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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The report, Path of Most Resistance, argues the province’s proposed pathway to net-zero electricity emissions by 2050 depends largely on natural gas plants equipped with carbon capture and storage (CCS), hydrogen fuel and future nuclear technologies such as small modular reactors (SMRs).

Those technologies could eventually play a role in reducing emissions, the Calgary-based think tank says, but relying on them as the backbone of the power system represents a series of “risky bets.”

The analysis comes as Alberta negotiates with Ottawa over the future of electricity regulation under a Canada–Alberta memorandum of understanding signed last November.

Under the agreement, the federal government has indicated it could suspend its Clean Electricity Regulations in Alberta if the province can demonstrate that its own policies would achieve equivalent emissions reductions.

Pembina says that outcome should depend on whether Alberta presents a credible and detailed alternative plan.

Heavy reliance on uncertain technologies

The report argues Alberta’s current strategy places a large share of its emissions reductions on technologies that remain expensive, uncertain or years away from widespread deployment.

Carbon capture has been demonstrated at only a handful of power plants globally. Small modular reactors are still under development, with most projects not expected to come online until the 2030s or later.

Hydrogen, which Alberta officials have promoted as a potential fuel for power generation, also faces significant economic and technical hurdles, including high production costs and transportation challenges.

According to Pembina researchers, relying on these technologies to decarbonize Alberta’s grid could delay emissions reductions and increase costs if they fail to scale as expected.

Renewable growth slowed by policy changes

At the same time, the report says provincial policy decisions over the past two years have slowed the development of wind and solar power.

In 2023 the Alberta government imposed a seven-month moratorium on approvals for new renewable energy projects while regulators reviewed land-use rules and grid impacts. The government later introduced new regulations governing renewable development.

Since the moratorium began, nearly 11 gigawatts of wind, solar and energy storage projects have left the Alberta Electric System Operator’s development queue, according to Pembina analysis.

That amount of capacity exceeds Alberta’s average electricity demand.

The province had been a national leader in renewable energy development earlier in the decade, attracting the majority of new wind and solar investment in Canada.

But analysts say regulatory uncertainty and shifting market rules have made developers more cautious about building projects in Alberta.

Government emphasizes reliability

The Alberta government has defended its approach, arguing intermittent power sources such as wind and solar must be balanced with reliable generation to maintain grid stability and keep electricity affordable.

Provincial officials have pointed to natural gas, nuclear and emerging technologies as key components of a reliable, low-emissions electricity system.

However, the Pembina report suggests Alberta could reduce emissions more quickly and at lower risk by accelerating renewable deployment while expanding grid connections with neighbouring provinces.

Greater electricity trade with hydro-rich provinces such as British Columbia and Manitoba could help balance renewable generation by using hydroelectric reservoirs as a form of large-scale energy storage.

Industrial self-generation — including rooftop solar, geothermal and on-site wind generation — could also help reduce demand on the grid while cutting emissions from heavy industry.

Negotiations with Ottawa could shape future

The negotiations between Alberta and the federal government could determine how the province’s electricity sector evolves over the coming decades.

If Alberta can demonstrate a credible pathway to reduce emissions while maintaining reliability and affordability, Ottawa may allow the province to regulate its electricity sector independently through an equivalency agreement.

But if the province’s strategy relies too heavily on technologies that take decades to scale, Pembina warns Alberta could risk missing emissions targets while other jurisdictions move ahead with cleaner power systems.

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By Mitchell Beer

An updated industrial carbon pricing system must deliver outcomes as well as optics, the Canadian Climate Institute (CCI) concludes this week, based on a review of 57 possible future scenarios for how Alberta’s emission pricing system can deliver on a target price of $130 per tonne of carbon dioxide emissions by 2030.

The $130 target under Alberta’s Technology Innovation and Emissions Reduction (TIER) regulation is built into last November’s controversial memorandum of understanding (MOU) between the Canadian and Alberta governments. But the climate institute warns there’s a difference between the advertised price per tonne in a carbon regulation and the effective marginal credit price (EMCP)—the real-world price a carbon polluter actually has to pay, and therefore the strength of the incentive they receive to reduce their emissions.

The institute released its analysis [pdf] this week as Environment and Climate Change Canada (ECCC) looks into whether the federal government’s current benchmarks for industrial carbon pricing “can distinguish systems that merely function from those that deliver outcomes of equivalent stringency,” the CCI paper states. Most of the 57 scenarios could meet the 2030 benchmark on paper, “yet fail[ed] to deliver stringency equivalent to $130-per-tonne EMCP.”

