This story was originally published by Canary Media.

Last summer, when the Republican-controlled Congress took a wrecking ball to the Inflation Reduction Act, Tom Matzzie was pissed. Though some Republican members of Congress had written letters trying to save wind and solar tax credits, when it came time to vote, they nearly all fell in line behind President Donald Trump. The One Big Beautiful Bill Act passed with widespread Republican support, canceling a decade-long tax incentive meant to accelerate America’s transition to cheaper, cleaner energy.

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This story was originally published by Canary Media. It has been edited to conform with Corporate Knights style.

Europe’s increasingly hot summers come with a worrying trend. The air conditioning that the continent long eschewed as an American indulgence is becoming a necessity, and some of the nuclear reactors needed to run those cooling units are tapping out right as thermometers spike. This summer was especially bad: the series of extreme heat waves that roasted Europe, killing thousands and fuelling historic wildfires, also severely affected the rivers that provide water to cool thermal power plants such as nuclear stations.

In France and Switzerland, nuclear plants went offline as river temperatures rose, to prevent the discharge of warm water into sensitive aquatic ecosystems. In Romania, Hungary and Bulgaria, nuclear plants built along the Danube River either shut down or reduced output as drought dropped the water levels below intake pumps.

Critics of nuclear power have seized on the moment to challenge whether nuclear energy is as reliable and efficient as its supporters claim. “Strange that anyone would support new nuclear, which depends on cooling, in the face of an ongoing superlinear global temperature rise,” Mark Z. Jacobson, a Stanford University professor who has long advocated for replacing atomic energy with renewables such as wind, solar and hydropower, wrote in a post on X after France took 6.3 gigawatts of nuclear plants offline amid the heat wave.

A question of reliability

At the heart of the issue is the large supply of water that nuclear plants need to cool their reactors. The problem is most acute in Europe, where many plants rely on rivers – unlike in Asia, where most stations are built near the ocean, or in North America, where reactors more often have cooling towers that help avoid problems with overheated water supplies. Experts say that Europe’s situation has more to do with how its individual plants are engineered and that the flaws are fixable.

“There are multiple solutions to this,” says Madison Hilly, managing director of the nuclear consultancy Radiant Energy Group. But ​“if you don’t like nuclear, this is the annual occurrence that basically allows you to try . . . and say, ​‘No, actually, nuclear is not reliable and it can’t be built for a changing climate.’”

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The climate challenge for Europe’s nuclear plants is twofold. First, above-average river temperatures trigger environmental regulations that bar the release of water that’s too warm. Second, drought conditions mean that the water levels are too low for the plants’ intake pumps to work. Along the Danube, the intake pumps that pull cooling water into the plant weren’t constructed to handle the low water levels reached this summer. When these plants were designed and built between the 1970s and 1990s, ​“there was no awareness of the dramatic changes in river flow rates and temperatures that we are witnessing now,” says Jacopo Buongiorno, the director of science and technology at the Massachusetts Institute of Technology’s Nuclear Reactor Laboratory. Still, he says, ​“moving the intake is technically feasible, albeit expensive.”

“One has to put things in perspective. Even a severe heat wave like the one experienced by Europe this summer reduces the average capacity factor of these plants by only a few percent on an annual basis,” Buongiorno says. ​“And while all the attention goes to a handful of struggling facilities located on problematic rivers, the vast majority of nuclear power plants go through the summer heat without any issue. Nuclear plants remain the most reliable power generators on the planet.”

Making nuclear plants more resilient

The most obvious solution to water levels dropping below the intake pump is, as Buongiorno describes, to lower the equipment. It’s difficult to say exactly how much that would cost, since the renovation of the relevant components would amount to a bespoke engineering project.

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Repeated record-breaking heat waves cooked the European continent this summer, delivering the region’s hottest June on record. A simultaneous, though possibly related, drought shrivelled rivers to record lows. In addition to their impact on public health, the dual crises put pressure on Europe’s energy system: wind power struggled under stagnant conditions created by heat waves, and “thermal” power plants – nuclear, gas and coal plants – had to reduce their output as European waterways warmed and dried, taking away water used for their cooling systems.

Solar power proved the only major energy source that performed better than normal during Europe’s summer of extremes, experts found. When paired with batteries, it helped supply thousands of air-conditioning units during historic hot conditions.

Scientists are still trying to understand why so many recurring heat waves materialized this summer, but studies have found that individual heat events are more likely and more intense because of climate change. The intensity of the June heat wave that scorched Western Europe was roughly 200 times more likely in today’s fossil-fuel-warmed climate than it would have been two decades ago, one study found. As the continent continues to warm and Europeans install more cooling systems to cope  just 23% of households currently have access to or use air conditioning – experts say this summer provides lessons for the future.

Extreme temperatures in late June bumped up Italy’s power demand by 28% compared to the previous week, according to the energy think tank Ember. In France, that number was 14%. Electricity and natural gas prices spiked in evening hours as demand grew highest and solar generation ended, with some prices hitting their highest levels since the 2022/2023 winter gas crisis following Russia’s invasion of Ukraine.

As demand and prices were climbing, power generation in some areas was falling. In the United Kingdom, five gas plants reduced their output by a combined 2.5 gigawatts in generation because heat reduced their cooling systems’ effectiveness. At the same time, heat-induced low wind speeds halved the country’s typical wind farm generation in June.

