By Michael J. Armstrong

The United States and Israel have repeatedly boasted about airstrikes in their current war with Iran. In Week 1, they claimed the destruction of 75 per cent of Iran’s missile launchers. By Week 2, they had reduced Iranian missile fire by 90 per cent and said the war was “already won in many ways.”

And yet, Iran keeps damaging refineries and blocking tankers from crossing the Strait of Hormuz.

The country has certainly suffered many tactical losses. But its missiles and drones have been strategically successful.

Iran so far has launched at least 5,400 such projectiles. Surprisingly, less than a tenth of them have targeted Israel, its traditional rival.

Missiles over Israel

Israel faced about 450 Iranian missile attacks during the war’s first four weeks. The rate of fire fell rapidly after the first weekend but has never halted.

Some missiles carry several hundred kilograms of explosives, enough to destroy an entire building. The rest instead dispense dozens of cluster bombs over wide areas. Those are less powerful but still lethal.

Israel’s long-range Arrow interceptors engage the missiles first. Its mid-range David’s Sling and short-range Iron Dome interceptors provide backup. (The country’s Iron Beam lasers are not being used.) Together, they’ve reportedly intercepted 92 per cent of incoming missiles.

But interceptors sometimes miss. And their supply is limited. Consequently, at least nine large warheads and 150 cluster bombs have hit populated areas.

These numbers imply that almost all Iranian missiles are accurate enough to need interception. By contrast, during Israel’s earlier conflicts with Gaza in 2008, 2011 and 2014, less than a third of incoming rockets were so accurate.

Meanwhile, more than 90 per cent of Iran’s missiles and drones have targeted Arab countries in the Persian Gulf.

Drones across the Persian Gulf

Saudi Arabia, Jordan, Iraq, Kuwait, Bahrain, Qatar, Oman and the United Arab Emirates (UAE) collectively reported around 4,900 Iranian attacks during the first four weeks. Only one fifth were missiles: the rest were drones.

These countries have stated they are neutral in the war. However, they do have defence agreements with the U.S., and some host American military facilities.

These countries defend themselves using weapons like the U.S.-made Patriot and Israeli-made SPYDER interceptors. Drone experts from Ukraine now advise the defenders too.

For example, the UAE reported attacks by 1,835 drones, 378 ballistic missiles and 15 cruise missiles. As of March 10, it claimed to have intercepted 94 per cent of the drones and 99 per cent of the missiles.

The deadliness of these attacks has varied.

Continuing lethality

In Israel, Iranian missiles have killed 20 people, implying roughly 4.1 deaths per hundred missiles arriving.

That’s less than the 5.1 the country saw during its 2025 war with Iran. But it’s four to 40 times higher than the rates it suffered from rockets in earlier Gaza and Lebanon conflicts.

In the Persian Gulf, Iranian projectiles have killed at least 15 civilians, 13 U.S. soldiers and seven merchant sailors.

There were about 0.6 deaths per hundred Iranian attacks in Kuwait, Bahrain and the UAE combined. That’s much lower than Israel’s rate, presumably because those countries were attacked by drones and short-range missiles carrying smaller warheads.

Interestingly, although the quantity of Iranian attacks fell after the first week, their lethality did not. Death rates per projectile in Arab countries showed little change week-to-week. In Israel, the rates were highest in Week 3.

In fact, Iranian missiles keep hitting precise targets, like U.S. military aircraft parked beside runways.

This implies Iran’s government has recovered from its initial surprise. It’s likely benefiting from Russian intelligence and Chinese technology too.

Tactical U.S. vs strategic Iran

So, U.S. and Israeli warplanes have bombed thousands of targets, killed thousands of civilians, and slowed Iran’s missile fire. But they haven’t stopped it.

That’s not surprising. Airstrikes alone didn’t stop rocket fire during Israel’s previous conflicts in Gaza and Lebanon. Ground invasions were needed for that.

U.S. President Donald Trump can post jingoistic mashup videos and “bullshit” about having “militarily won” the war in Iran. But he hasn’t achieved strategic outcomes like “unconditional surrender” from Iran or regime change there.

By contrast, Iran’s missiles have been strategically effective. They’ve damaged Persian Gulf refineries and halted tanker traffic. They’ve forced Trump to relax sanctions on Russian and Iranian oil, and on Belarusian fertilizer. And they’ve shown Arab monarchies that U.S. defence agreements have limited value.

Trump recently, and inadvertently, admitted this weakness. While discussing Iran’s closure of the Strait of Hormuz, he said “it would be great if we could do something, but they have to open it.”

This strategic failure despite tactical success is reminiscent of the Vietnam War. U.S. units had overwhelming firepower as they killed enemy soldiers. But body counts by themselves indicated little about strategic progress.

Some historians rank that war as the second worst U.S. foreign policy decision ever. The 2003 invasion of Iraq was ranked the worst.

Trump talks about being the greatest U.S. president in history. So, perhaps his Iran war will make him the new leader on that policy failure list.