The analysis by CCI Chief Economist Dave Sawyer and Executive Vice President Dale Beugin found that:

• 84% of the scenarios met the federal government’s design criteria for a provincial pricing system;

• But of those apparently successful design options, 77%  failed to deliver the equivalent of a $130-per-tonne EMCP by 2030, meaning that only 11 of the original 57 succeeded.

A High-Stakes Review

The stakes for the ECCC review are high, the paper states, since this year’s decisions on system design and stringency will shape Canada’s industrial carbon pricing market into the 2030s.

The review is also taking place in a deeply politicized atmosphere, with Canada facing a serious sovereignty threat from south of the border and a separation referendum likely to take place in Alberta this year. “Against this backdrop, the federal government has launched a process to modernize large-emitter trading systems,” CCI writes. “The first track is regulatory and technical,” while “the second track is political and bilateral, centred on negotiations between Canada and Alberta.” The paper says the Canada-Alberta MOU sets the $130-per-tonne benchmark, but contains no plan or deadline to meet the stringency target.

The weaknesses in the current system have been accumulating for some time, the institute says. Existing large-emitter trading systems (LETS) “are opaque, rely on outdated design choices, and have been systematically weakened by provinces over time.” The federal government, meanwhile, has been inconsistent in its oversight and “reluctant to impose the backstop where provincial systems fall short, most notably as Saskatchewan zeroed out its industrial carbon price in 2025.”

But improving the system wouldn’t just make it easier to link provincial carbon trading systems and reduce disparities between polluters operating in different jurisdictions: “It would also help shield Canadian exports from rising border carbon tariffs, including the EU Carbon Border Adjustment Mechanism.”

Asked what it would take for the federal government to adopt a more consistent, evidence-based pricing strategy, Beugin replied that “grounding the benchmark in concrete, transparent metrics of stringency is the best way to shift the federal government’s approach to industrial carbon pricing. It’s currently too easy for provincial systems to comply with the federal benchmark without delivering robust carbon markets with strong incentives to invest in low-carbon projects.  That’s why we’ve proposed an approach that’s focused on market outcomes and ensuring a minimum effective carbon price in each system.”

In response to Trump’s annexation agenda and the separatist threat at home, the CCI’s plan would also “ensure provinces have plenty of flexibility in designing provincial carbon markets,” Beugin added in an email. “We’re suggesting that the federal benchmark makes provinces accountable for delivering an outcome (minimum effective carbon price) without being prescriptive as to how. Provinces can and should tailor their approach to their own context.”

An ‘Unresolved Tension’

However, in the consultation materials that ECCC released late last month, the climate institute said it detected an “unresolved tension” between the carbon pollution price signal the government wants to send and the tools it is proposing to assess polluters’ performance.

“By establishing minimum national stringency standards, the benchmark seeks to ensure that regulated facilities face comparable incentives to reduce emissions and invest in low-carbon technologies,” the CCI explains. But the gap is in the detailed factors ECCC is proposing to measure, including market balance, credit availability, and banking dynamics. “These considerations are necessary to ensure market operation and compliance feasibility,” the paper states, but they aren’t enough on their own to ensure that provincial pricing systems meet the federal target, and meet it on schedule.

“This distinction matters. The relevant question is not simply whether systems adopt the minimum national carbon price (MNCP) schedule, but whether the price signal delivered by the system achieves the intended outcome,” the CCI stresses. “Tests of net demand, market balance, and static banking metrics are useful for determining whether a market is operational. They are not sufficient for determining whether a system meets a given stringency requirement.”

The report identifies the size of the buffer—the extent to which a carbon pricing system adapts to keep the demand for carbon credits higher than the supply—as a key factor driving the stringency of the system. A 6% buffer, the level ECCC has proposed, is enough to keep a carbon market from failing. But carbon pricing systems only “begin to deliver stronger outcomes” with buffers of 10 to 305. They can only deliver reliable price signals, consistent with the federal targets, with buffers of more than 30%.

What Works, What Doesn’t

The CCI paper identifies tighter benchmarks over time as the single most important tool to create a scarcity of carbon credits and reduce emissions. By contrast, that stringency is severely diluted by direct investment credits that allow polluters to directly fund emission reduction projects instead and increase the number of carbon credits in the system while paying a lower carbon price.

“In the scenarios, introducing direct investment credits reduces costs by roughly two-thirds and cuts abatement by more than half,” the paper states. “The cost savings are therefore not a productivity improvement but rather a dilution of policy stringency.”

With a half-dozen policy options included in the analysis, the paper lays out a “clear hierarchy of levers,” Sawyer and Beugin write. “Benchmark tightening does the heavy lifting for equivalency attainment. Floor escalation and banking controls protect and stabilize the signal that benchmarks create. Credit and offset limits provide guardrails. Direct investment credits, by contrast, act as a dilution lever capable of neutralizing even aggressive benchmark tightening.”

