Canadian Energy Centre
Top 10 good news stories about Canadian energy in 2024
From the Canadian Energy Centre
Record oil production, more Indigenous ownership and inching closer to LNG
It’s likely 2024 will go down in history as a turning point for Canadian energy, despite challenging headwinds from federal government policy.
Here’s some of the good news.
10. New carbon capture and storage (CCS) projects to proceed
Photo courtesy Shell Canada
In June, Shell announced it will proceed with the Polaris and Atlas CCS projects, expanding emissions reduction at the company’s Scotford energy and chemicals park near Edmonton.
Polaris is designed to capture approximately 650,000 tonnes of CO2 per year, or the equivalent annual emissions of about 150,000 gasoline-powered cars. The CO2 will be transported by a 22-kilometre pipeline to the Atlas underground storage hub.
The projects build on Shell’s experience at the Quest CCS project, also located at the Scotford complex. Since 2015, Quest has stored more than eight million tonnes of CO2. Polaris and Atlas are targeted for startup in 2028.
Meanwhile, Entropy Inc. announced in July it will proceed with its Glacier Phase 2 CCS project. Located at the Glacier gas plant near Grande Prairie, the project is expected onstream in mid-2026 and will capture 160,000 tonnes of emissions per year.
Since 2015, CCS operations in Alberta have safely stored roughly 14 million tonnes of CO2, or the equivalent emissions of more than three million cars.
9. Canada’s U.S. oil exports reach new record
Expanded export capacity at the Trans Mountain Westridge Terminal. Photo courtesy Trans Mountain Corporation
Canada’s exports of oil and petroleum products to the United States averaged a record 4.6 million barrels per day in the first nine months of 2024, according to the U.S. Energy Information Administration.
Demand from Midwest states increased, along with the U.S. Gulf Coast, the world’s largest refining hub. Canadian sales to the U.S. West Coast also increased, enabled by the newly completed Trans Mountain Pipeline Expansion.
8. Alberta’s oil production never higher
A worker at Suncor Energy’s MacKay River oil sands project. CP Images photo
In early December, ATB Economics analyst Rob Roach reported that Alberta’s oil production has never been higher, averaging 3.9 million barrels per day in the first 10 months of the year.
This is about 190,000 barrels per day higher than during the same period in 2023, enabled by the Trans Mountain expansion, Roach noted.
7. Indigenous energy ownership spreads
Communities of Wapiscanis Waseskwan Nipiy Limited Partnership in December 2023. Photo courtesy Alberta Indigenous Opportunities Corporation
In September, the Bigstone Cree Nation became the latest Indigenous community to acquire an ownership stake in an Alberta energy project.
Bigstone joined 12 other First Nations and Métis settlements in the Wapiscanis Waseskwan Nipiy Holding Limited Partnership, which holds 85 per cent ownership of Tamarack Valley Energy’s Clearwater midstream oil and gas assets.
The Alberta Indigenous Opportunities Corporation (AIOC) is backstopping the agreement with a total $195 million loan guarantee.
In its five years of operations, the AIOC has supported more than 60 Indigenous communities taking ownership of energy projects, with loan guarantees valued at more than $725 million.
6. Oil sands emissions intensity goes down
Oil sands steam generators. Photo courtesy Cenovus Energy
A November report from S&P Global Commodity said that oil sands production growth is beginning to rise faster than emissions growth.
While oil sands production in 2023 was nine per cent higher than in 2019, total emissions rose by just three per cent.
“This is a notable, significant change in oil sands emissions,” said Kevin Birn, head of S&P Global’s Centre for Emissions Excellence.
Average oil sands emissions per barrel, or so-called “emissions intensity” is now 28 per cent lower than it was in 2009.
5. Oil and gas producers beat methane target, again
Photo courtesy Tourmaline
Data released by the Alberta Energy Regulator in November 2024 confirmed that methane emissions from conventional oil and gas production in the province continue to go down, exceeding government targets.
In 2022, producers reached the province’s target to reduce methane emissions by 45 per cent compared to 2014 levels by 2025 three years early.
