The report highlights a rapidly evolving energy system, driven by rising electricity demand, continued reliance on natural gas, and the growing complexity of balancing affordability, reliability, and emissions reductions.

The CER’s Energy Futures analysis is not a prediction, but rather a series of scenarios exploring how Canada’s energy mix could evolve under different economic, technological, and policy conditions.

Still, one conclusion is clear: electricity demand is expected to surge, while natural gas remains a key part of the energy system—even as the country works toward lower emissions.

That finding aligns with a growing body of industry and policy analysis pointing to the same dual trend.

Electricity demand in Canada is rising quickly, driven by electrification of transportation, industry, and buildings. A recent industry report described the situation as requiring Canada to “build big again,” warning that the country may need to dramatically expand its grid to keep pace with demand growth.

At the same time, reliability concerns are emerging. A North American reliability assessment cited by Global News found Canada’s power grid is under increasing strain, with demand expected to outpace new supply in several regions later this decade.

Against that backdrop, natural gas is expected to continue playing a significant role, particularly as a flexible source of power generation that can support intermittent renewables like wind and solar.

Canada’s broader energy landscape is already moving in that direction. Federal data shows renewable electricity is growing, but oil and natural gas remain foundational to the economy and energy system.

The CER report suggests this dual-track evolution—more electricity, but continued natural gas use—will define Canada’s energy transition over the coming decades.

That reflects a broader shift in how policymakers and industry are framing the transition: not as a simple replacement of fossil fuels, but as a more complex transformation of the entire energy system.

Recent federal policy signals point the same way. Ottawa has emphasized the need to invest in grid infrastructure and energy systems to maintain affordability and reliability while transitioning to lower-carbon sources.

The challenge, analysts say, is scale.

Electrification alone could require doubling or even tripling parts of Canada’s electricity system, while maintaining reliability during extreme weather events and peak demand periods. At the same time, natural gas infrastructure continues to expand in some regions to meet growing demand and support economic activity.

This creates a tension at the heart of Canada’s energy future.

On one hand, electricity—particularly from low-emission sources—is expected to do much of the heavy lifting in reducing emissions. On the other, natural gas remains critical for reliability, industrial use, and export opportunities.

The CER’s outlook underscores that both trends are likely to unfold simultaneously.

It also reinforces a key message for policymakers: the transition will require significant investment, regulatory reform, and coordination across provinces and sectors.

Canada’s energy system is already diverse and regionally fragmented, with provinces relying on different mixes of hydro, nuclear, fossil fuels, and renewables. Integrating these systems—while expanding capacity and reducing emissions—will be a major undertaking.

The CER’s modelling highlights the uncertainty involved. Long-term energy forecasts depend on assumptions about technology costs, climate policy, global markets, and consumer behaviour, all of which can change rapidly.

Even so, the direction of travel is becoming clearer.

Electricity is poised to become the backbone of a lower-emissions economy. Natural gas, meanwhile, is expected to remain an important—if evolving—part of the mix.

For Canada, the question is no longer whether the energy system will change, but how quickly—and whether the country can build the infrastructure needed to support that transformation.

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The IEA’s annual Electricity 2026 report — released February 6 — finds that world electricity demand is set to grow by more than 3.5 per cent annually on average through the end of the decade, more than two-and-a-half times faster than overall energy demand. The report underscores that this surge is reshaping power systems around the world and accelerating what the agency calls the “Age of Electricity.”

IEA Director of Energy Markets and Security Keisuke Sadamori said the forecast reflects a fundamental transformation in how people and industries consume energy. “Meeting this demand will require annual investment in grids to rise by 50 per cent by 2030,” he said, adding that expanding system flexibility — including storage, demand-side management and market reforms — is equally critical.

Growth driven by electrification and digitalisation

The report identifies multiple drivers of rising electricity use. The global transition to electric vehicles, widespread adoption of heat pumps and air conditioning, and the burgeoning infrastructure for digital services and data processing all contribute to demand growth.

Independent analysis by Axios highlights how data centres — particularly those serving artificial intelligence and cloud computing — are emerging as some of the fastest-growing sources of U.S. power demand, with projections showing these facilities could account for roughly half of increased U.S. electricity consumption through 2030. This reflects a broader global trend in digital electricity demand.