The two authors recommend four steps to bolster the system:

• Strengthening the investment incentive for emission reductions—in an updated federal benchmark, and in the MOU—by basing it on what carbon polluters actually have to pay, rather than the average market price of the credits;

• Allowing Alberta and other provinces to find their own way to hit the $130 threshold “subject to a small set of non-negotiable conditions” to ensure their programs meet the test for stringency—including benchmarks that get progressively tighter, minimum and maximum prices that shift over time, and limits on compliance options that dilute the carbon price’s impact;

• Requiring data that is transparent and credible enough to verify compliance;

• Tracking performance over time.

“Taken together,” they write, “these recommendations support a benchmark framework that verifies equivalency based on outcomes rather than optics while maintaining flexibility in provincial system design and strengthening confidence that industrial carbon pricing delivers federal climate objectives.”

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By Stewart Prest

The recently struck memorandum of understanding (MOU) between Canada and Alberta is a high-stakes strategy that risks deepening already deep divides in Canadian politics.

While the MOU touches on a number of issues, at its heart is a shared vision for a new pipeline from Alberta to British Columbia’s protected northern coast.

In effect, the deal offers a quid pro quo: Ottawa agrees to relax a range of federal environmental regulations — including a ban on tanker traffic in B.C.’s north — and to support a pipeline in exchange for a commitment from Alberta to eventually increase the price of carbon on industrial emissions in the province to $130 a tonne.

It’s a vision negotiated without the involvement of either the B.C. government or the Indigenous Peoples affected by the plan. While the agreement calls for consultations with both groups, they are relegated to the status of secondary partners, with concerns to be addressed in the execution of the plan outlined by Ottawa and Alberta.

A policy solution for an identity issue

The deal is clearly meant to bridge the gap between populist voters centred in the Prairie provinces and the rest of the country. But both the content and the process risks widening that gap, even as it deepens divisions elsewhere in the country.

Simply put, Prime Minister Mark Carney is trying to find a policy solution to an identity problem, and doing so by picking sides rather than neutrally facilitating agreement.

It’s part of the polarized, populist identity in Alberta, in particular, to oppose Ottawa and Liberal governments. In fact, when Alberta Premier Danielle Smith referred to the MOU in front of the United Conservative Party (UCP) convention, she was roundly booed. Rather than being hailed as champion who had achieved valuable policy concessions, she was greeted as a traitor to the cause.

Given the rude reception, it’s not surprising that in recent days Alberta has sought ways to limit its environmental commitments.

Read more: How ideology is darkening the future of renewables in Alberta

Playing favourites in the federation

Over the longer term, the agreement risks legitimizing the narrative of “Alberta aggrieved” by treating it as a distinct, sovereign jurisdiction entitled to special treatment.

In fact, the trappings and language of the agreement seem to reinforce the idea that “Alberta” is a natural negotiating partner with “Canada” rather than part of Canada.

The MOU’s signing ceremony in Calgary — not the provincial capital of Edmonton or Ottawa — bore all the hallmarks of international treaty-making, complete with flags and a formal text in both official languages. The symbolism reinforced the image of the deal as a kind of grand bargain between Ottawa and oil country.

While the federal government often strikes deals with provincial governments, this situation is quite different. It’s a deal only with Alberta but it primarily involves British Columbia. The agreement therefore elevates Alberta to the level of a quasi-sovereign jurisdiction to be treated as an equal with Canada. B.C., site of any future hypothetical pipeline terminals, has been rendered a deal-taker, not a deal-maker.

Unfortunately, that’s not how the federation is supposed to work. Just because the federal government has ultimate jurisdiction doesn’t mean other regions don’t get a say. It’s hard to imagine the federal government striking a deal with Ontario about what should happen in Québec without Québec’s involvement.

Read more: Alberta has long accused Ottawa of trying to destroy its oil industry. Here’s why that’s a dangerous myth

B.C. fury

B.C. Premier David Eby was accordingly furious with the federal government’s approach before the deal was announced.

Since then, while pointing out weaknesses in the deal, the NDP premier has also been at pains to show his willingness to work with Alberta on workarounds, including an expanded Transmountain pipeline or another pipeline that would leave the oil tanker moratorium in place on B.C’.s northern coast.

In leaving Eby out of the conversation, the federal Liberals have alienated a natural ally in their pursuit of economic development, forcing the premier to defend B.C.’s status within the federation, the rights of the province’s Indigenous communities and the province’s protected northern coast and Great Bear Rainforest.

Constitutional obligations to consult

Even more telling is the united reaction of First Nations. The Assembly of First Nations has unanimously voted in favour of a motion calling for the MOU to be scrapped. In fact, the federal government may have put itself in legal jeopardy over its failure to consult prior to the MOU.

