$100 Oil Isn’t Enough to Balance Alberta’s Books

By Alex Kimani - Apr 02, 2026

• Oil prices surged sharply after Donald Trump signaled further escalation against Iran, raising fears of prolonged conflict and supply risks.
• 
  
• Higher prices are hurting consumers (e.g., rising fuel costs) but boosting energy stocks and oil-producing economies, though not enough to fix all budget deficits.
• 
  
• Fiscal impacts vary widely: some producers benefit from higher prices, while others still struggle due to high budget break-even levels.
• 
  

Oil markets reversed their recent downtrend on Thursday, with oil prices surging after President Donald Trump declared that the U.S. would continue to hit Iran "extremely hard" for the next two to three weeks. Trump warned that he would hit all of Iran's electric generating plants if a deal is not reached, sending the country back to the Stone Age. Trump’s bellicosity marks a sudden shift in policy, suggesting that securing the Strait of Hormuz is no longer Washington’s top priority. Brent crude for May delivery was up 7.58% to trade at $108.8 per barrel at 2.50 pm ET, while the corresponding WTI crude contract jumped 11.54% to change hands at $111.70/bbl.

Oil consumers are beginning to bear the brunt of the oil price spike, with the average price of gasoline in the U.S. surging past $4 per gallon for the first time since the summer of 2022. However, oil companies and oil-dependent economies are enjoying a rare bonanza: previously, we reported that the Energy sector is outpacing the other 10 U.S. market sectors by a wide margin, with the sector’s nearly 40% gain in the year-to-date incomparable to the -4.5% decline by the S&P 500. Still, oil prices are not high enough for some economies to dig themselves out of their deep holes. According to Alberta Finance Minister Nate Horner, it is "highly unlikely" the recent surges in oil prices will be enough to erase the province's multibillion-dollar deficit for the 2025–26 fiscal year. Horner says the deficit is likely to narrow considerably from the earlier projection of $4.1-billion, but has emphasized a surplus remains out of reach. The final deficit number will be revealed before the end of June when the year-end fiscal report is tabled. Alberta’s new fiscal year starts on April 1.

“There’s been a lot of napkin math done in my office,” he said. “We’re very interested in this, too. All I can say for sure is that the position will have improved. Is it enough to take us out of a deficit position? Highly unlikely.”

Every $1 change in the price of WTI impacts Alberta's annual revenue by approximately $680 million. However, oil prices only surged in late February when US-Israel launched attacks on Iran, meaning Alberta only got to enjoy higher oil revenues for just over a month for the last fiscal year. Previously, Alberta had projected a massive $9.4-billion deficit for the 2025/2026 fiscal year, based on a WTI forecast of US$60.50.

Thankfully, the province might be able to balance its books in the current financial year since it requires oil prices to average $74 and $77 per barrel for the entire year. StanChart has increased its average Brent price forecast for 2026 to $85.50/bbl from $70.00/bbl and for 2027 to $77.50/bbl from $67.00/bbl. However, StanChart has predicted that oil prices will gradually ease as the months and quarters roll on, with Brent crude averaging $78.00/bbl in Q1 2026; $98.00/bbl in Q2 2026, $85.00/bbl in Q3 2026, and $80.50/bbl in Q4 2026.

That said, the budget outlook is mixed for Gulf producers. Saudi Arabia will need some luck to avoid posting a deficit in the current year, with the Kingdom needing a Brent oil price between approximately $90 and over $100 per barrel to balance its 2025-2026 budget, according to IMF and Bloomberg estimates. The high price is driven by massive spending on Vision 2030 projects, public services, and previously lower production levels under OPEC+ cuts.

The UAE is almost certain to post a big surplus in the current year, thanks to a low breakeven oil price of just under US$66 per barrel to balance its budget. The UAE’s strategic economic diversification allows its budget to be balanced at lower levels. Similarly, Qatar could be gushing cash for years, with Fitch projecting the country’s fiscal breakeven oil price could fall to around $50 by 2027. Qatar has traditionally employed a conservative oil price estimate to enhance financial flexibility, ensuring that even with lower oil prices, it can manage its expenditures. Oman is also in good standing, with a budget breakeven oil price estimated to be between US$65 and US$80 per barrel.

Unfortunately, Bahrain can only hope to narrow its budget deficit despite the high oil price, due to the country’s high breakeven oil price of $124.9 to $125.7 per barrel, largely due to a high reliance on oil revenues and lower diversification.

By Alex Kimani for Oilprice.com

Suncor plans major shift in focus to in situ oil sands output by 2040

Reuters | April 3, 2026 | 

Loading a truck at the Fort Hills oilsands mine in Alberta. Image from Suncor Energy.

Canada’s Suncor Energy said on Tuesday the majority ‌of its bitumen output by 2040 will be produced using steam-assisted extraction technology, an announcement that marks a significant structural shift for the oil sands heavyweight and which the company said will result in lower costs and higher cash flow over the long term.

Currently, 70% of Suncor’s oil sands crude ​is produced at its large-scale mining operations in northern Alberta, where trucks and shovels are used to extract the ​thick, heavy bitumen deposits that lie close to the surface. The remaining 30% comes from deeper ⁠deposits that require the use of steam technologies, a method called in situ, to loosen the oil underground before it can ​be pumped to the surface.

But over the next 15 years, Suncor’s production mix will shift so that by 2040, 60% of ​its oil sands barrels will come from in situ developments, and just 40% from mining, CEO Rich Kruger said at an investor day presentation. The change reflects anticipated declining production from Suncor’s Base Plant mine, which is expected to be largely depleted by the mid-2030s, but also reflects the ​company’s desire for lower-cost production.

“All barrels are not created equal,” Kruger said. “In situ delivers two times the relative cash flow per ​barrel compared to mining today.”

Already, Suncor’s most profitable asset is its Firebag site, which produces approximately 245,000 barrels per day using in situ technology. On Monday, the ‌company filed ⁠a regulatory application to expand the site’s permitted capacity from an existing limit of 368,000 bpd to 700,000 bpd.

