This article was written by Jeffrey Jones and was published in the Globe & Mail on December 24, 2025.

Energy storage developer Hydrostor Inc. is close to breaking ground on its first utility-scale project after receiving final regulatory approval in California.

Toronto-based Hydrostor said it is finalizing offtake agreements with utilities in the state before starting construction at its US$1.5-billion Willow Rock Energy Storage Center in Kern County, Calif., north of Los Angeles.

The U.S. project, which has been under review for more than four years, is one of two large developments the company expects to start in 2026. The other is in New South Wales, Australia.

Its long-duration technology, known as advanced compressed air energy storage, is designed to smooth out electricity supply on power grids, storing excess power generated from fast-growing renewable sources such as wind and solar until it’s needed.

Hydrostor’s system works by pumping compressed air into a cavern deep underground. The rush of air pushes water up to a reservoir at the surface. When electricity is needed, the water is released back into the cavern, sending the air out and driving turbines to generate power.

The benefits are that the facility can store energy for longer periods than batteries, and the system can run on either excess or off-peak power from the grid or from renewable sources.

Last Friday, the California Energy Commission granted final permitting approval to the 500megawatt/4,000-megawatt-hour project, which will have the capacity to power more than 400,000 homes for more than eight hours at a time.

Hydrostor president Jon Norman said the company has grid interconnection agreements for its planned facility, as well as engineering, procurement and construction contracts, and union deals, in place.

“That’s good to start constructing the project. We just need those last pieces of revenue,” Mr. Norman said. Early this year, the project won conditional approval from the U.S. Department of Energy for a loan guarantee of up to US$1.76-billion. However, since then, U.S. President Donald Trump has cancelled many green and climatefriendly programs.

The company said, based on its discussions with the department, that it is confident its financing is secure. It offers benefits to U.S. utility customers, and “grid reliability and resilience are bipartisan priorities,” chief executive Curtis VanWalleghem said in a statement Tuesday.

In February, Hydrostor secured US$200-million in financing from the Canada Growth Fund, Goldman Sachs and the Canada Pension Plan Investment Board to push forward with its projects. Its other investors include ArcTern Ventures, Loren Partners and Canoe Financial.

The company plans to have the Willow Rock project in operation in five years. Mr. Norman said there is more opportunity on the horizon, as California has called for a major expansion of storage capacity by 2032.

In Australia, Hydrostor is nearing the start of construction on a 200-megawatt/1,600-megawatt-hour project in Broken Hill, New South Wales, which is estimated to cost about US$640-million.

Mr. Norman said its proposal has been delayed for regulatory reasons – its planned method of storing and transmitting power is a first for the country.

Those details, as well as sales contracts, are being finalized. “We expect to have an announcement early in the year about a priority designation for that project from the New South Wales government that will form a very strong basis for it to go forward,” Mr. Norman said. “So we’re really looking at getting to construction on these projects in parallel.”

In total, the company says it has the potential to develop 7,000 megawatts’ worth of projects in the next few years in Canada, the U.S., Australia and Britain.

Hydrostor plans to construct some of them itself, but also sell the systems to utilities and independent power producers that can operate them on a turnkey basis, Mr. Norman said.

“So this really is the beachhead for an entire growth industry around compressed air energy storage,” he said.

U.S. firm says Alberta can be leader in car­bon cap­ture

Man­tel Cap­ture says province has policy sup­port needed to develop tech

This article was written by Lauren Krugel and was published in the Toronto Star on December 23, 2025.

The chief exec­ut­ive of a U.S.­based car­bon cap­ture star­tup embark­ing on a project in Alberta’s oils­ands says Canada ticks a lot of the boxes needed to bring the emis­sions­redu­cing tech­no­logy into wide­spread use.

“Alberta spe­cific­ally is a really great con­flu­ence of all the right factors com­ing together to give Canada a chance to lead in this eco­sys­tem,” said Cameron Hal­l­i­day, cofounder of Cam­bridge, Mass.based Man­tel Cap­ture.

“You’ve got the policy sup­port. You’ve got the car­rot and the stick.”

Man­tel announced last week it has begun an early engin­eer­ing and design study for a com­mer­cials­cale project in Alberta’s oils­ands. It’s not identi­fy­ing its part­ner at this stage, but it’s a pro­du­cer that uses steam­assisted grav­ity drain­age tech­niques to extract bitu­men from deep under­ground.

