Canadian Energy Centre
Indigenous communities shut out by B.C. tanker ban want another chance
From the Canadian Energy Centre
By Deborah Jaremko and Will Gibson
“Canada’s Indigenous communities need projects, not lawsuits that hold them up”
From the outset, projects must unite leadership from proponents, governments and affected First Nations
The head of the National Coalition of Chiefs (NCC) is calling for the repeal of the oil tanker ban on B.C.’s north coast as Canada seeks “nation-building” projects to strengthen economic independence.
With short shipping times to hungry Asian markets, ports like Prince Rupert or Kitimat offer a strong business case – but only if the tankers can dock.
“No proponent is going to look at investing in a pipeline to the north coast with that kind of legislation in place,” says NCC founder and CEO Dale Swampy.
Formed in 2016, the NCC is a group of pro-development First Nation leaders including some who were equity partners in the cancelled Northern Gateway pipeline from Edmonton to Kitimat.
Canada’s Indigenous communities need projects, not lawsuits that hold them up, he says.
Original map of the proposed Northern Gateway Pipeline, submitted to regulators as part of a preliminary information package in October 2005. Map courtesy Canada Energy Regulator
Northern Gateway and the tanker ban
The tanker ban and Northern Gateway are intrinsically linked.
The moratorium contributed to the loss of Indigenous ownership stakes and an estimated $2 billion in economic opportunity for First Nations and Métis communities.
“We have consistently spoken up against this legislation, which directly affects the ability of our communities to participate in developing resources,” Swampy says.
With the aim to diversify markets for Canadian oil by reaching customers in Asia, Enbridge announced Northern Gateway in 2004.
The project’s 7,800-page regulatory application to the National Energy Board (NEB) – including more than 1,600 pages specific to marine safety – followed in May 2010.
In December 2013, after extensive assessment and public hearings, including with Indigenous communities, a three-member Joint Review Panel from the NEB and the Canadian Environmental Assessment Agency recommended the project to go ahead.
In June 2014, the federal government approved Northern Gateway with 209 conditions, including a requirement to fulfill over 400 voluntary commitments, many tied to marine safety.
After receiving approval, Northern Gateway’s management team and the project’s Aboriginal Equity Partners proposed an increase in Indigenous ownership from 10 per cent to 33 per cent.
They also created a joint governance structure where the communities and the company would have an equal voice.
The modified project would also incorporate First Nations and Métis environmental stewardship and monitoring using traditional science.
Meanwhile, legal actions were underway by environmental groups and Indigenous communities outside the equity partners.
By December 2014, the Federal Court of Appeal had consolidated multiple cases challenging the project’s approval.
Blocking the Northern Gateway pipeline and enacting a moratorium on oil tanker traffic on B.C.’s north coast became cornerstones of the Liberal Party’s 2015 election platform.
Oil Tanker Moratorium Act legislated moratorium area, 2017. Map courtesy Transport Canada
In November 2015, just a week after being sworn in, former Prime Minister Justin Trudeau instructed his transport minister to “formalize” the ban, a major setback for Northern Gateway.
Five months later, in June 2016 the Federal Court of Appeal overturned the government’s approval for the project, ruling that Canada had failed to fulfill its constitutional duty to consult Indigenous communities.
In November 2016, Trudeau officially rejected Northern Gateway, devastating hopes for the bands that would have become equity partners.
“Thirty-one of the 40 First Nations and Métis communities who were located on Northern Gateway’s right-of-way supported the pipeline, but a couple of communities backed by environmental groups were able to stop the entire project,” Swampy says.
“That’s not fair or democratic.”
In May 2017, Bill C-48, also known as the Oil Tanker Moratorium Act, was formally introduced in the House of Commons.
Indigenous communities stripped of opportunity
At the time, Swampy told the Financial Post that the communities saw the decision to reject Northern Gateway as political and not acting in the best interests of Canadians.
“They weren’t asked about the financial effect, the lost employment,” he said.
The implications of the tanker ban go far beyond the West Coast, Indian Resources Council CEO Stephen Buffalo told the Standing Senate Committee on Transport and Communications in March 2019.
Buffalo joined Swampy and other Indigenous leaders to speak to the committee as part of its consideration of Bill C-48.
Representing more than 130 First Nations that produce or have the potential to produce oil and gas, he said community prosperity is closely tied to the sector.
“The industry is suffering greatly from the lack of pipeline access…We need access to new markets to obtain fair value for our oil resources,” Buffalo said.
“We are struggling with addictions and depression, and people are losing hope. If we are ever going to make faster progress on these issues, our First Nations communities need more own-source revenues to fund cultural programs, sports programs or health activities for our young people,” he said.