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By Mitchell Beer

With the federal government expected to release its long-awaited national electricity strategy this week, Canada could be in line to lose $110 to $220 billion in new investment and 40,000 to 80,000 direct jobs if it fails to deliver a clean power grid “at the scale and speed that industry and investors need,” a recent report concludes.

While senior executives across Canada’s finance, technology, heavy industry, mining, and clean energy sectors recognize that clean power is essential, it’s only worth pursuing “when it is predictable, cost-competitive, and available at scale,” states the report released earlier this month by the Shareholder Association for Research and Education (SHARE).

Canada enters the energy transition with an advantage over many other industrialized nations, with about 85% of its power coming from non-emitting sources, consultants at Dunsky Energy + Climate report. Clean economy sectors like electric vehicles, batteries, and the grid itself have received about $65 billion in new investment, producing at least 26,000 direct jobs and tens of thousands more across related supply chains.

That investment is taking place at a moment when access to electricity is central to site selection and capital allocation for new projects, adding asset value and enabling market access for new investments in tech, artificial intelligence, and mining.

But “Canada’s clean electricity edge is under threat,” Dunsky warns. “Grid constraints, permitting delays, and interconnection uncertainty are already slowing or cancelling investments.”

Canada faces those challenges in a moment of intensifying global competition, the report adds, with other jurisdictions “rapidly decarbonize their grids with the aim of attracting clean investment.”

The national electricity strategy has been in development for some time. Insiders say its release is now just days away, and it’s expected to focus on east-west transmission, Indigenous leadership, and better collaboration among provinces. Earlier this month, Ontario announced a “major nation-building milestone” when 10 provinces and territories—everyone but Quebec, Newfoundland and Labrador, and Nunavut—agreed to work together on new transmission infrastructure.

There was no official word on the national strategy’s release as this story went to virtual press. But The Energy Mix has learned that it may appear as soon as this Wednesday or Thursday and feature federal investment in grid interties between provinces, though the form of investment—through loans, grants, federal ownership, of investment tax credits—remains to be seen. The strategy is expected to remain silent on the fate of the federal Clean Electricity Regulations, and it isn’t clear whether it will address the role of gas-fired electricity or carbon capture and storage on the grid.

The Dunsky report calls for long-term coordination and policy certainty across federal, provincial, and territorial governments to make permitting and grid interconnections faster and more transparent, all with the goal of accelerating the buildout of clean generation, storage, and transmission. It points to Indigenous partnerships as an element that could “unlock project development”, and stresses the role of demand-side solutions to “lower system costs, defer infrastructure, and improve reliability—especially for fast-growing data centre and industrial loads.”

SHARE Public Affairs Director Jennifer Story said the consultants sought interviews with executives whose companies will need reliable supplies of green energy. “There’s a growing number of investors and companies that are hearing back from regulators, hearing back from provincial decision-makers, that they’re in the queue or that their needs can’t be met.,” she told The Energy Mix in an interview.

“If Canada is really serious about creating new opportunities in our economy to buffer the effects of the worsening relationship with the United States, this is a really obvious place to do it,” she added. “We’ll certainly be looking to see whether or not [the federal electricity strategy] goes the distance to meet this need.”

With net-zero commitments and carbon pricing systems in place in 10 of Canada’s 11 biggest trading partners—the U.S. is the outlier—Story said faster buildout of a clean electricity grid could be an essential nation-building project to protect Canadian sovereignty.

“It does tie in to trade strategy,” she told The Mix. “Some countries and regions are imposing carbon border adjustments, for example. Responding to that reality means again demonstrating clearly that we can supply our issuers, our publicly-traded and private companies, with the clean power they need to not have those border adjustments be a barrier to market access in other parts of the world.”

And to attract climate-aligned investment, “we also need to demonstrate to those investors that the companies they’re considering, the projects they’re considering, have not just green but also reliable, affordable, consistently available clean power.”

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New data from the U.S. Energy Information Administration (EIA) shows output rose by about 3 per cent, or 350,000 b/d, compared to 2024. The increase came despite a 5 per cent drop in active rigs and fewer wells drilled, highlighting a structural shift in how U.S. producers are growing supply.

The gains reinforce the United States’ position as the world’s largest oil producer and contribute to expectations of a global supply surplus. Reuters has reported that rising U.S. output is a key factor behind forecasts of an oversupplied global market, with production expected to average roughly 13.6 million b/d in 2025.

Efficiency offsets lower prices

The 2025 production increase came as benchmark West Texas Intermediate (WTI) crude prices fell to about $65 per barrel, down from $77 in 2024. Normally, lower prices would dampen output, but U.S. producers continued to extract more oil from fewer wells.

New wells added 2.9 million b/d of production in 2025, while existing wells accounted for 8.3 million b/d. Industry analysts have increasingly pointed to productivity gains — including longer laterals, improved fracking techniques, and better data analytics — as the main driver of growth.