The project is designed to cap­ture 60,000 tonnes of car­bon diox­ide per year. Usu­ally, car­bon cap­ture projects con­sume a lot of energy, but Man­tel’s tech­no­logy aims to har­ness what powers its sys­tem instead of wast­ing it, as the 150,000 tonnes of high­pres­sure steam it gen­er­ates can be used in its oils­ands part­ner’s oper­a­tions.

Man­tel is not dis­clos­ing the cost of the project at this time. It is receiv­ing sup­port from Alberta Innov­ates, a pro­vin­cial Crown cor­por­a­tion.

It builds on a demon­stra­tion project at Kruger Inc.’s Way­agamack pulp and paper mill in Trois­Rivières, Que., that’s designed to cap­ture 2,000 tonnes of car­bon diox­ide and gen­er­ate steam for the mill.

Hal­l­i­day said Man­tel’s mod­u­lar equip­ment can be bolted on to many dif­fer­ent kinds of indus­trial plants, like cement, steel, chem­ic­als and power gen­er­a­tion. He called it a “value­addit­ive exer­cise” on top of the bene­fit of pre­vent­ing cli­mate­w­arm­ing emis­sions from enter­ing the atmo­sphere.

“We need a way to do this, frankly, that makes money for the people that are put­ting their neck out and invest­ing in these things,” he said. “The way to do that is to do it effi­ciently.”

Alberta is a “soph­ist­ic­ated” player in the car­bon cap­ture space with the right policy sup­port with both a price on car­bon and tax incent­ives, Hal­l­i­day said.

Another thing the province has going for it is the people, as skills in the oil and gas industry mir­ror many of those needed in the car­bon cap­ture busi­ness.

“They have a good under­stand­ing of the sub­sur­face for sequest­ra­tion. Even the equip­ment above ground — it’s chem­ical­pro­cessing type equip­ment that these guys just under­stand. It looks famil­iar to them.”

Man­tel is not involved in the Path­ways Alli­ance, a group of some of Canada’s biggest oils­ands com­pan­ies pro­pos­ing to build what would be one of the world’s largest car­bon cap­ture projects, with an estim­ated cost of $16.5 bil­lion.

Path­ways would cap­ture car­bon diox­ide emis­sions from more than 20 oils­ands facil­it­ies in north­ern Alberta and trans­port them 400 kilo­metres away by pipeline to a ter­minal in the Cold Lake area in east­ern Alberta, where they would be stored in an under­ground hub.

It was a key fea­ture of a memor­andum of under­stand­ing signed between the Alberta and fed­eral gov­ern­ments late last month. Path­ways and a new West Coast bitu­men pipeline going ahead are “mutu­ally depend­ent,” the agree­ment says.

This article was written by Mathieu Dion and was published in the Toronto Star on December 18, 2025.

Brit­ish star­tup Awen­dio Sol­aris is draft­ing plans to invest as much as $1 bil­lion into a solar tech­no­lo­gies fact­ory in Canada, though it still needs to secure power sup­ply and fin­an­cing.

The com­pany wants to build a man­u­fac­tur­ing facil­ity and a research and devel­op­ment centre on an indus­trial site in the Montreal region. The oper­a­tion would man­u­fac­ture solar cells and assemble solar pan­els for North Amer­ican util­it­ies, deliv­er­ing up to 2,500 mega­watts of annual pro­duc­tion capa­city in its first phase, accord­ing to the firm’s web­site.

“It’s massive,” Awen­dio CEO Marc Deschamps said. “It is the equi­val­ent of 20 Maersk con­tain­ers full of pan­els, flat­pack pan­els, com­ing out every day.”

There’s one major advant­age to loc­at­ing in Que­bec, accord­ing to Deschamps. The province has cheap, clean power because of its vast net­work of hydro­elec­tric dams. Awen­dio’s first phase would require about 32 mega­watts of elec­tri­city from Hydro­Que­bec, he said — the rest of the fact­ory’s needs would be filled with solar power.

But the state­owned Que­bec util­ity has been under pres­sure lately on its sup­ply out­look, partly because of con­tracts it nego­ti­ated years ago to sell power to the U.S. Pro­pos­als for new indus­trial projects are now under more scru­tiny.