Historic dryness dropped river levels across Europe: England and Wales reported their driest July on record, while water levels in the Danube River in Central and Eastern Europe reached record lows, exposing Second World War shipwrecks and prehistoric relics. Europe’s hydropower production hit its lowest July level in a decade, and multiple countries curtailed nuclear power generation as warm, low rivers threatened water supplies for cooling. France lost 18% of its nuclear capacity to “environmental factors” in mid-July, Ember found, extending a trend of summertime nuclear outages that has plagued the country in recent years. French nuclear plants often use river water as a vital component of their cooling systems, drawing the water in at natural temperatures and then discharging it back into the rivers slightly warmer. Because French law caps the temperature of this discharged water to protect aquatic life, plants must reduce cooling operations and related power generation when the intake water from rivers is already warm because of heat waves or drought.

But where these sources faltered, solar shone through. European heat waves tend to deliver optimal conditions for solar power: clear, sunny days. Europe’s solar panels produced 17% more power during the summer’s heat waves than they normally do, stabilizing the grid as afternoon cooling demand climbed, according to Ember. Battery systems helped deliver this solar power into the evening hours, when heat still lingered and air conditioners cranked to allow households to sleep.

“The next challenge is the evening period. Temperatures often remain high after sunset and AC demand can stay elevated, even as solar production declines,” says Walburga Hemetsberger, CEO of SolarPower Europe, an industry group. “This is why battery storage is becoming such an important part of the energy transition.”

For as much as this summer’s extreme heat strained Europe’s grid, the continent’s cooling demand has a lot of room to grow: about half of households in Italy and Spain have air conditioning, and a quarter in France – compared to 90% in the United States.

“There are places where we just can’t do without it now,” Marine Tondelier, national secretary of the Ecologist Party, said this June, a reversal in the party’s long-standing argument against air conditioning because of its greenhouse gas emissions.

France’s state-owned utility plans to spend more than $10 billion to adapt its nuclear and hydropower plants to warmer temperatures and lower water availability over the next 15 years, including investments in equipment that cools the water that nuclear plants discharge into rivers so that it complies with environmental standards. But adapting to that new demand could also take new generation and storage, especially as grids simultaneously increase demand from data centres.

Solar and batteries have already been growing at a breakneck pace across Europe, with 36 gigawatt-hours installed in 2025, a 48% increase over new additions the previous year. Battery installations saw their 12th straight year of growth in 2025, according to industry group SolarPower Europe.

“Extreme price spikes during heat waves are a blaring signal for regulatory changes that increase power system flexibility,” says Beatrice Petrovich, a senior energy analyst covering Europe at Ember. “Treating this summer as a turning point for energy storage would be an opportunity to remove existing barriers.”

This article originally appeared in Grist at https://grist.org/energy/heat-waves-europe-grid-solar-energy/.

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Governments are preparing to absorb a risk that highly profitable oil companies have declined to take. That is not a technical detail of project financing; it is the clearest signal yet of a fraught economic strategy for Canada’s near future – one that puts resource extraction at the centre of national development.

A strategy, not a project

On July 2, the federal government and British Columbia committed billions in public investment to liquefied natural gas development, mining and other extractive industries, and to expanding the Roberts Bank port terminal south of Vancouver, later identified as the marine terminus for the new Alberta pipeline. Later that day, the West Coast line was revealed. The following week, Alberta and Ontario proposed a second pipeline, also without a private proponent and also likely to require substantial public money.

Whether or not that second line is ever built, the sequence confirms that these are not separate infrastructure decisions. They are part of a broader commitment to an extractive economy: the federal Major Projects Office is now fast-tracking 23 “nation-building” initiatives worth well more than $130 billion across liquefied natural gas, nuclear, mining and transportation.

A bet the industry won’t make

Ottawa has formally proposed listing the pipeline as a “project of national interest.” Alberta’s submission puts the cost at $35.2 billion to $43.7 billion, excluding escalation and financing costs, and assuming regulatory savings. It would be built by a new entity jointly owned by Trans Mountain Corporation, Alberta’s Petroleum Marketing Commission and Pembina Pipeline, a Calgary-based company whose non-binding 10% stake is the only private participation. Taxpayers would carry the rest, and there is still no finalized financing plan.

The pipeline is also only part of the public bill. Add the Roberts Bank terminal at roughly $10 billion and the linked carbon-capture project at $16.5 billion officially, and more than $20 billion by recent estimates, and allow for overruns of the kind Trans Mountain produced, and the public commitment could exceed $100 billion – an estimate from market-oriented critics, not climate advocates.

The project includes an Indigenous equity purchase right, to be drawn from the two governments’ shares, but its size and timing remain unspecified. First Nations along the southern route say they were not consulted before the announcement, and 14 First Nations are challenging the fast-tracking law in court.

Canada has been here before: Ottawa acquired the Trans Mountain system in 2018 after private investors stepped back. The expansion ultimately cost about $34 billion, more than six times the original estimate.

The reluctance of industry is not hard to explain. Bitumen is among the highest-cost sources of oil, highly sensitive to price swings and exposed to declining long-term demand as decarbonization accelerates. The International Energy Agency expects global oil demand to peak by 2030, with supply capacity running well above it. With the West Coast line unlikely to be complete before the early-to-mid 2030s, the project risks becoming a stranded asset.

Companies are behaving accordingly. Through the recent price boom, the four largest oil-sands producers cut investment – to $15.9 billion a year across 2021 to 2024, down from $27.9 billion a year in the 2011 to 2014 boom – while sharply increasing dividends and share buybacks. Capital is being returned to shareholders, not committed to new production. If the industry believed in the economics of expansion, it would be leading the investment.

Who this economy is for

Ottawa and Alberta describe the West Coast line as the way to build a strong, prosperous, sovereign Canada. But the record of the last boom complicates these claims.