Moreover, the expansion of electrification in emerging economies — especially China and India — is expected to account for the bulk of global demand growth over the next decade, reaffirming long-standing IEA forecasts that these regions will drive power sector expansion.

Renewables and supply mix evolution

The rapid increase in demand is being met largely by low-emissions sources and natural gas. The IEA report shows that renewables, bolstered by record solar and wind deployment, and nuclear power are together set to generate about half of global electricity by 2030. That would mark significant progress toward decarbonising power systems, even as natural gas output expands to meet demand and coal’s share declines.

Despite these gains, global electricity generation from fossil fuels is not disappearing in the near term, and utility planners are being challenged to integrate variable renewable output with reliable supply across regions. Bloomberg’s analysis of future grid capacity needs notes that integrating high levels of renewables without additional grid flexibility and storage creates technical and economic challenges that could slow emissions reductions.

Grid investment and flexibility imperative

A central theme of the IEA report is the imperative of modernising and expanding electricity grids. Existing infrastructure — much of which was built in the 20th century — was not designed for the scale and variability of today’s power systems. The agency warns that grids could become the “weak link” in clean energy transitions unless policymakers and investors act quickly.

Current grid investment levels lag behind the pace of renewable deployment, with thousands of gigawatts of wind, solar and battery projects stalled in connection queues worldwide. Without faster buildout of transmission and distribution lines, grid congestion and curtailment — where renewable output goes unused — could rise, reducing the economic and environmental benefits of clean power.

Beyond physical infrastructure, the IEA and analysts emphasise system flexibility measures such as energy storage, demand response, digitalisation and market reforms that can help balance variable supply and demand more efficiently. A recent World Economic Forum report highlights that enhancing grid flexibility could underpin resilience, reduce costs and unlock greater renewable integration by 2030.

Affordability and reliability challenges

Rising electricity demand also intersects with concerns about affordability and reliability. In parts of the United States, electricity prices have surged as ageing infrastructure and demand spikes from data centres strain existing grids, prompting political pushback and highlighting the social dimensions of power system evolution. Financial Times reporting notes that rising wholesale power costs are becoming a contentious issue in industrial and policymaker circles alike.

India, the U.S., and China are all projected to see notable increases in electricity demand through the decade, prompting varied responses from national policymakers on grid investment, electrification incentives and energy security measures.

As the world heads deeper into the Age of Electricity, experts and energy officials warn that investment in grids and flexibility is not optional — it is central to satisfying rising demand, reducing emissions and ensuring reliable power for economic and social needs through 2030 and beyond.

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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 David Pickup

It’s a happy coincidence of timing: we need a lot more electricity generation, and fast — and we’ve also experienced more than a decade of price reductions in renewable energy.

A look at projects built in Canada shows a clear trend: contracted energy costs from wind and solar have been cut in half over the last 10 years, the period of time during which most projects were built in Canada.

These wind and solar projects provide concrete, local examples of how costs are coming down as the technology improves and the market matures. Each point in the graph below reflects one or more real projects from signed deals. Altogether, the deals come from procurements in seven provinces across Canada.

The utilities that operate the electricity systems in most provinces held competitive procurement processes to secure contracts. This gave the market the certainty to grow and build projects that deliver low-cost energy. To top off all that good news, analysts expect that the cost of renewables will continue to drop further by between 25 to 50 per cent over the next decade.

In contrast, the cost of new nuclear projects, including refurbishments, has risen over the same period, so that the energy delivered by nuclear projects contracted over the last couple of years will likely be two to three times the cost of energy from renewables projects contracted in that year. We estimate the Pickering nuclear refurbishment will deliver power at $266 per megawatt-hour (MWh), and the Darlington small modular reactor project will be $152 per MWh; compare that to wind and solar procured in Saskatchewan and B.C. at $64-110 per MWh.

It’s worth noting, too, that the energy from renewables will come along sooner — in the next three to five years — rather than 10 years or more for nuclear projects. It’s important to move quickly as forecasts across the country show a rapid and substantial increased need for additional electricity. For example, Ontario expects electricity demand will grow by 75 per cent by 2050, while Alberta expects a 26 to 44  per cent increase between 2024 and 2043.

