By Ian Munroe, Anna Berka and Christina E. Hoicka

The number of renewable energy projects that are fully or partly Indigenous-owned is growing quickly in Canada, and our new research suggests that their benefits reach far beyond reducing greenhouse gas emissions.

The number of such projects on traditional Indigenous territories and reserve lands jumped by more than 300 per cent between 2009 and 2020. Nearly one-fifth of the country’s electricity-generating infrastructure involved First Nations, Métis and Inuit partners or beneficiaries as of 2022.

Yet little is known about the impacts of these renewable-energy projects within the participating communities beyond the physical footprint of the construction.

We aimed to fill this information policy gap in response to a request from two organizations that work extensively with First Nations, the Clean Energy Association of British Columbia and the New Relationship Trust, which obtained funding from Natural Resources Canada to conduct research.

Together we conducted a study to paint a more complete picture of these broader impacts, interviewing knowledge-holders in 14 First Nations in British Columbia involved with 36 planned or operational Indigenous-led renewable energy projects.

We found that these projects employ “placed-based” approaches, often with a high degree of community engagement early on, and revenues often allocated to support their own culture, governance, ecology, support services and economy.

Transformational change

We found that when First Nations’ worldviews are centred and community control is enabled, broad social and cultural benefits result, providing greater self-determination.

As part of our research, we interviewed knowledge-holders from the West Moberly First Nations near Peace River, B.C. The nation has used wind-project revenues to support cultural camps and youth programs. As one knowledge-holder there told us:

“We are involved in it, and we are engaged in it. We are co-owners. And I know our Elders feel really good about hearing that. Knowing that we are not just sitting on the sidelines, while other people fill their pockets in our territory. And our community is doing that kind of stuff more and more. There is a connection there, right, because you are involved. More money is flowing to the community.”

In the Fraser Canyon region, the T’eqt’aqtn’mux (Kanaka Bar Indian Band), which has been affected by wildfires in recent years, has used proceeds from solar projects to reduce fire hazards and protect homes.

In the case of the Skidegate Band Council, we heard that revenues from a two-megawatt microgrid solar project would go toward funding Tll Yahda Energy, a partnership with the Old Massett Village Council to develop renewable energy projects in Haida Gwaii.

While these results demonstrate that a broad range of positive outcomes can flow from Indigenous-led renewable energy projects, the social and cultural impacts remain neglected in conventional energy practice.

An alternative to traditional energy planning

The Indigenous-led projects we heard about stand in contrast to typically used top-down decision-making, favoured by governments.

This approach is often characterized by public consultation that occurs after the decision of where to site the project has been made, often leading to local rejection of the project, and sometimes cancellation.

The bottom-up nature of the approaches we heard about hold important lessons that can enable widespread acceptance of energy transitions.

This is particularly relevant in B.C., where the provincial government is encouraging renewable energy projects to create economic opportunity and counter external economic shocks, including tariffs from the United States.

This policy push extends to the province’s more than 200 First Nations, with a 2025 procurement call that requires at least 25 per cent First Nations ownership of a project.

The B.C. government must also meet its obligations under the Declaration on the Rights of Indigenous Peoples Act (DRIPA), which aims to bring provincial legislation into agreement with the United Nations Declaration on the Rights of Indigenous Peoples.

The UN treaty requires that state parties enable self-determination and obtain free, prior and informed consent from Indigenous Peoples for projects that impact their lands or resources. Indigenous-led renewable electricity projects in B.C. could help meet requirements under DRIPA to provide pathways for First Nations to improve their economic and social conditions without discrimination.

The Indigenous-led approaches we studied provide a vehicle to support Indigenous communities and make progress toward the province’s decarbonization goals. They also hold valuable lessons for developing policy in other jurisdictions like Ontario, where the provincial government has pledged to boost support for the growing number of Indigenous energy projects.

The world is entering a new era in which energy independence will be more important. Our findings about Indigenous-led projects illustrate a radically different approach to growing the Canada’s renewables industry in a way that can provide energy and facilitate transformational social and cultural change.

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Contracted energy costs for wind and solar projects in Canada have fallen to half of what they were 10 years ago, new analysis shows.

“Now, they’re the lowest-cost form of new electricity generation,” write Pembina Institute electricity program manager David Pickup and senior analyst Will Noel, citing Ontario and Alberta grid operators and global analysts. The authors say the trend is expected to continue, with projections that wind and solar costs will fall another 25% to 50% over the next decade.

The cost decline comes at a good time, as demand for new electricity generation rises with the increasing adoption of electric vehicles, heat pumps, and other new technologies.

Plunging price trends make new wind and solar projects more affordable, and they can also be brought online faster than fossil fuel and nuclear power plants, Pickup and Noel add. “Getting more affordable electricity generation onto the grid— fast—underpins the competitiveness of the economy.”

Competitive procurement processes at the provincial level helped the wind and solar sectors expand by creating market certainty. The provinces that ran these procurements are now on track to bring online thousands of megawatts of renewable energy in the coming years. Quebec, for instance, has announced plans to develop 10,000 megawatts of wind and 3,000 megawatts of solar energy by 2035, and Manitoba is set to request proposals this March to procure 600 megawatts of wind. In Ontario, a technology-agnostic competitive bid process for up to 7,500 megawatts of new energy and capacity is under way, open to wind and solar developers, energy storage projects, and gas plants.

The Pembina analysts say provincial and territorial governments aiming to take advantage of low-cost electricity from wind and solar will need to plan their systems around a modernized grid.

“This means harnessing the latest technology—including interprovincial interties, demand-side measures, and long-duration energy

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The New England Clean Energy Connect (NECEC) line, a 1,200-megawatt high-voltage direct current (HVDC) transmission project, began delivering electricity on January 16, 2026, after nearly a decade of planning, regulatory reviews, legal challenges and construction delays. Designed to carry firm hydroelectricity from Hydro-Québec into the Independent System Operator-New England (ISO-NE) grid, the line is widely positioned as a key element in decarbonising the region’s power mix and lowering wholesale electricity prices.