While most of the planned ramp-up of in situ development will come after 2032, Kruger said, Suncor expects to be able to increase output from Firebag to 275,000 bpd by 2028, through a series of debottlenecking and optimization projects.

The company also has a proposed in situ ​development, called Lewis, which is expected ​to produce 160,000 bpd ⁠and which Kruger said will be developed in phases, sequenced to coincide with the timing of the Base Plant mine’s gradual depletion.

Suncor’s investor day had been highly anticipated by the market, which has ​been waiting to hear how the company plans to secure a long-term bitumen supply to ​replace its Base ⁠Plant production.

One option the company had previously proposed was a new, 225,000-bpd, open-pit oil sands mine expansion, which would be located adjacent to its existing Base Plant operations. But it has been unclear whether such a project would get the go-ahead from Canadian regulators.

On Tuesday, ⁠Kruger said ​the company’s latest reserve estimate indicates it has 11 billion barrels more in ​reserves than previously estimated, bringing its total bitumen reserves to 30 billion barrels. Suncor expects to grow its upstream production by about 100,000 bpd by 2028.

($1 = ​1.3936 Canadian dollars)

(By Amanda Stephenson and Sumit Saha; Editing by Shinjini Ganguli and Chris Reese)

MONOPOLY CAPITALI$M

Red-Hot Canadian Oil Patch M&A Likely to Cool

By Andrew Topf - Feb 11, 2026

• Canada’s upstream oil and gas sector saw a record $31.2 billion in M&A activity in 2025.
• 
  
• 2025 saw major deals such as Whitecap Resources’ merger with Veren and Cenovus Energy’ takeover of MEG Energy.
• 
  
• Sayer Energy Advisors expects deal activity to moderate in 2026 due to a shrinking pool of high-quality targets, strong producer balance sheets, and structural constraints despite improving policy signals.
• 
  

Last year saw a record number of deals in the Canadian oil patch, with sectoral consolidation reaching an eight-year high.

But a new report from Calgary-based Sayer Energy Advisors anticipates mergers and acquisitions in Canada’s upstream oil and gas will moderate over the next 12 months.

The report’s findings go against the expectations of industry analysts and executives of more US buyers searching for acquisition targets, along with more favorable government policies towards the sector spurring more action in 2026.

According to the report, via the Calgary Herald, the upstream oil and gas sector saw an estimated $31.2 billion of M&A activity in 2025, a 53% jump from the previous year and the most dealmaking since 2017, when five large transactions led by foreign firms exiting the oilsands accounted for 80% of the total deal value.

The 2025 total included Whitecap Resources’ (TSX:WCP) $15 billion merger with Veren Inc. last March, and Cenovus Energy’s (TSX:CVE) $8.6B takeover of oilsands producer MEG Energy in November.

Other deals saw Sunoco LP’s (NYSE:SUN) purchase of fuel giant Parkland Corp. for $9.1 billion; Keyera Corp.’s (TSX:KEY) $5.1B acquisition of Plains All American Pipeline’s (NASDAQ:PAA) NGL (Natural Gas Liquids) Division; Ovintiv Inc.’s (TSX:OVV) purchase of NuVista Energy for $3.8 billion, and Canadian Natural Resources’ (NYSE:CNQ) acquisition of Chevron’s (NYSE:CVX) Oilsands/ Duvernay Assets ($1.0B).

Buyers bulked up to achieve better returns and operational synergies during a period of lower oil prices averaging roughly $60 a barrel, rather than investing in new drilling.

About 30% of last year’s M&A activity targeted assets in the Montney formation of northeastern British Columbia and northwestern Alberta — a region known for its natural gas, condensate and NGLs.

Most major deals were completed by domestic players, although interest from US buyers began to increase as US shale wells started to become depleted.

A separate report from ATB Capital Markets notes most producers still have strong balance sheets, which could slow M&A in 2026, as there will be fewer firms looking to sell.

“We anticipate a modest slowdown in Canadian (exploration and production) M&A activity through 2026 following three years of robust consolidation within the sector,” the report states, per the Herald.

“This expected decline in momentum is driven by an intersection of structural and economic factors, most notably the scarcity of remaining high-quality targets that possess adequate scale and inventory depth to justify valuation premiums.”

On the other hand, Grant Zawalsky, senior partner and vice-chair at law firm Burnet, Duckworth and Palmer LLP in Calgary, was quoted by The Canadian Press as saying that “M&A is a way that you can grow when you don’t want to invest in drilling, when you’re not going to get the kind of returns you’re expecting,” he said.

“Until the fundamentals change, we’ll likely see more of the same.”

He should know. Zawalsky worked on three major energy transactions last year: the Cenovus-MEG Energy acquisition, Whitecap’s combination with Veren, and Ovintiv’s purchase of NuVista Energy.

BD&P was involved in eight of the 10 biggest transactions.

Tom Pavic, president of Sayer Energy Advisors, said that while the investment environment has been improving due to the Canadian and Alberta governments reaching an energy accord that includes support for a new West Coast oil pipeline, he hasn’t observed increased global interest in Canadian acquisitions.

Pavic chalked the disinterest up to lingering concerns over regulatory burdens and infrastructure needed for overseas exports.

However, US private equity players have been showing an interest in picking up Canadian assets, building up production and then selling the companies or taking them public.

“Anywhere they see a value arbitrage with Canadian assets selling lower or being developed at a lower cost, they view that as an opportunity,” Zawalsky was quoted by The Canadian Press.

“And they tend to be more willing to take risk on the regulatory side than established oil and gas producers.”

By Andrew Topf for Oilprice.com

Big Oil’s Merger Boom Is Being Driven by a Surprisingly Small Club

By Haley Zaremba - Feb 06, 2026

• Just 20 oil and gas companies accounted for more than half of the total M&A deal value over the past decade, according to Bain & Co.
• 
  
• Frequent acquirers dramatically outperformed non-acquirers, delivering shareholder returns roughly 130% higher over ten years.
• 
  
• Recent mega-deals, including Devon’s acquisition of Coterra, highlight how consolidation is reshaping U.S. shale even as future dealmaking may slow or shift focus.