At some point, it will likely have to explain in court how it could be serious about consulting in good faith with Indigenous Peoples in accordance with its obligations under Section 35 of the Constitution Act when the MOU gives the appearance of approving the project in principle before such conversations even begin.

Offering ownership stakes to Indigenous groups in a project devised without their involvement is not consultation. Simply put, unless governments can show they’re open to amending their plans in light of information they receive during consultations, they risk falling short of their obligations.

Cracks in the Liberal coalition

While polls suggest a majority of Canadians support the idea of a pipeline so far, the Liberals’ own coalition shows some signs of fraying.

Former environment minister Steven Guilbeault’s resignation from cabinet over the deal, along with the resignations of multiple environmental advisers to the Liberal government, suggest the party’s reputation for environmental progress has taken a hit given the slow and fuzzy approach to climate action outlined in the MOU.

Other federal parties sense an opportunity. The Bloc Québecois has strongly denounced the deal and has offered to support B.C. in its campaign to defend the province’s autonomy. The move underscores the sensitivities that remain in Québec around issues of provincial rights.

Even more tellingly, federal Conservatives, perhaps initially dismayed by a deal uniting federal Liberals and Alberta Conservatives, are now putting a motion before the House of Commons asking it to endorse the government’s position on the MOU and make good on its commitments. The Liberals, for their part, have vowed to vote against the motion, arguing that it only endorses part of the MOU.

In effect, the Conservatives are seeking to turn the government’s own MOU into a wedge issue against it. The Conservatives will likely continue to press the issue going forward given how the idea of a pipeline at any cost unites Conservatives and divide Liberals. Liberal MPs in B.C. and Québec, in particular, will also likely feel torn between loyalty to the party and deference to the views of constituents opposed to the deal.

In short, a pipeline intended to unify threatens to throw divisions into even sharper relief — even within the Liberal Party itself.

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Alberta has introduced changes to its industrial carbon pricing that will make it harder to meet a key commitment in its new memorandum of understanding (MOU) with the federal government.

The amendments to the province’s Technology Innovation and Emissions Reduction (TIER) Regulation were announced in September but formally introduced December 5, the Canadian Climate Institute reports, scarcely a week after Premier Danielle Smith and Prime Minister Mark Carney signed the controversial MOU. In addition to—and perhaps in exchange for—laying the groundwork for a new bitumen pipeline from Alberta to British Columbia’s environmentally sensitive northwest coast, the MOU commits the two governments to increase carbon credit prices under TIER to $130 per tonne, after reaching an agreement on industrial carbon pricing by April 1.

Even though it fell short of the current federal pricing benchmark of $170 per tonne by 2030, that target was still walked back by Smith’s chief of staff, Rob Anderson, within hours of the signing. Even so, news reporting in the days after the MOU identified the industrial carbon pricing deal as the key win the federal government was looking for, even if it mean trading away hundreds of millions of tonnes of emission reductions through the federal Clean Electricity Regulations.

But days later, Smith’s government “introduced regulatory changes that will flood the province’s industrial carbon pricing market with credits and further weaken the carbon price signal for major emitters,” the Climate Institute’s Principal Economist Dave Sawyer said in a statement Friday.

“By issuing new compliance credits for direct investment and reactivating previously used credits, Alberta is adding more supply to an already oversupplied market,” he explained. “These changes work against the direction set out in [the MOU], which included commitments to strengthen Alberta’s industrial carbon pricing system. When Alberta first signalled its intent in September, TIER credit prices crashed to below $20. This change locks in that crash, and puts significant downward pressure on future prices.”

Achieving the $130 target in the MOU, by contrast, “would require immediate steps to close loopholes in the credit market and address the oversupply of credits” that drives down their value and makes the system as a whole less effective, Sawyer added. “Instead, introducing new investment credits increases oversupply, weakens the price signal, and moves Alberta further away from the path needed to reach $130 per tonne.”

“Well that didn’t take long,” veteran energy policy analyst Dan Woynillowicz wrote on LinkedIn. “When someone shows you who they are, believe them the first time.”

Although Alberta first announced the regulatory change in September, “following through was a choice, and undoubtedly one made very deliberately,” Woynillowicz added in a follow-up post. “Expect Alberta to continuously test the federal government for weakness, using moves like this to inform their approach at the negotiating table.”

In a statement to the Toronto Star, Alberta Environment Minister Rebecca Schulz said the changes would entice more companies to invest sooner in emissions reduction technology. “We’re implementing the changes announced in September to defend jobs and keep industry competitive while still reducing emissions,” she said. “This will lead to more emissions being reduced and a stronger system.”

