There is no better time for the Atlantic to follow the Pacific as the next stage of Canadian energy development

Premier Tim Houston says it’s time for Nova Scotia to develop its energy industry

In late January, Nova Scotia Premier Tim Houston announced that natural resources would become a major focus of his government, stating that it was time to, “We can’t expect Nova Scotia to prosper when we ban industry after industry after industry.”

It was announced that his government would look into fracking for natural gas, uranium mining, and lifting fossil fuel extraction moratoriums along the coast.

Atlantic Canada is poised to become the next major player in Canada’s energy expansion. With growing global demand for clean energy, a shift toward resource independence, and the looming threat of U.S. tariffs, provinces like Newfoundland and Labrador and Nova Scotia are taking bold steps to develop their energy sectors. Recent developments in liquefied natural gas (LNG), offshore oil, green hydrogen, and critical minerals are positioning the region as a crucial pillar of Canada’s energy future.

Donald Trump’s threats to impose tariffs on Canadian energy exports have forced Canada to reassess its reliance on the United States as its primary customer. This shift has already played out in Quebec, where the government is reconsidering its stance on LNG projects. Similarly, Atlantic Canada recognizes the need to diversify its energy exports to Europe and Asia. With vast offshore oil reserves and new LNG projects in the works, the region is set to capitalize on international markets.

Premier Houston has emphasized the importance of local resource development to secure the province’s economy. Though he has walked back on previous comments about revisiting the Georges Bank offshore drilling moratorium, his government is clearly focused on increasing natural resource production. The seafood industry, a vital component of the region’s economy, has expressed concerns about potential energy developments affecting fisheries, but a balance must be struck to ensure both industries thrive.

Newfoundland and Labrador Premier Andrew Furey has made it clear that offshore oil will continue to play a key role in the province’s economy for decades. Addressing industry leaders, Furey positioned Newfoundland as the future “energy capital of North America,” highlighting new offshore projects and hydrogen development. ExxonMobil’s $1.5 billion investment in offshore infrastructure underscores industry confidence in the region’s potential.

Despite dubious global forecasts suggesting oil demand will peak in the coming years, Newfoundland and Labrador believes its high-quality, low-emission crude will remain in demand, particularly in Europe and Asia. Additionally, the province is exploring hydrogen production, backed by federal incentives and private investment. Companies like World Energy GH2 are pushing forward with large-scale green hydrogen projects, despite local opposition from residents concerned about the environmental impact of wind farms.

As British Columbia emerges as an LNG powerhouse, Atlantic Canada is following suit. The region’s proximity to European markets gives it a significant advantage, particularly in light of geopolitical instability affecting global energy supplies. With European nations scrambling to secure reliable energy sources, Atlantic Canada’s LNG potential is more valuable than ever.

Much like British Columbia, where First Nations have played a central role in LNG expansion, Atlantic Canada has an opportunity to develop Indigenous-led energy projects. Federal tax incentives and emissions regulations will shape how LNG projects move forward, ensuring they align with Canada’s climate commitments while driving economic growth.

The combination of Trump’s tariffs, shifting global energy markets, and renewed provincial interest in resource development has created a perfect storm for Atlantic Canada’s energy sector. With strong government backing, significant private investment, and growing international demand, the region is well-positioned to become a major energy player.

As Canada navigates this new era of energy expansion, Atlantic Canada’s strategic location, resource wealth, and commitment to innovation make it a natural frontier for growth. Whether through LNG, offshore oil, hydrogen, or critical minerals, the region’s energy sector is set to thrive in the coming decades.

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Energy

Thawing the freeze on oil and gas development in Treaty 8 territory

Published on November 8, 2025

Todayville

From Resource Works

Will direct tenure awards to First Nations unlock Montney gas?

By Nelson Bennett

In an attempt to open an area that producers have essentially been shut out of in northeastern B.C., the B.C. government directly awarded oil and gas tenure to the Halfway River First Nation, giving them greater control over how oil and gas extraction in the area might happen.

That tenure is now getting “farmed out” to companies like ARC Resources.

“The granting of the tenure by the B.C. government to the nation is new,” said Greg Kist, executive manager for Tsaa Dunne Za Energy, the Halfway River First Nation’s energy business.