The new data shows that as of 2023, methane emissions have been reduced by 52 per cent.
4. Cedar LNG gets the green light to proceed
Haisla Nation Chief Councillor Crystal Smith and Pembina Pipeline Corporation CEO Scott Burrows announce the Cedar LNG positive final investment decision on June 25, 2024. Photo courtesy Cedar LNG
The world’s first Indigenous majority-owned liquefied natural gas (LNG) project is now under construction on the coast of Kitimat, B.C., following a positive final investment decision in June.
Cedar LNG is a floating natural gas export terminal owned by the Haisla Nation and Pembina Pipeline Corporation. It will have capacity to produce 3.3 million tonnes of LNG per year for export overseas, primarily to meet growing demand in Asia.
The $5.5-billion project will receive natural gas through the Coastal GasLink pipeline. Peak construction is expected in 2026, followed by startup in late 2028.
3. Coastal GasLink Pipeline goes into service
Workers celebrate completion of the Coastal GasLink Pipeline. Photo courtesy Coastal GasLink
The countdown is on to Canada’s first large-scale LNG exports, with the official startup of the $14.5-billion Coastal GasLink Pipeline in November.
The 670-kilometre pipeline transports natural gas from near Dawson Creek, B.C. to the LNG Canada project at Kitimat, where it will be supercooled and transformed into LNG.
LNG Canada will have capacity to export 14 million tonnes of LNG per year to overseas markets, primarily in Asia, where it is expected to help reduce emissions by displacing coal-fired power.
The terminal’s owners – Shell, Petronas, PetroChina, Mitsubishi and Korea Gas Corporation – are ramping up natural gas production to record rates, according to RBN Energy.
RBN analyst Martin King expects the first shipments to leave LNG Canada by early next year, setting up for commercial operations in mid-2025.
2. Construction starts on $8.9 billion net zero petrochemical plant
Dow’s manufacturing site in Fort Saskatchewan, Alberta. Photo courtesy Dow
In April, construction commenced near Edmonton on the world’s first plant designed to produce polyethylene — a widely used, recyclable plastic — with net zero scope 1 and 2 emissions.
Dow Chemicals’ $8.9 billion Path2Zero project is an expansion of the company’s manufacturing site in Fort Saskatchewan. Using natural gas as a feedstock, it will incorporate CCS to reduce emissions.
According to business development agency Edmonton Global, the project is spurring a boom in the region, with nearly 200 industrial projects worth about $96 billion now underway or nearing construction.
Dow’s plant is scheduled for startup in 2027.
1. Trans Mountain Pipeline Expansion completed
The “Golden Weld” marked mechanical completion of construction for the Trans Mountain Expansion Project on April 11, 2024. Photo courtesy Trans Mountain Corporation
The long-awaited $34-billion Trans Mountain Pipeline Expansion officially went into service in May, in a game-changer for Canadian energy with ripple effects around the world.
The 590,000 barrel-per-day expansion for the first time gives customers outside the United States access to large volumes of Canadian oil, with the benefits flowing to Canada’s economy.
According to the Canada Energy Regulator, exports to non-U.S. locations more than doubled following the expansion startup, averaging 420,000 barrels per day compared to about 130,000 barrels per day in 2023.
The value of Canadian oil exports to Asia has soared from effectively zero to a monthly average of $515 million between June and October, according to ATB Economics.
Wapisiw Lookout, reclaimed site of the oil sands industry’s first tailings pond, which started in 1967. The area was restored to a solid surface in 2010 and now functions as a 220-acre watershed. Photo courtesy Suncor Energy
From the Canadian Energy Centre
By CEC Research
Mines demonstrate significant strides through technological innovation
Tailings are a byproduct of mining operations around the world.
In Alberta’s oil sands, tailings are a fluid mixture of water, sand, silt, clay and residual bitumen generated during the extraction process.
Engineered basins or “tailings ponds” store the material and help oil sands mining projects recycle water, reducing the amount withdrawn from the Athabasca River.
