths that can’t be undone by AI.
The vision is to create a nationwide network of Geothermal Drilling Centers of Excellence that will conduct training and research to develop the geothermal drilling workforce. Each center would offer programming tailored to meet the location’s specific needs.
“It’s a huge advantage to have something like this exist regionally, so you can pace the workforce development with the market development in a more cost-effective, reasonable way,” said Zeyneb Magavi, HEET’s executive director.
The first center is set to launch later this year in Framingham, Massachusetts, home of the country’s first utility-owned, neighborhood-scale thermal network. The training will build on the Geothermal Drillers Association’s existing two-week pre-apprenticeship program, which provides the groundwork for understanding the field, including the basics of geothermal science, the fundamentals of drilling boreholes, the differences between various drilling disciplines, and workplace safety and protocols.
This training provides a valuable on-ramp into the industry, but so far has been missing a major component: real-world drilling practice. Buying a drill rig was not in the budget, and leasing one proved difficult. After two days of safety training, students visit jobsites and observe work, but are not allowed to operate the drilling equipment.
“Right now, we can do the classroom work, and we go into the field and visit projects,” Yordy said. “But you can’t get the practical piece.”
The Framingham Center of Excellence will solve that problem. In April, the Massachusetts Clean Energy Center, an economic development agency, awarded the program $1.2 million in grants that will allow the initiative to buy a drilling rig and mobile classroom. This equipment will allow students to do hands-on drilling.
At the same time, Framingham State plans to launch a more intensive offering: a yearlong, six-course certificate program in geothermal science and engineering. Currently, the only comparable training operates out of a college in Canada, Magavi said. The Massachusetts program will delve into all the trigonometry and thermodynamics needed to understand how the systems work, and include several lab classes. The program will work with the Geothermal Drillers Association to give students access to hands-on training.
“They’re out doing the very work they’re going to do when they finish, with real equipment and real professionals in the field,” McKenna said.
Organizers are still figuring out exactly what the first Center for Excellence will look like. They’re reviewing possible sites for training and drilling practice within Framingham and nailing down the specifics of the partnership with Framingham State.
“This Center of Excellence is very much being collaboratively bootstrapped into existence, moving from our collective imaginations into reality,” Magavi said.
If the vision is realized, the benefits will reach beyond just the individuals entering new careers and the residents getting cleaner, more affordable heating and cooling, supporters say. A thriving geothermal workforce can lead to more widespread economic development.
“It’s not just about the jobs,” Magavi said. “Building the energy infrastructure of the future is an extraordinary development action.”
Corrections were made on June 11, 2026. The story misstated the access that students in pre-apprenticeship training have to jobsites and the topics to be covered in the Framingham State University certificate program.
The state’s Republican attorney general — a gubernatorial candidate — sued to stop the new Trump-backed smelter, which would double America’s aluminum output.
A power-hungry aluminum smelter planned in Oklahoma is facing a new legal challenge that aims to stop the massive project in its tracks.
Last week, Oklahoma’s attorney general sued to block Emirates Global Aluminium (EGA) and Century Aluminum from building the $4 billion facility, which is slated to more than double the nation’s capacity for producing aluminum from scratch.
Gentner Drummond, the state’s attorney general, said he took action to protect Oklahomans from the “anticipated public nuisance” he claims the smelter represents. Drummond is running to be the Republican candidate for Oklahoma governor, and the lawsuit has intensified debate about the project in what is becoming an increasingly heated primary race.
Drummond raised concerns that the facility would pollute the air and water and harm cattle and crops in Inola, the rural town in northeastern Oklahoma that is set to host the plant. Residents in Inola share those environmental worries, and local opposition to the smelter — which would be America’s largest if built — is mounting as developers get closer to starting construction this year.
The lawsuit also flagged the smelter’s enormous electricity appetite. The new facility is expected to require over 1 gigawatt of continuous electricity to operate — enough to power a city the size of Boston or Nashville annually. The attorney general claimed that this level of consumption will place “extraordinary strain on the regional grid” and threaten “the reliability and affordability of electricity for Oklahoma ratepayers.”
The developers are currently pushing to finalize a crucial long-term power contract for the smelter, which could draw from Oklahoma’s abundant natural gas and wind energy resources and solar energy potential.
Drummond further objected to the foreign involvement in the project: EGA, a state-owned enterprise of the United Arab Emirates, has a 60% stake in the smelter, while Chicago-based Century owns 40%.