Why the timing of the renewable energy price drops matters

A decade ago, wind and solar electricity generation were more expensive than other types of generation. But since then, prices have dropped steadily. Now, they’re the lowest-cost form of new electricity generation, according to the grid operators in Alberta and Ontario, as well as global analysts.

The timing of this price drop could not have come at a better time. Electricity demand is surging to accommodate the electrification of vehicles, home heating and industrial processes, so provinces across Canada are making crucial decisions about how to add more electricity to their systems. Getting more affordable electricity generation onto the grid —  fast — underpins the competitiveness of the economy.

How electricity users benefit when renewable energy is added to the grid 

Even if solar panels or wind turbines are not on your shopping list, your budget can still benefit from a growing clean energy sector. That’s because when the most affordable forms of new electricity generation — namely solar, wind and battery storage — are added to the electrical grid in your province or territory, they help keep electricity prices low for everybody.

The biggest cost involved in the life of a wind or solar farm is the upfront capital cost to build the infrastructure. Once they’re built, they run on free fuel (wind and sunshine), unlike natural gas or nuclear plants.

There are effective ways of making sure this low-cost energy is still available when the sun sets and the wind isn’t blowing. Ontario figured this out when it contracted 1,885 megawatts of battery storage capacity in its first long-term procurement. Extra wind and solar power is stashed away during peak energy producing hours and is discharged to the grid when it’s most needed. The province is also harnessing energy savings by working with electricity consumers to reduce demand when necessary, and it’s building transmission lines to move energy from high production to high consumption areas.

The overall cost reductions of renewable energy over time and the continued low operating costs are the reasons why 93 per cent of new electricity infrastructure built in the United States last year was solar, wind and batteries. It’s also why renewable energy overtook coal as the largest source of electricity worldwide in 2025.

Where clean energy is being added to the Canadian grid now

Canadian provinces, having recognized the value of adding more renewables to their electricity mix, are scaling up calls for wind and solar project proposals in 2026. The fact that they’re using competitive auctions to secure the additional electricity means they’re getting the best value for their dollar. Here’s what we’ll be watching this year:

• Ontario: Over four years, the province is running a technology-agnostic competitive bid process for up to 7,500 megawatts (MW) of new energy and capacity. It’s open to wind and solar developers, as well as energy storage projects and natural gas plants. The first round of results are expected in April.
• Quebec: Hydro-Québec announced plans last year to develop 10,000 MW of wind and 3,000 MW of solar energy by 2035. The first call for tenders for 300 MW of solar energy is opening in April.
• B.C.: BC Hydro launched a bid process in 2025 to acquire up to 5,000 gigawatt hours per year of new clean or renewable energy projects. For comparison, this is roughly equivalent to either 1,600 MW of wind or 2,500 MW of solar. BC Hydro got 14 proposals totaling more than 9,100 gigawatt hours per year, nearly double the targeted amount, and final results are expected in the coming months.
• Manitoba: Manitoba Hydro is procuring 600 MW of wind power this year, with the official request for proposals coming out in March.
• The territories do not have centralized renewable energy requests for proposals. They’re typically smaller community-oriented projects, funding programs, and utility procurements rather than large multi-hundred-MW auctions. Our recent report, Restoring the Flow, explores the status of policies supporting Indigenous-led clean energy in remote communities.

However, a couple of provinces are choosing to go a different direction with new energy needs, and are missing out on the opportunities of low-cost renewable energy:

• Alberta: Until recently, Alberta led the country in renewable energy deployment. However, after a series of major policy changes, the market is stalling, as our report from last year highlights.
• Saskatchewan: The Government of Saskatchewan decided in the middle of last year to extend its coal fleet to power its grid until nuclear plants come online sometime later in the century. Although it is also procuring some renewable energy, we believe the decision to extend coal is going in the wrong direction.

The provincial and territorial governments with the foresight to take advantage of the low-cost electricity available from wind and solar can do so by planning their systems around a modernized grid. This means harnessing the latest technology — including interprovincial interties, demand-side measures and long-duration energy storage — to manage their energy in a way that delivers affordable and reliable electricity as demand grows.

2026 will be another exciting year for clean energy in Canada as federal, provincial and territorial governments adjust to the new reality of low-cost renewable energy and make crucial decisions about the future of our energy supply.