A report by the Alberta Federation of Labour and Canadians for Tax Fairness found that between 2021 and 2023, the oil and gas industry earned $135.2 billion in operating profits while paying $43 billion in wages – $3.14 in profit for every dollar paid to workers, up from $0.92 in the previous boom. The sector employs roughly 30,000 fewer people than in 2014. And the owners collecting those profits are largely not Canadian. The report estimates that the big four producers are 73% foreign-owned and 60% U.S.-owned, with an estimated $58 billion in dividends and buybacks flowing to foreign owners between 2021 and 2024.

An industry that produces more with fewer workers, invests less, and sends most of its returns abroad is a weak foundation for shared prosperity – and a strange candidate for one of the largest public commitments of the coming decade.

The rollbacks are part of the plan

You might wonder about the environmental safeguards in place, especially as the urgency of climate change is evident all around us. Projects on this scale face barriers under existing environmental rules. So, those rules are being loosened. Canada and Alberta signed a cooperation agreement to streamline and add flexibility to impact assessment; their implementation agreement commits both governments to regulatory frameworks enabling substantial oil-sands growth. The federal government is now proposing faster approvals, expanded pre-designated development zones, and a narrower scope for environmental assessment.

The retreat extends beyond permitting: over the past year, Ottawa has scrapped or weakened the consumer carbon price, the planned oil and gas emissions cap, the electric vehicle mandate, the clean-electricity regulations and the industrial carbon price. Deregulation and environmental rollbacks are not incidental to this strategy. They are what makes it possible – and they build higher emissions into it by design.

The environmental case offered in return is the multibillion-dollar plan to capture and store 16 million tonnes of carbon dioxide a year from the oil sands by 2045. The so-called Pathways project – designed by an alliance of five major oil-sands players – would itself require substantial public funding. Reducing production emissions is worthwhile and should be required of the industry. But about 80% of a barrel’s life-cycle emissions come from burning the fuel, not from producing, refining and transporting it – which is what carbon capture addresses.

Pathways is to capture six million tonnes a year by 2035, while the pipeline is sized to carry a million barrels a day – 365 million barrels a year, or about 157 million tonnes of carbon dioxide when burned. So the “decarbonized oil” the prime minister has invoked would, even if every commitment in the package is met, be oil whose emissions are lower by less than a 10th. In exchange, the companies get a slower rise in carbon-price stringency.

The path not taken

Capital markets respond not only to subsidies but to perceived direction. When governments commit to fossil expansion while delaying climate policy, they signal that Canada’s economic future remains anchored in extraction – shaping where investment flows, which technologies scale and which regions are seen as growth areas while eroding the policy certainty that clean industries need.

The contrast with other jurisdictions is stark. Across Europe, parts of Asia and especially China, governments are pursuing electrification strategies built on renewable energy, grid expansion, electric mobility and low-carbon industry. These are not environmental side projects; they are 21st-century industrial strategies designed to win in a decarbonizing economy. Ottawa’s recently proposed electrification strategy will be credible only if matched by fiscal and regulatory decisions of comparable weight.

Fiscal capacity is finite. Hundreds of billions of dollars committed over the coming decade to extractive infrastructure, nuclear development and military expenditure will press on everything else – healthcare, education, affordable housing, climate adaptation and the care economy, sectors already facing hiring freezes and service reductions even as capital commitments are made elsewhere.

Political capital is finite, too. Aligning closely with the governments of Danielle Smith and Doug Ford eases agreement on these projects while making a different course harder to take later. Pipelines built in the 2030s will still be seeking returns in the 2060s. That is the definition of lock-in, at a time when Canada is already off-track for its climate targets and when extreme heat, wildfire smoke, floods and drought are already damaging health, infrastructure and public finances.

A better bet

Canada does need an ambitious strategy for a low-carbon future – one that diversifies trade, strengthens economic sovereignty and builds at scale. And the same public investment and political capital could go to renewables, a national electricity grid, storage and efficiency, building retrofits, electrified transportation, a circular economy, climate resilience, the care economy and a just transition for the workers and communities that depend on extraction. All this builds value as the world decarbonizes, employs more people per dollar, and cannot be stranded by a shift in global demand.

Before Canada commits another generation of public money to the industries of the last century, governments should be able to explain why this is a better investment in the country’s future than the alternatives competing for the same support. So far, they have not.

Ricardo Grinspun is professor emeritus of economics at York University and a member of Seniors for Climate Action Now!

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​This story was originally published by Canary Media. It has been edited to conform with Corporate Knights style.

The U.S. Department of Energy is backing a major battery project to bolster Puerto Rico’s fragile electric grid – even as the Trump administration axes funding for key clean-energy initiatives across the U.S. territory.

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These profits are largely a product of supply constraints brought on by the war in the Middle East. With the Strait of Hormuz effectively blockaded, oil suppliers have rerouted shipments over land and through pipelines. The resulting supply shortages, constrained refining capacity and higher transportation costs have driven up oil and gasoline prices, delivering windfall profits for producers.

But companies aren’t using those profits to drill lots of new wells or explore untapped oil fields. Instead, they’re pocketing the cash and paying their shareholders, experts say. What was once an industry defined by the “drill, baby, drill” ethos is now defined by another term: “capital discipline.” It’s a phenomenon in which rampant drilling and production growth has given way to tightened belts and bigger payouts to investors.

Oil executives expected a weak financial year in 2026 as a result of a supply glut, but the closure of the Strait of Hormuz constrained oil production and allowed companies to charge top dollar for use of their refineries outside the Middle East.