But University of Calgary energy science professor Sara Hastings-Simon told the Star that made no sense. An oversupply of carbon credits had already brought Alberta’s “headline” industrial carbon price down to $95 per tonne, making it more palatable for companies to buy the credits rather than investing in actual emissions reductions.

“I don’t think there is a credible argument that this action is making the system stronger,” Hastings-Simon said. “It’s doing the opposite.”

Former federal environment minister Steven Guilbeault, who resigned from the Mark Carney cabinet over the MOU, agreed that the regulatory change would make it harder for Smith to keep her promises. “Is this what Premier Smith meant when she spoke of proceeding ‘with a (measure) of good faith’?” he wrote on social media.

In his Thoughtful Energy Journalism newsletter, energy transition expert Markham Hislop speculates that Smith must have known all along what she was doing.

“It is inconceivable that a policy change that directly affects a major agreement with Ottawa was brewing in the Department of [Energy and Minerals] and Smith knew nothing about it,” he writes. “A reasonable inference, then, is that she did know. And if she knew, then she negotiated the deal in bad faith.”

In the aftermath of the MOU, Guilbeault is now warning that the Carney government has put Canada’s climate targets out of reach while fuelling Quebec separatism.

“With what has been announced, there’s no way Canada can meet its 2030, even its 2035, climate change objectives,” he told the Bloomberg news agency. “And frankly, I doubt that we could even be carbon neutral by 2050.” And “there is a feeling right now that by abandoning our climate goals we are fuelling the separatist movement,” the Montreal-area MP and former Canadian identify minister warned on CBC.

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By Jody MacPherson

This story is part of The Energy Mix ongoing investigative series, Hidden Wonder Valley.

Celebrity investor Kevin O’Leary’s proposed $70-billion data centre, designed to run on 7.5 gigawatts of gas-fired power, could raise Alberta’s greenhouse gas emissions to levels not seen since the coal era, according to estimates obtained by The Energy Mix.

Planned in an area battling drought, the project’s water needs would also be vast, rivalling the annual use of hundreds of thousands of Alberta households.

Wonder Valley is still nowhere near getting off the ground. But if it ever gets built as planned, it could pump out 25.7 to 30.5 megatonnes of emissions a year, depending on what turbines and gas are used, and whether or not it includes carbon capture, found [pdf] Pembina Institute Senior Analyst Jason Wang, who crunched the numbers for The Mix.

“It would be the equivalent of a return to the era of mostly coal-fired electricity,” said Wang.

The reversal would set the province and Canada back about 20 years, matching the 27 megatonnes of coal emissions Alberta phased out between 2005 and 2023.

The data centre complex, which O’Leary claims will be the “largest on Earth,” would require the equivalent of about 10 per cent of all gas supply in Alberta once fully operational.

It’s still just a concept, but in the Municipal District of Greenview where it’s planned, local officials are confident it will be built.

“We’re about to pull off the largest project in Canadian history in this sector and I think Greenview should be really proud of that,” Chief Administrative Officer Stacey Wabick told council members at a budget review meeting in November.

Wonder Valley was announced with great fanfare last December, a few days after the Alberta government unveiled a new data centre strategy designed to attract $100 billion in investments.

At the time, Innovation and Technology Minister Nate Glubish said data centres would play a “significant role” in Premier Danielle Smith’s plan to double oil and gas production by increasing domestic demand for gas.

The land designated for Wonder Valley is south of Grande Prairie, about 460 kilometres northwest of Edmonton. It’s located on the massive Montney Formation, one of North America’s, and perhaps one of the world’s, largest gas reservoirs.

Wang said the first phase of the project, requiring 1,400 megawatts (MW) of power, would generate about 4.7 megatonnes of carbon dioxide per year using shale gas to run a combined-cycle gas turbine, the most efficient type of gas power. That would make it one of the largest industrial facilities in the province, he said.

Carbon capture and storage has been promised for Wonder Valley, but not necessarily at startup. Wang said a carbon pipeline would need to be built between the facility and an injection site.

“With carbon capture efficacy at about 80 per cent, it would still mean the first phase of Wonder Valley would be 1.3 Mt/year of greenhouse gas emissions,” Wang said.

Huge Water Demand, No Consultation

Another requirement for data centres is the large amount of water they use for cooling. But water is also needed to run gas power plants. Even though the Grande Prairie area is known for longer, colder winters, Wang estimated the water needed for the fully completed data centre, including both cooling and for the power plant, would be between 112 and 195 billion litres per year. That is roughly one-third to two-thirds of the total annual water consumption of all the households in Alberta.

Multiple communities in the region are struggling with drought and water supply issues. Greenview itself declared an agricultural disaster due to drought this past summer, and that same day, its council approved adding more land to the purchase agreement being negotiated with O’Leary.