“We need more jobs available for our people. We need them to earn good wages — wages that can support their families. Right now, Bill C-48 and other policies threaten all of that for us.”
Buffalo questioned the necessity of the tanker ban.
“I think all First Nations would support development of strict regulations that protect the environment, but that’s different from arbitrarily stopping just Canadian oil tanker activity,” he said.
The Senate approved the tanker ban and it became law upon Royal Assent on June 21, 2019.
Shifting times and new pipelines
Six years and the threat of U.S. tariffs later, the view on Canadian oil pipelines — and, potentially, the tanker ban itself — is shifting.
Growing public support for pipelines in recent opinion polls has encouraged Swampy.
So, too, has the change in attitudes towards development by coastal First Nations that have experienced the benefits of working with industry.
“Many of the coastal First Nations in northwestern B.C. are either building or looking at building LNG facilities. They appreciate the fact prosperity can be gained by partnering on these projects,” he says.
The NCC wants to see that same opportunity for the communities that would have benefited from Northern Gateway, through a new oil pipeline proposal to either Kitimat or Prince Rupert.
“We are hoping providing some certainty with Indigenous consultation and participation will give proponents some certainty they have a willing partner,” Swampy says.
To avoid lawsuits that delay or cancel projects and drive developers out of Canada, Swampy says agreements must, from the outset, unite leadership from proponents, governments and affected First Nations.
“We hope governments hear our message: we want projects, not lawsuits,” he says.
“Communities don’t need a cheque or a handout. They need the opportunity to participate in a meaningful way.”
Aspenleaf Energy vice-president of wells Ron Weber at a clean-up site near Edmonton.
From the Canadian Energy Centre
Aspenleaf Energy brings new life to historic Alberta oil field while cleaning up the past
In Alberta’s oil patch, some companies are going beyond their obligations to clean up inactive wells.
Aspenleaf Energy operates in the historic Leduc oil field, where drilling and production peaked in the 1950s.
In the last seven years, the privately-held company has spent more than $40 million on abandonment and reclamation, which it reports is significantly more than the minimum required by the Alberta Energy Regulator (AER).
CEO Bryan Gould sees reclaiming the legacy assets as like paying down a debt.
“To me, it’s not a giant bill for us to pay to accelerate the closure and it builds our reputation with the community, which then paves the way for investment and community support for the things we need to do,” he said.
“It just makes business sense to us.”
Aspenleaf, which says it has decommissioned two-thirds of its inactive wells in the Leduc area, isn’t alone in going beyond the requirements.
Producers in Alberta exceeded the AER’s minimum closure spend in both years of available data since the program was introduced in 2022.
That year, the industry-wide closure spend requirement was set at $422 million, but producers spent more than $696 million, according to the AER.
In 2023, companies spent nearly $770 million against a requirement of $700 million.
Alberta’s number of inactive wells is trending downward. The AER’s most recent report shows about 76,000 inactive wells in the province, down from roughly 92,000 in 2021.
In the Leduc field, new development techniques will make future cleanup easier and less costly, Gould said.
That’s because horizontal drilling allows several wells, each up to seven kilometres long, to originate from the same surface site.
“Historically, Leduc would have been developed with many, many sites with single vertical wells,” Gould said.
“This is why the remediation going back is so cumbersome. If you looked at it today, all that would have been centralized in one pad.
“Going forward, the environmental footprint is dramatically reduced compared to what it was.”
During and immediately after a well abandonment for Aspenleaf Energy near Edmonton. Photos for the Canadian Energy Centre
Gould said horizontal drilling and hydraulic fracturing give the field better economics, extending the life of a mature asset.
“We can drill more wells, we can recover more oil and we can pay higher royalties and higher taxes to the province,” he said.
Aspenleaf has also drilled about 3,700 test holes to assess how much soil needs cleanup. The company plans a pilot project to demonstrate a method that would reduce the amount of digging and landfilling of old underground materials while ensuring the land is productive and viable for use.
Crew at work on a well abandonment for Aspenleaf Energy near Edmonton. Photo for the Canadian Energy Centre
“We did a lot of sampling, and for the most part what we can show is what was buried in the ground by previous operators historically has not moved anywhere over 70 years and has had no impact to waterways and topography with lush forestry and productive agriculture thriving directly above and adjacent to those sampled areas,” he said.
At current rates of about 15,000 barrels per day, Aspenleaf sees a long runway of future production for the next decade or longer.
Revitalizing the historic field while cleaning up legacy assets is key to the company’s strategy.
“We believe we can extract more of the resource, which belongs to the people of Alberta,” Gould said.
“We make money for our investors, and the people of the province are much further ahead.”
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.”
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