However, the timing of Drummond’s June 2 filing has raised questions about his motivations, and it’s unclear how big a threat the legal action poses to the smelter’s prospects.
Drummond filed his lawsuit four days after President Donald Trump — who has championed the smelter — endorsed Drummond’s rival, former state Sen. Mike Mazzei, for the June 16 gubernatorial primary election.
Mazzei himself had strongly opposed the aluminum plant until very recently, criticizing the hundreds of millions of dollars in tax incentives the project is expected to receive from the state of Oklahoma, including power discounts. The project has also been awarded a $500 million grant from the U.S. Department of Energy.
On May 29, just hours before Trump endorsed him, Mazzei publicly reversed course. He announced on social media that he would strongly support the smelter as governor and would “work with the Trump administration to bring more projects like it to Oklahoma.”
Oklahoma’s outgoing Republican governor, Kevin Stitt, accused Drummond of “weaponizing” the attorney general’s office to retaliate against Trump. In a video message on Facebook, he framed the smelter as key to protecting America’s national security interests, given that China accounts for about 60% of the world’s annual output. Aluminum is used to make not only household products and construction materials but also fighter jets, warships, helicopters, and ammunition.
Drummond, for his part, has denied any ulterior motives. He said he filed his lawsuit in response to the developers’ air-quality permit application, which they submitted on May 19, the news site Oklahoma Watch reported.
“A primary aluminum smelter does not belong in a community’s backyard, and its emissions do not respect property lines,” Drummond said in his initial statement, adding that winds could carry pollutants into the surrounding northeastern Oklahoma communities.
Putting aside the messy governor’s race, the aluminum smelter will undoubtedly change the landscape in Inola, which hails itself as the world’s “hay capital” and is home to many thousands of heads of cattle. The industrial facility is set to span 350 acres along the Verdigris River, where every year it will convert raw materials into 750,000 metric tons of aluminum, not far from schools, homes, and farms.
Last fall, the climate advocacy group Industrious Labs conducted a statewide survey to gauge Oklahomans’ views on the proposed smelter. Some 62% of respondents said they supported the project. But proponents, opponents, and skeptics all said they had at least some environmental worries about bringing heavy industry like aluminum smelting to the state.
“We’ve seen bipartisan support for reshoring domestic manufacturing, and specifically aluminum — both the Biden and Trump administrations are prioritizing this,” said Annie Sartor, senior campaigns director at Industrious Labs. “But concern around local air and water pollution is also bipartisan. People are concerned about dirty industry coming into their neighborhoods.”
Traditionally, America’s smelters have spewed significant amounts of pollution, including fluoride and mercury, which can damage crops and livestock. They also release perfluorochemicals — potent and long-lasting greenhouse gases — and emit sulfur dioxide, which can harm people’s respiratory systems and damage vegetation. Smelters have discharged wastewater into rivers and streams, and they generate toxic waste as the lining in the smelting tanks breaks down.
EGA and Century claim the Inola facility will be significantly cleaner than existing U.S. smelters — the last of which was built in 1980. The companies are building the project through a joint venture named Oklahoma Primary Aluminum, which will use the latest version of technologies that EGA has been developing over decades.
“This facility is designed to be the most modern aluminum plant in the world,” Oklahoma Primary Aluminum said in a statement to Canary Media. On their website, the developers say the smelter will be “highly controlled, with multiple environmental safeguards in place,” including for filtering and monitoring pollution and reducing emissions and energy use.
Oklahoma Primary Aluminum also nodded to questions about the smelter’s enormous draw on the region’s grid. Developers have been negotiating a power agreement for more than a year with Public Service Company of Oklahoma, a subsidiary of the utility giant AEP. Any deal will need to be reviewed through a regulatory process overseen by Oklahoma’s public utilities commission.
“A key purpose of that process is to assess and minimize potential impacts on residential and commercial customers,” the developers said in response to the lawsuit. They added that EGA’s modern smelting technology can reduce electricity use by about a third for every ton of aluminum produced, compared with America’s remaining fleet of aging smelters.
Most U.S. grid operators already use OATI’s software. Now the firm wants to tap AI and data to boost transmission capacity — and it’s asking the DOE for funding.
A major grid-tech company is asking the Trump administration to fund a project it says could significantly boost the nation’s ability to move power around — without building a single new transmission tower or line.