The oil and gas sector is continuing to consolidate after years of ‘merger-mania’, with ramifications for the entire energy sector and wider economy. But a recent report reveals that the spate of mergers and acquisitions that has characterized the fossil fuels industry over the last decade is not as widespread as it may seem, but rather concentrated among a few key players. 

A newly released report from the consulting firm Bain & Co found that, within the oil and gas sector, “fewer companies are doing more of the deals and creating more of the value.” In fact, over the last ten years, just 20 companies were responsible for 53% of total deal value when it comes to mergers and acquisitions within the sector.

“And it’s not only the large supermajors,” Bain & Co report, “but also independents such as Diamondback Energy and large midstream companies such as ONEOK and Energy Transfer.” Indeed, this consolidation frenzy is reshaping the landscape of Big Oil, with not-quite-supermajors gobbling up more and more of the market.

What is more, the companies that are driving merger-mania are winning big. The report concluded that the companies considered to be ‘frequent acquirers’ ultimately provided shareholder returns that dwarfed the firms that were not involved in acquisitions over the last ten years. Companies completing at least one acquisition per year yielded returns that were a jaw-dropping 130% higher than companies that did not conduct acquisitions. This is more than double the performance gap seen between acquirers and non-acquirers in the sector a decade ago.

What is the math behind this massive performance gap? In layman’s terms, as explained by news outlet Semafor, “mergers tend to allow companies to capture scale and reduce unit costs through operational efficiencies and consolidated infrastructure, savings that have become more important now that oil prices have retreated from their 2022 peak.”

The consolidation boom has been especially concentrated in the United States, where “year-over-year mergers and acquisitions (M&A) activity surged 331%, totaling $206.6 billion,” according to an August report from Ernst & Young. In fact, the domestic oil and gas sector has shrunk from a field of 50 major players to one of just 40 big names.

Just in the last two years, Chevron bought Hess for $53 billion, Exxon Mobil bought Pioneer Natural Resources for $60 billion, and Devon bought Grayson Mill Energy for $5 billion. And this merger-mania reached a new height just this month as Devon moved to acquire Coterra for nearly $26 billion in a marriage of two “crown jewels.” This deal “creates a domestic oil and gas juggernaut trailing only household names Exxon Mobil, Chevron, and ConocoPhillips in sheer production volumes” according to Fortune.

However, not everyone is thrilled about the new United States shale giant. The deal is a pure stock deal, with Devon shareholders set to hold 54 percent and Coterra shareholders 46 percent of the merged company. This makes it a bit contentious for investors. As explained by MarketWatch, “investors in the acquiring companies don’t usually like stock deals, because issuing new shares to fund the purchase dilutes their holdings, meaning they now own a smaller percentage of the company.”

The Devon-Coterra merger, popular or not, is major news after a relatively quiet year for mergers and acquisitions in 2025. In fact, it could be the harbinger of the next big consolidation wave. But probably not.

Some experts think that merger-mania is set to wind down or at least reorient its focus as prices become more volatile on the back of shifting demand patterns. “With ongoing uncertainty around supply and demand, pricing, tariffs, and geopolitics, operational efficiency and capital discipline will be critical,” says Ernst & Young’s Herb Listen. “The companies that adapt quickly, invest strategically and integrate effectively will define the next chapter of U.S. energy.”

By Haley Zaremba for Oilprice.com

CIBC forecasts wider discount for Alberta heavy oil in 2026 as Venezuelan supply looms

ByThe Canadian Press
Updated: January 13, 2026 at 2:00PM EST

The oil tanker named Xanthos Eos steam on Lake Maracaibo, Venezuela, Wednesday, Jan. 7, 2026. (AP Photo/Edgar Frias)

CALGARY — Analysts at CIBC are forecasting a wider discount on Alberta heavy crude this year as U.S. plans to rebuild Venezuela's ailing industry dominate headlines.

The bank estimates the differential between Western Canada Select, the heavy Alberta blend, and West Texas Intermediate, the U.S. light oil benchmark, will average US$14.25 a barrel in 2026.

For 2025, the price gap is estimated to have averaged US$11.30 as Canadian producers benefited from the first full year of operations of the Trans Mountain pipeline expansion to the West Coast, enabling exports to Asia.

Venezuelan and Alberta oilsands crude both have a thick, tarry consistency and require specialized equipment to refine into products like gasoline and diesel. Refineries on the U.S. Gulf Coast are set up to handle that type of oil, so any meaningful increase in Venezuelan supplies on the market would compete with imports from Alberta and could weigh on WCS prices.

The majority of the 4.4 million barrels per day Canada exports to the U.S. winds up in the Midwest, while about one-tenth heads to the Gulf.

"In the near term, we expect news around resuming investment in Venezuela and targeting production restarts will dominate headlines and cause pressure on WCS-WTI basis (as well as heavy oil realizations for Western Canadian producers)," the CIBC analysts wrote.

The U.S. has been working to exert control on Venezuela's oil sector since the capture of that country's leader in a military raid on Jan. 3. President Donald Trump has since said he wants American oil giants to invest US$100 billion to repair Venezuela's crumbling energy infrastructure and tap its vast reserves.

Mike Shaw, portfolio manager at Franklin Templeton's ClearBridge Investments, said in a written commentary that there's little risk of Canada being pushed out of the U.S. market in a meaningful way, given how integrated Midwest refineries are to cross-border pipeline networks.

"Canada’s primary exposure is to sentiment and marginal pricing, not to a sudden loss of U.S. market access. From a macro and fiscal perspective, a softer oil price environment would reduce cash-flow generation across the sector and dampen royalties, taxes, capital investment and employment tied to the energy complex," Shaw wrote.

"That said, the downside is partially mitigated by the fact that Canadian oilsands producers have materially lowered their cost structures and can remain profitable, albeit less so, at meaningfully lower oil prices than in prior cycles."

Meanwhile, the price of WTI was up almost three per cent to US$60.90 per barrel in afternoon trading Tuesday. The CIBC analysts forecast an average 2026 WTI price of US$60 per barrel, down from US$64.92 last year.

That report said Brent crude, the price linked to light oil produced in the North Sea, is expected to average US$63 this year. It fetches a higher price because of its ability to access global markets by sea.