Officials in Massachusetts and Maine welcomed the start of commercial operations with rhetoric emphasising affordability, reliability and climate benefits. In a press release celebrating the milestone, Massachusetts Governor Maura Healey said the project will deliver around 20 per cent of the state’s electricity needs and generate more than US$3.3 billion in net economic benefits through lower wholesale costs over the life of long-term contracts with Hydro-Québec.

“Today power is flowing to Massachusetts through the New England Clean Energy Connect transmission line,” Healey said, noting that the project has been completed through “planning, partnerships and perseverance.”

But just days after NECEC began commercial operation, the region was hit by Winter Storm Fern — a blast of Arctic cold that pushed both Canadian and U.S. electricity systems to the brink of peak demand. During the cold snap, power flows on the NECEC link abruptly stopped on January 24 and remained offline until January 26 after Québec restricted exports to meet higher domestic electricity demand as temperatures plunged.

The interruption meant that rather than importing electricity from Hydro-Québec, the ISO-NE grid actually exported power back to Canada, a reversal that lasted from the afternoon of January 24 through the evening of January 25.

That reversal highlighted the very challenge NECEC is meant to address: tight energy markets during winter months when natural gas pipeline capacity is constrained and demand for power and heat surges. During the flow interruption, New England turned to petroleum-fired generation, producing more electricity from oil than natural gas — a less carbon-efficient outcome and a throwback to older fuel sources that clean energy advocates hoped to displace.

Industry observers have been quick to point out that extreme weather conditions — the same conditions that stress grid reliability — also stress water supplies behind major hydroelectric systems, potentially limiting Québec’s ability to export power precisely when it’s needed most. Reporting from Energywire noted that some analysts view the outage as a test of whether cross-border links like NECEC can deliver under peak stress, especially as New England faces growing electricity demand and a shifting generation mix.

Hydro-Québec has acknowledged the interruptions but framed them as a function of record cold and extremely high demand within Québec itself, where much of the population relies on electric heating. A spokesperson for the company told power sector outlets that deliveries were expected to resume and emphasised contractual protections that mitigate ratepayer exposure to shortfalls.

Still, critics argue the early weather test underscores the need for a diversified portfolio of generation resources. Dan Dolan, president of the New England Power Generators Association, told E&E News that while NECEC can help reduce gas burn and emissions under normal conditions, “there is no single answer that will stabilize the system” during peak stress without a mix that includes local generation, storage, renewables and fossil backstops.

Proponents counter that NECEC’s strengths are structural and long-term. Analyses from project backers like Avangrid and Iberdrola — which built the line — point to tens of millions in tax revenue for host communities and savings for ratepayers, who benefit from stable, long-term pricing tied to hydropower contracts.

The project’s ability to reduce New England’s reliance on volatile fossil fuel markets comes as natural gas prices and price volatility remain high, particularly in winter, and as regional policymakers pursue ambitious decarbonisation goals.

Despite the early operational hiccup, NECEC represents one of the largest pieces of cross-border energy infrastructure in North America and a model of regional cooperation between Québec’s hydro-abundant system and U.S. utilities seeking cleaner, more reliable power sources.

Whether it will deliver under peak stress conditions remains an evolving story — one that utilities, regulators and market observers will be watching closely as winter continues and as the region’s energy transition accelerates.

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By Normand Mousseau and Roberta Dagher

Record forest fires, under-utilized agricultural residues like straw and husks and struggling sawmills have left Canada with an abundance of undervalued biomass. If carefully and strategically managed, this resource could become a powerful ally in the fight against climate change.

Canada’s biomass sectors are facing significant uncertainty because of political and natural disruptions. The forestry sector was hit last year by new American tariffs announced by the Donald Trump administration on Canadian forest products, bringing the total duties imposed on Canadian lumber to 45 per cent.

The agricultural and agri-food sector is also particularly vulnerable, since it exports more than 70 per cent of its main crops.

In addition to facing these political uncertainties, biomass sectors are increasingly experiencing the effects of climate disasters. In 2025, fires had burned 8.3 million hectares of Canadian forests by Sept. 30, making it Canada’s second-worst wildfire season on record. With climate change, extreme weather events like wildfires and droughts are likely to become more frequent and intense.

Change is accelerating and risks are mounting. For industries and communities that rely on biomass, this is the moment to define a long-term role in the climate transition.

Biomass resources

Canada needs to move towards a carbon-neutral economy, and the biomass sectors have a key role to play in this transition.

The availability of diverse biomass resources in Canada’s forests and agricultural lands, combined with new technologies to convert them into bioproducts and bioenergy, makes biomass a potential solution for reducing carbon emissions in several sectors, including industry, construction and all modes of transport (road, marine, rail and air).

Biomass can be part of climate change mitigation strategies. Used properly, it can replace fossil fuels and products, and help store carbon in different ways: in sustainable materials made from wood or agricultural residues, in the form of biochar that traps carbon in the soil or through bioenergy with carbon capture and storage (BECCS), which prevents carbon released during energy production from entering the atmosphere.

Several recent projects have demonstrated that interest in biomass feedstocks is high in many industries. In 2025, Canada’s first industrial-scale biochar plant was inaugurated in Québec, while the Strathcona refinery in Alberta will become Canada’s largest facility for renewable diesel.

The potential role of biomass becomes clear in the pathways now being modelled to achieve Canada’s climate goals. These analyses show that if a significant portion of available biomass were used differently, it would be possible to sequester up to 94 million tonnes of CO₂ equivalent per year through BECCS and biochar.

These results underscore the need for Canada to carefully plan new project developments and judiciously allocate biomass between its traditional and emerging uses.

Best uses for biomass

As we explain in a recent study, several factors influence the potential of biomass to reduce emissions, including the type of ecosystem where it’s harvested, the efficiency of its conversion, the fuels used and the products it replaces in the sectors concerned.

In other words, the climate benefits of biomass are not automatic: they depend on the choices that are made at each stage of the value chain. For example, if the processing or transport of resources requires a lot of fossil energy, or if the final product displaces a low-emission alternative, the climate benefit may be marginal or even negative.