Bloomberg has similarly reported that U.S. shale producers are pumping more oil per dollar invested, allowing output to rise even as capital spending and rig counts decline.

This decoupling of production from drilling activity marks a significant evolution in the shale sector, where companies have shifted focus from rapid expansion to capital discipline and efficiency.

Permian dominates growth

As in previous years, the Permian Basin remained the engine of U.S. production growth. Output in the region rose by 280,000 b/d in 2025 to reach 6.6 million b/d — nearly half of total U.S. supply.

Low breakeven costs continue to underpin Permian growth. According to the Dallas Fed Energy Survey, operators in the Midland and Delaware basins reported breakeven prices of roughly $61–$62 per barrel in 2025, below the annual average oil price. That cost advantage has allowed producers to sustain output even in a weaker price environment.

By contrast, other major shale regions showed limited growth. Production in the Eagle Ford rose modestly to 1.2 million b/d, while the Bakken saw a slight decline to a similar level.

Together, the Permian, Eagle Ford, and Bakken account for nearly two-thirds of total U.S. crude production.

Offshore projects add supply

Production in the Gulf of America also contributed to overall growth, rising by 111,000 b/d to average 1.9 million b/d in 2025.

Five new offshore projects — Whale, Ballymore, Dover, Shenandoah, and Leon-Castile — came online during the year. Unlike shale operations, offshore developments are less sensitive to short-term price fluctuations due to their long lead times and high upfront capital costs.

This steady pipeline of offshore projects is helping to diversify U.S. supply growth beyond shale basins.

Global implications

The global outlook for oil markets has shifted rapidly in recent weeks. The war in Iran and severe disruptions to shipping through the Strait of Hormuz — which typically carries about one-fifth of global oil — have tightened supply and driven prices sharply higher. With tanker traffic collapsing and infrastructure under attack, the market is moving away from fears of oversupply toward a more constrained and volatile environment.

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By Bob Weber

Prime Minister Mark Carney’s Major Projects Office is now six months old, just a baby in government years. But those gathered around the newborn’s crib already have plenty of ideas on how they’d like the infant to grow up.

Some look for an umpire—a neutral agency that simply evaluates big proposals and advises cabinet. “I hope they want someone who’s there to call balls and strikes,” Andrew Leach, an energy and environmental economist at the University of Alberta, told The Energy Mix. He said the MPO’s role should be to advance such projects, but also to ensure proponents have covered the environmental and consultation bases.

“You want someone in the room that when a company comes in and says, ‘Our project’s just not moving forward,’ (asks) ‘Have you done the work right?’”   Others want something more activist, pushing projects that further decarbonization, such as linking interprovincial electricity grids. “It needs to be a ramp up for renewable energy projects,” said Mark Kalegha, energy finance analyst at the Institute for Energy Economics and Financial Analysis. “Interconnectedness seems to be on their priority list and the MPO is able to help with the regulatory hurdles.”

A giant lab on regulatory reform would be welcome, say some. “What we’re hoping comes out of the Major Projects Office is learnings on how to accelerate reviews and processes without denuding them or making them any less stringent,” said Fernando Melo, public affairs director with the Canadian Renewable Energy Association (CanREA). “I’ve been out to many a project site where you ask, ‘How many permits are you filing?’ and the answer comes ‘Oh, five or ten’ … And I go, ‘One field.’”

Others expect it to serve an overall policy goal. “They’ve been focused on resources and infrastructure, in particular, trade facilitating infrastructure,” said University of Calgary economist Trevor Tombe. “That, to me, really speaks to the priority on trade diversification that the government has laid out.”

And some will be grateful if the whole thing doesn’t just turn into another deadening layer of lobbyist-ridden government bureaucracy. “

It does signal to investors that (their proposal) won’t be one of those Canadian proposals that takes 12 years. That’s the generous side of it,” said Heather Exner-Pirot, senior fellow at the Macdonald-Laurier Institute. But she asks, if excessive regulation is the problem, why not just reduce regulation?

“They’ve listed all these regulations that the MPO can bypass—why don’t they work on fixing those if they can be bypassed safely?”

But all say that attempts to assess the MPO’s direction need context. The office is just one part of a policy package aiming to reduce Canada’s dependence on increasingly unreliable United States trade, boost the country’s economic self-reliance, and move its economy toward a low-carbon future—all at once.

“Just as important, if not more important than the major projects themselves, is the policy,” said Janetta McKenzie, oil and gas director at the Calgary-based Pembina Institute. She said industrial carbon pricing, methane regulations, clean electricity regulations, and federal investment tax credits are just as big an influence on where investment goes as anything the MPO does. “

If the goal is to build a future-proofed Canadian economy that is more resilient to ongoing geopolitical shocks and volatility, then the investment signals need to be strong,” McKenzie said.

The Signals So Far

The signals, so far, haven’t been encouraging for climate goals. The federal government has junked consumer carbon pricing, tossed oil sands emissions caps, and weakened EV sales mandates. Tough economic times have proved tough for environmental policy, too, said Leach.