Enverus is expecting Brent to average US$55 in 2026. It was trading above US$65 on Tuesday.

"Our work shows oil prices will reset lower in 2026 without signalling long-term scarcity," said managing director Dane Gregoris.

"Upstream operators will continue to push for efficiency gains while capital stays highly selective.”

Both Enverus and CIBC are expecting weaker prices in the first part of this year, with some recovery in the second half.


This report by The Canadian Press was first published Jan. 13, 2026.

Lauren Krugel, The Canadian Press

LNG

Owner of B.C. ghost town taking another swing at energy exports

ByThe Canadian Press
February 01, 2026 

Businessman Krishnan Suthanthiran poses for a photo in Calgary, Sunday, Jan. 18, 2026. Suthanthiran, who owns the one-time company town of Kitsault, B.C., is trying to interest government in the site as an energy export terminal. THE CANADIAN PRESS/Larry MacDougal (Larry MacDougal)

Krishnan Suthanthiran is trying to make Kitsault, B.C., happen — again.

The Indian-born, U.S.-based medical technology entrepreneur says he spent about US$7 million two decades ago to purchase the uninhabited one-time mining town at the end of a scenic fiord. Some media reports have cited a lower purchase price.

His early plans for Kitsault included an eco-resort, an arts and science centre and a movie studio. In 2013, Suthanthiran turned his sights to energy, floating a plan for a liquefied natural gas export terminal.

None of those ideas have panned out and the town, about 140 kilometres northeast of Prince Rupert, B.C., remains mostly vacant.

But Suthanthiran believes Kitsault’s time as an energy hub has finally come, as trade and geopolitical upheaval focus political attention on boosting oil and gas exports to non-U.S. markets.


His latest pitch is to build two pipelines connecting Alberta to the coast, one for natural gas and one for crude oil. The oil and natural gas, in the form of liquid butanol, would be exported across the Pacific from a marine terminal near Kitsault.

He came armed with a pile of glossy brochures touting Kitsault’s housing and infrastructure offerings late last month when he visited Calgary, where he said he had meetings with Alberta energy ministry staff.

“I truly believe that this is the right thing for Canada and this is the right thing for the First Nations,” the 78-year-old told The Canadian Press in an interview.
The town

Kitsault’s life as a bustling mining town was brief.

Amax Canada Development Ltd. opened a molybdenum mine nearby in 1981. The town it built for workers once boasted 1,200 residents.

But shortly thereafter, the market tanked for molybdenum, an ore used in steelmaking, and the mine shut down. By the end of 1983, Kitsault was empty. It has remained frozen in a 1980s time warp ever since.

When the town was put on the market in 2004, it came with 92 houses, complete with period decor. It also had a hospital with a never-used X-ray machine, a curling rink, swimming pool, library, theatre, shopping mall and pub. The Kitsault Energy brochure says the town has full B.C. Hydro power service.

Over the years, the town has only housed groundskeepers and a smattering of mining workers. Suthanthiran figures he spends $2 million a year to maintain it.
The businessman

A biography on Kitsault Energy’s website tells the story of Suthanthiran’s humble beginnings in India, where it says he sold candy to classmates so he could afford schoolbooks. The bio says he came to Canada in 1969 with $400 and studied engineering at Carleton University in Ottawa. Three years later, unable to find a suitable job in Canada, he moved to the U.S.


His father’s cancer death inspired his career path and he founded a family of companies under the TeamBest Global umbrella focused on equipment used in cancer diagnosis and treatment, the bio said.

Some have run into legal and labour trouble.

In one case dating back more than a decade, Belgian authorities sought Canada’s help executing search warrants related to a criminal investigation into Best Medical Belgium Inc., one of Suthanthiran’s companies. A 2017 Court of Appeal for Ontario decision says the Belgians were looking into allegations of misuse of company assets, concealing assets in insolvency, making false statements, using false documents and money laundering. Suthanthiran has denied wrongdoing. CBC reported last June that the investigation was ongoing.

Later, workers at another one of Suthanthiran’s companies, Best Theratronics in Ottawa, went on strike for almost 10 months amid a bitter pay dispute until an agreement was finally reached early last year. At the same facility, which made equipment used in radiation therapy, the company ran afoul of the Canadian Nuclear Safety Commission over the financial guarantee for decommissioning required under its licence.

When asked how his expertise figures into his oil and gas ambitions, Suthanthiran replied: “I’m an innovator, I’m an engineer.”
The plan

Suthanthiran wrote in an open letter to Prime Minister Mark Carney and Alberta Premier Danielle Smith last month outlining a vision to “elevate Canada’s role as a global energy leader.”

He is proposing a marine terminal at a deepwater port on Observatory Inlet, about 30 kilometres from the town site, from which tankers of crude would depart for Asia. He says the site would also have a floating facility to manufacture liquid butanol — a chemical with a wide range of uses, including as a fuel — from natural gas. Suthanthiran says it’s a more cost-effective undertaking than LNG, which requires gas to be chilled into a liquid in ultra-cold temperatures.

Along the same inlet, but closer to the Pacific, the Nisga’a Nation and industry partners are planning the floating Ksi Lisims LNG development, which is being expedited as a federal project of national importance.

Barry Prentice, a business professor at the University of Manitoba, said the waters leading to Kitsault are navigable and sheltered.

“From a marine perspective, I don’t see any red lights flashing,” said Prentice, who specializes in transport and supply chains.

The fact that the town is connected to utilities and already has housing available is a bonus, Prentice added.

“If the idea is to move fast on things, I can’t think of any site that would be able to move faster than that,” he said. “Some of the pieces of the puzzle are there.”

Heather Exner-Pirot, senior fellow at the Macdonald Laurier Institute, hadn’t heard of Kitsault as a port option.

“Prince Rupert comes up as a more obvious one, because they have the deep water ports and because they have capacity for the size of the operation that we’d expect,” she said.

Further south and inland, the port of Kitimat already has the LNG Canada terminal in operation and another, Cedar LNG, under construction.

“It is busy and probably constrained,” said Exner-Pirot.

The best bet, she said, is wherever the support from local First Nations is strongest.