Using biomass effectively requires understanding what resources will be available under climate change and their true potential to cut emissions. That potential depends not only on technological efficiency, but also on the cultural, environmental and economic realities of communities.

Still no long-term vision

Decision-makers must avoid working in isolation and take into account the collateral effects of resource allocation. Practices in biomass sectors, whether in forestry or agriculture, evolve slowly. Forests, in particular, follow long growth and harvesting cycles, so the choices made today will influence emissions for decades to come.

Yet, despite the importance of its resources, Canada has no strategy or vision for the role biomass will play in the transition to carbon neutrality by 2050.

Canada has developed several bioeconomy frameworks, including the Renewed Forest Bioeconomy Framework (2022) and the Canadian Bioeconomy Strategy (2019). However, there is still no comprehensive strategy that defines the role biomass will play in achieving a carbon-neutral future, either in energy-related or non-energy-related sectors.

Read more: Océans : les poissons, un puits de carbone invisible menacé par la pêche et le changement climatique

Canada can draw inspiration from its own Canadian Hydrogen Strategy to develop a similar strategy for biomass, based on integrated modelling of its potential in different sectors of the Canadian economy. There is an urgent need to adopt a realistic approach based on analyses at multiple scales — from regional to national — rather than on isolated sectoral targets.

Many players in the sector are stressing the urgent need to adopt a clear national strategy for the bioeconomy in order to provide more predictability to biomass industries in Canada. In an article in Canadian Biomass Magazine, Jeff Passmore (founder and president of Scaling Up) says he’s been waiting for Canada to develop a concrete national strategy for the bioeconomy.

Another article in Bioenterprise in 2023 argued that “one of the key areas needed to build the future of biomass in Canada is a solid, long-term national bioeconomy strategy, supported by industry and governments.”

Finally, a call to action from Bioindustrial Innovation Canada recommends revising the national bioeconomy strategy by setting measurable targets for interdepartmental and intersectoral co-ordination, with a clear road map for collaboration between industry and the public sector.

Biomass cannot be managed blindly. Its impacts vary depending on the region and uses. For future projects to truly contribute to Canada’s climate goals, a coherent national vision is needed now.

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By Jake Bittle

Since his presidency began last year, Donald Trump has embarked on an all-out campaign to destroy the nation’s nascent offshore wind industry. He has halted all wind lease sales in federal waters, issued stop-work orders for nearly-completed wind farms, and told oil industry executives that his “goal is to not let any windmills be built.” Last month, his Interior Department said it would terminate five major wind farms that are under construction in the north Atlantic Ocean, citing vague “national security” issues. These wind farms would together generate around 5.6 gigawatts of power, enough to supply around 4 million homes.

Trump’s actions have all but destroyed the U.S. offshore wind industry, which was already facing significant economic challenges during the Biden administration. While developers behind the terminated wind farms recently secured court orders allowing them to complete construction, other potential wind installations have been scrapped, and investors are retreating from offshore projects. Even as solar energy continued to grow at a rapid clip in 2025, wind saw virtually no growth in the United States.

That’s not just bad for the climate — it will also make it harder to keep the lights on in the U.S. northeast.  The nation’s densest region is counting on dozens of new wind farms to meet rising power demand; the stretch of coastal states from Maine to Virginia have collectively committed to buy more than 45 gigawatts of offshore wind power by 2040, almost ten times more than the five nearly-complete projects will provide. The region does not have many other good options for filling the gap. Without wind, residents of states like Massachusetts and New York will pay more money for dirtier fuel. The energy future of these states now hinges on whether they can tempt offshore wind developers back to a market that the federal government has just spent a year destroying.

“The market is at less than zero confidence right now,” said Kris Ohleth, director of the Special Initiative on Offshore Wind, an independent organization that supports the buildout of the industry.

The country’s first crop of major offshore wind farms has been a generation in the making. Developers have been trying to sink steel turbines onto the ocean floor since the turn of the century, but their projects collapsed amid high costs and community opposition. It wasn’t until the Obama administration that the federal government laid the groundwork for wind leases in federal waters near Long Island, conducting landmark studies that identified ocean zones where wind is strongest and environmental risks are lowest. That attracted major renewable energy developers like the Danish firm Ørsted and the Norwegian company Equinor, who leased territory in the north Atlantic and sketched out billion-dollar wind farms.

Even before Trump, these projects were on shaky financial ground. Ørsted and its peers signed power contracts with states including New York, New Jersey, and Massachusetts before the COVID-19 disruptions, but pandemic-driven shortages and the supply-chain chaos of Russia’s war on Ukraine drove up costs for construction materials like steel and copper. State governments also demanded developers put up more money for port improvements and onshore manufacturing jobs.

At the same time, developers encountered a wave of opposition from fishermen’s groups, conservative activists, and shoreline residents concerned about their ocean views. Prominent Republicans like U.S. Representative Jeff Van Drew of New Jersey championed these groups. The opposition filed several lawsuits that slowed down the permit process for a few major wind farms, with one suit even reaching the Supreme Court.

“These were new, first-of-a-kind-in-the-U.S. permits, and we were trying to improve the permitting process as we were going along,” said Elizabeth Klein, who led the Interior Department’s Bureau of Ocean Energy Management under former President Biden. (Klein said that by the end of Biden’s term the average environmental permit review took between two and three years, much longer than the more established procedure for offshore oil and gas.)

After the 2024 election, Trump’s sudden assault on the industry destroyed what little investor confidence was left. Even though several companies still hold leases that give them the right to build wind farms in federal waters, the industry has frozen in place. Other than the handful of major wind farms that are suing Trump for permission to finish construction, there are no large-scale projects in the pipeline. This freeze stands in stark contrast to the fate of solar energy, where installed capacity grew by 27 percent in 2025.

“In order for someone to get a commercial gleam in their eye, you need alignment with the federal government, the state government, and the market,” said an energy consultant who has advised offshore wind developers. “That’s gone, and it makes projects literally impossible. There’s no beating around it.” (The consultant requested anonymity in order to speak frankly given federal government backlash against the wind industry.)