*Greg Kist, former president of Pacific NorthWest LNG and current managing executive for Tsaa Dunne Ta Energy*, *THE CANADIAN PRESS/Jeff McIntosh*.

Depending on the outcome of the experiment, it’s the kind of thing that might one day be showcased at a future Indigenous Partnership Success Showcase event.

For more than two decades, a large area in Halfway River First Nation traditional territory in northeastern B.C. has been off limits to industrial activities like logging and oil and gas exploration and extraction, due to treaty rights.

In 1999, the BC Supreme Court quashed a timber harvesting permit approved by the province for Canfor, based on Halfway River First Nation’s Treaty 8 rights.

An extraction moratorium of sorts was placed over core HRFN territory, which happens to be in the “fairway” of the Montney natural gas formation.

“All of the lands were deferred from any further development,” Kist said. “And that meant everything from logging it, to oil and gas activities.”

This “deferral” of industrial activities in the area has been one of the question marks hanging over the oil and gas-rich Montney formation in northeastern B.C.

The 2021 BC Supreme Court Yahey decision had also left Treaty 8 territory dotted with question marks.

In Yahey, the court ruled cumulative impacts of activities like oil and gas development constituted a breach of the treaty rights of the Blueberry River First Nation, one of eight B.C. signatories to Treaty 8.

These various treaty rights rulings in northeastern B.C. create a serious challenge: How can B.C. continue to benefit from an abundance of natural gas to feed a burgeoning LNG industry without infringing the rights of Treaty 8 First Nations?

In the case of Halfway River, the B.C. government, the First Nation and industry are taking an innovative approach, using oil and gas tenure.

Last year, the B.C. government and HRFN signed a treaty settlement agreement that grants the nation more control over land use and development. As part of the agreement, the B.C. government directly awarded HRFN oil and gas tenure over 34,000 hectares of land. It was the first time the province has directly awarded oil and gas tenure to a First Nation.

In turn, the HRFN is now farming out its tenure rights to companies like ARC Resources, whose existing land holdings in the Attachie play are directly adjacent to the HRFN tenure.

“The resource quality is comparable to ARC’s existing Attachie asset, further extending the development runway at one of ARC’s most profitable assets,” ARC said in its second quarter financials at the end of July.

The tenure awarded to HRFN through its energy business, Tsaa Dunne Ta Energy, encompasses prime Montney real estate that had been essentially sterilized from development for decades.

“That 34,000 hectares is right in the middle of the Montney fairway,” Kist said.

Under an “earning and development” agreement with Tsaa Dunne Za Energy, ARC Resources will gain access to 36 parcels of land contiguous with its existing land parcel in the Attachie play. This expands its Attachie holdings by 10%.

Green area denotes Halfway River First Nation tenure; blue represents ARC Resources tenure.

“Think of it as Tsaa Dunne farming that land out to ARC, and we have an agreement that benefits us financially,” Kist said.

“The tenure award and landscape planning pilot will help to ensure that oil and gas development in these areas is sustainable and managed in accordance with the values of the Halfway River First Nation,” Chief Darlene Hunter said last year with the signing of the treaty settlement agreement.

Kist notes that the agreement with ARC represents only 25% of the land tenure granted to HRFN. So 75% of the land tenure could be open to further agreements with other natural gas producers.

“There will likely be more deals over time as we look at the different opportunities that are out there,” Kist said.

Kist is the former president of Rockies LNG and, before that, president of Pacific Northwest LNG. He and Jim Stannard, a former Petronas executive, are now managers for Tsaa Dunne Za Energy.

The tenure award does not represent a transfer of subsurface rights. All subsurface rights to things like minerals, coal, and oil and gas belong to the Crown.

“And at the end of the day, the B.C. government still gets its royalties,” Kist said. “But now the nation is very much in control of that activity.”

The recent agreement with ARC to develop 36 parcels adjacent to its Attachie lands is just the first one to be signed so far. There may be more such agreements in the future, Kist said.

Kist said the First Nation tenure model could end up being used elsewhere.

“I think the B.C. government’s going to look at these sorts of opportunities in areas where maybe there is a lack of development moving things forward,” he said.

“I think this could potentially be the model for development, with First Nations leading the way.”