In 2023, 79 per cent of the water used for oil sands mining was recycled, according to the latest data from the Alberta Energy Regulator (AER).
Decades of operations, rising production and federal regulations prohibiting the release of process-affected water have contributed to a significant accumulation of oil sands fluid tailings.
The Mining Association of Canada describes that:
“Like many other industrial processes, the oil sands mining process requires water.
However, while many other types of mines in Canada like copper, nickel, gold, iron ore and diamond mines are allowed to release water (effluent) to an aquatic environment provided that it meets stringent regulatory requirements, there are no such regulations for oil sands mines.
Instead, these mines have had to retain most of the water used in their processes, and significant amounts of accumulated precipitation, since the mines began operating.”
Despite this ongoing challenge, oil sands mining operators have made significant strides in reducing fluid tailings through technological innovation.
This is demonstrated by reductions in “legacy fluid tailings” since 2015.
Legacy Fluid Tailings vs. New Fluid Tailings
As part of implementing the Tailings Management Framework introduced in March 2015, the AER released Directive 085: Fluid Tailings Management for Oil Sands Mining Projects in July 2016.
Directive 085 introduced new criteria for the measurement and closure of “legacy fluid tailings” separate from those applied to “new fluid tailings.”
Legacy fluid tailings are defined as those deposited in storage before January 1, 2015, while new fluid tailings are those deposited in storage after January 1, 2015.
The new rules specified that new fluid tailings must be ready to reclaim ten years after the end of a mine’s life, while legacy fluid tailings must be ready to reclaim by the end of a mine’s life.
Total Oil Sands Legacy Fluid Tailings
Alberta’s oil sands mining sector decreased total legacy fluid tailings by approximately 40 per cent between 2015 and 2024, according to the latest company reporting to the AER.
Total legacy fluid tailings in 2024 were approximately 623 million cubic metres, down from about one billion cubic metres in 2015.
The reductions are led by the sector’s longest-running projects: Suncor Energy’s Base Mine (opened in 1967), Syncrude’s Mildred Lake Mine (opened in 1978), and Syncrude’s Aurora North Mine (opened in 2001). All are now operated by Suncor Energy.
The Horizon Mine, operated by Canadian Natural Resources (opened in 2009) also reports a significant reduction in legacy fluid tailings.
The Muskeg River Mine (opened in 2002) and Jackpine Mine (opened in 2010) had modest changes in legacy fluid tailings over the period. Both are now operated by Canadian Natural Resources.
Imperial Oil’s Kearl Mine (opened in 2013) and Suncor Energy’s Fort Hills Mine (opened in 2018) have no reported legacy fluid tailings.
Suncor Energy Base Mine
Between 2015 and 2024, Suncor Energy’s Base Mine reduced legacy fluid tailings by approximately 98 per cent, from 293 million cubic metres to 6 million cubic metres.
Syncrude Mildred Lake Mine
Between 2015 and 2024, Syncrude’s Mildred Lake Mine reduced legacy fluid tailings by approximately 15 per cent, from 457 million cubic metres to 389 million cubic metres.
Syncrude Aurora North Mine
Between 2015 and 2024, Syncrude’s Aurora North Mine reduced legacy fluid tailings by approximately 25 per cent, from 102 million cubic metres to 77 million cubic metres.
Canadian Natural Resources Horizon Mine
Between 2015 and 2024, Canadian Natural Resources’ Horizon Mine reduced legacy fluid tailings by approximately 36 per cent, from 66 million cubic metres to 42 million cubic metres.
Total Oil Sands Fluid Tailings
Reducing legacy fluid tailings has helped slow the overall growth of fluid tailings across the oil sands sector.
Without efforts to reduce legacy fluid tailings, the total oil sands fluid tailings footprint today would be approximately 1.6 billion cubic metres.
The current fluid tailings volume stands at approximately 1.2 billion cubic metres, up from roughly 1.1 billion in 2015.
The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.