Though the Biden administration focused primarily on the north Atlantic, it also auctioned federal wind leases in places like South Carolina, Louisiana, and Oregon. Klein believes that those states may now turn away from offshore wind given the market turmoil — and also because they have increasing access to alternatives like solar and cheap natural gas.

The Northeast does not have the same luxury. It is too dense and too cloudy to allow for large-scale solar farms, and other baseload power sources like nuclear will be hard to site, given population density and local opposition.

“There’s no other energy source coming to save them,” said Klein.

The situation is most acute in New England. In a report analyzing decarbonization scenarios, the energy nonprofit Clean Air Task Force found that offshore wind would have to make up almost half of all power generation by 2050 for the region to fully decarbonize. But it’s not just that these states need offshore wind to ditch fossil fuels. Experts also say that, with federal support, wind could be both the easiest-to-build and the most reliable power source for New England. That’s in part because communities across the region have mobilized against new gas pipelines and power plants. Furthermore, the region’s winter power needs will increase as more homes switch away from heating oil and begin to use electric heat pumps instead. Offshore wind turbines also fare much better in cold weather than power plants fuelled by natural gas and oil.

“For all the difficulties, building [wind] and interconnecting is easier than almost anything else you would do,” said John Carlson, the senior Northeast regional policy manager at Clean Air Task Force, which co-produced the report on New England’s decarbonization. “At the end of the day, this has to happen. There isn’t another option.”

The first prerequisite to a revival of the industry would be a cooperative federal government. Given how long it takes to build a wind farm, many experts believe that some form of permitting reform will be necessary to tempt investors back into the market. Clean energy lobbyists and oil industry groups alike have endorsed bills that would prevent presidents from pulling already-approved permits, but Congress has yet to pass one. The most recent negotiations collapsed after Trump’s attempt to terminate the five major wind farms. (Beyond the five nearly-complete wind farms, there are several more projects that have obtained most or all of their federal permits, and their developers may just try to wait out the administration.)

But there are other constraints, one of which is money. Industry insiders say global firms like Ørsted and Equinor have little desire to make further investments in the U.S. market, though they’re still holding on to their federal leases in windy sections of the ocean. There may be smaller developers who may want to take the leases off their hands. Before the current crop of massive European-built wind farms, smaller American developers tried to build minor farms along New England’s coast. These projects collapsed amid local opposition, but it’s possible that American energy developers may now want to get back into the fray. (Both Ørsted and Equinor declined to comment on their future investment plans.)

The problem is that these smaller companies will have a harder time borrowing the billions of dollars it takes to build big wind farms, and they may need to charge more money for the electricity they produce. Experts say that state governments in the region will likely need to grease the wheels for investment by putting up taxpayer money rather than asking developers to bear all the costs.

“The ability for the state to de-risk the investment environment is enormously valuable in terms of making Maine an attractive state,” said Jeremy Payne, a lobbyist for the government affairs firm Cornerstone and the former director of Maine’s renewable energy trade association. Payne said that the state could attract investment by training wind workers or coordinating with neighboring states on transmission corridors for wind power cables, taking some of the work off the developer’s hands.

Infrastructure is also a key constraint. The first wind projects required states to spend hundreds of millions of dollars on port upgrades and onshore construction. Massachusetts has spent well over $100 million to upgrade the old whaling port of New Bedford so it can serve as a staging area for massive wind turbine blades that can stretch the length of a football field. New York built a similar wind staging area along the harbor in Brooklyn.

But this infrastructure is still not sufficient to support wind development on the scale that the region needs. The New Bedford port is just a quarter of the size of an offshore wind terminal under construction at the port of Rotterdam in the Netherlands, and it may be too narrow to accommodate some large vessels. Massachusetts is planning to build a second facility in Salem — but Trump canceled a $34 million grant for that project, and its future is now uncertain.

The states along the eastern seaboard must invest now in order to make it easier for future projects to get off the ground. That includes upgrading transmission infrastructure, investing in workforce training, and expanding ports to accommodate larger turbines.

“We understand that whatever we’re doing now, we’re doing for 2029 or maybe 2030,” said Bruce Carlisle, the managing director of offshore wind for the Massachusetts Clean Energy Center, a quasi-state agency that supports the buildout of renewable energy. “We want to make sure we’re balancing state investment with realistic timelines.”

At the same time, Carlisle said states may not get all they originally wanted from wind projects. In the first go-round, states pushed developers to hire local workers for manufacturing and assembly, but Carlisle now says that the states may need to walk some of those requests back, because they will further raise costs for developers. Instead, states may need to let developers source labor and materials from Europe — which has built out far more offshore wind and therefore has a developed labor force and supply chains already — rather than demanding they build out a U.S. manufacturing base.

Given that President Trump has refused to issue new permits for offshore wind, it will likely be impossible for states like New Jersey and Massachusetts to achieve their current procurement targets on time. In the rest of the country, planned projects may never materialize. But offshore wind will still dominate the Northeast power grid in the long run, even if future projects are more expensive and require more state support. For all the blows the industry has taken, the region just doesn’t have good alternatives.

“I think it’s more a question of ‘when’ than ‘if,’” said Ohleth.

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By Gaye Taylor

As the Canadian oil and gas sector continues to automate, shedding 10,000 jobs in Alberta alone last year, and as the low-carbon transition accelerates, a new report urges Ottawa to adopt a “future-ready work force strategy” that better connects displaced workers with real opportunities.

When it comes to employability within a lower-carbon economy “most Canadian workers already possess many transferable skills,” an “occupational compatibility” that bodes well, writes C.D. Howe Institute public policy analyst Lin Al-Akkad in her recent report, Future-Ready Workforce Strategies and Matching Skills Model: The Energy Transition Case.

But skill gaps remain, alongside limited clarity on how green job demand will evolve. There is an urgent need to “map how workers can shift into emerging green industries,” said Al-Akkad, who expanded on the issue in an Hill Times op-ed.

“Imagine a pipeline of workers laid off from one sector, discarded like old parts, while next door a booming green industry sits idle, struggling to hire,” she wrote.