“Once people became convinced, rightly or wrongly, that Canadian environmental policy was the source of all their woes, there wasn’t much ground there left for the PM. “Voters are very keen on environmental policy as long as it doesn’t cost them anything.”

For example, the memorandum of understanding now being finalized between Alberta and Ottawa includes a promise of industrial carbon pricing—but also support for a new pipeline, which a Pembina analysis concluded would increase Alberta’s carbon emissions even if that oil was “decarbonized” through capture and storage.

Leach said national security concerns may now support the project. “All our pipelines in the U.S. are subject to a presidential permit the president can revoke at any time at our expense,” he said. “It’s still a conversation that’s in a dark corner, so to speak, but it’s a conversation we should be having.”

A Pipeline Full of Obstacles

But any new line faces considerable obstacles.

There’s neither a route nor a proponent, and the increased production needed to fill one would require massive upstream investment.

The MOU signed between Alberta and the feds rules out public financing, but former Alberta energy minister Sonya Savage recently told a CBC podcast that without public support a private proponent is, at best, highly unlikely.

Still, there may be a financial case to be made, suggested Leach, pointing to 2010, when pipeline bottlenecks forced producers to discount Canadian oil. If that happened again, the discount would now be on roughly twice as much oil.

“This is the math that people miss,” he told The Mix. “Even if you said this (pipeline) would reduce the differential by a buck, that’s four million barrels a day, 365 days a year times 15 years. (The investment) doesn’t look terrible.” Price, he said, is far more important than sheer volume.

But Canada will likely need to reduce that discount and squeeze out every petrodollar it can, and sustain it over a longer haul that may not be realistic. Before the current war launched the price of oil, it was languishing around $60 a barrel, with most experts predicting further falls. That market is likely to eventually return once the U.S.-Iran conflict ends. When the missiles stop flying, so will the value of oil.

Diversified Trade Could Boost Climate Goals

But the Carney objective of diversifying Canada’s trading partners could also advance climate goals. The projects currently before the MPO suggest at least some emphasis on clean energy, with wind power and minerals critical to electrification in the mix.

There’s also a proposal to link electricity gids in northern British Columbia and the Yukon.Climate and energy transition advocates say that is exactly the sort of thing the MPO should be doing to move Canada towards electrons and away from molecules.

“The more we integrate provinces and (make them) able to call on each other’s resources, it’s going to be better,” said CanREA’s Melo. “Having more connectivity will help enable greater decarbonization of the grid.”

In fact, grid ties are probably the only electricity-related projects big enough to appear on the MPO’s “nation-building” agenda. Solar panels and wind farms are also regulated provincially, putting them outside the MPO’s purview.

“The barriers to renewable penetration of electricity generation are provincial policies,” said the University of Calgary’s Tombe.

Trade diversification could provide another decarbonization prod. Canada will have to meet the environmental standards of those it seeks to trade with. Europe, for example, implemented its carbon border adjustment program in January. The policy imposes a tariff on imports of carbon-intensive products such as steel, cement, and energy that don’t meet EU standards. Melo said if Canada wants to play in those markets, it will have to comply.

“With the Canadian government’s stated goal of 50% of exports reaching alternative markets— the European Union, Japan, and China, which everyone forgets has an industrial carbon price— there’ll be more and more demand that the goods they import have low-carbon attributes built in.”

Weighing the Consequences

It’s unlikely that Mark Carney, once the UN’s special envoy on climate action, has forgotten the need to reduce carbon emissions. But he’s a central banker, too, used to weighing consequences of action against each other.

“The end game is going to be overall policies on consumption and overall policies on production,” Leach said. This may mean a little water in the wine of carbon cuts. Rather than absolute targets—the meeting of which has failed dismally—Canada may instead focus on simply being better than our competitors, some analysts say.

“Sustainability includes financial sustainability,” said Exner-Pirot. “The goal is not to kill Canadian production, but to make it better. Trying to square the circle involves making Canadian products competitive on carbon intensity, aiming for the good rather than the perfect.”

The Carney government must now make tough choices in the face of a new world order different than the one we were told to expect, Tombe said. “Reality has just thrown a few curve balls at Canada.”

“I do not see the government having abandoned any consideration at all about climate objectives,” he added. “But it also keeps in mind other criteria like trade diversification, economic and productivity growth … (Government) could achieve a lot more if it was singularly focused on climate goals. But it is not. It is balancing lots of objectives.”

The MPO itself has offered few clues as to its direction and intent. Although CEO Dawn Farrell is a longtime fossil energy executive who shepherded the controversial Trans Mountain pipeline expansion project, she has a non-partisan and even-handed reputation. Still, in testimony last fall before a Senate committee, she spoke approvingly of the carbon intensity of Canadian LNG. She also suggested a new oil pipeline to the west coast would have climate benefits, since much if that oil is used to make components for electric vehicles.