“While we didn’t anticipate the current situation, we were prepared for it,” Exxon CEO Darren Woods said in a July call with analysts, according to The Wall Street Journal. “Despite the temporary loss of approximately 10% of our upstream production, we delivered exceptional financial results.”

Chevron executives offered a similar assessment. In July, chief financial officer Eimear Bonner told Bloomberg that the company didn’t adjust their production as prices rose. “We did not change any of our plan,” she said.

Finances first, politics later

The Trump administration’s focus on “unleashing” U.S. energy is running headlong into oil companies’ growing commitment to financial discipline. For instance, the administration assured the public that oil majors would leap at oil fields in Venezuela after the country’s leader, Nicolas Maduro, was detained in January. But drilling stayed low throughout the administration’s efforts to pry open public lands for oil development, and corporations have been wary and selective about new opportunities in Venezuela. Similarly, even as the administration has opened up U.S. federal lands for drilling, companies have shown only a lukewarm response. As Americans bleed cash at the gas pump, President Donald Trump has even accused oil companies of “making too much money” from the war, unable to otherwise influence them to significantly ramp up their production.

“Oil and gas companies respond more to financial incentives than they do to political signalling,” says Clark Williams-Derry, an energy finance analyst at the Institute for Energy Economics and Financial Analysis. “They’re going to be looking at their finances first rather than politicians’ demands.”

Lessons on discipline

If the U.S.-Israel war with Iran had occurred in 2012, oil companies might have seen the price spike as a chance to drill more wells. As fracking took off and prices rose during the 2000s, many companies tied their CEO compensation to production growth. Investors poured money into oil companies. But those days of aggressive production eventually ran into price crashes, especially after a Saudi-led coalition of oil-producing countries flooded the market with crude in 2014 and the COVID-19 pandemic sank prices again in 2020.

In the last five years, as investors soured on drill-happy oil companies, they embraced a new, more disciplined approach to capital expenditure. Investors wanted steadier returns. Rather than rewarding aggressive production growth, they pushed companies to focus on lower-cost drilling, restrain spending, and return more cash to shareholders.

“What is perhaps most telling about the corporate response to the turbulent forces impacting the oil and gas sector is just how little changed [in 2026],” Tom Ellacott, senior vice president of corporate research at Wood Mackenzie, said in a July press release. “Capital discipline has proved more durable than either the bears or bulls expected.”

Satisfied investors

Drilling in the United States, as measured by the number of oil rigs, has ticked up during the summer, Williams-Derry notes, but only after the president launched a war in Iran that drove up oil prices. As of June, it had recovered only to the rate recorded at the same point last year, according to data from Baker Hughes, an energy technology company.

In this new mode, Williams-Derry says, international oil companies have used wars, notably the conflicts in Ukraine and Iran, to boost their revenues so they can maintain large payments to their Wall Street investors. In times without price spikes, oil majors collectively took out debt as they paid their investors, their revenues unable to support the payments on their own, according to Williams-Derry’s internal analysis of their cash-flow statements. In an ironic twist, oil companies have benefited more from constraints on global oil production than from “unleashing” it.

The climate implications of this new ethos are complicated. Already, oil companies’ tight spending has drawn most of them away from renewable-energy investments. France’s TotalEnergies is the one supermajor that has charged ahead with its renewables business, though the Trump administration agreed to pay the company more than $900 million to cancel two offshore wind projects off New York and North Carolina. More discipline may also push companies to capture and resell the leaking natural gas from oil fields because maximizing revenue from existing wells has become more attractive than drilling expensive new ones. And this new attitude could keep oil and gasoline prices higher for longer, maintaining the appeal of electric vehicles and renewable-energy sources. (Chinese solar panel and EV exports to some countries have spiked during the war.)

A cash business

At least one analysis firm, Wood Mackenzie, believes disciplined oil companies could fall behind global demand, causing them to lose a share of the global oil market to nationally owned oil companies like Saudi Arabia’s, potentially changing the politics of energy security for Western countries.

Ultimately, however, this phase of “capital discipline” may be only temporary, Williams-Derry says. No oil company wants to be so disciplined that it begins to decline. Eventually, some growth will likely be necessary.

Still, those companies have proven as capable of benefiting from energy shocks to U.S. consumers as they are of relieving them, an important note for political actors hoping to rely on oil companies for energy security.

“At least for now, production of oil is no longer the way executives are getting paid,” Williams-Derry says. “What matters is their ability to generate cash.”

This article originally appeared in Grist. It has been edited to conform with Corporate Knights style. Grist is a non-profit, independent media organization dedicated to telling stories of climate solutions and a just future.

Austin Corona is an energy reporter at Grist.

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When Gerard Mullin decided to train in offshore wind, he didn’t know what to expect. But on his first long-term project in Massachusetts, he immediately relished the consistency of the work, the good pay and the novelty of labouring at sea. “I thought it was the best thing in the world,” he says.

In his first eight weeks working offshore, Mullin made more money than he had saved in the previous five years. But the industry was on shaky ground. Mullin had his bags packed for five weeks offshore with Empire Wind in New York when President Donald Trump’s stop-work order last year stranded him at home in Boston. Trump – who had railed against the industry in his 2024 election campaign – halted all future permitting last year and cancelled 12 offshore wind leases this spring and summer.

Thousands of workers like Mullin who were promised steady, well-paying careers in offshore wind now find themselves racing to secure the few positions left or returning to their prior work. Meanwhile, the supply chain that emerged to support offshore development has been left adrift, including in towns in need of a promised economic boost.

Those are less-discussed consequences of the political turmoil besetting the domestic industry, says Elizabeth Wilson, a professor at Dartmouth College studying offshore wind. “All of the promises of economic development that offshore wind was supposed to help support have evaporated,” Wilson says.