The nearby Sturgeon Lake Cree Nation (SLCN) received public assurances from the province that it would be consulted before water permits were issued. But records show that Greenview was granted Water Act licences for withdrawals from two locations on the Smoky River at the proposed Wonder Valley site before the First Nation’s input was sought.

“To this day, we have heard nothing from O’Leary other than generic statements, and Greenview has not said a word to us since the spring of 2024,” SLCN Chief Sheldon Sunshine told The Mix in a Dec. 1 email, adding that there has been “no meaningful consultation.”

“In fact, they claim there is no project, so we are completely in the dark.”

Jonathan Gauthier, press secretary to Glubish’s ministry, told The Mix in January that Environment and Protected Areas (EPA) had issued Greenview a “preliminary certificate which will allow a Water Act licence to be issued in future, provided various mandatory conditions are met,” emphasizing that the conditions included “appropriate consultation with First Nations.”

According to court-filed documents [pdf] provided to The Mix, SLCN requested a copy of the preliminary certificate, but never received it. When they met with then-Indigenous relations minister Rick Wilson, Glubish, and officials from the province’s Aboriginal Consultation Office (ACO) in April, they say they discovered that on top of the preliminary certificate, a full water permit had been granted without their knowledge. The full permit was dated one day before the meeting.

SLCN filed an appeal of the water licence to the environmental appeal board, which according to documents viewed by The Mix, Greenview has applied to strike, saying the board cannot consider Treaty and Aboriginal rights. Alberta has supported Greenview’s position.

In the public filing, SLCN said ACO officials told them they did an assessment and decided there was no duty to consult because “the issuance of the licence would have no impacts on SLCN’s Treaty and Aboriginal rights.” The Nation is asserting the land is part of their traditional territory, that members have registered traplines throughout the area, and that they should have been consulted.

“We knew AI data centres were water guzzlers. We didn’t know it was that bad,” Sunshine wrote to The Mix. “We also know that taking this much fresh water and then releasing it causes increased toxins, which is detrimental for us as well as those that farm, but where is the opposition?”

Putting Gas First

Many data centre developers around the world are looking to clean, cost-effective renewable energy to power their projects because “it’s cheaper to get electricity from wind and solar than it is from gas,” Pembina’s Wang said. Clean technology industrial areas are springing up in the United States, where renewable energy and data centres are located together, using “green” steel and cement.

“Renewable energy can be built faster right now than gas turbines can be procured and installed,” he added. And there could be an opportunity for wind and solar if Alberta loosened up some of its renewables restrictions, noting that the government had promised to open up an engagement process on the possibility of solar and wind development on Crown land.

Greenview has seen past plans fall through for the site they’ve dubbed the “Greenview Industrial Gateway.” In 2021, then-premier Jason Kenney said a planned $2.5-billion petrochemical plant to produce ammonia and methanol from gas was a “sign of hope in the province’s recovery.”

Northern Petrochemical Corporation’s website is still under construction four years later. CEO Geoff Bury did not respond to The Mix’s request for an update. In 2023, The Progress Report wrote that Bury expected to reach a final investment decision in 2024.

A combined geothermal and carbon sequestration project was also announced for the site by Alberta No. 1 Geothermal Energy, but the company’s website hasn’t been updated with any progress since July 2023.

“There definitely are opportunities for exploring other types of energy in my view,” Wang said, adding that Alberta is upgrading [pdf] the electricity line to Grande Prairie and most data centre projects see more benefits from being grid-connected due to the very high standard for power availability.

“And that might not mean the specific area where Wonder Valley is proposed, but maybe just a few kilometres away there’s really good potential that could be tapped into.”

Alberta’s “gas-centric” data centre strategy has also raised questions from energy experts who say the province may be sabotaging its own aspirations by discouraging wind and solar power.

But a new 2 per cent levy on data centres requiring grid connection favours projects that “bring their own power.” That makes the province’s ubiquitous gas more of an option as long as renewables are bogged down by Alberta’s strict regulations.

The Globe and Mail reports that around 29 data centre projects have requested connection to the grid for access to 16,000 MW, but the provincial grid operator has put a cap on the amount of electricity available to data centres.

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By Jody MacPherson

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By Mitchell Beer

The global oil industry is facing down a “flashing red warning light” and firing thousands of workers as analysts project several years of low prices, just as the government of Prime Minister Mark Carney debates whether or when to designate a new oil pipeline as a priority project of “national interest”.

“The world’s biggest oil and gas companies are cutting jobs, slashing costs, and scaling back investments at the fastest pace since the coronavirus market collapse,” the Financial Times reports. “Spending plans have been reined in, with some projects paused or put up for sale as groups seek to balance the books.”