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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 Chris Bonasia

A new power purchase agreement by Saskatchewan’s Crown-owned utility, SaskPower, has set the stage for a 100-megawatt solar farm to be built and operated with 50% Indigenous ownership.

The Mino Giizis solar project is being developed by Neoen—–a French renewable energy company that has built other solar farms in Canada— with the Anishinabek Power Alliance (APA), a partnership of four Treaty 4 Nations with political participation from the Yorkton Tribal Council. Neoen and APA will co-own the project through a 50% equity partnership.

The project “shows what genuine partnership looks like: shared power, shared responsibility, and shared benefit,” says a joint statement from five APA leaders: Kinistin Saulteaux Nation Chief Felix Thomas, Zagime Anishinabek Nation Chief Lynn Acoose, Cote First Nation Chief George Cote, The Key First Nation Councillor Fernie O’Soup, and Yorkton Tribal Council Tribal Chief Isabel O’Soup.

“Our Nations see this as a way to move into the future without harming the land, while creating much-needed revenue and employment opportunities for our people,” the statement continues. “Rooted in the spirit of Treaty and our responsibility to future generations, this historic moment is taking our Nations to another level in Treaty 4 Territory.”

On Jan. 14, the two partners signed a 25-year power purchase agreement for SaskPower to buy all the electricity generated by the solar farm. The project is set to go online in 2028, reports SaskToday.

“Southern Saskatchewan and Southern Alberta have the best solar resources in all of Canada,” explained Ryan Dick, Neoen’s province director for Alberta and Saskatchewan. “SaskPower targeted south central Saskatchewan, where they wanted the procurement to take place. So that’s where we began our prospecting in order to site the project.”

The Mino Giizis project was chosen through a two-year procurement process led by the First Nations Power Authority (FNPA), which provided technical support and evaluated team project proposals from Saskatchewan First Nations and their independent power-producing partners.

According to the Canadian Renewable Energy Association, the project will be the largest-ever solar farm in Saskatchewan and will bring the province’s total installed capacity of renewables to just under 1,000 MW. The organization says more such projects are expected in coming years, given SaskPower’s 2022 commitment to procure 3,000 MW of wind and solar by 2035.

Construction is set to begin in 2027. Neoen has said it aims to hire 350 people to build the project, 75% of whom will be Indigenous.

Dick said Neoen is working with First Nations and Métis educational and employment organizations “to really figure out how can we hire people, how can we train people, and how can we not only create jobs for this project” but also  provide future work “in the growing solar industry in western Canada,” reports CTV News.

The Regina Leader Post says the project will create five full-time jobs once it goes into operation.

“When we look at projects like this, we see opportunity for our children and grandchildren, economic reconciliation taking root, and our voices and actions helping to shape Saskatchewan’s energy future,”  the First Nation leaders wrote in their joint statement.

“That is what truth and reconciliation means. We move forward together, in a good way.”

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The EIA estimates that electricity generation by the U.S. electric power sector totalled about 4,260 billion kilowatt-hours (BkWh) in 2025. Generation is forecast to grow by 1.1 per cent in 2026 and 2.6 per cent in 2027, reaching 4,423 BkWh, driven largely by new solar capacity and rising electricity consumption.

While dispatchable power sources — natural gas, coal and nuclear — accounted for about 75 per cent of total generation in 2025, the EIA expects their combined share to fall to roughly 72 per cent by 2027. Over the same period, the share of electricity generated from wind and solar is projected to rise from 18 per cent to 21 per cent, continuing a longer-term shift toward cleaner sources.

Solar leads growth, especially in Texas

Utility-scale solar is expected to be the fastest-growing source of electricity generation in the United States. The EIA forecasts solar generation will rise from 290 BkWh in 2025 to 424 BkWh by 2027, supported by nearly 70 gigawatts (GW) of new capacity scheduled to come online in 2026 and 2027 — a 49 per cent increase in operating solar capacity compared with the end of 2025.

Much of that growth is concentrated in Texas, where the grid managed by the Electric Reliability Council of Texas (ERCOT) continues to attract large-scale renewable investment. Solar generation in ERCOT is expected to nearly double, from 56 BkWh in 2025 to 106 BkWh by 2027.