Open Access Technology International (OATI) is a Minneapolis-based firm whose software is used by nearly every North American transmission grid operator to manage the flow of electrons. Now, it envisions developing new features for that software. Huge amounts of data, parsed by artificial intelligence, would be used to more accurately calculate how much power can run along power lines — providing both real-time estimates and forecasts days and weeks into the future. That intel would be automatically shared among neighboring grid operators, allowing them to make better decisions about how to run their networks.
If all goes to plan, OATI says the facelift could accomplish a 10% to 20% increase in capacity across participating systems by 2030.
OATI unveiled its scheme in a May proposal for an undisclosed amount of money from the Department of Energy’s $1.9 billion SPARK grant program. The program uses money from the 2021 bipartisan infrastructure law, in a somewhat rare example of Biden-era energy funding spared from the Trump administration’s clawbacks.
The company’s proposal is a kind of “grid-enhancing technology,” a family of hardware and software that could squeeze more capacity out of the nation’s increasingly congested grid. These solutions have the potential to save the nation billions of dollars in excess power costs by unclogging transmission bottlenecks that prevent cheap electricity, much of it from wind and solar farms, from reaching places that need it. That could help curb skyrocketing utility bills for households and businesses.
The problem in the U.S. today is that these tools are almost exclusively deployed as pilot projects on one power line at a time. To achieve the big savings, multiple utilities and grid operators will need to use this tech in a coordinated way across the country’s region-spanning transmission networks.
OATI — with its decades of data and vast existing connections across the power industry — thinks it can catalyze that sort of large-scale deployment. It’s already enlisted a sizable group of partner organizations that have agreed to implement the new software add-ons, among them the grid operators California Independent System Operator, New York Independent System Operator, and Southwest Power Pool; the utilities Dominion Energy, Duke Energy, NextEra’s Florida Power & Light, PacifiCorp, and Portland General Electric; and the electricity cooperatives Great River Energy and Lakeland Electric.
John Engel, OATI’s associate vice president of strategic marketing, noted the company would bring significant matching funds to the table to deploy its software.
“What we can do is across 95% of North America,” Engel said. “There’s a speed and scale there that’s unique — and the [Trump] administration has said they want fast, durable, and cost-effective solutions.”
One of the key goals of OATI’s proposal is to deploy a version of a technology called dynamic line rating, or DLR. Over the past 20 years, DLR has evolved from devices that clip onto power lines, to sensors on transmission towers that monitor lines via optics and electromagnetics, to software-only approaches — like OATI’s — that use weather and grid data.
All these different methods have a common purpose: to determine the constantly changing true capacity of high-voltage power lines.
Quite often, that true capacity is greater than the traditional “static” ratings assigned to power lines, which don’t take weather and wind speed into account. For example, breezy conditions can cool lines, allowing them to safely carry more electrons at the same time that wind farms are generating the most energy.
Armed with this knowledge, operators can dispatch higher levels of power flows across parts of the grid they’d otherwise have to curtail. In a 2024 report, the DOE estimated that widely deployed DLR could increase existing grid capacity by roughly 80 gigawatts, saving billions of dollars in transmission infrastructure costs.
DLR in the U.S. has been hindered by a fractured regulatory landscape and the fact that transmission-owning utilities earn money by investing in new infrastructure, not by installing technology that makes their existing grids operate more efficiently. But players in Europe have been using the tech in a systematic way for more than a decade. Belgian grid operator Elia has achieved an average 30% increase on its transmission grid using DLR.
OATI, for its part, already has some experience tweaking line ratings based on weather, said Kevin Sarkinen, the company’s chief operations officer.
Back in 2021, federal regulators ordered all transmission operators to start using ambient adjusted ratings — essentially, hourly ratings based on daily temperature forecasts — by July 2025. OATI’s platform has already integrated those ratings into its transmission capacity calculations. “Now we’re adding in the capability for the DLRs,” Sarkinen said. That will bring in additional real-time data, like cloud cover, heating from the sun, and, most importantly, wind speed and direction, which have a huge impact on power line capacity.
The U.S. hasn’t been standing still on DLR. Deployments in Indiana, Minnesota, New York, Ohio, Pennsylvania, Texas, Virginia, and other states have shown the technology can significantly increase capacity on individual power lines.
But getting more headroom on one line only gets you so far on a networked grid that must operate as a unified whole. As a 2019 DOE report put it, “DLR has the potential to expand the Nation’s power highway system, but the exits and intersections must be capable of using that new capability for it to be worthwhile.”
OATI wants to leverage its broad customer base to make such an integration possible, Sarkinen noted. It will work the real-time DLR data into its software suite, which 95% of North American transmission operators use to share information about their available capacity and to manage the flow of power across networks.