That news landed with Canadian media reporting that a new oil pipeline will not be included in the hotly-anticipated first list of national interest projects the federal government was due to release Thursday, September 11, notwithstanding a tentative list published by the Globe and Mail last week.

However, “behind the scenes, a Liberal source insisted that the absence of a pipeline on the initial list does not mean that one will never happen,” CBC reports, citing interviews gathered by Radio-Canada. “Approval of a natural gas pipeline project is also not out of the question.”

When the PM and Alberta Premier Danielle Smith discussed the matter over the summer, “Carney was clear: the involvement of a private developer is essential for a project to move forward,” CBC writes. “So far, no company has expressed interest in financing or carrying out such a project.”

But Smith is still pushing Carney to rescind the federal Impact Assessment Act and cap on oil and gas emissions, both enacted by the previous government led by then-PM Justin Trudeau, The Canadian Press says. She’s claiming those regulatory factors are the only thing holding back investment.

And yet, the impact of weak oil prices is affecting projects across the globe. The impact is falling most obviously on the U.S. shale industry, where the Times reported last week that colossal fossil ConocoPhillips was cutting one-quarter of its work force. That dispatch attributed the price drop to the decision by the Organization of the Petroleum Exporting Countries and its allies (OPEC+) to increase production, combined with “soaring production costs” brought on by Donald Trump’s tariffs on steel and other inputs.

But “this isn’t just a Conoco problem,” Kirk Edwards, president and CEO of Odessa, Texas-based Latigo Petroleum, told the Times. “It’s a flashing red warning light for the entire U.S. oil and gas industry.”

Crude oil prices are down by half from their peak during Vladimir Putin’s 2022 invasion of Ukraine, and “an OPEC+ decision at the weekend to continue boosting output, despite forecasts of a looming supply glut, will add to the price pressure.” the Times adds. At a price below US$60 per barrel—the threshold that analysts at Wood Mackenzie are projecting through the next few years—”none of the big western oil companies can cover their investment plans and the dividends and buybacks that investors expect.” Their borrowing, meanwhile, has been creeping up, with some companies taking on new debt to pay off their shareholders.

And it’s not just the U.S. or North American industry.

“Even the largest state-run energy companies have not been immune, with Saudi Aramco selling a $10-billion stake in a pipeline network to raise cash and Petronas of Malaysia cutting 5,000 jobs from its work force,” the Times writes. WoodMac expects capital investment in oil and gas production to fall 4.3% this year, its first drop since 2020, though it will still come in at $341.9 billion.

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By Mitchell Beer

Alberta has lost 10.7 gigawatts of clean energy capacity in the two years since the province slapped a moratorium on renewable energy and battery storage development, enough to meet 109% of its average power demand and 89% of its peak demand, in what the Pembina Institute calls an “alarming milestone”.

The analysis shows 5.3 GW of solar+storage, 1.6 GW of wind+storage, and 3.8 GW of stand-alone storage projects that have been withdrawn since October 2023 from the project development queue maintained by the Alberta Electric System Operator.

Those losses were equal to 109% of Alberta’s average electricity demand and 89% of its peak demand, Pembina says. Last year, The Narwhal reported that nearly 80% of the province’s electricity was supplied by gas, most of it coming from a few large suppliers—Enmax, Heartland Generation, Capital Power, and TransAlta.

“Though not all proposed projects make it all the way to completion, cancellations for renewables over the last two years have been concerningly high, at 44%,” Pembina writes. “By comparison, 11% of gas capacity proposed in the same time frame has been cancelled.”

The cancellations are about more than just lost power supply, said Will Noel, senior analyst in Pembina’s electricity program.

“Economic development from renewables is not just economic development from renewables,” he told The Energy Mix. “It’s vitally important to clean up our power supply and keep it affordable so we can attract more investment from other sectors like data centres that are looking for clean, cheap power.”

Those investors are now turning to provinces like British Columbia for wind and solar, or to Ontario for battery storage, he added. “If Alberta wants to diversify its economy, it can’t really do it without cleaning up its grid.”

The string of cancellations also “means that Albertans are losing out on low-cost power—as well as tens of millions of dollars each year of potential tax revenues, which would have largely gone to rural municipalities,” Pembina writes. The latest estimate from the Pembina-affiliated Business Renewables Centre-Canada, published last year, pegged those local losses at $91 million per year spread across 53 cancelled projects, some of them in cash-starved rural communities where fossil companies of steadfastly refused to pay their taxes.

The latest Pembina Institute infographic shows another 19 GW of projects that are still in progress as of this month.

The new data is an update on a May 2025 report [pdf] that “detailed the litany of challenges faced by renewable energy developers in Alberta,” Pembina said in a release. “This includes outright bans and ambiguous restrictions on areas of land where wind and solar projects can be built, new requirements relating to equipment recycling and land reclamation, and changes to transmission legislation, all of which will likely add new regulatory burdens and upfront costs.”