Bloomberg has reported that Texas’s relatively streamlined permitting, abundant land and strong power demand from industrial users and data centres have made it one of the most active solar markets globally. The expansion is increasingly supported by battery storage, which helps manage fluctuations in solar output. The EIA expects battery capacity in ERCOT to rise from about 15 GW in 2025 to 37 GW by the end of 2027.

Wind growth slows in the Midwest

Wind power, long concentrated in the central United States, is expected to see more modest growth in the coming years. In the Midcontinent Independent System Operator (MISO) region, which covers much of the Midwest, wind generation is forecast to average just over 100 BkWh annually through 2027, reflecting a slowdown in new wind installations.

Reuters has noted that rising costs, supply-chain constraints and transmission bottlenecks have tempered wind development in parts of the U.S., even as solar continues to expand. In MISO, new solar plants are beginning to offset slower wind growth, with solar generation expected to increase from 31 BkWh in 2025 to 46 BkWh in 2027, according to the EIA.

Natural gas remains dominant, but its share slips

Natural gas remains the largest single source of U.S. electricity generation, although its share has declined from a peak of 42 per cent in 2024. The EIA forecasts natural gas-fired generation will total 1,696 BkWh in 2026, roughly flat with 2025 levels, before rising slightly to 1,711 BkWh in 2027 as overall power demand increases.

Because total electricity generation is growing faster than gas-fired output, natural gas’s share of the power mix is expected to fall to 39 per cent by 2027, down from 40 per cent in 2025.

Regional growth in gas generation remains uneven. The EIA expects gas-fired output to increase 23 per cent in ERCOT and 5 per cent in the PJM Interconnection region, which covers much of the U.S. Mid-Atlantic. Both areas are seeing rapid growth in electricity demand from data centres, a trend Reuters and NPR have linked to the expansion of cloud computing and artificial intelligence infrastructure.

Coal declines after a temporary rebound

Coal-fired electricity generation rose 13 per cent in 2025 to 731 BkWh, supported by colder-than-average weather in some regions and relatively higher natural gas prices. But that rebound is expected to be short-lived.

With existing policies and planned retirements, the EIA projects coal-fired generation will decline by an average of 5 per cent per year over the next two years, falling to 661 BkWh in 2027. Coal’s share of total generation would drop to 15 per cent, from 17 per cent in 2025.

NPR has reported that while coal plants can still play a role during extreme weather or fuel price spikes, utilities continue to retire aging units as renewable capacity and storage expand and operating costs rise.

A power system in transition

Taken together, the EIA’s outlook underscores a U.S. power sector in transition: electricity demand is rising, driven by digital infrastructure and electrification, while solar and battery storage grow rapidly and fossil fuels gradually lose market share.

As Bloomberg has noted, the pace at which new generation and grid infrastructure can be built — particularly transmission and storage — will be critical in determining how smoothly that transition unfolds through the latter half of the decade.

Canada context: How U.S. power trends compare north of the border

While the United States is seeing rapid growth in solar power and battery storage alongside rising electricity demand, Canada’s electricity system is evolving along a different path — shaped by its heavy reliance on hydroelectricity and a slower pace of large-scale solar deployment.

Hydropower accounts for roughly 60 per cent of Canada’s electricity generation, according to Natural Resources Canada, providing a large source of dispatchable, low-emissions power that the U.S. largely lacks. Nuclear power contributes about 15 per cent, concentrated mainly in Ontario, while natural gas plays a smaller but growing role in provinces such as Alberta and Saskatchewan.

Unlike the U.S., where solar is the fastest-growing source of generation, Canada’s recent renewable additions have been led by wind power, particularly in Alberta, Ontario and Quebec. Utility-scale solar remains a relatively small share of Canada’s power mix, although installations are increasing in Alberta and Saskatchewan, where market structures and solar resources are more favourable.

Battery storage is also expanding more slowly in Canada than in the U.S., though several provinces are beginning to add grid-scale storage to support renewable integration and manage peak demand. Alberta and Ontario, in particular, have announced or approved new battery projects over the past two years.

One area where trends converge is rising electricity demand, driven by electrification, population growth and data centres. Canadian utilities and grid operators have warned that meeting future demand will require significant investment in generation, transmission and storage — even in hydro-rich provinces.