For Mullin, the change was shocking. “All of a sudden, the federal government is concerned with my work, and there’s nothing I can do to change how they view it,” he says. “Now there are things completely outside of my control, changing how I make a living.”

Trump has long scorned offshore wind, calling the 2012 project he unsuccessfully opposed near one of his Scottish golf courses “disgusting and inappropriate.” His administration, which has inaccurately described renewables as costly and unreliable as it tries to block them in favour of climate-altering fossil fuels, said his offshore wind policies are good for the economy and workers.

“President Trump has delivered on his popular promise to reverse the Left’s costly Green New Scam to lower prices for families and businesses and strengthen our country’s energy security,” Taylor Rogers, a White House spokeswoman, said in a statement. “By prioritizing the production of reliable, affordable, and secure energy sources, the President has restored U.S. energy dominance – creating thousands of good-paying energy jobs across the country.”

Tim Sullivan, who was CEO of the New Jersey Economic Development Authority until December, says he can’t comprehend the White House’s logic. “It’s the strangest thing: I’ve spent 15 or so years working in public-sector economic development; I’ve never seen people cheering for job destruction, particularly elected officials.”

As a pile driver, a specialized structural labourer essential to offshore wind projects, Mullin lived and worked on a ship five weeks at a time, followed by five weeks at home with his family. It was a schedule that suited him well.

Mullin joined offshore wind projects across Massachusetts, Virginia and New York. His employer, an international contractor, even brought him and other members of his union across the Atlantic for a wind project off the coast of Scotland.

Now, Mullin is back to the same type of onshore construction work he did four years ago, before he started with wind. “The writing was on the wall that this idea that I’m going to go to the same ship, five weeks on, five weeks off, steady – that just isn’t the reality anymore,” he says.

Opportunity lost

Joshua Grigsby, 42, took his son to Rio de Janeiro, Disney World and SeaWorld. Natalie MacDonald, 26, stopped living paycheque to paycheque. Others bought homes and started families.

Inside Climate News spoke with more than a dozen workers and union leaders who said the financial opportunities from the nascent U.S. offshore wind industry had been unparalleled. They saw long-term careers ahead of them. They feel that opportunity slipping through their fingers.

Anthony Hibbard was on one of the first boats that carried ironworkers to Vineyard Wind, off the coast of Massachusetts. What he found was “financial freedom,” he says, and he worked his way up to become a foreman on Coastal Virginia Offshore Wind.

After the Trump administration’s moves to scuttle the industry, Hibbard returned to local, onshore jobs in Portland, Maine, where he earns just one-fifth of what he did offshore. “I make enough to get by, but I like to be smart with my money, and I don’t have the scope to continue being smart with it,” he says. “It’s definitely – you can feel the difference, that’s for sure.”

The loss of offshore wind has had financial consequences for many union workers. While many were paid the same per hour as they were in jobs they could find onshore, they could work more than double the hours, and the company covered many living expenses. Grigsby made double to triple what he did onshore.

When Zaheer Razi, 28, joined the Piledrivers Local 56 union as a commercial diver, he transitioned into offshore wind as soon as he could. The logic was that it could be the anchor for people’s careers, he says – union leaders told workers to “set your roots down,” expecting more than a decade of steady work.

He’s still working on Revolution Wind near Rhode Island, but he knows it won’t last. “I’m probably one of the few guys that’s probably going to be working till mid-August, I believe, and then it’s really going to be silent for the next two or three years,” Razi says. “It is very frustrating, but it’s out of our control. Nobody could have really predicted it, but at this point, we’re just riding it out for what we can.”

Razi’s project is one of the five major U.S. wind farms that appear to remain on track despite the political backlash. But they are nearing completion and the permitting pipeline is all but blocked, meaning construction jobs will soon evaporate, according to multiple experts and union leaders.

Kris Ohleth, director of the Special Initiative on Offshore Wind, a U.S. policy think tank, attributes the lack of employment prospects to the political uncertainty that has stymied investor interest. “We’ve trained them, we’ve given them this great experience, they’re building their futures for their families, and now they have no projects to work on,” Ohleth says of the offshore wind labour force, “and that’s because of the lack of market confidence.”

At the time of Trump’s election, the market research firm BloombergNEF forecast that the United States would build 39 gigawatts of offshore wind by 2035, enough electricity to power 13 million homes. By the end of last year, the firm had downgraded that prediction to just six gigawatts, according to Harrison Sholler, a wind analyst at BNEF.

For Garrison Biel, an offshore wind diver, the industry’s decline has meant there are close to no employment opportunities left. “They’re more gigs than jobs,” Biel says. “They’re like short hitches, trying to wrap things up, tidy everything up. So I know people that are still working, but it’s not like how it was the first couple of years when it started, where that’s all you needed to do.”

He switched back to commercial diving around eight months ago because “what was available left offshore was slim pickings,” he adds.

Biel says the offshore wind industry was supposed to be reliable, with guaranteed time off to make up for the long periods away from home and the weeklong, 12-hour-per-day shifts. “Now, everybody that’s doing it, they get off the boat after working 7-12s for a couple of weeks and they go right back to work, because they don’t know if they’re ever going to go back out on a boat again,” he says.

Grigsby was able to buy a house with his money from offshore wind. His union’s business manager, John Dunderdale, says at least a dozen other members of Piledrivers Local 56 did the same. When these projects disappear, “you’re taking away their means of bringing back into the community,” Dunderdale says. “Now you have a member sitting home, collecting unemployment, because there’s no work.”