It’s “notable,” Pembina adds, “that many of these new requirements are not equally applied to other industries, including other energy sectors such as oil and gas.”

Earlier this month, Pembina said Alberta’s renewable energy queue had hit a four-year low—even as other provinces like British Columbia and Nova Scotia moved to get new projects under way.

“I’d love to hope that this is as bad as it gets and that we can see things turn around,” Noel told The Mix. “We really need to restore that certainty for investors,” including tech companies like Bell Canada, Microsoft, and Amazon as well as big cities like Edmonton and Calgary.

“Right now, both buyers and developers don’t know what the costs are going to be because of all of these price impacts, the stack of policy decisions and market changes and transmission regulations. We really need to see concrete answers in order to spur these contracts.”

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In 2024, Canada experienced strong growth in natural gas liquids (NGLs) exports, driven by increased natural gas production in Alberta and British Columbia. This rise in gas output led to greater production volumes of NGLs, including propane and butane. Daily exports of Canadian NGLs in 2024 averaged 218.3 thousand barrels per day (Mb/d) for propane and 56.1 Mb/d for butane, representing an 9.2 per cent increase for propane and a 15.0 per cent increase for butane from the previous year’s volumes.

In 2024, the average export price of propane rose to 33.93 Canadian cents per litre (¢ /L), up from 30.31 ¢ /L in 2023. The total value of propane exports reached $4.31 billion (3.15 billion USD⁽¹⁾) in 2024 , an increase of 22.6 per cent from the previous year.

In 2024, the average export price of butane was 31.79 ¢ /L, slightly up from 31.28 ¢ /L in 2023. The total value of butane exports reached $1.04 billion (0.76 billion USD) in 2024, an increase of 17.2 per cent from the previous year.

Figure 1: Propane and Butanes- Exports by Year or Month

In 2024, 57.7 per cent of Canada’s propane exports went to the U.S. This was a slightly lower share than 2023, even though total volumes to the U.S. rose by 8.6 per cent . Within the U.S., imported volumes varied by region: 25.9 per cent went to Petroleum Administration for Defense District (PADD)⁽²⁾ I (with volumes up 31.1 per cent from 2023), 31.1 per cent to PADD II (up 11.7 per cent ), 4.4 per cent to PADD III (up 85.9 per cent ), 5.2 per cent to PADD IV (down 28.0 per cent ), and 33.4 per cent to PADD V (down 4.3 per cent ). The share of propane exports to non-U.S. markets grew slightly in 2024, to 42.3 per cent from 41.8 per cent in 2023. These exports, which grew by 10.8 per cent , went to non-U.S. markets such as Japan, South Korea, and Mexico.

In 2024, all of Canada’s butane exports went to the U.S., with different regions receiving varying volumes. Specifically, 8.3 per cent was delivered to PADD I (with volumes down 3.4 per cent from 2023), 31.7 per cent to PADD II (up 28.8 per cent ), 2.3 per cent to PADD III (up 45.6 per cent), 5.0 per cent to PADD IV (up 45.4 per cent ), and 52.6 per cent to PADD V (up 8.7 per cent ).

Figure 2: Propane and Butanes Export Volumes to U.S. by Region

In 2024, rail was the primary mode of transportation for Canadian propane and butane exports, accounting for 49.0 per cent and 90.5 per cent , respectively. Marine shipments made up 40.8 per cent of propane exports. Since 2020 Canada has become the second largest supplier of propane to Japan and South Korea, after the U.S. The Ridley Island Propane Export Terminal (RIPET) in Prince Rupert, British Columbia, began operating in May 2019 and now ships propane directly to Asia. The Ferndale terminal in Washington State also helps to move Canadian propane to Asian markets. Pipelines transported 7.1 per cent of propane and 9.2 per cent of butane. Truck exports were minimal, representing just 2.9 per cent of propane and 0.2 per cent of butane⁽³⁾.

Figure 3: Propane and Butanes Exports by Mode of Transportation

For more information on the Canada’s natural gas liquids trade, please visit the Propane and Butanes Export Summary.

Footnotes

1. Using average exchange rate for 2024
2. U.S. Petroleum Administration for Defense Districts (PADDs) are geographic aggregations of the 50 U.S. States and the District of Columbia into five districts: PADD I is the East Coast, PADD II the Midwest, PADD III the Gulf Coast, PADD IV the Rocky Mountain Region, and PADD V the West Coast. PADDs were originally developed in the 1940s to help geographically ration fuel in the event of war. U.S. oil data is tracked by PADD.
3. Numbers may not add due to rounding.
4. REEF received Final Investment Decision (FID) in May 2024.

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