“The most welcoming Indigenous nation on that coast would have a very good chance of attracting it.”
The moment

Suthanthiran believes the “stars are lined up” for his latest vision for Kitsault to succeed. The Canada-U.S. trade relationship has been rattled by tariff chaos and annexation threats. That’s honed political attention on boosting exports to markets besides the United States, by far the biggest buyer of Canadian oil and gas.

U.S. plans to boost Venezuelan oil production following the ouster of President Nicolas Maduro in January has intensified calls for Canada to ramp up energy exports to Asia via the West Coast.

The Alberta government is currently leading the charge for a new oilsands pipeline, committing $14 million to early work on a proposal to the federal major projects office, established last year to speed along infrastructure deemed in Canada’s national interest.

Smith has said the aim is for the private sector to eventually take on the project alongside First Nations partners. A sweeping energy agreement Smith and Carney signed late last year envisions a new bitumen pipeline being built in tandem with emissions-reducing measures.

Suthanthiran said Canadian industry remains “gun shy” about taking on such a project.

“Everybody is pointing a finger at somebody else. Who’s going to take the lead? It’s like a dance floor. Nobody wants to go first.”

Suthanthiran said he’s open to selling Kitsault and letting someone else take the reins.

“I don’t have to own the town forever.”

Lauren Krugel, The Canadian Press

PM Carney, Alta. Premier Smith open to alternate oil pipeline routes

By Spencer Van Dyk
January 29, 2026 

Alberta Premier Danielle Smith and Prime Minister Mark Carney both say they’re open to alternate routes for a potential pipeline to get Alberta oil to Asian markets, which does not necessarily need to end at B.C.’s northwest coast.

“Some of the alternatives are already emerging,” Smith told reporters in Ottawa on Thursday, when asked whether the northwest coast route is the only one being considered.

Prime Minister Mark Carney and Alberta Premier Danielle Smith both say they’re open to alternate routes for a potential pipeline to get Alberta oil to Asian markets, which does not necessarily need to end at B.C.’s northwest coast. (The Canadian Press combined photo)

She said several options to boost oil exports are currently being considered, including an expansion of Enbridge’s main line and exploring ways to better utilize old Keystone assets, among other ideas.

“North, south, east, west, we’re willing to go in every direction,” Smith said.

Smith has been at odds with B.C. Premier David Eby over the issue for months. In June, Eby said he wouldn’t support a new pipeline — arguing the Trans Mountain Expansion Project is already in place — to which Smith responded that she would “convince” him.

Prime Minister Mark Carney, right, signs an MOU with Alberta Premier Danielle Smith in Calgary,Thursday, Nov. 27, 2025. THE CANADIAN PRESS/Jeff McIntosh

Then, in November, Carney and Smith signed a historic memorandum of understanding (MOU) outlining the conditions that need to be met for a new oil pipeline to the Pacific to proceed.

In the MOU, Alberta agreed to negotiate an industrial carbon pricing agreement by April 2026, which would implement an industrial carbon price with a floor of $130 per tonne.

In return, the federal government has agreed not to implement the oil and gas emissions cap, to suspend the clean electricity regulations in the province, and if required, make an exemption to the federal tanker ban.

But Eby has been staunchly opposed to lifting the tanker ban, which was enacted in 2019 and prohibits oil tankers carrying more than 12,500 metric tons of crude or persistent oil from docking, loading or unloading at ports on the B.C. north coast.

B.C. Premier David Eby, speaks during an announcement for new funding to support victims of crime, in Surrey, B.C. on Friday, Nov. 28, 2025. THE CANADIAN PRESS/Ethan Cairns

“We are doing our work to put the project together by June, and we are hoping that the federal government can move swiftly on making a decision so we can get down to technical details on that,” Smith said on Thursday.

“I’m very confident that once approved, we will have one or more strong proponents in the private sector willing to work with us to build it.”

Asked to respond, Eby said Smith is “committed to keeping (B.C.) updated on her progress,” and that he looks forward to that.

Canada’s premiers are in Ottawa this week for a meeting of the Council of the Federation. On Thursday, they also collectively sat down with Carney, largely to discuss trade amid the ongoing trade war with the United States.

While they’re in town, a few also met with Carney separately, including Smith and Eby, who said pipelines were a topic of conversation.

The B.C. premier described the sit-down as “very civil,” and “borderline friendly.”

Prime Minister Mark Carney takes his seat at the First Ministers Meeting in Ottawa, Thursday, Jan. 29, 2026. (Adrian Wyld/The Canadian Press)

Speaking to reporters on Thursday, Carney said he wanted to “re-emphasize” that the MOU includes many other provisions, including cooperation on data centres, nuclear power, and inner ties.

“With respect to a route, and under the MOU, ‘a bitumen pipeline to Asian markets,’ is the way it’s described, and therefore the specific routes are not outlined,” Carney said.

“Of course, work is being done to explore the feasibility of various routes, and there are many factors that affect the feasibility, starting with Indigenous support, as well as technical and economic considerations,” he also said.

Alberta is currently acting as a proponent to fund the initial planning stages of a proposed bitumen pipeline to B.C. northwest coast, and Smith re-asserted her desire on Thursday to present a proposal to the Major Projects Office by June.

“We are hoping that the federal government can move swiftly on making a decision so we can get down to technical details on that,” Smith said. “I’m very confident that once approved, we will have one or more strong proponents in the private sector willing to work with us.”

A private proponent for a pipeline has yet to come forward.

With files from CTV News’ Stephanie Ha
Spencer Van Dyk
Writer & Producer, Ottawa News Bureau, CTV News

Shell, Mitsubishi exploring sale options for their stakes in LNG Canada: Reuters exclusive

By Reuters
January 16, 2026 

The Shell Oil logo and the logo of Mitsubishi Motors Corp in a combination photo. (AP Photo / Gene J. Puskar)

Oil company Shell and Japanese conglomerate Mitsubishi are exploring sale options for their respective stakes in the $40-billion LNG Canada project, three sources familiar with the matter told Reuters.

The moves come as owners of the massive liquefied natural gas facility weigh a potential expansion, and after another stakeholder, Petronas, successfully offloaded a piece of the project.