Some other senior staff bring past background in renewable energy and in reconciliation with Indigenous communities, but staffers have provided little information about where the office is going. Federal officials have told The Mix that Farrell maintains close contact with Carney and his senior staff, and that “all the major calls” will be made by the Prime Minister’s Office.

It’s early days for the MPO and the baby is barely walking. Where its first steps take it will be determined as much by the paths other policies have opened for it as its own inclinations.

But like any infant, observers broadly agree that it will take a while to mature. A $3.3-trillion economy does not turn around overnight.

“This process of diversifying trade, of boosting investment and growth, is going to be a multi-year, potentially multi-decade road that we’re on,” Tombe said. “We’re only at the very, very beginning. There’s so much left to do and so many unanswered questions still that need resolving.”

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by Mitchell Beer

The federal and Alberta governments have reached a preliminary agreement that will allow the province to set its own regulations on climate-busting methane emissions and postpone its emission reduction deadline by five years.

The deal’s effectiveness in putting a lid on methane pollution will depend on details that are still under development. But experts say Ottawa already traded away the equivalent of 53 million tonnes of carbon reductions last November, when it first signalled that it would allow Alberta to postpone methane controls from 2030 to 2035.

Methane carries about 84 times the global warming potential of carbon dioxide over the crucial 20-year period when humanity will be scrambling to get climate change under control. The Intergovernmental Panel on Climate Change identifies methane reductions as one of the cheapest paths to the quickest, deepest greenhouse gas emission reductions by 2030.

The agreement in principle, released Wednesday, cements a five-year postponement in Ottawa’s 2030 methane target that first appeared in the November, 2025 memorandum of understanding (MOU) between Canada and Alberta. If the two governments can agree on an “outcome-based equivalency agreement” under the Canadian Environmental Protection Act, Canada will stand down its own methane regulations in deference to Alberta’s.

The two governments have also agreed to identify an independent third party “to conduct methane modelling, analysis of emissions reductions, and to assess methane reduction results”. That provision is being hailed as an important step, a week after analysis by the Calgary-based Pembina Institute concluded that Alberta’s methane emissions are up to 90% higher than the province’s official estimate, which relies on self-reporting by industry.

The agreement is to take effect on January 1, 2027, following a 60-day consultation on the draft plan.

The methane equivalency agreement was one of several commitments in the Canada-Alberta MOU that were meant to be finalized by April 1. Alberta Premier Danielle Smith now says other elements of the deal, including a proposed new oil pipeline to Canada’s West Coast, will be delayed beyond next week’s deadline.

Canadian Climate Institute (CCI) President Rick Smith declared the agreement in principle a “positive step forward”. He called the provision for an independent third party “an important approach to reinforce policy ambition and integrity, and help ensure the regulations cover the true extent of methane pollution levels from Alberta’s oil and gas sector.”

But he cautioned that “the final details of the equivalency agreement, and follow-through on the commitment to independent and transparent verification of outcomes, will be critical to determine the agreement’s success.”

CCI Senior Research Associate Alison Bailie said she had confidence in the agreement’s focus on “looking at the Alberta numbers, not just accepting them,” adding that methane measurement technologies have improved in recent years—with some of the gains achieved by Emissions Reduction Alberta with funding from the province’s Technology Innovation and Emissions Reduction (TIER) system.

“That’s where I see the hope and the benefits of doing this properly,” she told The Energy Mix. “It helps Alberta’s own companies,” creating a business case for methane controls in Canada and enabling them to position themselves for methane abatement projects overseas.

Bailie added that Canada has “tended to see greater emission reductions” when federal and provincial governments actually work together. “That can work really well,” she said. “We’d like to see more.”

Aly Hyder Ali, senior program manager, oil and gas at Environmental Defence Canada, called the five-year delay an “unnecessary concession” that represents a “bad deal for everyone outside the oil patch.” Citing Pembina Institute modelling, he said the carveout would pour 1.9 million extra tonnes of methane into the atmosphere, the equivalent of 53 million tonnes of carbon dioxide over a 100-year period—or far more over a 20-year span.

Amanda Bryant, manager of Pembina’s oil and gas program, agreed in a release that independent, third-party verification is a “vitally important and positive step”, allowing Alberta to “report its methane progress more credibly”. She said the agreement “signals an end to the roadblock that had been preventing progress on this crucial element of climate and energy policy,” enabling industry to “invest and hire with confidence to advance the next stage of methane mitigation work.”

But so far there’s no clarity on whether the “independent party” responsible for monitoring Alberta’s methane controls will rely on theoretical modelling or actual measurement of releases from oil and gas infrastructure, or on whose data the monitor will rely. Real measurement “will be vital, both for an effective response to climate change and to ensure ongoing access to major international natural gas markets that are demanding provably low-emissions-intensity fossil fuel imports, such as the European Union, South Korea, and Japan,” Bryant said.