Oil and Gas Jobs Fall As Output Climbs

Alberta’s oil sector slashed 10,000 jobs in 2025 despite soaring production, the Edmonton Journal reports. “The industry is finding ways to do more with less,” Mark Parsons, chief economist at ATB Financial told the newspaper, identifying “driverless trucks in the oil sands” and other forms of automation as examples.

The Journal says the 2025 layoffs bring oil and gas employment closer to its 20-year average, following a hiring surge during the 2014 boom, but a recent analysis indicates the trend reflects longer-term operational changes. Last October, the Institute for Energy Economics and Financial Analysis found that in the United States, the industry’s shift toward hydraulic fracturing—a practice increasingly used in Alberta—has contributed to what it calls “long-term employment decay.”

In 2014, the U.S. oil patch required 53 workers to produce 1,000 barrels of oil equivalent per day. By 2024, after fracking became the dominant extraction method, that figure had fallen to 27.

Millions of New Green Jobs

By 2030, the energy transition is expected to disrupt 14.4 million jobs globally, with 12 million jobs created and 2.4 million lost, according to  [pdf] the World Economic Forum.

In Canada, an estimated loss of 1.5 million oil and gas jobs by 2050 in a net-zero world will be “far exceeded” by a gain of 2.2 million jobs in clean energy, according to a March 2023 report from Clean Energy Canada. The sector is projected to grow at 7% per year through mid-century.

But a smooth transition depends on deliberate policy choices. “To date, energy transition planning in Canada has been long on verbiage and aspiration, but short on concrete levers and commitments to shape the outcome of transitions in ways that benefit workers,” wrote [pdf] the Centre for Future Work in a recent report.

Mapping, Bridging the Green Skills Gap

A key recommendation in Al-Akkad’s report is a significant expansion of Ottawa’s Occupational and Skills Information System (OaSIS) database into a “centralized labour market intelligence platform.”

An expanded platform would map current and emerging green occupations by sector and identify “skills adjacencies and transferable competencies.” This in turn would help identify transition pathways that require “minimal upskilling,” improving the chances for oil workers to secure employment in a low-carbon economy.

The system would also link with training providers and employers to forecast job demand, inform curriculum development, and integrate international benchmarks from organizations like the European Centre for the Development of Vocational Training.

Training programs, writes Al-Akkad, must be innovative and aligned with decarbonization goals. Industries like low-carbon cement manufacturing, hydrogen production, and green construction each “demand specialized competencies, adaptable delivery models, and strong partnerships between industry and educational institutions,” she writes.

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By Rebecca Schulz, Senior Oil Market Analyst
Martina Lyons, Energy Analyst
Deniz Ugur, Consultant
Simon Bennett, Energy Technology Analyst
Courtney Turich, Energy Analyst

Geothermal energy harnesses naturally occurring heat found beneath the Earth’s surface to provide heating and cooling, electricity and energy storage. As global electricity demand rises and power systems place a growing premium on firm supply, geothermal energy’s ability to provide an around-the-clock, low-emissions source of power is attracting renewed attention. However, easy-to-access conventional geothermal resources are relatively rare and mostly confined to a small number of shallow geothermal hotspots globally, accounting for only about 1 per cent of global electricity demand today.

Next-generation geothermal technology developers are seeking to overcome these limits by drilling deeper and harnessing heat from hard-to-reach reservoirs. Operators can either circulate fluid through fractures that have been induced (through what is known as enhanced geothermal systems) or transfer heat to the surface through closed-loop circuits. These technologies are advancing quickly, potentially enabling economically-viable geothermal development nearly anywhere in the world. The IEA’s Future of Geothermal Energy report, published in late 2024, estimated that with continued technology improvements and reductions in project costs, next-generation geothermal could meet up to 15 per cent of global electricity demand growth to 2050.

Next-generation geothermal technology remains at an early stage of development. In general, geothermal projects remain among the most capital-intensive in the energy sector, with drilling and well costs often representing up to 80 per cent of total costs. Yet the past year has seen notable progress. Once considered prohibitively expensive, next-generation projects are now demonstrating measurable efficiency gains and more competitive drilling costs amid ongoing innovation, building investor confidence. These advances – arriving just as global electricity demand surges – have helped boost fundraising. Meanwhile, new supply agreements with data centre operators, along with the prospect of geothermal projects co-producing critical minerals such as lithium, are adding to the momentum.

Investment in next-generation geothermal has risen sharply

According to IEA analysis of new data – including exclusive data shared by Underground Ventures, a firm that invests in next-generation geothermal – financing for the sector reached nearly USD 2.2 billion in 2025, an 80 per cent increase year-over-year and up from just USD 22 million in 2018.

Mature conventional geothermal attracted strong investment as well. Funding for conventional geothermal power projects reached nearly USD 5 billion in 2025 – a four-fold increase from 2018 – while geothermal heating projects, such as those used for district heating, secured over USD 11.5 billion in 2025 alone.

In another sign of growing investor confidence in the sector, the global share of equity financing declined from 70 per cent between 2018 and 2020 to just over half between 2023 and 2025, as companies were increasingly able to secure debt alongside data centre power and critical mineral supply agreements. Debt-based financing now accounts for nearly 30 per cent, with financing terms expected to improve further as risks continue to fall.

While public funding is essential to incubate and reduce the financial risks of next-generation technologies, overall, its relative share in total financing is relatively low. Publicly-sourced grants are currently about 9 per cent of next-generation funding globally, down from 12 per cent between 2018 and 2020. The United States leads in the number of grants awarded, though the European Union provides the largest share of total public funding by value.

The crossover of oil and gas technologies and engineering advances continue to drive progress

The increase in financing has been underpinned by rapid technological progress, with new innovations and knowledge from other parts of the energy sector helping next-generation geothermal projects move closer to commercialisation. Recent advances in subsurface engineering – many of them driven by techniques pioneered in the shale oil industry – have been particularly important, helping to accelerate project development and reduce costs.