The firm also plans to leverage its AI-informed Genie platform to boost the usefulness of all these figures. It’s been deploying that tech with California’s grid operator over the past two years, Engel said, processing large amounts of data to quickly decide how to safely reconfigure systems when power plants go offline or individual transmission lines are overloaded.
In this new use case, OATI’s Genie platform “looks at the modeling and coordination of these grid operators, and applies some AI technology to these coordination processes to increase the accuracy of the grid,” Sarkinen said. The AI applications allow for “constant assessment of how accurate your calculations were” as well as forecasting “if you want to make capacity available tomorrow or next week.”
OATI and its partners hope to start turning these technology deployments into real-world grid capacity improvements by the third and fourth years of their joint project, Sarkinen said. That’s practically light speed in the world of transmission, where construction of a single line can sometimes take decades.
All this is easier said than done.
OATI may not get the DOE funding, although company executives said they plan to move forward with the initiative regardless.
And the project could face unforeseen technical hurdles and delays. The new features are still works in progress, and even though they are based on lots of data, dynamic line ratings are still just estimates. Utilities and grid operators will need to learn to trust the data for both real-time decisions and forecasts, since these organizations make commitments to transport energy hours, days, or even weeks in advance.
“We can’t perfectly predict the weather, and we have to integrate that uncertainty into how we operate the grid,” said Aidan Tuohy, director of R&D for transmission operations and planning at the Electric Power Research Institute, a nonprofit utility research organization that’s working on a range of grid-enhancing technology projects with partners including OATI. But the latest advances in AI are increasingly useful in “using past data to predict what’s going to happen,” he said, by cross-checking ongoing forecasts against historical data from grids operating under similar conditions.
A lack of confidence in these weather-based predictions is one of the main barriers to making the most out of DLR, said Georg Rute, CEO of Gridraven, a startup that’s deployed its technology across Finland’s national grid and relocated to Texas last year to support plans to expand in the U.S.
“What I hear from the engineers, who have a veto right at transmission companies to turn on DLR, is that they don’t have the confidence that the forecasts work,” he said. “That is the real blocker. It’s not so much the incentives or the regulation.”
But although sticking with the status quo may be simpler, all U.S. utilities and grid operators are under federal mandate to integrate grid-enhancing technologies into how they bring new power generation online and make long-term plans for expanding their grids — and to find near-term ways to manage strains caused by power demand from data centers.
Meanwhile, utilities are struggling to manage a “more complex grid, with more exchanges between regions, more data centers, more variable and distributed resources,” Tuohy said. “Having the data to make decisions is going to become increasingly important.”
A correction was made on June 10, 2026: This story originally misstated that OATI executives declined to comment on whether they would move forward with their grid-enhancing tech project without DOE funding. Executives have clarified they plan to move forward with the initiative regardless of whether it secures the federal funding.
The company’s Cartersville, Georgia, factory is the largest of its kind in the nation — and it just started producing the key solar panel component.
Qcells has officially begun commercial production of silicon solar cells at its factory in Cartersville, Georgia, the company said Tuesday. That factory is the largest of its kind in the country — and a long-awaited boost to the U.S. solar supply chain.
For five years straight, the U.S. power sector has built more solar farms than any other kind of power plant. In 2022, the Biden administration crafted industrial policy to ensure as many of those solar panels as possible were made in America. Previously, the U.S. solar manufacturing base had withered in the face of stiff competition from China — but the industrial revival effort worked. In just a few years, the U.S. has opened up enough factories to assemble nearly 70 gigawatts of finished solar panels, according to the Solar Energy Industries Association.
That’s well beyond what the U.S. installs in a year, but production of the cell — the high-value component that converts sunlight into electricity — has lagged far behind.
Previously, just three other companies made the component in the U.S.: Suniva can produce 1 gigawatt at its cell factory in Georgia, and ES Foundry and Silfab each can make 1 gigawatt in South Carolina. In a few months, Qcells will be able to manufacture 3.3 gigawatts at its cell factory, which would more than double the current operational U.S. solar-cell capacity.
“It’s a great achievement for an industry that had zero active cell capacity in the last couple of years,” said Scott Moskowitz, vice president of market strategy and public affairs at Qcells.
Qcells, once a German solar-cell maker and now a subsidiary of Korean industrial giant Hanwha Group, first announced the Cartersville project in early 2023, pledging to colocate production of four components of the solar supply chain: silicon ingots, wafers, cells, and modules. The module lines went live in 2024. The full facility was originally supposed to open that year, but it took longer to calibrate those more complicated processes. Currently, the full 3.3-gigawatt production of the four solar components is slated for the third quarter.