Benjamin Hawkins, who lives in Whitman, Massachusetts, says he made enough to upgrade his parents’ house and enjoy a new degree of “leverage” over his life. “It’s heartbreaking, because you wonder about what’s going to happen in the future with your money,” he says. “Offshore wind was the reason I could improve that life, so to have the president affect my life, just as an average American – it was not on my bingo card.”

“We sold this dream”

Offshore wind first began edging into the U.S. energy market in 2011, decades after it had taken off in Europe. An Obama administration study that year predicted that a vibrant offshore wind industry could help meet the nation’s renewable-energy needs while investing in infrastructure and creating “thousands of construction and operational jobs.”

The first U.S. offshore wind farm, Block Island, came online near Rhode Island in 2016, and states began offering financial incentives to drive development. The Biden administration made offshore wind a central priority in 2021, and from there, state and federal agencies geared up for a boom. The federal government sold leases to major international energy companies that began to see the United States as an attractive market, centred in the Northeast, Virginia and California.

Construction and permitting began in force not long before Trump returned to office with a promise to kill offshore wind. “That’s like somebody working on skyscrapers, and then somebody saying, ‘We’re not allowed to build any skyscrapers,’” Biel says. “It’s just a kind of crazy thing.”

No comprehensive or exact estimate of offshore wind-related jobs exists, but New Jersey’s Economic Development Authority estimated in 2022 that a typical project creates around 1,000 construction jobs per year and 100 lifetime operational jobs.

Dunderdale says that shutting down any project at that size and scale is a “huge hit,” both for the workers and their local economies.

Central to the fledgling domestic industry was the growth of training and certification programs, primarily through community colleges and unions.

Millwrights Local 1121, which operates across New England, met with developers in 2021 to start offshore-wind job training, which would cost $10,000 to $20,000 per person. It was worth it, says the union’s vice president and business manager, Andy Benedetto, because they had heard there would be “years’ and years’ worth of work.”

“We invested millions of dollars in training, more or less, and lots of hours went into putting all this together, and now that work is dried up for the foreseeable future,” Benedetto says. “We hope not too long, but we built this whole workforce, and we sold this dream to our members that if they get involved and get the training and go on this first project, then they’re going to carry over for the next 10 years.”

His union wasn’t alone. Public and private investments poured in to develop the new workforce. New York, New Jersey and Massachusetts led the Northeast with millions of dollars in grants to training and research programs.

Ironworkers Local 7, which operates across the Northeast, received $300,000 from Massachusetts in 2022 “to be ready for when the work comes,” says Grant Provost, the union’s Maine business agent. “And the work never really came.”

Dunderdale helped build the only U.S.-based school with heavy-lift training for Piledrivers Local 56. In total, offshore wind training cost the union about $30,000 per person, which he says was “an investment in the member.”

Esther Rosario, executive director of the labour coalition Climate Jobs New York, says unions that spent years preparing for the offshore wind economy have to reassess their plans. “We’re ready to work, we’re ready to build, we have the trained workforce – we need work,” Rosario says. “You can’t apprentice somebody into a job that doesn’t exist.”

Offshore wind was billed as a boon not just for the building trades but for the entire economy. Manufacturing would move to the United States and locals would fill those jobs. For port cities like Massachusetts’ Salem and New Bedford, or New Jersey’s Paulsboro, the loss has threatened years of expected economic progress.

In August 2025, Trump cancelled a $34-million grant to build an offshore wind terminal in Salem, which Frank Callahan Jr., president of the Massachusetts Building Trades Unions, said at the time put 800 construction workers out of a job. “It means fewer jobs, fewer career opportunities,” Callahan says in a recent interview. As an example of this loss, he points to Prysmian Group, an Italian manufacturer, abandoning plans in January 2025 for an offshore wind cable plant near New Bedford.

At one point, Salem County, New Jersey – one of the state’s poorest counties – was poised to gain 1,500 new jobs for its population of 65,000. “That’s a huge inflection point in that county’s economy that at this point is hard to see materializing any time soon,” says Sullivan, the former New Jersey official.

What’s next?

The thousands of offshore wind workers aren’t all suddenly unemployed. Most did some trade work before, and unions are used to moving members on to different projects when conditions shift. Still, Provost, the Ironworkers business agent, says offshore wind is a huge dent in unions’ portfolio of opportunities. “If we’re not building offshore wind, and we’re not building jobs like that, you got to get in on university- and state-funded projects, and that doesn’t keep everybody busy,” Provost says. “We’ve got a massive amount of unemployed people in Local 7 right now.”

And just because workers can transition doesn’t mean they want to. If he had a choice, Hawkins says, “I’d never work on land again.”

In addition to the financial opportunity, Razi says offshore wind was a once-in-a-lifetime experience. “We were meeting people from all over Europe, all over the world, and it was just a great environment to learn as somebody being in their mid-20s,” says Razi, who is finishing up an offshore diving job.

Living and working together consistently for weeks on end, crews became good friends, even vacationing together and learning each other’s languages. Hawkins jokes that every rigger knew how to curse in at least three languages. “It’s like being at the UN,” he says.

Benedetto says the millwrights he represents are eager to return to offshore wind, but they feel burned by political headwinds turning against them. “They did a good job,” he says, “and they’re bummed out that they’re middle-class workers being used as pawns.”

Last November, Mullin’s building in Boston caught on fire, and he lost everything he owned. Six weeks later, he says, he was able to buy a condo near the city. “That would not have been possible without offshore wind,” he says.

Mullin says he wishes others, especially young people entering the trades for the first time, could have the opportunity he did. “It’s just too bad because they were good jobs and people were happy with them,” he says. “And it really was just a fair day’s work for a fair day’s pay.”