As in the U.S., the pace at which new infrastructure can be built, and how costs are managed for consumers, is emerging as a central challenge for Canada’s power transition.

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Ford framed the move as a “decisive redeployment of capital” in a Monday announcement that accompanies its 2026 business plans, as part of its broader Ford+ strategy. The company plans to redirect investment away from larger EVs that have struggled to meet sales and profitability expectations, and toward products and technologies where it sees stronger near-term returns.

“The operating reality has changed, and we are redeploying capital into higher-return growth opportunities,” Ford President and CEO Jim Farley said in a company press release outlining the new strategy. That includes expanding its lineup of hybrid and extended-range vehicles, as well as a new battery energy storage systems (BESS) business, which Ford said will use existing battery production capacity in the U.S.

Major write-down underscores EV market headwinds

Ford’s nearly US$19.5 billion impairment charge — one of the largest in recent corporate history — reflects the cancellation of planned EV models, the dissolution of a battery joint venture with South Korean partner SK On, and other program-related write-downs. About $8.5 billion of the charge relates to scrapped EV projects, including large pickups and vans, while roughly $6 billion reflects the end of the SK On venture and $5 billion covers other program expenses.

Reuters reporting notes that Ford is discontinuing the fully electric F-150 Lightning and its next-generation sibling, the T3, in favour of an extended-range hybrid model that incorporates a gasoline engine to recharge the battery. Ford is also shelving planned electric commercial vans and repositioning its production lines to prioritize trucks, vans, and hybrid vehicles.

The retrenchment comes as U.S. EV sales have faltered — in part due to federal policy changes that ended consumer tax credits and relaxed emissions regulations — and overall EV market penetration has remained lower than earlier projections. According to Reuters, EVs now account for roughly 10 per cent of new vehicle sales in the U.S., compared with about 25 per cent globally.

Battery plants repurposed for grid and data-centre storage

One of the most notable aspects of Ford’s pivot is its intention to repurpose existing EV battery manufacturing capacity to produce large-scale energy storage systems. At its Glendale, Kentucky battery plant — originally built for EV battery production — Ford plans to invest roughly US$2 billion over the next two years to build lithium iron phosphate (LFP) cells and assemble them into 20-foot energy storage containers with at least 5 megawatt-hours (MWh) of capacity each. The company aims to produce at least 20 gigawatt-hours annually by the end of 2027.

The storage units are intended for grid operators, utilities and data centres, where demand for reliable power buffering and peak shaving is growing rapidly. Analysts say that as data centres and other large energy users seek to manage peak demand and integrate more renewable generation, the market for grid-connected battery systems is expanding quickly. One report projected that U.S. energy storage deployments will reach record levels this year amid surging interest.

In reporting by Canary Media, industry watchers say Ford’s strategy reflects broader trends in the energy transition. “They have built up battery manufacturing capacity, and now they need to do something with it,” Pavel Molchanov, managing director for renewable energy and clean technology at Raymond James, told reporters. “While EV demand is languishing, U.S. energy storage deployments are skyrocketing.”

Broader industry and market dynamics

Ford’s shift comes amid a broader reevaluation of EV strategies across legacy automakers. General Motors has also taken impairment charges related to EV production, while Stellantis has scaled back some EV plans in favour of hybrid platforms. Reuters coverage notes that many traditional carmakers — constrained by higher development costs, weakening demand and shifting regulatory environments — are returning to hybrid and traditional powertrain investments.

Analysts also point to weakening consumer incentives as a factor. The U.S. federal EV tax credit, once worth up to US$7,500 per vehicle, expired this year following legislative changes, removing a key subsidy that helped boost EV demand earlier in the decade. At the same time, average gasoline prices in the U.S. have fallen below US$3 per gallon in recent months, making conventional vehicles more attractive to cost-conscious buyers.

Strategic reset and future prospects

Ford’s revised approach prioritizes profitability and flexibility. The company says it expects its global mix of hybrids, extended range vehicles and EVs to reach roughly 50 per cent of total volume by 2030, up from about 17 per cent today, suggesting hybrids will play a major role alongside any future EV offerings.

The move also underscores widening divergence between the EV market and energy storage. Where EV sales have slowed, grid storage demand — particularly for data centres and utility applications — remains robust, driven by efforts to stabilise electricity systems and integrate renewables.