Shell, the largest owner with a 40-per-cent stake in LNG Canada, has been working with investment bankers at Rothschild & Co to sound out interested parties in recent weeks, said two of the sources. Two sources added that Shell could offload as much as three-quarters of its holding, or 30 per cent of the project.

Shell has expressed willingness, however, to consider different options relating to its exposure to the project’s Phase 1, which is operational, and the proposed Phase 2, given their different risks.

One of the sources estimated that any buyer for Shell’s stake could be committing roughly $20.9 billion, inclusive of the equity stake, debt and capital requirements for Phase 2.

Royal Bank of Canada signage is pictured in the financial district in Toronto on September 8, 2023. THE CANADIAN PRESS/Andrew Lahodynskyj

Mitsubishi hires RBC

Mitsubishi, which holds a 15-per-cent stake, has hired RBC Capital Markets as it weighs its options, two of the sources said, cautioning deliberations were early and any sale effort would not kick off until later this year. The sources did not elaborate on how much of its stake Mitsubishi could market.

All the sources said sales involving Shell and Mitsubishi were not guaranteed, and spoke on condition of anonymity to discuss confidential deliberations.

CTV News reached out to LNG Canada, which referred questions to Shell and Mitsubishi. Shell said they would not be commenting on this story, while Mitsubishi has not responded.

MidOcean, backed by investment firm EIG and Saudi Aramco, closed a deal in December to buy a fifth of the Petronas venture that held a 25-per-cent stake in LNG Canada.

PetroChina holds a 15-per-cent stake, while Korea Gas Corporation owns five per cent of LNG Canada.

A tanker being loaded with the first cargo of Canadian liquefied natural gas is shown at the port of Kitimat, B.C. on Saturday June 28, 2025. THE CANADIAN PRESS/Handout — LNG Canada (Mandatory Credit)

LNG Canada’s cost advantage

LNG Canada is the first major LNG facility in North America with direct access to the Pacific Coast. The project in Kitimat, B.C., has a supply cost advantage because prices for Canadian natural gas consistently trade at a discount to the U.S. Henry Hub benchmark.

Even so, existing and potential owners will consider industry fears of global oversupply of the supercooled fuel, as new LNG output comes online. Energy Transfer said in December that it was suspending development of its Lake Charles LNG export facility in Louisiana.


LNG Canada started production in June, but has since run into operational problems. Its second processing unit, known as Train 2, was down in December, nearly a month after its startup, two sources told Reuters

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The terminus for the Coastal GasLink natural gas pipeline is seen at the LNG Canada export terminal under construction in Kitimat, B.C., on Sept. 28, 2022. THE CANADIAN PRESS/Darryl Dyck

When fully ramped up, Phase 1 will have the capacity to export 14 million metric tons of LNG per year.

Shell told potential bidders it will keep a gas contract with the terminal for 30 years, one source said.

Developers of major infrastructure projects often reduce their stakes once they become operational, allowing them to book profits and recycle cash into new ventures. Large investment firms and infrastructure funds are ready buyers of such stakes, as they like the projects’ steady revenue.

Shell, the world’s biggest LNG trader, said in March it targeted a four-to-five per cent annual increase in LNG sales over the next five years and one-per-cent annual production growth.

Shell and its partners were working toward a final investment decision for Phase 2, as soon as this year, which would double capacity.

By Arathy Somasekhar, David French and Andres Gonzalez, Reuters

Fear at work is a hidden safety risk — and it helps explain why hazards go unreported


Creating safer workplaces requires cultures where speaking up is not punished, dismissed or ignored. 

Published: January 21, 2026 
THE CONVERSATION

Psychological safety — the belief that it is safe to speak up with concerns, questions or mistakes — is widely recognized as essential for organizational learning, innovation and workplace safety.

Yet its absence — interpersonal fear — is rarely examined in investigations of serious workplace incidents. My new research on workplace fatalities, conducted with several co-researchers, suggests this missing factor may help explain why hazards so often go unidentified or unreported.

We surveyed more than 4,600 workers and analyzed thousands of incident reports across five mine sites and over 100 mining and contractor companies. We asked workers: “Why aren’t hazards identified or reported?”

We found that interpersonal fear — the perception that speaking up or challenging the status quo will lead to humiliation or punishment — was one of the strongest predictors of silence. Workers who were more likely to be fearful were also more likely to withhold information.
A pattern we’ve seen before

Our recent findings echo earlier research I conducted following a fatal mining accident near Fort McMurray, Alta., in 2017, when a Suncor employee fell through ground softened by a leaking tailings pipeline and was unable to free himself.

I led a team analyzing geohazards associated with working around oilsands tailings ponds. During a safety workshop that concluded the two-year investigation, my co-researchers and I asked the attendees to answer the same question — “Why are hazards not identified or reported?”

Our mission is to share knowledge and inform decisions.About us

We expected technical responses, but instead, they focused overwhelmingly on human and organizational factors: lack of training, fear, inappropriate risk tolerances, external pressures, cultural inaction and complacency

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Responses from 117 mine workers to the question: ‘why aren’t hazards identified or reported?’ (Lianne M. Lefsrud), Author provided (no reuse)

The predominance of fear shocked us. Workers described being more afraid of the social consequences of reporting hazards than of the hazards themselves. As a result, they were putting their own lives at risk.

Our newer, larger study confirms this pattern at scale. Using machine-learning techniques, we were better able to identify where fear was most likely to flourish, its organizational causes and consequences and how it undermines companies.

We found management dismissiveness, a lack of managerial action or follow-up and a lack of training were more likely to cause fear — especially among contractors — and suppress hazard identification and reporting.
Fear isn’t limited to the frontline

Employees lower in company hierarchies tend to experience less psychological safety. But senior leaders are not immune to it either. They can encounter situations where raising concerns feels risky, particularly in executive settings where disagreement can be interpreted as “too political,” disloyal or a sign of weakness.

Leadership scholar Amy Edmondson’s research helps explain this dynamic. Her psychological safety matrix shows that fear flourishes when high performance standards are combined with low psychological safety.