Ajani Stella is a Dow Jones reporting fellow at Inside Climate News, based in New York City. Previously, he interned at amNewYork, covering politics, housing and crime. His reporting experience also includes immigration, labour and higher education policy issues. Stella is currently a junior at Georgetown University, where he serves as executive editor of the student newspaper, The Hoya.

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Grid-scale batteries are an important part of the energy system today, providing a mechanism to compensate for fluctuating renewable-energy supply by storing power when there is a lull in energy production.

For decades, the backbone of the electrical grid has been transmission infrastructure. But as more activities shift from fossil fuels to electricity, and demand for power lines from renewable-energy projects surges, the infrastructure is struggling to keep up. Instead of building massive new wires, experts say that batteries can help bridge the gap during peak hours when power is needed. Battery power is cheaper, faster to build, and can be deployed precisely where the demand is coming from, such as near an artificial intelligence data centre or electric vehicle factory.

The last five years have seen grid battery capacity boom as developers push for large utility projects all over the world, in the United States, China, South Africa, Chile, Canada and Australia, among others.

But the prolonged and increasingly extreme heat is also degrading batteries’ lifespans. According to a report by the International Energy Agency, most grid batteries deployed today cluster around two to four hours – a capacity insufficient to last through the night or support the grid during extreme weather conditions when demand reaches its peak.

With modern technology, grid storage is transitioning beyond the four-hour lithium-ion default toward long duration. These are some of the technologies that have moved past their pilot stage and are now being deployed for large-scale, long-duration storage.

Iron-air batteries

Form Energy is a U.S.-based company that has invented an iron-air battery technology capable of storing and discharging electricity for up to 100 hours on multiple consecutive days. This is a significant edge on lithium-ion batteries, which provide energy for shorter time spans, depending on the device in which they are installed.

The battery cycle of iron-air batteries operates like reversible rusting. During the discharge process, the battery inhales oxygen from the air and converts the metallic iron to rust. While charging, an electrical current converts the rust back into iron while the battery breathes out oxygen.

In October 2024, Form Energy began production at its first high-volume manufacturing facility in West Virginia, powering more than 75 gigawatt-hours of projects, according to Fast Company. In October 2025, it deployed its first commercial batteries, and earlier this year it announced plans to build what some called the “largest battery in the world by energy capacity” as part of a project to support powering a Google data centre in Minnesota.

The venture was developed in collaboration with the Xcel Energy utility, which is headquartered in Minneapolis. Xcel Energy will supply the power for this new data centre, while Google will cover the infrastructure and utility costs associated with its own electric service.

Form Energy anticipates delivering and shipping the first iron-battery modules to the data centre by the end of 2028. The company also expects to hit a yearly production capacity of 500 megawatts before the end of 2028.

Compressed-air technology

Compressed air is an ancient technology. Its first practical application emerged in the 1600s, and it went on to revolutionize construction and mining efforts by running pneumatic drills to bore tunnels through the Alps in the 1800s. In the modern age, companies such as Toronto-based Hydrostor have developed a system of compressed-air energy storage, or A-CAES (for “advanced compressed air energy storage”), to support off-peak electricity.

Founded in 2010, Hydrostor stores energy in rock caverns. It says that a single 500-megawatt, eight-hour A-CAES facility can store enough electricity to power a city the size of Boston for eight hours on less than 100 acres of land.

“At its core, A-CAES functions as a giant air battery,” Hydrostor’s chief technology officer, Chris Phebus, wrote in June. “When discharged, the cavern is flooded with water. To charge, compressed air is injected into the cavern, displacing water upward into a surface reservoir. It is 100 percent charged when the cavern is filled with air. To discharge, water flows back into the cavern, pushing the compressed air to the surface to generate electricity. The cavern operates at a fixed pressure band with the weight of the water column acting as a massive underground piston.”

Hydrostor’s facility in Goderich, Ontario, is the world’s first commercially contracted A-CAES project. The company is now scaling through its Willow Rock facility located in Kern County, California. In early 2026, Hydrostor signed a 50-megawatt offtake agreement with California Community Power (CC Power). This partnership enables the Willow Rock facility to supply and store energy for eight hours of continuous, emission-free discharge to six distinct local, non-profit public energy agencies.

The tech is part of a growing field known as long-duration energy storage, which is meant to increase the reliability of grids during peak demand or when renewable-energy generation lulls.

Carbon dioxide

Founded in 2020 in Milan, Italy, Energy Dome is a deep-tech facility adapting long-duration energy storage with its innovative battery technology of storing 2,000 tons of carbon dioxide daily in a dome at its primary hub in Piacenza.

When demand for energy peaks, Energy Dome treats carbon dioxide like a giant, reusable battery. When renewable energy is abundant, the facility uses this electricity to compress carbon dioxide into a high-pressure state. This stores the energy in the pressure of the gas. When the grid requires power, the system releases the pressure, which expands the carbon dioxide, generating electricity on demand. It doesn’t use lithium or other critical materials. The facility’s batteries have a much longer life expectancy than lithium-ion batteries.

In July 2025, Energy Dome announced a partnership with Google, using the facility’s carbon dioxide battery technology to provide carbon-free energy to power the electrical grids serving Google’s operations.

The firm is also developing its first U.S.-based 200-megawatt-hour facility in Columbia County, Wisconsin, in a partnership with Alliant Energy. Construction is slated for 2026 and completion is expected by late 2027. This project will “deliver enough electricity to power approximately 18,000 Wisconsin homes for 10 hours on a single charge,” according to Alliant.