Yet Ford’s transition is not without risks. Energy storage markets are competitive, with established players such as Tesla already commanding significant shares of the grid-scale battery business. Whether Ford can carve out a meaningful position in storage while recalibrating its vehicle lineup remains to be seen.

For now, the Detroit automaker is betting that redeploying capital from struggling EV programs into hybrids, extended-range vehicles and energy storage will position it for more sustainable, profitable growth in a shifting automotive and energy landscape.

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By Mitchell Beer

After adopting a series of rolling deadlines to phase out Russian gas imports by 2027, the European Union still won’t need new supplies—from Canada or anywhere else—to make up the difference, energy analysts say.

On Wednesday, the European Parliament voted to phase out imports of Russian liquefied natural gas (LNG) by the end of next year and pipeline gas by September, 2027, Reuters reported. The European Commission will also propose measures early next year to phase out Russian oil purchases.

Russia was once the continent’s biggest supplier of gas, the news agency writes. But since Vladimir Putin launched his invasion of Ukraine in 2022, his country has seen its market share in Europe fall from 45 per cent to 12 per cent.

One analyst put the value of those remaining cargos at €25 to €30 million each, with more than 200 tankers filled with Russian Arctic gas landing at European ports this year.

Over the past several months, the Canadian government has pushed hard to encourage LNG exports to Europe, with Energy and Natural Resources Minister Tim Hodgson maintaining in August that a first shipment might be possible in “as little as five years”. But analysts say Europe will have no need for new gas, even with Russia falling out of the supply mix.

“The big fear is always this question of how to find alternative supply,” said Sebastian Rötters, sanctions campaigner with Urgevald, a climate finance non-profit based in Sassenberg, Germany. But “from 2027 onwards, there will be an oversupply in the market, and this is something we can already start to see.”

With multiple experts predicting a gas glut, “I don’t really think the EU will replace these volumes, and I hope they won’t replace them with long-term contracts,” he told The Energy Mix. “If we see the need for alternative supply, but at the same we don’t want to throw our climate goals out the window, it’s difficult to sign a 20-year contract.”

In a market assessment released last March, the Ember energy policy think tank said Europe will see a 54 per cent increase in LNG import capacity between 2023 and 2030, even though the continent’s gas grid operators only foresee a 4 per cent increase in demand. That disconnect will lead to more than 100 billion cubic metres of “costly supply capacity potentially being unneeded and underutilized,” the report stated. “This scale of overinvestment is equal to the combined annual gas demand of Germany, France, and Poland.”

Throughout 2024, those gas supplies also drove up gas prices by 59 per cent, Ember added, leading to higher electricity costs for consumers.

Ana Maria Jaller-Makarewicz, lead energy analyst, Europe at the Institute for Energy Economics and Financial Analysis, said Russia supplied 16 per cent of the continent’s LNG and 13 per cent of its combined LNG and pipeline gas in the first half of 2025, even after the EU decreased its gas dependence by 20 per cent between 2021 and 2023.

But “if the EU continues with policies to reduce gas consumption and scale up renewables, the bloc could replace this supply without increasing gas imports from any source.,” Jaller-Makarewicz said.

Rötters said the real issue is whether EU members—including countries like Hungary and Slovakia that are more closely aligned with the Putin regime—would want to take those steps.

“Could we offset this? Of course we could,” he said. But “in Europe at the moment, renewable energy deployment and climate-related work are not really the number one priority. So of course energy efficiency is a priority, in the sense that the EU wants to be less dependent, but we could do a lot more if the political will were there.”

Beyond geopolitics, Rötters explained that Hungary and Slovakia worked to slow down the EU ban to protect their access to relatively inexpensive pipeline gas from Europe. That led countries to negotiate a phaseout in four stages: short-term LNG contracts in April, 2026, followed by short-term pipeline contracts in June and longer-term deals at the end of this year and the following September, respectively.

If the goal is to cut off financing for Putin’s war machine, one question is whether Russia will find other customers for the gas it can no longer sell to the EU.