Another 22 gigawatts of cell capacity is under construction across the U.S., per the Solar Energy Industries Association, though that figure is constantly evolving. On Monday, Japan-headquartered Toyo said it would spend $357 million to add 1.5 gigawatts of cell production at its Houston module-assembly plant. ES Foundry is working to expand its factory to 3 gigawatts by year’s end. T1 Energy is building a cell fab outside Austin. Additionally, First Solar’s U.S. factories produce up to 14 gigawatts of cadmium-telluride thin-film panels, which generate electricity without needing silicon-based cells.
Crucially, potential manufacturing capacity does not equate to production. Silfab, for instance, temporarily closed its cell factory after it accidentally released potassium hydroxide and hydrofluoric acid in rapid succession in March. (State authorities found no impact to the surrounding community, including a nearby elementary school.) Compared with the largely mechanical work of robotically assembling all the pieces into a finished panel, etching silicon wafers into cells is heavy industrial work that involves potent chemicals and other cleanup concerns.
“You’re leveraging complicated science to create a solar cell that generates electricity,” Moskowitz said. “There are more steps to the process, and the steps are more intensive.”
The giant, L-shaped Cartersville site houses “four factories in one,” he noted. At one end, polysilicon gets melted into ingots, and the pieces move sequentially through the discrete steps until complete panels roll off the line at the other end of the building. Between this factory and the module assembly operation about 30 miles north in Dalton, Georgia, Qcells expects to employ 3,800 people in the region doing high-tech, robot-assisted manufacturing.
Developers who use domestically produced cells can more easily qualify for the domestic-content tax credit bonus. Qcells also earns a higher manufacturing tax credit for each cell that it makes. These policies arose in the Biden-era Inflation Reduction Act, which was intended to spur a U.S. manufacturing renaissance for clean energy. The Trump administration subsequently phased out the credit for installing solar projects after July 4, but projects can still claim the credits for four years under “safe harbor” rules.
Once the safe-harbored projects get built or fall through, developers will lose the major financial incentive to buy American cells and panels rather than look for the cheapest imports that can get past the U.S. tariff regime. Domestic production does, however, offer a potentially winning story for developers to tell to skeptical communities or political leaders. It also insulates their project timelines from disruptions in foreign trade, as seen during Covid, or the current surge in shipping costs linked to the U.S. war with Iran.
The future is hard to predict, but for now, demand for electricity production is higher than it has been in a generation. The tech giants building AI have become obsessed with “speed to power,” and it’s hard to imagine a faster way to achieve that than to order solar panels that arrive on a truck straight from the factory.
Can electric vehicles finally start working as backup batteries for homes and the grid? This 120-home pilot project in California is working out the kinks.
At first glance, Frances Bell’s home in Oakland, California, doesn’t look like a postcard from the EV-powered future. But if a new program takes off, it could be a harbinger of what’s possible for homes across the state and the country.
Sure, there’s a shiny new Kia EV9 in the driveway and a black charging cord that runs from the car to an EV charger on the side of her house. But that’s a pretty standard setup in California, the nation’s leader in electrical vehicle adoption.
What makes this EV and the charger special is that they don’t just draw power — they also send it back to both Bell’s home and the grid.
As the CEO of Bidirectional Energy, Bell is outfitting homes across California with the same Wallbox Quasar 2 bidirectional direct-current charger that’s mounted to her house. This year, Bidirectional Energy and Wallbox are installing the equipment at about 120 homes as part of a state-funded pilot program that offers participants rebates for two-way chargers. Bell’s household was among the earlist to enroll, primarily to test the technology firsthand.
Their goal: to establish rules of the road for city and county permitting inspectors and utility interconnection engineers to handle these installations, similar to the standards for regular one-way EV chargers and backup batteries.
“From my perspective, a DC bidirectional charger is essentially the same technology as a solar or battery inverter,” Bell said. And those technologies are straightforward for a household to install.
Bidirectional systems are not anywhere near as simple to adopt. Pilot projects have been going on for decades, and federal and state governments have been working with automakers, charging manufacturers, and utilities to standardize the underlying technologies. Nevertheless, no large-scale programs exist today to allow customers to send power from their EVs to the grid or their homes.