A spokes­per­son for Que­bec’s eco­nomy min­is­ter said the province is “cur­rently ana­lyz­ing the file with great interest.”

Deschamps said that Awen­dio’s man­age­ment, two U.S. fam­ily offices and First Nations groups are fin­an­cially back­ing the project for now, and that National Bank of Canada is put­ting together a con­sor­tium of funds to sup­port it. Awen­dio is also seek­ing fin­an­cial aid from gov­ern­ments.

There are con­struct­ive con­ver­sa­tions occur­ring with offi­cials in the fed­eral gov­ern­ment, accord­ing to a per­son famil­iar with the mat­ter, speak­ing on con­di­tion of anonym­ity because the dis­cus­sions are still private.

This article was written by Emma Graney and was published in the Globe & Mail on December 17, 2025.

Oil and gas producers and operators of large landfills will be subject to new methane regulations come 2028, under federal rules that are more stringent – but also more flexible – than those that previously governed emissions reduction.

Reducing methane pollution is seen by policy-makers as something of a lowhanging fruit to help combat climate change. The gas is potent; it is roughly 80 times more harmful than carbon dioxide over a 20-year period. But the technology to abate it is proven to work and is relatively cheap.

The goal of the federal government’s new regulations, released Tuesday, is to reduce methane emissions from the oil and gas sector by 304 megatonnes between 2028 – when the rules take effect – and 2040. Ottawa estimates doing so will cost industry roughly $14-billion.

Landfill regulations are separate from oil and gas. The government expects them to reduce emissions by around 100 MT by 2040, in part through robust methane monitoring.

Julie Dabrusin, Minister of the Environment, Climate Change and Nature, said Tuesday that Canada has “both a moral imperative and an economic opportunity” to reduce emissions, and the new regulations are “a massive step forward” in doing so.

“It is one of the most important things that we can do and one of the most costeffective things that we can do,” Ms. Dabrusin said at an event in Burnaby, B.C.

The new rules for oil and gas build on those released in 2018, when Canada became one of the first countries to enact regulations to reduce methane emissions from the sector’s new and existing facilities.

They were a key part of Ottawa’s climate-change plan at the time, which included a goal of reducing methane emissions by 40 per cent to 45 per cent from 2012 levels by 2025.

The new regulations contain stronger requirements to reduce methane emissions than the 2018 rules, along with more robust requirements to strengthen leak detection and make repairs.

Operators will have two ways to comply.

They can choose to take action to stop methane venting and establish an inspection schedule to find leaks and repair them. Their other option is to design their own methane-control approaches, though they must meet specific emissions limits.

Ms. Dabrusin said this gives operators flexibility to implement methane-reduction solutions that make the most sense for them.

The regulations will apply to gas processing plants, transmission facilities and onshore oiland-gas production, such as well sites and pipelines. Oil refineries, fuel terminals and municipal gas distribution infrastructure are exempt. The rules will be phased in starting Jan. 1, 2028.

However, Alberta – by far Canada’s largest producer of oil and gas – will have longer to meet any emissions-reduction target, under the memorandum of understanding signed last month by Prime Minister Mark Carney and Alberta Premier Danielle Smith.

Canada has a commitment to reduce oil-and-gas methane emissions 75 per cent from 2012 levels by 2030. Under the MOU, Alberta has a 2035 target date – five years later than the rest of the country.

Amanda Bryant, a senior analyst at the Pembina Institute, a think tank, said while the federal methane regulations are well designed, their effect will be decided in Alberta through MOU talks.

The five-year carve-out means “the path forward for these new regulations in Alberta is already unclear,” Ms. Bryant said in a statement.

“We therefore urge the federal government to use these new federal regulations as the yardstick against which it assesses whatever proposed pathway to reducing methane Alberta presents during the forthcoming MOU negotiations.”

Rebecca Schulz, Alberta’s Environment Minister, said the province would “focus on practical and flexible methane reduction solutions that enable our industry to stay competitive” when it develops its plans.

The new regulations are part of Ottawa’s Climate Competitiveness Strategy, contained in the federal government’s 2025 budget.

Ms. Dabrusin said a progress report on Ottawa’s emissions-reductions plan will be released before the end of the year.