Alberta

Canada’s heavy oil finds new fans as global demand rises

Published on November 8, 2025

Todayville

From the Canadian Energy Centre

By Will Gibson

“The refining industry wants heavy oil. We are actually in a shortage of heavy oil globally right now, and you can see that in the prices”

Once priced at a steep discount to its lighter, sweeter counterparts, Canadian oil has earned growing admiration—and market share—among new customers in Asia.

Canada’s oil exports are primarily “heavy” oil from the Alberta oil sands, compared to oil from more conventional “light” plays like the Permian Basin in the U.S.

One way to think of it is that heavy oil is thick and does not flow easily, while light oil is thin and flows freely, like fudge compared to apple juice.

“The refining industry wants heavy oil. We are actually in a shortage of heavy oil globally right now, and you can see that in the prices,” said Susan Bell, senior vice-president of downstream research with Rystad Energy.

A narrowing price gap

Alberta’s heavy oil producers generally receive a lower price than light oil producers, partly a result of different crude quality but mainly because of the cost of transportation, according to S&P Global.

The “differential” between Western Canadian Select (WCS) and West Texas Intermediate (WTI) blew out to nearly US$50 per barrel in 2018 because of pipeline bottlenecks, forcing Alberta to step in and cut production.

So far this year, the differential has narrowed to as little as US$10 per barrel, averaging around US$12, according to GLJ Petroleum Consultants.

“The differential between WCS and WTI is the narrowest I’ve seen in three decades working in the industry,” Bell said.

Trans Mountain Expansion opens the door to Asia

Oil tanker docked at the Westridge Marine Terminal in Burnaby, B.C. Photo courtesy Trans Mountain Corporation

The price boost is thanks to the Trans Mountain expansion, which opened a new gateway to Asia in May 2024 by nearly tripling the pipeline’s capacity.

This helps fill the supply void left by other major regions that export heavy oil – Venezuela and Mexico – where production is declining or unsteady.

Canadian oil exports outside the United States reached a record 525,000 barrels per day in July 2025, the latest month of data available from the Canada Energy Regulator.

China leads Asian buyers since the expansion went into service, along with Japan, Brunei and Singapore, Bloomberg reports.

Asian refineries see opportunity in heavy oil

“What we are seeing now is a lot of refineries in the Asian market have been exposed long enough to WCS and now are comfortable with taking on regular shipments,” Bell said.

Kevin Birn, chief analyst for Canadian oil markets at S&P Global, said rising demand for heavier crude in Asia comes from refineries expanding capacity to process it and capture more value from lower-cost feedstocks.

“They’ve invested in capital improvements on the front end to convert heavier oils into more valuable refined products,” said Birn, who also heads S&P’s Center of Emissions Excellence.

Refiners in the U.S. Gulf Coast and Midwest made similar investments over the past 40 years to capitalize on supply from Latin America and the oil sands, he said.

While oil sands output has grown, supplies from Latin America have declined.

Mexico’s state oil company, Pemex, reports it produced roughly 1.6 million barrels per day in the second quarter of 2025, a steep drop from 2.3 million in 2015 and 2.6 million in 2010.

Meanwhile, Venezuela’s oil production, which was nearly 2.9 million barrels per day in 2010, was just 965,000 barrels per day this September, according to OPEC.

The case for more Canadian pipelines

Worker at an oil sands SAGD processing facility in northern Alberta. Photo courtesy Strathcona Resources

“The growth in heavy demand, and decline of other sources of heavy supply has contributed to a tighter market for heavy oil and narrower spreads,” Birn said.

Even the International Energy Agency, known for its bearish projections of future oil demand, sees rising global use of extra-heavy oil through 2050.

The chief impediments to Canada building new pipelines to meet the demand are political rather than market-based, said both Bell and Birn.

“There is absolutely a business case for a second pipeline to tidewater,” Bell said.

“The challenge is other hurdles limiting the growth in the industry, including legislation such as the tanker ban or the oil and gas emissions cap.”

A strategic choice for Canada

Because Alberta’s oil sands will continue a steady, reliable and low-cost supply of heavy oil into the future, Birn said policymakers and Canadians have options.

“Canada needs to ask itself whether to continue to expand pipeline capacity south to the United States or to access global markets itself, which would bring more competition for its products.”