The US Department of Energy’s Utah Frontier Observatory for Research in Geothermal Energy (FORGE) has showcased the benefits of knowledge sharing from the oil and gas sector. FORGE drilled its first wells in 2021, and by 2024 had successfully demonstrated enhanced geothermal systems in practice, nearly doubling previous drilling rates from 8 meters per hour (m/h) to almost 15 m/h, with peak rates reaching nearly 26 m/h. FORGE collaborator Fervo, a US enhanced geothermal company that raised over USD 1 billion between 2022 and 2025, has achieved drilling rates of 30 m/h. Several companies have now demonstrated similar performance, including Mazama Energy’s recent high-temperature well construction demonstration at its 15 megawatt (MW) enhanced geothermal pilot in the US state of Oregon.

Resurgent demand for firm power, especially from data centres, is driving interest in geothermal

As technological advancements continue, geothermal’s ability to deliver reliable, around-the-clock baseload power is drawing growing interest. This is proving particularly attractive to the data centre industry, whose global electricity consumption is set to surge by more than 300% by the end of this decade – creating a group of  long-term paying customers that are helping push financing to new levels.

Geothermal projects, whether producing heat or electricity, usually sell their output through long-term contracts. These include heat purchase agreements or power purchase agreements with utilities or industrial customers, which provide stable income to facilitate debt financing. Until 2023, most next-generation geothermal project developers could only secure electricity price guarantees equivalent to solar and wind projects, or about USD 30-60 per megawatt-hour. But as electricity demand grows strongly in major markets – including in the United States, where data centres are helping lift power consumption for the first time in two decades – geothermal developers have begun securing significantly higher contract prices, in some cases reaching about USD 130 per megawatt-hour.

In 2024, Google and NV Energy signed a power purchase agreement for electricity from Fervo’s 115 MW Corsac project, while Meta committed to sourcing 150 MW from Sage Geosystems starting in 2027. This shows that companies are willing to pay a premium for clean, dependable power that can operate continuously, even for the first projects that may have the highest unit costs.

Critical material supply chains offer extra revenue potential

Efforts to build out critical mineral supply are also giving next-generation geothermal a lift. Geothermal energy projects can serve as a source of lithium, demand for which is expected to grow strongly in the next decade under all IEA scenarios.

Lithium that is dissolved in geothermal brine can be obtained via a direct extraction method. This process has the potential to require less water, land and energy use than traditional hard-rock mining, while providing developers with an additional source of revenue.

Geothermal projects currently under development in the European Union and the United States could yield 47 kilotonnes of lithium per year by 2035, which would meet 5 per cent of global demand based on today’s policy settings. Vulcan Energy’s Phase 1 Lionheart project in Germany, which fully secured financing in 2025, not only has offtake agreements with local district heating and industry consumers for power and heat, but also with Glencore, Stellantis, LG Corp and Umicore for lithium. Similar integrated geothermal‑lithium developments are actively underway across Europe and the United States, demonstrating the potential for this model to bolster growth.

Policy support remains crucial for next-generation geothermal to bridge from promising pilots to large-scale deployment

Recent advancements in next-generation geothermal are promising and the potential they open is enormous, particularly as global electricity demand continues to grow. Combining new drilling and materials technologies with real-time downhole sensor data has cut well costs by up to 30 per cent and may extend asset lifetimes beyond 25 years. Further cost reductions are anticipated as developers gain experience through construction and operations and as multiple players continue to compete.

Even so, large-scale geothermal projects face major challenges that could stymie future progress. These include exploration and upfront financial risks, as well as those related to execution. In general, next-generation geothermal projects remain too big for venture capitalists alone and too risky for established corporate energy players. This “missing middle” – also known as the “the technology valley of death” – is where governments traditionally step in. While some energy customers, primarily data centres, are now willing to pay a premium to see if the technology can work at scale, this demand alone appears insufficient to move the technology towards widespread commercialisation.

Given this backdrop, government support remains vital to the sector’s ongoing development. By setting targets and roadmaps that raise awareness, pursuing permitting reform, implementing risk-mitigation schemes, and ensuring power-market designs that make it easier to sell on the electricity produced directly to offtakers, they can help next-generation geothermal move through this “technology valley of death.” Encouraging examples include the US Department of Energy’s geothermal R&D funding, Germany’s new accelerated permitting law combined with drilling risk-insurance, and risk-mitigation facilities in the Philippines, Germany and East Africa. The EU’s forthcoming Geothermal Action Plan is another welcome step towards giving geothermal the dedicated policy attention it has long lacked, and can realise its full potential only by covering both conventional and next-generation geothermal technologies.

Delivering on the promise of next-generation geothermal everywhere will also require economic conditions that make projects both viable and scalable, alongside supportive policies, strong market design and investment incentives. Additionally, growth in the sector – especially growth that supports new demand sectors and sparks fresh innovation – will be amplified if companies can share their learnings through government programs or industry organisations, such as Geothermal Rising, Project InnerSpace, Clean Air Task Force Superhot Rock Initiative and the European Geothermal Energy Council.

The IEA will continue to provide data and analysis to support these efforts, including through a forthcoming publicly accessible global database on geothermal projects. This will provide comprehensive, up-to-date tracking of conventional and next-generation geothermal, alongside the broader assessment of progress via the Races to First data tool.

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Canary Media reports that the town of 2,000, once anchored by coal mining and a coal-fired power plant that supplied jobs and tax revenue for decades, is now drilling into subterranean thermal resources to heat and cool buildings in a new industrial and business park. The project is intended not just to lower utility bills for prospective tenants but to help counter the economic shock of the local coal plant’s scheduled closure in 2028, town officials and residents say.

“This area, with the exception of agriculture, was built on oil and gas and coal,” Dallas Robinson, a former town councillor and lifelong resident whose family’s excavation business once supported the region’s fossil fuel infrastructure, told Canary Media. “It’s hard to see people lose their jobs and have to move away.”

From coal dust to geothermal loops

The geothermal project is part of a broader business park on 58 acres designed to attract firms seeking low, predictable utility costs. To achieve that, crews are drilling boreholes about 1,000 feet deep and installing ground-loop piping that will transfer heat between the earth and buildings’ heating and cooling systems. The municipal utility being formed to manage the system will spread infrastructure costs over customer energy bills rather than charging large upfront fees.