As part of Tuesday’s announcement, Ms. Dabrusin also announced nearly $16-million in funding for investment in methane emissions-reduction technologies across Canada.

• This opinion was written by Bruce Lourie and was published in the Globe & Mail on December 15, 2025. Bruce Lourie is the president of the Ivey Foundation and a professor of practice at the Trottier Institute for Sustainability in Engineering and Design, McGill University.

What if our pursuit of a perfectly clean electricity grid undermines the broader electrification revolution we need? The answer lies in understanding the economics of that final push toward 100-percent renewable electricity, and nowhere is this tension more visible than in Canada.

That’s because Canada’s electricity system stands as one of the cleanest in the industrialized world, already 84-per-cent decarbonized. This is an impressive achievement, built largely on the foundation of hydroelectric power in Newfoundland and Labrador, Quebec, Manitoba and British Columbia, complemented by nuclear generation in Ontario.

For most of the past two decades, Canadian policymakers have celebrated this advantage, viewing it as a springboard for climate action. But the calculus becomes more challenging with a push toward 100-per-cent decarbonization.

Sometimes called “the last mile problem,” the challenge is straightforward but profound. The first 84-per-cent of decarbonization in Canada came relatively easily. Natural geography and historical public investments provided reliable and affordable electricity. The final stretch is different.

The Energy Transitions Commission and the Rocky Mountain Institute (global think tanks) have documented this challenge across multiple jurisdictions. Their research shows that the cost curve for grid decarbonization is not linear. Going from 50-per-cent to 80-per-cent decarbonized electricity is cost-effective. Above 80 per cent, the costs increase, and that final push from 90 per cent to 100 per cent can cost exponentially more still. Pushing beyond 95 per cent requires infrastructure investments that can double or triple the marginal cost of that final clean energy.

In Canada’s case, this could mean electricity rate increases of 20 to 40 per cent in the non-hydro provinces. This isn’t a failure of renewable technology. It’s simply the reality that the last few percentage points of demand require massive investments in energy storage, transmission infrastructure, carbon capture technology or significant overbuilding of renewable capacity to ensure reliability during peak periods.

Alberta has achieved 60-percent decarbonization with natural gas replacing coal. And while wind and solar capacity have grown dramatically over the past decade, there is room for much more to further decarbonize the system and bring down the province’s sky-high electricity rates. This will only happen once the electricity market is freed from political intervention that prevents renewable power development. Over 90-per-cent decarbonization of the system is doable while maintaining a few natural gas peaking plants for reliability during January cold snaps, when electricity demand surges and evening solar production plummets.

British Columbia is a different story. It already has 98-per-cent clean electricity through hydroelectric power. BC Hydro has projected that achieving 100-percent clean energy and shutting the natural gas peaking plants would add massive cost. Similar dynamics play out in Nova Scotia, Quebec and Manitoba.

The situation is urgent, and long-term energy storage solutions are expensive. This doesn’t mean gas “peakers” forever; only until alternative technologies are proven at the scale and cost needed to get us through a January cold snap.

Modelling done by the Transition Accelerator (a Canadian think tank) shows that for Canada to achieve 2050 climate targets, roughly 60 per cent of current end-use energy needs to be electrified requiring a doubling of electricity supply. The entire climate strategy for Canada, and indeed most industrialized countries, depends on rapid electrification of transportation and heating.

This is where the paradox becomes dangerous and introduces the counterintuitive idea that total decarbonization of the electricity grid could stall economywide electrification and delay the achievement of climate change targets.

Here’s the problem: Consumers make decisions based on affordability. A family considering an electric vehicle or heat pump compares the lifetime operating costs against conventional alternatives. If electricity rates increase 30 per cent while natural gas prices remain stable, the case for electrification weakens considerably. That heat pump is less appealing if it means higher heating costs.

Now more than ever, we need a thoughtful approach to electricity planning. Maintaining a small percentage of natural gas generation for peak demand provides low-cost reliability while still achieving 95-per-cent decarbonization in the power sector. The mathematics are compelling. The emissions from gas peaker plants running a couple of hundred hours per year pale in comparison with the emissions avoided by accelerating electrification of transportation and heating.

Regulations are important to drive decarbonization, but flexibility is foremost if we are to double down on the main issue: rapidly accelerating the electrification of the economy.