Last week, a Pembina technical analysis flagged data and regulatory gaps in Alberta’s current approach to methane controls, resulting in actual emissions that have been up to 90% higher than official government figures.

“Alberta should not be afraid modernize its measurement data and methods, including vehicle-based systems, aircraft, and satellites to effectively reduce its methane emissions,” Bryant said at the time.

But Alberta Premier Smith may have a different take on what to expect from the independent third party. During an unrelated media conference Wednesday, she said the goal is to arrive at “a common set of facts” after “some other reports that have been put out there kind of put us at odds,” iPolitics reports.

The agreement in principle states that, “should third party analysis determine that emissions are higher than expected, Alberta commits to take the necessary corrective actions.”

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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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Chinese electric vehicle giant BYD is open to acquiring a competing manufacturer and setting up shop to produce cars in Canada—but not if it means entering a joint venture with another company.

“The Shenzhen-based automaker is studying the Canadian market for a potential manufacturing facility, although no decision has been made,” Bloomberg News reports, citing an interview with BYD Executive Vice President Stella Li.

“Perhaps more striking than the Canada factory talk is Li’s candid acknowledgment that BYD is evaluating potential acquisitions of established automakers,” Electrek writes. “Several American, European, and Japanese manufacturers are struggling under the financial strain of maintaining both combustion and electric vehicle product lines simultaneously.”

But while “we’re open to every opportunity we have,” Li said, “I don’t think a JV [joint venture] will work.”

In mid-January, Prime Minister Mark Carney agreed to sharply reduce tariffs on electric vehicle imports from China, while China offered up tariff relief for Canadian canola, peas, pork, and seafood. At the time, Canadian observers predicted lower EV prices and possible long-term advantages for the country’s automotive industrial base.

Canada agreed to slash duties on up to 49,000 Chinese EVs per year to a “most-favoured-nation tariff rate” of 6.1 per cent, Carney’s office said in a release. The imports will amount to less than 3 per cent of annual new vehicle sales in Canada, but “will drive considerable new Chinese joint-venture investment in Canada with trusted partners to protect and create new auto manufacturing careers for Canadian workers, and ensure a robust buildout of Canada’s EV supply chain,” the PMO said.

Days later, Carney said he saw the deal as an opportunity for Ontario’s automaking heartland. “We’ve had direct conversations directly from the Chinese companies… with explicit interest and intention to partner with Canadian companies,” he told media during a stopover in Doha, Qatar. “We’ll see what comes to pass. This is an opportunity for Ontario. It’s an opportunity for Ontario workers, opportunity for Canada, done in a controlled way with a modest start.”

Now, Bloomberg says BYD is looking at expanding its reach in overseas markets where it can repeat the “Brazil model”, a marketing and sales approach that has worked well for it in South America and Europe. “Buying existing production capacity with trained work forces is faster and cheaper than building greenfield—and BYD appears to be applying the same logic globally,” Electrek explains.

One place the company isn’t considering an expansion is the United States, a “complicated environment” where tariffs on Chinese-made vehicles exceed 100 per cent and connected car technology is banned.

BYD’s sales fell 36 per cent, to 400,241 vehicles, in the first two months of this year, both news outlets say. “But exports gained momentum, and the company is targeting 1.3 million overseas vehicle sales for the full year,” Electrek reports. “Li said BYD’s recently launched next-generation Blade Battery and ultra-fast flash charging architecture, capable of delivering up to 1,500 kW, will help reverse the domestic sales dip.”

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By Philippe Le Billon

War is costly. The ongoing American-Israeli war on Iran is already reverberating through the global economy. For most people, including American citizens, it means higher fuel prices and greater economic uncertainty.

But for a narrower group of entities, war can also be extraordinarily profitable. Chief among them are segments of the United States oil and gas industry, which have already profited from Russian President Vladimir Putin’s decision to invade Ukraine and the ensuing sanctions on Russian oil and gas exports.

Now, the escalation of hostilities between the U.S., Israel and Iran has once again rattled global energy markets. Fighting and the closure of the Strait of Hormuz — one of the world’s most important oil shipping routes — have triggered what some have described as “the biggest oil disruption in history.”

Read more: What is the Strait of Hormuz, and why does its closure matter so much to the global economy?

By early March, oil prices had briefly surged to US$119 per barrel — roughly double their level at the end of 2025. Prices have since settled at near US$100 a barrel, though volatility remains.

The escalation illustrates a familiar pattern in the political economy of fossil fuels: public costs paired with private windfalls.

The shock to global energy markets

Three months ago, few analysts expected 2026 to be a particularly profitable year for fossil fuel producers. Global supply was expanding rapidly and U.S. gas prices were expected to fall below US$3 a gallon.

Production growth in the U.S., Canada, Brazil and Argentina was colliding with weaker demand growth and the ineffectiveness of sanctions on exports from Russia, Iran and Venezuela. Many analysts warned of an emerging glut that could push prices downward. The International Energy Agency, for instance, projected a potential global oil surplus of nearly four million barrels per day in 2026.