If companies like Bidirectional Energy and Wallbox can crack the code on broader adoption, it could unlock serious benefits to the grid and consumers. Vehicle-to-grid (V2G) applications can turn cars into cheap energy storage for the electricity system and vehicle-to-home applications (V2H) can turn their cars into batteries that can power their house, saving them money.
Bell is convinced that the larger scale of this California program will help push the technology out of pilot purgatory and into the mainstream.
“Previous bidirectional demonstrations were in the ones and twos,” Bell said. “When you get to 100 or more, you start to get to more standard processes. That’s how you start to scale.”
On a sunny May afternoon, Bell showed off her bidirectional charging system — and the benefits it provides.
The combination of Wallbox’s hardware and Bidirectional Energy’s software can actively draw power from the battery of a Kia EV9 to reduce a household’s costly utility bills, to send power to the grid to prevent rolling blackouts, or to power a home during an outage. The system isn’t available for use with other EVs yet, though the companies are in discussions with undisclosed automakers.
“If the grid goes down, this will just kick in. You don’t have to walk out here and switch it,” Bell said. Then she flipped a switch in the Wallbox power recovery unit, which connects the Quasar 2 to Bell’s electrical meter and the grid beyond, to mimic a power outage.
With a click, Bell’s home was being powered by the Kia EV9’s battery, which stores about 99 kilowatt-hours of energy. That’s as much as seven Tesla Powerwall batteries, and enough to keep a typical home powered for about three days, Bell said.
Next, Jessica Kwong, Bidirectional Energy’s senior software engineer, sent instructions from her laptop to the company’s software platform to curb grid power use to avoid high time-of-use rates. Bell opened the Bidirectional Energy app on her iPhone to track the shift in home power coming from the EV battery. Then she toggled to a screen that showed the money she’s saving on her utility bill.
“Every day, when I plug in my car, this number ticks up,” Bell said.
Finally, Kwong mimicked a demand-response event, when utility customers are asked to either send stored energy back to the grid or simply use less energy when the grid is under stress. The EV’s battery started delivering 12.5 kilowatts of steady power back to the grid — and earning money for the grid relief it was providing.
None of this is particularly groundbreaking from a technical perspective, said Bell, who’s worked at battery companies including Tesla and Fluence and as a grid planner for Northern California utility Pacific Gas & Electric. And after years of work from automakers, charger manufacturers, and software companies, a lot of progress has been made on setting the technology standards for bidirectional charging, she said.
That’s why this Bidirectional Energy and Wallbox project, funded by the California Energy Commission, is focused on more than simply proving the technology works, she said.
“We’re training some of the first installers, we’re getting the first interconnection processes established, and hoping to take that to other geographies.”
Bidirectional charging is an intuitive idea: Most cars spend most of their lives parked, which means that EVs are often sitting there with unused battery capacity that could be helping the grid, making money, or providing emergency backup services.
Lots of utilities are working on managed-charging programs, which ask customers to shift when their EVs pull power from the grid, whether to mitigate their contribution to peak power demand or to avoid overloading local circuits and transformers. That’s important, but it ignores EV batteries that could actively bolster the grid, not just reduce strain on it.
In California, the value of that latent EV capacity could be “an order of magnitude larger” than simply throttling EV charging, according to a 2021 study by University of California, Irvine, professor Brian Tarroja and Rochester Institute of Technology professor Eric Hittinger. It could also provide EV owners with thousands of dollars per year in utility bill savings and demand-response revenue, the report found.
Still, the approach has remained elusive — something of a holy grail for the EV industry.
Automakers have promoted these kinds of uses for years, from the earliest Nissan Leaf EVs to the now-discontinued Ford F-150 Lightning. Some automakers have designed their own vehicle-to-home connectors, as with the PowerShift charger from General Motors’ GM Energy business and Tesla’s Backup Switch for enabling Cybertruck Powershare mode. A growing number of EV-charger manufacturers make bidirectional-capable chargers that have been certified for use in California and in other states.
Many other states are pushing utilities to explore the concept, too, whether it’s using electric school buses as grid batteries or enabling homes to rely on plugged-in EVs for grid relief.
But California has set a goal of having 8 million light-duty EVs on its roads by 2030, making it ground zero for development via utility trials, state-funded pilot programs, and regulatory guidelines for streamlining bidirectional charger interconnections.
Wallbox, a Spanish company that does a lot of business in Europe, has seen a big uptick in North American sales in recent years, “especially when we talk about V2G,” said Oliver Waterhouse, the company’s director of strategic partnerships.