Town manager Mathew Mendisco told Canary Media that the initiative was a “long-term bet” on geothermal’s potential to eliminate dependence on coal and natural gas while anchoring sustainable economic activity. Geothermal systems use less energy than conventional space-conditioning and offer stable performance in both winter and summer, advantages that local officials say make them well suited to the Rocky Mountain climate.

The development is expected to provide more than 70 jobs and deliver energy costs roughly 40 per cent below conventional heating systems, according to Mendisco. Early adopters of the park’s geothermal energy include an industrial painting company and a regional distributor, suggesting that new industries see value in Hayden’s clean energy story.

Broader context for geothermal in Colorado and the U.S.

Hayden’s initiative comes as geothermal interest is rising across Colorado and the U.S. Though direct use of geothermal for heating and cooling is more common, the state has also seen a broader push to support geothermal networks. In 2025, the Colorado Energy Office awarded millions in tax credits to projects in Vail, Colorado Springs, Steamboat Springs and other communities, reflecting state efforts to help small towns diversify energy sources.

Across the Mountain West, rural communities are navigating the decline of coal and traditional energy jobs, with residents in nearby Craig, Colorado noting the broader uncertainty as mines close and employment shifts toward new sectors. “People have to start looking beyond coal,” one resident told Colorado Public Radio, echoing a sentiment felt in places like Hayden.

Nationally, geothermal energy — including both shallow ground-source systems like Hayden’s and deeper enhanced geothermal systems (EGS) — is gaining attention as a firm, low-carbon energy resource. While wind and solar dominate renewable discourse, geothermal’s ability to provide continuous heat or power gives it a unique value in energy portfolios. Bloomberg has reported that new drilling technologies and supportive federal tax incentives are helping geothermal projects edge closer to cost competitiveness with traditional fuels and intermittent renewables.

Geothermal proponents include companies like Calgary-based Eavor Technologies, whose proprietary closed-loop systems are designed to deliver scalable, dispatchable geothermal heat and power without relying on naturally occurring hotspots — potentially broadening geothermal’s applicability well beyond volcanic regions.

Geothermal as part of post-coal economic strategy

Analysts say geothermal and other renewables could play a meaningful role in diversifying economies that have long depended on fossil fuels. Geothermal heat pumps, for example, are noted for efficiency and environmental benefits; NPR reporting underscores their climate friendliness and energy savings compared with conventional furnaces or boilers in residential and commercial applications.

In Hayden, drilling has already begun on about half the district’s geothermal loops, with completion slated by 2028. Officials say the system’s low operational cost and sustainability could make the town an example for other communities facing similar transitions.

“Geothermal’s here to stay and its workforce is going to get bigger,” Bryce Carter, geothermal programme manager at the state energy office, underscoring how local capacity building could support long-term clean energy deployment, told the Colorado Sun.

Experts say the success of projects like Hayden’s — and eventual advances in deeper geothermal electricity generation — will depend on continued investment, improved drilling technologies, and supportive policy frameworks at state and federal levels. But for now, a former coal town is demonstrating that heat from beneath the earth can offer a viable path toward economic revival and energy resilience that resonates well beyond its mountain borders.

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The report, “Renewable Energy in Canada: Current Status and Near-Term Developments,” outlines a possible expansion of more than 8,745 MW in renewable capacity by 2030. In addition to new wind — the bulk of the growth — planned capacity includes about 2,337 MW from solar and 202 MW from hydroelectric projects.

With these additions, renewables could represent approximately 72.9 per cent of Canada’s total electricity capacity by 2030, up from 70.5 per cent in 2025.

Provinces at the Forefront: Quebec, Alberta, British Columbia

The report highlights that three provinces — Quebec, Alberta and British Columbia — lead the slated growth in renewable power capacity. Quebec is projected to add 3,545 MW, sustaining its position as the province with the largest share of renewables. Alberta, with 2,413 MW of planned additions, ranks second; British Columbia follows with 1,635 MW of new capacity.

By 2030, Alberta’s renewable-capacity share is forecast to grow from 46.6 per cent in 2025 to 53 per cent. In British Columbia, the share would rise modestly, from 97.2 per cent to 97.6 per cent. In Quebec, which already operates with a high proportion of renewable generation mostly from hydroelectricity, the share is expected to edge up slightly from 97.5 per cent to 97.7 per cent by 2030.

Furthermore, the report notes a rising number of renewable projects owned by — or developed in partnership with — Indigenous communities, suggesting a larger role for Indigenous-led or co-developed clean energy projects across Canada.

Renewable Growth Outpacing Overall Capacity Expansion

Between 2010 and 2023, Canada’s total electricity generation capacity increased by 19 per cent. Over the same period, renewable electricity capacity expanded by roughly 30 per cent.

The CER’s latest projections indicate that renewables remain the backbone of Canada’s electricity-system growth, with the bulk of near-term new capacity coming from wind, followed by solar and small incremental hydro additions.

Drivers Behind the Forecast

According to the CER, several factors support the expected surge in renewables. Declining capital costs for wind and solar, emerging provincial and federal policy frameworks, and improving technology efficiencies have made renewables — especially wind — increasingly cost-competitive with conventional electricity generation.

The regulator’s forecast aligns with broader market-analysis from industry groups, which suggest strong growth potential for wind, solar and storage across major Canadian markets.

The growing involvement of Indigenous communities in project ownership and development is another trend noted by CER, reflecting a shift toward more inclusive renewables deployment models.

Implications for Canada’s Energy Future

If the forecast materialises, Canada’s electricity sector will draw even more heavily on wind power. That would reduce reliance on fossil-fuel generation and help the country progress toward national clean-electricity and decarbonisation targets — with wind at the core of the transition.

For provinces such as Alberta and British Columbia, which have traditionally relied more on thermal or hydro generation, the planned renewables build-out signals a shifting regional energy landscape. For Quebec, it reinforces its dominant position in clean power, while potentially offering new diversification in generation mix.

The expansion underlines the importance of transmission infrastructure, grid integration and planning — including updated regulation, investment, and grid upgrades — to accommodate new intermittent renewable capacity. The growing role of Indigenous-led or partnered projects may also influence community-level energy governance, benefit distribution, and First Nations participation in the low-carbon transition.