Sites where workers report higher levels of fear had lower hazard reporting rates and higher rates of serious incidents. A steel worker builds a structure in Ottawa in 2018. THE CANADIAN PRESS/Sean Kilpatrick

In teams with high levels of psychological safety and highly challenging tasks and standards, she found employees are curious and engaged problem-solvers. However, when the same high standards exist without psychological safety (where people believe that they might be punished or humiliated for speaking up), anxiety prevails.

The goal is to have your team experience the first scenario. Because psychological safety operates at the team level, organizations can have multiple teams doing similar high-risk work with dramatically different outcomes, depending on whether people feel safe enough to speak up.
Creating safer systems starts with leadership

Since interpersonal fear is shaped by perception, it doesn’t matter whether leaders believe they are approachable; what matters is whether their teams think they are. If employees are spending more time worrying about managing impressions than operations, hazards go unreported and people are unknowingly put at risk.

Creating safer workplaces requires cultures where speaking up is not punished, dismissed or discouraged. Leaders can start by asking themselves questions: who is least likely to challenge me at work? What information might I not be hearing as a result?

Read more: Silence speaks volumes: How mental health influences employee silence at work

Often, the employees with the most job security, such as union reps or those nearing retirement, are the most honest sources of insight. Listening to these voices is often a good place to start.

Research shows that organizations can improve psychological safety through practical leadership changes. Supervisors who listen, seek feedback, share reasoning behind decisions and are team-oriented instead of self-serving are more likely to create and maintain psychological safety.

Leaders should also pay attention to variations across teams. Useful questions to ask include:

Which teams are feeling fearful?

Which teams are feeling curious and engaged?

How can you create more high-performance teams?

Understanding why some teams feel safer than others can reveal opportunities for improvement.

For leaders, the greatest worry should be whether your employees are afraid to speak up. Be suspicious of “good news only” green dashboards, obsequious agreement or stony silences. Do not punish messengers — rather, embrace their candour as a gift and a sign that your organization is preventing harm.

Author

r

Lianne M Lefsrud
Professor 

Risk, Innovation & Sustainability Chair (RISC), University of Alberta
Disclosure statement
Lianne M Lefsrud receives funding from the Natural Science and Engineering Research Council of Canada (NSERC), Alberta Justice, WorkSafeBC, Mitacs, Alberta Innovates, and the Lynch School of Engineering Safety and Risk Management endowed funds.
Partners

BC Premier Eby says Canada should build refineries, not pipelines, after Venezuela attack

ByTodd Coyne

January 06, 2026

B.C. Premier David Eby, speaks during an announcement for new funding to support victims of crime, in Surrey, B.C. on Friday, Nov. 28, 2025. 

THE CANADIAN PRESS/Ethan Cairns (ETHAN CAIRNS)

British Columbia Premier David Eby says Canada should prioritize building more oil refinery capacity over new export pipelines amid the threat that Venezuelan oil could begin to displace Canadian crude in U.S. refineries.

The premier was responding to recent calls from the Alberta government to expedite new pipeline infrastructure from the oilsands to the B.C. coast, following the American capture of Venezuelan President Nicolás Maduro and the Trump administration’s stated plans to take control of that country’s vast oil resources.

“I, like many Canadians, am glad to see the back of Mr. Maduro,” Eby told reporters Tuesday, referring to the ousted Venezuelan leader as a “terrible man” and a “tyrannical dictator.”

But the economic risk that is posed by a potential glut of Venezuelan crude displacing Canadian heavy oil at U.S. Gulf Coast refineries would be better mitigated by refining more oil domestically, Eby said.

“If we’ve got tens of billions of dollars to spend, I think we should spend it on a refinery, and we should develop oil products for Canadians and for export, instead of being reliant on American and Chinese refineries to do it for us,” the premier said ahead of his departure on a planned trade mission to India later this week.


“We’ve got to stand on our own feet here, and building that capacity and jobs in our country is something we should be talking about as opposed to shipping raw resources out as quickly as possible,” he added.

The premier reiterated his opposition to building new oil pipelines through northern B.C., and said the existing Trans Mountain pipeline to Burnaby is not at full capacity and could be expanded further within its existing right of way.

“If we’re going to do public investment into our resources here in Canada, I think it might be time to pivot that discussion to a refinery,” he said. “We still buy oil products from the United States.”

More than 90 per cent of Canada’s oilsands exports are currently shipped to the U.S. for refining, according to data from the Canada Energy Regulator.

Venezuela boasts the world’s largest proven reserves of crude oil, primarily in the same form of bituminous heavy oil that is produced in Alberta.

Shares in many of Canada’s largest oilsands companies have been trading at a discount following the ouster of Maduro and Washington’s assertion of control over Venezuela’s energy industry.

Oil production in Venezuela peaked in the 1990s but struggled in the years since under international sanctions. A resurgence of Venezuelan crude production under American control would likely further discount Canadian oil prices in a U.S.-dominated market.

“I don’t understand why, if we’re talking about massive public investment into supporting Albertans in this fragile global time, we can’t talk about supporting all Canadians with oil and gas products that are made right here at home while we transition,” Eby said.

He added the B.C. government remains focused on diversifying markets for a variety of Canadian products away from the U.S. in light of Trump’s attacks on Canadian sovereignty through threats of annexation and tariffs.

The premier also condemned the U.S. military’s unilateral actions against Venezuela as “deeply unsettling,” and said the focus of his trip to India will be on making B.C. “more independent than ever from the United States.”

Eby will be joined on the trade mission by Ravi Kahlon, the province’s minister of jobs and economic development.


Todd Coyne
CTVNewsVancouver.ca Journalist

U.S. designs for Venezuelan oil industry put pressure on Canadian oil stocks

ByThe Canadian Press
Updated: January 05, 2026 


Shares in Canada’s biggest oilsands producers came under pressure Monday after the U.S. military captured the Venezuelan leader and President Donald Trump announced plans to put that country’s oil industry into the hands of American companies.

Cenovus Energy Inc. and Canadian Natural Resources Ltd. were each down about five per cent and Suncor Energy Inc. dropped 1.4 per cent. Enbridge Inc., which operates a vast cross-border oil pipeline network that it plans to expand, and South Bow Corp., whose Keystone system ships crude to the U.S., each fell around three per cent.