But injecting power from EV batteries to the grid “requires collaboration with utilities and grid operators,” he said — and while customers are eager to set up their EVs as backup batteries, “a lot of demand falls off when it takes 6 to 9 months to get an interconnection complete.”
Wallbox initially launched the Quasar 2 in partnership with Kia as a home backup system, he said. “Then Bidirectional Energy came in and said, ‘Let’s make it V2G as well.’”
One of the trickier tasks for the two companies has been getting the components of the bidirectional system to feel like a single streamlined experience for the customer, Bell said. To achieve this, the companies have been establishing the linkages between onboard EV-battery management systems, the controls embedded in the chargers, and the inverters within those chargers, which deliver power to the home and the grid, Bell said.
Industry groups and certification organizations have settled on a plethora of technology standards for handling those tasks. But every automaker and charger manufacturer may implement them slightly differently, which means each combination has to go through its own round of testing.
Automakers also need to make sure cars are charged when drivers need them to be. “First and foremost, you want your car to be a car,” Bell said. Bidirectional Energy’s software allows customers to set what time in the morning they want to be fully charged and establish limits on how much power can be pulled from their EV batteries, she said.
Getting utilities to trust that these underlying controls can safely send power back to the grid has been the next challenge, Waterhouse said. Wallbox has gone through these processes with all three of California’s major utilities, he said, “but when you submit interconnection applications, they all have different questions.”
This is where doing hundreds of installations, as is the plan for the second phase of the Wallbox and Bidirectional Energy pilot, can start to smooth things out, Bell said. Utilities have sent engineers to pore over every detail of the first installations done by Wallbox and Bidirectional Energy, she said. That’s pretty similar to how utilities used to treat conventional home batteries, she noted.
“For solar and batteries today, there’s no engineer that gets sent to the house,” Bell said. “Getting these first 120 right will be really key for the next hundred or thousand — or million.”
A correction was made on June 9, 2026. The story misstated that bidirectional charging systems can export EV battery power to the grid during an outage.
The Tumbleweed installation just went online in Kern County. It can store clean energy and discharge it for eight hours straight, a harbinger of what’s to come.
On June 1, the Tumbleweed project in California’s Kern County became the first major battery installation in the U.S. that can discharge power for up to eight hours at a time — twice as long as typical energy-storage facilities.
The U.S. power sector now builds more battery storage capacity than any other form of on-demand power, like gas, nuclear, or geothermal. But battery developers typically design their projects to discharge at maximum capacity for four hours before running out of juice; that’s what has made sense, so far, given equipment costs and market opportunities. Analysts have concluded that longer-duration storage is needed to cost effectively power the grid with clean energy 24/7.
Consequently, California regulators in 2021 ordered power companies to procure longer-duration storage as part of the state’s planned transition to zero-carbon energy. California Community Power, a consortium of local nonprofit power providers, issued a contract for Tumbleweed back in 2022 to fulfill this obligation.
“This was one of our first eight-hour contracts in the country for batteries, and now it’s one of the first projects online, and it’s a complex deal with a bunch of members coming together,” said Alex Morris, general manager of California Community Power. “It’s designed to be part of the clean energy mix, helping capture the solar and discharge that later when they need it.”
Granted, the system’s 125 megawatts of instantaneous capacity are modest compared with the multi-hundred-megawatt batteries getting built elsewhere in the West. But Tumbleweed is far bigger than the 6-megawatt, eight-hour battery installed in Nantucket in 2019 for a special-case island power role, and larger than the 50-megawatt, eight-hour battery that went live in Australia in May. Tumbleweed has finally delivered eight-hour storage at a meaningful scale to test what this emerging resource means for the grid.
The patch of inland Southern California that surrounds Tumbleweed resembles Texas, said Cody Hill, who leads storage development for Rev Renewables, which built the project. It’s a flat, scrubby desert that’s hosted ample oil production for decades and more recently turned into a hot spot for wind turbines, vast solar arrays, and batteries. Rev picked up a parcel there that was too small to fit serious solar capacity but just right for an energy-dense battery installation.
Rev built the site in two phases, first activating 125 megawatts with four hours of duration back in the summer of 2024. Ava Community Energy, the locally governed nonprofit that secures electricity for customers in Alameda and San Joaquin counties, paid for 50 megawatts to serve its capacity obligations. For two years, Rev used the rest of the available capacity as a merchant power plant, bidding into the markets run by the California Independent System Operator.
To convert this very regular four-hour battery into a groundbreaking eight-hour battery, Rev “literally doubled the number of battery boxes on the site,” Hill said. “Technology-wise, the differences are pretty trivial.”