What’s Next

The CER report provides a snapshot of planned projects as of 2025. Actual delivery will depend on financing, timelines, provincial and federal policy consistency, supply-chain conditions, and permitting environments. Changes in any of these factors — along with evolving demand patterns and grid-system realities — could affect outcomes.

The regulator’s underlying datasets are publicly available, allowing analysts, policymakers and stakeholders to explore regional breakdowns and scenario projections. As renewables deployment accelerates, future CER updates will be key to tracking whether Canada stays on the projected path toward a largely renewable electricity system by 2030 and beyond.

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The International Energy Agency has always built its authority on policy. Its World Energy Outlook models are maps of intent: what governments say they will do, not necessarily what markets or industries are already doing. That worked when energy transitions moved at a bureaucrat’s pace. But today, the engine of change is industrial, not political. China — through sheer manufacturing scale and global electrification reach — is driving a transformation that the IEA’s scenarios struggle to capture.

The agency dropped APS from the World Energy Outlook 2025, saying that national commitments are too uneven to model reliably. Instead, it focused on the Current Policies and Stated Policies Scenarios. In effect, the IEA narrowed its gaze to a future far more friendly to oil and gas. A world that changes, but only as fast as formal policy permits. Yet the real world is moving faster, driven not by pledges but by production lines and industrial policy.

China: The Electrifier-in-Chief

Over the past decade, China has fused state planning, industrial finance, and scale to build the world’s most powerful clean-energy ecosystem. In 2024 alone, it sold 12.8 million New Energy Vehicles and exported 1.3 million more. It now accounts for roughly 60 percent of all new renewable capacity installed globally each year. Its solar panel manufacturing capacity will soon exceed the United States’ total electricity demand.

This is not just an energy story; it is an industrial one. Chinese automakers — BYD, SAIC, Geely, Changan — are flooding the Global South with affordable sub-$20,000 EVs, the ubiquitous two- and three-wheelers, bundled with charging networks, battery-recycling plants, and joint-venture factories. Beijing’s “industrial diplomacy” is electrifying emerging markets in the way Western aid once sought to wire them for fossil fuels.

The IEA sees policy diffusion as the main driver of energy transitions. China shows us something else: industrial diffusion. What the IEA calls “infrastructure limitation” in Africa, Southeast Asia, and Latin America is being dismantled by Chinese capital, logistics, and engineering. Electrification is becoming an export commodity.

The Physics of Scale

The story that the IEA’s model misses is not ideological; it’s arithmetic. Every doubling of cumulative solar production cuts costs by about twenty percent; every doubling of battery output by roughly eighteen percent. Those learning curves compound faster than politics can keep up. In 2010, a battery pack cost over $1,000 USD per kilowatt-hour; by 2023, $130. By 2030, it may hit $60. Solar module prices have fallen by over ninety percent since 2010.

Once parity arrives, substitution accelerates. Each ten million EVs on the road displaces around half a million barrels of oil demand daily. At projected adoption rates, that’s the equivalent of erasing an entire Saudi Arabia of oil demand within a decade.

This is the industrial feedback loop that OPEC, ExxonMobil, and the U.S. Energy Information Administration have consistently failed to model. Their scenarios assume hydrocarbons’ dominance and treat innovation as exogenous, a polite way of saying “someone else’s problem.” The IEA broke from that orthodoxy with the APS, which embedded learning curves and cost feedback. Yet by retreating from APS in 2025, the agency risks losing sight of the very dynamics that once made it the gold standard.

The Global South’s Leapfrog

Look beyond Beijing. Across the Global South, Chinese-financed solar farms, grid-stabilization projects, and electric-mobility programs are rewriting development logic. In Kenya, rooftop solar is offsetting diesel generation. In Brazil and Indonesia, low-cost Chinese EVs are scaling faster than policy incentives can track. In the Middle East, Chinese firms are co-building battery-storage complexes once thought decades away.

This diffusion matters because it shifts the geometry of the transition. For decades, energy modernization flowed North to South. Today, it runs in reverse. China’s overcapacity — derided in Western policy circles — is accelerating global deployment by forcing prices down. The IEA’s models, calibrated to declared policies rather than industrial momentum, under-represent this structural feedback.

Capital Flows Tell the Truth

Follow the money. Global clean-energy investment surpassed $2 trillion USD in 2024 and continues rising about 6–7 percent annually. Fossil-fuel investment, meanwhile, has plateaued or declined. Capital allocation now looks more like APS than like the new CPS (Current Policies Scenario), or even the still conservative Stated Policies Scenarios (STEPS). Markets are already betting that electrification, not hydrocarbons, defines the mid-century energy mix.

If the IEA’s CPS and STEPS project fossil demand growth into the 2040s, they describe a world that capital markets have already abandoned. APS aligns more closely with where investors are placing real money — grids, storage, batteries, renewables, and electrified transport.

The Model and the Machine

What’s unfolding is a divergence between two kinds of forecasting: the model built on policy, and the machine built on production. The model counts regulations; the machine multiplies learning. The IEA’s WEO 2025 treats electrification as an outcome of government intent. But China’s industrial ecosystem shows it is increasingly a self-propelling system — feedback, not fiat.

This is not to diminish policy. Without it, China’s ecosystem would not exist. But policy there functions as scaffolding for industry, not a ceiling. The IEA’s omission of APS makes sense within its institutional DNA; it reflects what can be officially promised. Yet it leaves unmodelled the real-world force now shaping the transition: manufacturing momentum.

The Consequences for Analysts and Policymakers

For analysts, the lesson is simple: the energy transition is being built, not legislated. The baseline for understanding it is no longer the pace of policy but the speed of industrial learning. For policymakers, particularly in countries like Canada still investing billions in hydrocarbon expansion, the implication is brutal. The world is electrifying faster than you can permit a pipeline.

The APS still fits the facts because it embeds the physics of feedback. The IEA may have stopped publishing it, but China is still proving it — one gigafactory, one grid, one EV fleet at a time.

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