Overall, the TSX energy subindex was down more than three per cent.

Refineries on the U.S. Gulf Coast are set up to process heavy crude like that produced in Alberta’s oilsands and in Venezuela. But U.S. sanctions on the South American country have meant virtually none of its supplies go to the U.S. market today.

“If those restrictions were lifted, then Canada may have more competition right away in terms of Venezuelan oil that now technically can access the U.S. Gulf Coast,” said Jackie Forrest, executive director of the ARC Energy Research Institute.


But Forrest said any discounts on Canadian heavy oil prices would be “modest” — in the US$2 to US$3 per barrel range — so the market reaction Monday “seems a bit overdone.”

Canada sends about 400,000 barrels a day of crude to the world’s largest refining complex on the Gulf Coast, a relatively small portion of the roughly four million barrels a day of oil Canada supplies to the U.S. overall. Most currently goes to refineries in the Midwest region, which is deeply integrated with pipeline networks originating in Alberta, like Enbridge’s Mainline and South Bow’s Keystone.

There are ways to offset some of that pricing pressure by exporting crude abroad, via the Gulf Coast or from the Trans Mountain pipeline on the West Coast, Forrest added.

Not much has changed in oil markets near-term and it could be months or even years before the fate of sanctions and Venezuela’s production shakes out, said Dane Gregoris, managing director of Enverus’s oil and gas research group.

“Political changes happen quickly, but industrial changes happen very slowly,” he said.

But he said there’s a “reasonable case to be made” for investors to reduce their exposure to Canadian energy names under the assumption that more heavy oil may eventually flow to the U.S. market and weigh on Canadian prices.

“I think that’s why you’re seeing a broad sell-off of oil and gas equities today,” he said. “Some of that seems a little bit overstated or kind of snap reaction.”

Up until 2000, Canada and Venezuela each sent about the same amount to the U.S., but Venezeula’s exports have since dwindled to virtually nothing while the Canadian share has grown, Derek Holt, head of capital markets economics at Scotiabank wrote in a report Monday.

It’s clear Trump wants to take control of Venezuela’s oil reserves — 300 billion barrels or about 17 per cent of the world’s total, Holt wrote.

“It’s a hostile takeover in the global energy sector, the only difference being that guns were used instead of shareholder tactics.”

But he cautioned against leaping to the conclusion “that this will unleash a torrent of new supply on world markets with effects that allegedly include snowing under Canada’s oil industry.”


Venezuelan production peaked at 3.5 million barrels a day in 1998, and it now churns out less than a third of that, with most going to China. Holt said he doubts a U.S. intervention will lead to a swift return to its glory days.

“Its energy and broader infrastructure lay in shambles. Political uncertainty is off the charts. American hubris thinks it can restore order and run the country with a compliant local administration,” he wrote, noting past forays into Iraq, Afghanistan and elsewhere suggest otherwise.

Meanwhile, the United States’ own production has been crowding out imports and the world is awash in supply, putting pressure on global prices. The price of West Texas Intermediate crude, the key U.S. light oil benchmark, saw a bump on Monday, but it was still below the US$60 per barrel mark and about 20 per cent lower than it was at this time last year.

“What do you think unleashing three billion barrels of reserves in Venezuela would do to world oil prices relative to production break-evens? U.S. Big Oil isn’t that dumb,” Holt wrote, adding that domestic and Canadian infrastructure is also well established in the U.S. market.

“Nevertheless, the prudent thing for Canada to do would be to act with a greater sense of urgency in terms of building capacity to export oil to Asia (arguably ditto for Mexico),” Holt wrote.

It could take five to 10 years for Venezuela to meaningfully ramp up its production if it were to get a stable government and attract investment, Forrest said. But long term, it makes sense for Canada to send more of its oil to Asia, Forrest said.

“Hopefully it increases our motivation,” she said. “We need new outlets for our crude oil to diversify our export markets to protect us from threats like this.”

This report by The Canadian Press was first published Jan. 5, 2026.

Lauren Krugel, The Canadian Press.

Alberta’s Danielle Smith says Maduro capture outlines urgency of West Coast pipeline

ByThe Canadian Press
Published: January 05, 2026 

Prime Minister Mark Carney, right, signs an MOU with Alberta Premier Danielle Smith in Calgary,Thursday, Nov. 27, 2025. THE CANADIAN PRESS/Jeff McIntosh (Jeff McIntosh)

Alberta Premier Danielle Smith says the American capture of Venezuelan President Nicolás Maduro underlines the urgency of building oil pipelines to export Canadian oil to new markets.

U.S. President Donald Trump sent political shock waves around the world with the weekend military raid, saying Washington aimed to seize the South American country’s oil reserves for American companies to exploit.Download our app to get Edmonton alerts on your device

“Recent events surrounding Venezuelan dictator Nicolás Maduro emphasize the importance that we expedite the development of pipelines to diversify our oil export markets,” said Smith in a Monday statement.

That includes a new pipeline to British Columbia’s West Coast to reach markets in Asia, she said.

In November, Smith signed an agreement with Prime Minister Mark Carney paving the way to a potential Indigenous co-owned bitumen pipeline and to claw back environmental policies standing in the way, including the B.C. tanker ban.


The deal aims for Alberta and Ottawa to agree on an industrial carbon price by April 1 and sets a July 1 deadline for a pipeline proposal to Ottawa’s Major Projects Office.

Smith said her government is continuing its work to submit that application and expects the federal government to move forward “with urgency.”

“Alberta supports building pipelines in all directions to get our product to market and we look forward to continuing to work with provincial and federal partners to advance these projects,” Smith said.

The premier’s comments echo that of many commentators and industry experts who argued Trump’s military strike bolsters Alberta’s case for building more export capacity with a pipeline to the Pacific.

On Monday, shares in Canada’s biggest oilsands producers came under pressure, with the TSX energy subindex down more than three per cent.

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This report by The Canadian Press was first published Jan. 5, 2026.

Lisa Johnson, The Canadian Press