Sodium-ion batteries

Founded in 2011, China’s Contemporary Amperex Technology Co., Limited’s technology consists of cheap, abundant sodium-ion batteries to reduce dependence on lithium.

This battery technology operates through “reversible sodium-ion movement between the cathode and anode,” according to Tycorun, a Chinese battery manufacturer.

In July 2021, CATL unveiled its first-generation sodium-ion battery. It was a test case to demonstrate that sodium-ion chemistry can realistically compete with lithium.

CATL is currently scheduling the delivery of its first sodium-ion energy storage system, which is expected to enter commercial deployment in September 2026.

ESS News says battery shipments are expected to  to reach one gigawatt-hour by the end of 2026 across four sectors: “battery swapping, passenger vehicles, commercial vehicles, and energy storage.”

Zinc-air batteries

In the bid to come up with longer duration batteries, a Toronto-based company is making waves: e-Zinc’s electromechanical technology stores energy in zinc metal. Unlike lithium-ion, e-Zinc’s technology incorporates zinc-air chemistry that provides 10- to 100-hour discharge at a cheaper cost than other battery technologies.

The World Economic Forum called it an “affordable, flexible and long duration energy storage solution” in naming it to its global list of 100 Technology Pioneers in 2023. Zinc is an abundant metal, with between 30% and 40% of it coming from recycled scrap metal. “e-Zinc’s solution can replace diesel generators for backup power for commercial and industrial customers or run on remote microgrids or at grid scale to firm up renewable generation,” the World Economic Forum noted.

In 2024, the company raised US$31 million in Series A2 financing and later that year opened a 42,000-square-foot pilot facility in Mississauga, Ontario. It has partnered with the California Energy Commission and Toyota Tsusho Canada to develop two commercial pilots that are expected to validate e-Zinc’s technology in customer-facing settings.

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This “clean and conventional energy superpower” construct pops up a lot in recent government speeches and announcements and was the framing for the prime minister’s “Forward Guidance: Canada’s Energy Future” video released just before Canada Day.

The argument is a double-barrelled one.

Let’s start with the clean part of the equation: looking into the future, the world will be powered by electricity, not fossil fuels. Electricity is inherently more efficient, and therefore cheaper for consumers. It’s also something that can be produced domestically at lower and lower costs, and something that we can control, freeing the Canadian economy from the volatility and unpredictability of foreign-caused oil price spikes.

Canada needs to lay track to prosper in this emerging Electric Age, but in the meantime the Carney government argues that the path to that cleaner future will be paved with the profits from expanded oil and gas production. Maximizing this profit requires curbing the industry’s greenhouse gas emissions so that Canadian oil and gas is the “greenest” option in the marketplace (something, it should be noted, that Canadian companies have been claiming for years). This is the “conventional” part of the argument, and there is no doubt, after last week, that the federal government is prepared to throw everything but the kitchen sink at it to make it a reality.

In fact, it appears Ottawa is even prepared to ignore an important aspect of the recently signed Alberta–federal memorandum of understanding related to the necessity of the new pipeline having a private-sector proponent. With none in the offing (which Canadian Climate Institute board chair Peter Nicholson predicted would be the case in a widely read recent article), the Alberta and federal governments are contemplating up to 90% public ownership.

What isn’t yet clear is the extent to which the federal government is prepared to put its money where its mouth is when it comes to sparking the “clean” side of its energy superpower ambitions.

The prime minister’s statements last week could not have been more categorical. Invoking the name of the visionary founder of Ontario Hydro, he said, “Our new plan will help build clean energy on a scale that would astound even Sir Adam Beck.” Later in his video, the PM underlined the broad societal benefits of electrification: “The path to affordability is electrification. The path to competitiveness is electrification. The path to sustainability is electrification.” He’s on solid ground with all of this, and recent Canadian Climate Institute research underlines this point.

Thus far, however, the rhetorical enthusiasm for “clean” has not been backed by on-the-ground support at a scale similar to what’s rolling out for “conventional” projects. The duelling announcements last week were a case in point. The press conference by Minister Hodgson referenced above was for a federal government contribution of $26 million for 17 clean-energy projects. A couple of days prior, Prime Minister Carney and Alberta Premier Danielle Smith announced that Canadian taxpayers may be on the hook for up to 90% of a $35- to $43-billion price tag.

Millions of dollars for “clean” versus billions for “conventional.”

The next few months will provide no shortage of key moments that put the federal government’s “clean” commitments to the test.

Will Saskatchewan keep burning coal in violation of a Harper-era policy? Will the dispute between Newfoundland and Labrador and Quebec over hydro development on the lower Churchill River be resolved? Will Alberta continue its de facto moratorium on low-cost renewables while building new unabated natural gas plants for artificial intelligence?

There will also be ongoing tests of the commitment to shrink the emissions of Canadian oil and gas production: it’s not clear at the moment whether the revised industrial carbon price will actually enable the long-promised Pathways carbon-capture project.

After last week, it’s clear that Carney intends to forge an entirely new way forward on climate and energy – one he views as more strategic and sustainable than climate policies of the past and aligned with a goal of net-zero emissions by 2050. In his own words: “The climate crisis is still with us and our commitment to fighting it is absolute.”

Achieving that goal requires deliberate policy choices. Net-zero isn’t a switch that can be flipped in 2045; becoming a clean-energy superpower requires steady, sustained effort. The most interesting question to watch in the months ahead is whether Carney’s government assembles a new climate and clean-growth plan with sufficiently ambitious detail to achieve the outcomes the prime minister has now personally set.

Rick Smith is president of the Canadian Climate Institute.

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