“The market continues to be very volatile and dependent on geopolitical issues that could affect prices, supply, and demand,” Jaller-Makarewicz told The Mix. But already, “Russia has been selling gas and LNG at discounted prices to attract buyers,” and “it might be difficult to find a market that will import the same amount of Russian gas as Europe did before Russia’s full-scale invasion of Ukraine. Gas demand in different regions has been declining, and countries like China have been decreasing their LNG needs.”

That means it will serve the EU’s geopolitical agenda if imports can be shut down, Rötters said.

“Would it help to cut this money off? I would say yes, it would,” he said. “We are pushing for very strong and immediate sanctions because the Russian economy is really in trouble. This is something Putin can still hide, but… the existing sanctions do hurt.”

At the same time, Urgevald is stressing the urgency of stopping the flow of gas payments from the EU to Russia, with Rötters pointing out that Ukraine “is helping the EU” by “saving Europe from defending against a Russian attack on EU territory. Because I don’t think it’s a fairy tale to say the Baltic countries are in imminent danger of Russian aggression.”

After the deal was adopted, Denmark’s minister for climate, energy and utilities, Lars Aagaard, praised the EU agreement as “a big win for us and for all of Europe. We have to put an end to the EU’s dependence on Russian gas, and banning it in the EU permanently is a major step in the right direction.”

But in a release following Wednesday’s announcement, Urgevald said the continent is moving too slowly.

“While the EU congratulates itself on phasing out Russian gas by 2027, the Kremlin is still set to receive billions in the meantime,” Rötters said in the release. “At the current pace, the EU will pay over €4 billion for Russian-linked LNG in 2026 alone. That is not a phaseout. That is financing a war,” and  “every delay weakens sanctions and strengthens the Kremlin.”

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By Chris Bonasia

In Australia, a major battery energy storage project and a new requirement for data centres to invest in renewable energy show some ways the country is preparing for the energy transition.

Australia’s largest energy storage battery will be paired with gas turbines, with past statements by one of the project’s partners hinting the move is part of a plan to set up battery infrastructure in anticipation of future clean energy supply.

“When you look at the technology improvement curve of batteries, even over the next two to three years, it’s nothing short of breathtaking,” said David Scaysbrook, co-founder and managing partner for Quinbrook Infrastructure Partners, as reported in Renew Economy. Scaysbrook explained that surplus solar energy can be stored in batteries as a reliable source of cheap energy, “and if you’ve got 320 sunny days a year, that is a very, very powerful combination.”

“Forget subsidies,” he added. “I’m not talking about subsidies. I’m talking about Quinbrook, or someone else, building a large-scale solar-battery hybrid with an eight-hour battery,” capable of “delivering incredibly competitive energy cost without government handouts.”

Quinbrook offshoot Private Energy Partners is currently building the Gladstone State Development Area Energy Hub Project in Queensland, where it proposes to combine a 780-megawatt, eight-hour battery energy storage system with up to 1,080 MW of open-cycle gas turbines. The firm recently signed a memorandum of understanding with Stanwell, a state-owned regional energy generator, which gave Stanwell exclusivity over the project.

The agreement is part of Stanwell’s efforts to move away from burning coal, Renew Economy says. For Quinbrook, the project is part of a strategy to set up long-duration “infrastructure batteries” in Australia that are poised to help soak up cheap renewables and power big industrial loads.

Meanwhile, Australia’s recently-released National AI Plan is requiring that data centre developers pair projects with their own renewable energy generation. Australia’s data centres already consume roughly four terawatt hours of electricity each year—around 2 per cent of the country’s total electricity demand—and that number is expected to triple by 2030 and eventually make up more than 10 per cent of grid demand by 2035, says Renew Economy.

The National AI Plan, broadly, is an attempt by the Australian government to chart out a course for the country to manage the proliferation of AI throughout the economy. But according to The Conversation Canada, the plan’s requirement for renewable energy—and what that could mean for building out infrastructure that will be needed for an energy transition—is a major selling point.

“The government is working with the states and territories, energy market bodies, network service providers, and the data centre industry to harness opportunities from the growth of data centres to promote investment in renewable energy and maintain affordable energy for households and businesses,” the National AI Plan states.

“Australia has the opportunity to take advantage of ambitious AI infrastructure initiatives in ways that accelerate our renewables transition and drive investment in skills, research, and sustainable technologies.”

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