Rev hired the same construction firm, Mortenson, to build both phases sequentially, so lessons learned during the first stage ensured that “the expansion went really smoothly,” Hill added. Now, Ava controls 50 megawatts with eight hours’ duration, and California Community Power can use 75 megawatts with eight hours’ duration.
Any grid needs power 24/7, and by law, California is working to provide that without burning fossil fuels by 2045. At the highest level, the state’s strategy is to build as much solar power as possible and add enough storage to spread that throughout the day (and then hope that a major floating offshore wind complex materializes sometime in the 2030s, but that’s another story).
At this time of year, California gets strong solar generation from around 8 a.m. to 6 p.m.; Tumbleweed can fill up on that very cheaply, given its proximity to the sun-drenched solar fields, and then push that clean energy back onto the wires for another eight hours, say from 6 p.m. to 2 a.m. That leaves six low-demand hours while most people are sleeping; California currently serves the 2 a.m. to 8 a.m. period with a mix of wind, nuclear, geothermal, hydropower, and some fossil gas. If this eight-hour battery format takes off, California would have a clear path to serving clean electricity for nearly all of a typical 24-hour cycle.
That’s the theory, anyway. California Community Power and Ava are deciding exactly how to operate their portions of Tumbleweed in California’s wholesale markets in order to fulfill their capacity obligations and maybe even generate savings for their customers. The real run-time data will tell the full story.
People generally agree that at some point between now and a 100% clean grid, renewables will produce such an abundance that they’ll effectively require longer-duration bulk storage to distribute that power through the day and night. But experts and grid planners have not formed a consensus on when exactly that tipping point will hit.
Regulators at the California Public Utilities Commission originally mandated the state’s utilities to start obtaining some long-duration storage by 2026, to figure out what it takes to build this new kind of project. Later, the commission punted its own deadline to 2031. This happens sometimes when investor-owned utilities, armed with vast capital budgets and legions of in-house experts, fail to deliver on deadlines they’ve known about for years. The scrappy teams at Ava and California Community Power plowed ahead with the project even as state officials took their feet off the pedal.
So now the eight-hour battery is online even though it no longer technically has to be.
The project wouldn’t make financial sense without the anchor contracts spurred by California’s long-duration procurement policy, Hill noted. In other words, the additional merchant market revenue from doubling the size of the battery wouldn’t justify the additional costs on its own. But the goal of the mandate was to start building things the grid will need soon, so the state doesn’t have to scramble to keep pace with a rapidly changing market.
“This is proactive and not driven by the short-term energy markets,” he said.
With the battery fully operational, though, the customers are going to make the most of the opportunity. California is already tapping batteries as the biggest power source for two- to three-hour stretches after sunset. Tumbleweed can keep that discharge going into the night. Batteries are very inexpensive to run, since their fuel can be low-priced midday solar power, and they have few moving pieces. As long as more-expensive gas-powered plants are setting the market price through the night, Tumbleweed can displace them with its cheaper, cleaner power.
Scores of entrepreneurs have raised billions of dollars from venture capitalists on the presumption that lithium-ion batteries — the kind used at Tumbleweed and nearly every other existing battery facility — cannot meet the needs of shifting renewables to round-the-clock energy delivery. In the last decade or two of trying to come up with an alternative, though, this long-duration startup sector has delivered a raft of bankruptcies and hardly any utility-scale projects.
Tumbleweed, by its very existence, suggests that all this investment in novel technologies may have been a massive waste — at least for the ones purporting to reach up to eight hours.
Hill said he takes calls from startups pitching new storage devices, but he chose lithium-ion phosphate cells from Chinese energy giant BYD as a bankable technology that was already in high-volume production. Lithium-ion, he added, keeps getting better.
“It improves along every metric, and it gets cheaper,” Hill said. “It is totally ready to be deployed at infrastructure scale today.”
That doesn’t preclude the potential for alternative devices to serve multiday storage, like Form Energy’s iron-air batteries and Noon Energy’s carbon-based system. At the 100-hour level, the material costs of lithium-ion look prohibitively expensive. But many startups launched to beat 2010-era projections for lithium pricing at four-, six-, or eight-hour durations, and they’ve now been overtaken before they ever got to scale.
If Tumbleweed can do eight-hour grid storage today, lithium-ion won’t stop there. It forces the question of how much further this tech can push with additional cost declines and improvements, if more regions realize a need for longer-lasting storage.
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