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Canadian Energy Centre

Indigenous communities shut out by B.C. tanker ban want another chance

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9 minute read

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.”

Alberta

India and Spain are buying Canadian oil…from the U.S.

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Infrastructure at the Enbridge Ingleside Energy Center near Corpus Christi, Texas. EIEC is the largest crude oil storage and export terminal by volume in the United States. Photo courtesy Enbridge

From the Canadian Energy Centre

By Deborah Jaremko

‘Re-exports’ from terminals on the U.S. Gulf Coast continue at a steady pace

International shipments of Canadian oil from ports on the U.S. Gulf Coast continue at a steady pace, according to a new report by RBN Energy.

Major buyers in recent months were India and Spain, said analyst Martin King.

These are so-called “re-exports” — oil produced in Western Canada that moves by pipeline or rail through the U.S. to terminals primarily in Port Arthur, Texas.

Citing data compiled by Bloomberg and the U.S. Census Bureau, King said re-exports averaged 117,000 barrels per day in June, the third consecutive month over 100,000 barrels per day.

Re-exports of Canadian oil from the U.S. Gulf Coast have slowed somewhat since the Trans Mountain pipeline expansion came online in May 2024, King said, as China shifts to using closer access via the West Coast.

In addition to export terminals, the U.S. Gulf Coast has the world’s largest cluster of refineries designed to process “heavy” oil, Canada’s main export to the region.

Total U.S. Gulf Coast imports of Canadian oil so far this year have averaged about 400,000 barrels per day, according to the U.S. Energy Information Administration.

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Business

Growth in value of Alberta energy has benefits nationwide

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From the Canadian Energy Centre

By Grady Semmens

The recent expansion of the Trans Mountain pipeline helped drive a surge in the value of Alberta’s energy production, which rose to $139 billion in 2024, according to the latest Alberta Energy Outlook.

The Alberta Energy Regulator (AER) reported that last year was the second-highest value of the province’s energy production on record, after 2022’s banner year of $167 billion.

For comparison, the annual average between 2015 and 2019 was just $74 billion.

Industry experts say the strong numbers highlight the continued importance of oil and gas to Canada’s economic prosperity.

“Every Albertan will benefit from this windfall, but it trickles through the Canadian economy as well, notably in higher GDP, productivity, exports and trade diversification: all things we badly need,” said Heather Exner-Pirot, director of energy, natural resources and environment at the Ottawa-based Macdonald-Laurier Institute.

“If the case for another bitumen pipeline wasn’t already clear, this seals the deal.”

The additional export capacity provided by the Trans Mountain expansion has enabled producers to move more oil to international markets at stronger prices — fueling both production growth and higher revenues for companies and governments.

An economic powerhouse

Bitumen from the oil sands remains the largest contributor to Alberta’s energy economy, according to the AER’s analysis, and improved market access has narrowed the discount faced by Western Canadian Select crude.

“Alberta continues to lead Canada’s energy story — not only through robust oil and gas production but also by accelerating momentum in emerging resources like hydrogen, lithium, and geothermal,” said AER principal economist Afshin Honarvar.

The regulator’s annual outlook found that the value of bitumen production in 2024 totaled $95.8 billion.

Natural gas liquids including propane, butane and ethane generated $19.7 billion, followed by conventional crude oil at $18.2 billion and natural gas at $5 billion.

A drilling rig operates near Cremona, Alta., July 2021. CP Images photo

Western Canada also stands to benefit from continued growth in natural gas production to meet global demand, particularly with the LNG Canada export terminal now operating.

The AER undertook a reassessment of natural gas reserves, which saw Alberta’s volume increase by 440 per cent, taking Canada from 15th place to ninth place globally.

Alberta’s oil reserves – already fourth in the world – also increased by seven billion barrels.

“This is telling us that Alberta is a crucial part of the energy supply in North America,” Honavar said.

“We are a reliable source and an affordable source, without any worries that we will run out of reserves or resources.”

LNG Canada announced its first official cargo of liquefied natural gas destined for global markets on July 1, 2025. Photo courtesy LNG Canada

Benefits across the country

According to Canada Energy Regulator data, Alberta is responsible for about 84 per cent of Canada’s total oil and equivalent production and about 60 per cent of the country’s natural gas output.

Across the country, Natural Resources Canada estimates the sector employs about 450,000 people directly or indirectly.

Energy products were by far Canada’s top export in 2024, valued at $196 billion — more than double the next largest category, metal and mineral products, at $94.8 billion, according to Statistics Canada.

In 2023, the most recent year of data available, oil and gas contributed 7.7 per cent of Canada’s GDP, or $209 billion, the federal department says.

“It’s a huge industry, dominated by the oil sands, that Canada really benefits from and will continue to benefit from for decades,” said Richard Masson, executive fellow with the School of Public Policy at the University of Calgary.

He said the rise in Alberta’s production value translates directly into fiscal gains for the provincial and federal governments.

Well pad at Cenovus Energy’s Christina Lake oil sands facility southeast of Fort McMurray, Alta. CP Images photo

Alberta collected $19.2 billion in resource royalties during the 2023–24 fiscal year, with corporate taxes and income tax revenues also boosted by high industry activity.

The province also reported an unexpected $8 billion budget surplus for 2024-25 due to higher energy revenues.

“Energy royalties provide almost as much as personal income tax does for Alberta. If we didn’t have it, we would have to have a sales tax and other government revenues,” Masson said.

Rising production

According to the AER, bitumen production climbed by 4.3 per cent last year to an average of 3.56 million barrels per day. Driven by continued investment, the regulator forecasts output will rise to about four million barrels per day by 2034.

The key to realizing this potential is further expansion of export pipeline capacity to ensure additional oil production can reach international markets.

Investment in emerging energy technology

Wells at the Clive carbon capture, utilization and storage (CCUS) project near Red Deer, Alta. Photo courtesy Enhance Energy

The AER report says capital investment in Alberta’s energy sector hit $30.9 billion in 2024, the highest level in nearly a decade.

That spending included not just oil and gas, but growing investments in hydrogen, helium, lithium, and carbon capture and storage (CCS) projects.

The regulator forecasts continued momentum in both traditional and emerging sectors.

Hydrogen production in Alberta is expected to grow from 2.6 million tonnes per year to 4.4 million tonnes by 2034.

Since 2015, CCS projects have captured and stored 16 million tonnes of CO₂ deep underground — equivalent to taking over 3.7 million cars off the road for a year.

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