This article was written by Emma Graney and was published in the Globe & Mail on December 15, 2025.

Mantel Capture is targeting Alberta’s oil sands for a project with an unnamed Canadian producer

A Boston-based startup, whose technology can cut the cost of carbon capture in half, is targeting Alberta’s oil sands, launching an engineering study for a commercial-scale project with an unnamed Canadian producer.

Mantel Capture Inc.’s foray into the oil and gas sector comes at a time of renewed interest in carbon capture and storage (CCS). The technology received a significant boost under the energy accord signed last month by Ottawa and Alberta that included a plan for construction of the Pathways Project. The massive CCS effort would create a 400kilometre pipeline to transport carbon emissions to an underground storage hub. The accord aims to have the project built by 2040.

Mantel chief executive officer Cameron Halliday said while federal and provincial policy changes are still in flux, “they’re all pointing in the right direction, which is that carbon capture is the pragmatic solution people can align on and rally around.”

Mantel already has a demonstration CCS project at Kruger Inc.’s Wayagamack pulp and paper mill in Quebec, which aims to capture 2,000 tonnes of carbon dioxide each year. The company’s new partnership in the oil and gas sector is a significant step-up in scale, designed to capture roughly 60,000 tonnes of CO2 annually.

While that represents only a fraction of the 70 megatonnes of emissions produced by Alberta’s oil sands each year, it would, if successful, demonstrate how CCS could be used in the sector.

Traditional carbon capture consumes large amounts of energy in the form of steam, making them expensive to run. But Mantel’s CCS technology instead creates steam as an endproduct, which can then be used in on-site industrial processes.

Along with capturing carbon, the oil sands project aims to generate 150,000 tonnes of highpressure steam a year.

Mr. Halliday was tight-lipped about the name of its oil producer partner, but confirmed it is a steam-assisted gravity drainage (SAG-D) operator in the Cold Lake basin, which is roughly 300 kilometres northeast of Edmonton. (The vast majority of oil sands production comes from the Athabasca basin, which is more than 400 kilometres north of Cold Lake, near Fort McMurray, Alta.)

Along with capturing carbon, the oil sands project aims to generate 150,000 tonnes of high-pressure steam a year.

Most oil sands are buried too deep below the surface for open pit mining, and use techniques like SAG-D to extract crude. Those sites use steam to heat and thin the heavy oil so it can flow into a well and be pumped out.

“That’s one of the reasons we’re super-excited about this project, because these folks use steam directly,” Mr. Halliday said.

Instead of CCS being a waste management tool to reduce emissions, he said, “we can start to be value creators.” That makes the economics of CCS more compelling – and, ultimately, more investable, he said.

Clean Prosperity, a climate policy think tank, has said the memorandum of understanding struck between Alberta and Ottawa earlier this month has the potential to attract more than $90-billion in low-carbon capital investment to the province, the vast majority of which would be in the CCS space.

But to get there, projects have to be financially attractive and in a policy environment that encourages investment, Mr. Halliday said.

Unlike the United States or Europe – which mostly use only incentives or penalties, respectively – Canada takes “both a carrot and a stick” approach that couples a CCS investment tax credit with a price on carbon to motivate companies to reduce their emissions.

“Then it’s on the technology providers and the projects to be able to deliver something that actually makes sense. What we’re able to do is, by and large, cut the cost by about 50 per cent. That’s a radical change.”

While Mantel’s partner for the venture is not one of the companies involved in the Pathways project, Mr. Halliday said his company is already working with other oil sands producers.

The ultimate goal is to provide CCS technology to sites that are further north, leveraging the Pathways project to decarbonize the oil sands, he said.

“The vast majority of Canada’s CO2 emissions are coming from these industries. It would be a massive win to be able to do that in a way that doesn’t break the bank.”

Mr. Halliday said the project is being supported in part by Alberta Innovates, a Crown corporation that provides funding for research, innovation and entrepreneurship across various economic sectors.

Alberta-based oil and gas companies are particularly sophisticated on CCS, he said, owing to the deep technical expertise they have developed over years of trying to find emissions-reducing solutions for industry.

Mantel’s oil sands engineering-design study will likely be finished toward the end of 2026, Mr. Halliday said, with project execution roughly two years after a final investment decision.