That outlook changed abruptly following the U.S.-Israeli attack on Iran and the country’s retaliatory attacks on energy infrastructure and tanker traffic through the Strait of Hormuz, a strategic chokepoint that normally carries roughly one-fifth of the world’s traded oil and natural gas.

Even a partial disruption carries immediate consequences.

Though the strait has been a cornerstone of U.S. and world energy security for more than 60 years, the Donald Trump administration apparently underestimated the possibility that the Iranian regime would blockade it and pummel U.S.-allied countries in the region.

For consumers and most businesses, such price spikes function as a tax. Higher energy costs ripple through transport, food production, manufacturing and household budgets. American drivers feel the impact at the pump, while industries dependent on fuel or petrochemicals see their operating costs climb.

The hidden household costs of war

Estimates suggest that for every increase of US$10 per barrel, additional fuel costs amount to roughly US$560 per year per American household, including costs embedded in goods and services.

If prices remain at around US$86 instead of the expected US$51 forecast for 2026, the added burden could reach about US$2,000 per household annually.

These figures do not include the direct military expenditures, which were conservatively estimated at US$11 billion for the first week of strikes against Iran.

Even military spending of US$200 million per day (10 times less than the highest estimates at the current intensity) would amount to an additional cost of US$541 per household annually.

In short, a prolonged war combining high energy prices and sustained military expenditures would likely amount to between three to four per cent of the median U.S. household expenditure — roughly half of what many families spend annually on food or health care.

Lessons from recent wars

Recent history offers revealing precedents.

The costs of the Iraq War (2003 to 2011) for Americans has been estimated at about US$1.2-3 trillion in total long-term costs, equivalent to about US$16,700 to US$41,750 per household in current U.S. dollars. Yet the war did achieve the goal of reopening access to Iraqi oil fields for American oil companies.

More recently, the invasion of Ukraine by Russia cost an estimated one per cent of global GDP in 2022 and added 1.5 per cent to global inflation in 2022-23. Ukraine, of course, paid the largest price for the war, but direct impacts in Europe amounted to about 1 trillion euros.

Much of these costs ultimately translated into profits for oil and gas companies, especially liquefied natural gas (LNG) companies from the U.S. and producers in Australia and the Gulf states.

Profits on a single LNG shipment from the U.S. to Europe increased fivefold from about US$17 million to US$102 million.

A similar dynamic is now unfolding again.

Who really benefits from rising oil prices?

This time, with major Gulf states themselves exposed to the conflict, U.S. and other exporters less directly affected by the war may have even greater room to increase profits. American LNG companies could see windfalls approaching US$20 billion per month.

The main lesson is that petro-states, including Iran, Russia and the U.S., don’t hesitate to go to war partly because they believe oil revenues will bail them out, if not further enrich them.

In fact, in seeking to justify the attack on Iran and the continuation of the conflict, Trump argued that “the United States is the largest oil producer in the world, by far, so when oil prices go up, we make a lot of money.”

This, of course, depends on who “we” refers to. The populations of most petro-states have paid dearly for the wars involving their countries, whether it’s been Angola, Chad, Iraq, Libya, Nigeria, Russia, Syria and now Iran.

The U.S. has fared much better economically, but the gains have been mostly for its companies, not its population. Higher oil and natural gas prices generate enormous revenues for U.S. oil producers and LNG exporters along the Gulf Coast as global gas markets tighten. Investors and shareholders in these sectors stand to gain from rising margins and market valuations.

American households, however, face the opposite effect. Fuel prices rise. Inflationary pressures intensify. Transport and heating costs increase.

The gains accruing to producers are therefore not only partially financed by the most import-dependent countries with the least strategic reserves but also by low-income households who are stuck in a carbon-intensive economy they can least afford to escape.

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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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By Jody MacPherson

Facing community outcry over the location and regulatory rejection, Synapse Real Estate Group says it will continue to pursue its plans for a gas-powered plant and “Canada’s largest” data centre in the small farming town of Olds, Alberta.

Alberta’s utility regulator rejected the company’s application for a 1.4-gigawatt generating plant to supply the proposed artificial intelligence (AI) data centre, which would use as much power as one million homes. The gas plant would generate three times the power of Suncor’s Firebag cogeneration plant.

The Alberta Utilities Commission (AUC) issued [pdf] the decision in a letter to Synapse CEO Jason van Gaal on March 6, citing “significant deficiencies” in environmental evaluations, noise impact assessments, and “particularly” the company’s failure to consider concerns from those “directly and adversely affected by a proposed development.”

“I think, ultimately, the AUC wants to make sure that we’re communicating effectively with the community and receiving feedback, and we’re absolutely doing our best to do that,” van Gaal told The Albertan in an interview.

Van Gaal replied to The Energy Mix’s questions with a prepared statement, writing, “the commission made clear this decision does not assess the merits of the project and that Synapse can reapply once the required information is completed. We are reviewing the guidance and will work with regulators and the community to ensure the next application fully meets those requirements.”

More than 40 residents of Olds submitted objections to the Synapse power plant, citing concerns about noise, mental health impacts, health effects of air pollution, water usage, property values, stress on municipal infrastructure, electronic waste, chemicals, and affordability for low-income residents.

But Olds town council welcomed the province’s second-largest gas-powered plant to use 300 acres of farmland within the town’s eastern boundary, reclassifying it as “light industrial.” Olds is about 90 kilometres north of Calgary, and has a renowned agricultural college, beloved locally for its botanic gardens and wetlands.

“I don’t believe it is ‘light industrial’ zoning,” Janey Olson, an 18-year resident of Olds, told The Mix. “If you go by the description of what heavy and light are, this is heavy industrial.”

Olson said a group of residents who attended the town’s zoning meeting had asked the council to “please table that decision until we know more,” but the zoning decision still went ahead.

The Mix emailed Olds Mayor Dan Daley about the Synapse project zoning two weeks ago but he has not yet responded. This story will be updated with any new information he provides.

The town had declared the company’s development permit complete the same day the AUC decision was issued. Synapse has now withdrawn its development permit application, according to the Town of Olds website.

In its letter, the AUC said the company could reapply in the future, but detailed several deficiencies:

• The participant involvement program lacked detail and sufficient information;

• Information in the environmental evaluation document was provided in draft format;

• Field studies on wildlife and wetlands were incomplete;

• The noise impact assessment did not include the project’s 600 backup diesel generators;

• The plan was missing a reclamation security plan; and

• The company filed an incomplete listing of other approvals required.

Synapse stated in its application that the federal Impact Assessment Act did not apply to the project. But the AUC said Synapse would have had to submit a project description to the Impact Assessment Agency of Canada to determine whether the Act applies, adding that any new fossil-fired power generating facility with production capacity of 200 megawatts or more falls under the Act.

On March 9, Olds Chief Administrative Officer Brent Williams said he would be meeting with the company and the AUC separately in the coming days.

For some residents, the AUC rejection brings an opportunity to pause and take stock in what has been a busy couple of months since finding out about the proposal.

Eric Carlson, who lives about 600 metres from the proposed site with his wife and three children, told The Mix he had full trust in the AUC’s process and appreciated the care the commission took to ensure applications meet the required standards before moving forward.

But he is now preparing to go through the process again, since Synapse is pressing on with the power plant in its same location.

Rachel Sorenson, whose home is directly across the street from the project, said she wouldn’t be able to stay if the project goes ahead. A retired paramedic, she told The Mix she was elated when she heard of the AUC decision, but that was short-lived when she found out Synapse would be reapplying.

“I love Olds, it is a beautiful close-knit community,” she said, “but there are no health benefits to living next to a power plant.” She has serious concerns for herself and one of her grandsons who suffers from asthma. Sorenson believes the Synapse plant is not appropriate within town limits.

Edmonton-based resident doctor Julia Sawatzky, a board member and Alberta regional co-chair for the Canadian Association of Physicians for the Environment (CAPE), told the Mix in September that nitrogen oxides from gas turbines are released into local communities, causing air pollution that contributes to respiratory diseases.

“We know that nitrogen oxides can contribute to both the development of asthma and chronic obstructive pulmonary disease,” she said. “And there’s also small particulate matter emitted from gas turbines which is similar to what is in wildfire smoke or other really visible heavy air pollution.”

The particulate matter is so small that it can lodge deep in the lungs and also cross over into the bloodstream, contributing to high blood pressure and causing heart attacks and strokes, Sawatzky said.

Gas turbines also emit volatile organic compounds that are known carcinogens, putting people at risk, or higher risk, of various types of cancer.

“It’s actually an environmental justice issue because the projects and the impacts and the harms are being put in places far away from places like Edmonton and Calgary where the decisions tend to be made,” Sawatzky added.

Sorenson said another citizen-led meeting March 13 will a chance for Olds residents to gather to discuss how the power plant and data centre will affect their daily lives. Olson said she’s written a letter to Premier Danielle Smith and, along with several other residents, met with the local Member of the Legislative Assembly, Tara Sawyer. She has questions about cumulative impacts on the regional water supply and whether the province is doing its due diligence on AI data centre developments, but said she has yet to receive answers.

“We’re not a big city, we are a small town, and I don’t remember when we agreed as a small town to become a tech hub for the province or for our council,” she said. “I just don’t remember that conversation happening.”

Synapse’s public statement about the setback concluded with: “We have taken the AUC’s guidance and our community’s feedback to heart, and we are pleased to launch www.synapsedatacenter.com/we-are-listening/ as a first step in facilitating our long-term dialogue.”

The web page includes a series of videos to answer common questions about the project. When Olson watched one of the videos, she noticed it had a “strange voiceover.”

“I might have been tongue in cheek, but I said, Jason, you didn’t hire a local voice actor, you hired an AI?”

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