This opinion was written by Eric Reguly and was published in the Globe & Mail on December 13, 2025.

Canada is embracing the carbon business again. New oil pipelines are almost certainly coming and the Alberta tar sands will expand to feed them. In the European Union, natural gas plants are under construction and coal lives on in some countries.

All in all, this is bad news for the health of the planet, but can you blame the overhauled Canadian and European energy plans? No Canadian or European leader will admit so publicly, but it appears that they realize that any of their own carbon savings would be more than offset by the still-rising output of greenhouse gases in China. U.S. President Donald Trump figured that out long ago.

The corporate bosses in the EU, home to crippling electricity prices, are especially galled by the failure of the green agenda to bring down power bills. Deindustrialization is the outcome while coal-mad China goes in the opposite direction, as the latest trade figures suggest. According to China’s customs agency, the country’s trade surplus in the first 11 months of 2025 will exceed US$1-trillion, in spite of the Trump tariffs, putting it on a record trajectory for the full year. China can keep its trade surplus intact in good part because of cheap, plentiful energy produced from hydrocarbons, especially coal.

China plays a clever PR game: Ever-rising output of renewable energy and lowor zero-carbon products, like electric vehicles (EVs), make the headlines; the country’s rising carbon emissions receive much less publicity. China is certainly a green-energy champion but continues to rely on coal plants to generate more than half of its electricity.

There is no doubt that China is turning its green agenda into a world-beating force. In 2024, EVs accounted for almost half of all Chinese car sales, according to the International Energy Agency. The 11 million EVs sold in China last year were greater than total global sales of such cars just two years earlier.

At the same time, some 85 per cent of global lithium ion battery cell manufacturing is done in China. About 80 per cent of solar panels sold around the world are Chinese. China also dominates the production of wind vanes used to make electricity. China would rather you ignore the fact that much of the domestic production of these products is powered by fossil-fuel plants, as is the electricity for charging EV batteries.

Generating electricity from coal, as China has learned, has huge advantages.

Coal plants can be built quickly and relatively cheaply. There are endless supplies of thermal coal and today’s prices are a quarter of their peak in 2022 and 2023, when the pandemic recovery sent electricity demand in China, India and elsewhere soaring. Coal power is also more flexible; output from coal plants, unlike that of nuclear power, can be quickly ramped up or down depending on demand.

No wonder that the construction of coal plants in China never ceases. Britain’s Carbon Brief climate website earlier this year reported that China accounted for 93 per cent of all new coal-plant construction in 2024. If completed, those plants would boost electricity generation capacity by almost 95 gigawatts (GW), the highest rate in a decade. That’s the equivalent of about 60 per cent of Europe’s total nuclear power production, and seven times that of Canada’s.

There is every reason to believe that China’s coal-plant construction pace continued this year, in spite of Beijing’s pledge to “strictly control” the rollout of new capacity, and will continue in the years to come. China’s demands for energy security means coal will live on even though the fuel is the top source of carbon dioxide emissions from electricity production.

The EU has spent decades winding down its coal program. Poland is the only large EU country where half or more of its electricity comes from burning the grubby fuel. The plants face their last gasp in 2049, when the last of Poland’s coal mines is set to close.

But with electricity prices atrociously high in the EU and energy-intensive industries closing or decamping to cheaper countries, hydrocarbon-fueled electricity production is far from dead. Germany is building 10 GWs of gas-fired power plants on the condition that they can run on hydrogen power at some point. Italy, Greece and several other EU countries are doing the same in an effort to keep a lid on electricity prices and ensure that supplies are secure when the sun doesn’t shine and the wind doesn’t blow. Elsewhere, net-zero power projects are being postponed or cancelled.

Europe has come to the belated conclusion that renewable energy alone cannot keep its industrial base intact or its voters happy. Germany, Britain and Italy, each watching the erosion of its industrial base, have the highest industrial electricity prices in the developed world, roughly twice those of the U.S. and 50 per cent more than China, according to a recent Wall Street Journal report.

Europe realizes it cannot compete with China or the U.S. if it delivers a death sentence to all its hydrocarbon plants. The net-zero agenda will be delayed to preserve industries and their jobs. China knew that all along, not Europe.

China’s demands for energy security means coal will live on even though the fuel is the top source of carbon dioxide emissions from electricity production.