The Port of Prince Rupert on the north coast of British Columbia. Photo courtesy Prince Rupert Port Authority
From the Canadian Energy Centre
By Will Gibson
Moratorium does little to improve marine safety while sending the wrong message to energy investors
In 2019, Martha Hall Findlay, then-CEO of the Canada West Foundation, penned a strongly worded op-ed in the Globe and Mail calling the federal ban of oil tankers on B.C.’s northern coast “un-Canadian.”
Six years later, her opinion hasn’t changed.
“It was bad legislation and the government should get rid of it,” said Hall Findlay, now director of the University of Calgary’s School of Public Policy.
The moratorium, known as Bill C-48, banned vessels carrying more than 12,500 tonnes of oil from accessing northern B.C. ports.
Targeting products from one sector in one area does little to achieve the goal of overall improved marine transport safety, she said.
“There are risks associated with any kind of transportation with any goods, and not all of them are with oil tankers. All that singling out one part of one coast did was prevent more oil and gas from being produced that could be shipped off that coast,” she said.
Hall Findlay is a former Liberal MP who served as Suncor Energy’s chief sustainability officer before taking on her role at the University of Calgary.
She sees an opportunity to remove the tanker moratorium in light of changing attitudes about resource development across Canada and a new federal government that has publicly committed to delivering nation-building energy projects.
“There’s a greater recognition in large portions of the public across the country, not just Alberta and Saskatchewan, that Canada is too dependent on the United States as the only customer for our energy products,” she said.
“There are better alternatives to C-48, such as setting aside what are called Particularly Sensitive Sea Areas, which have been established in areas such as the Great Barrier Reef and the Galapagos Islands.”
The Business Council of British Columbia, which represents more than 200 companies, post-secondary institutions and industry associations, echoes Hall Findlay’s call for the tanker ban to be repealed.
“Comparable shipments face no such restrictions on the East Coast,” said Denise Mullen, the council’s director of environment, sustainability and Indigenous relations.
“This unfair treatment reinforces Canada’s over-reliance on the U.S. market, where Canadian oil is sold at a discount, by restricting access to Asia-Pacific markets.
“This results in billions in lost government revenues and reduced private investment at a time when our economy can least afford it.”
The ban on tanker traffic specifically in northern B.C. doesn’t make sense given Canada already has strong marine safety regulations in place, Mullen said.
Notably, completion of the Trans Mountain Pipeline expansion in 2024 also doubled marine spill response capacity on Canada’s West Coast. A $170 million investment added new equipment, personnel and response bases in the Salish Sea.
“The [C-48] moratorium adds little real protection while sending a damaging message to global investors,” she said.
“This undermines the confidence needed for long-term investment in critical trade-enabling infrastructure.”
Indigenous Resource Network executive director John Desjarlais senses there’s an openness to revisiting the issue for Indigenous communities.
“Sentiment has changed and evolved in the past six years,” he said.
“There are still concerns and trust that needs to be built. But there’s also a recognition that in addition to environmental impacts, [there are] consequences of not doing it in terms of an economic impact as well as the cascading socio-economic impacts.”
The ban effectively killed the proposed $16-billion Eagle Spirit project, an Indigenous-led pipeline that would have shipped oil from northern Alberta to a tidewater export terminal at Prince Rupert, B.C.
“When you have Indigenous participants who want to advance these projects, the moratorium needs to be revisited,” Desjarlais said.
He notes that in the six years since the tanker ban went into effect, there are growing partnerships between B.C. First Nations and the energy industry, including the Haisla Nation’s Cedar LNG project and the Nisga’a Nation’s Ksi Lisims LNG project.
This has deepened the trust that projects can mitigate risks while providing economic reconciliation and benefits to communities, Dejarlais said.
“Industry has come leaps and bounds in terms of working with First Nations,” he said.
“They are treating the rights of the communities they work with appropriately in terms of project risk and returns.”
Hall Findlay is cautiously optimistic that the tanker ban will be replaced by more appropriate legislation.
“I’m hoping that we see the revival of a federal government that brings pragmatism to governing the country,” she said.
“Repealing C-48 would be a sign of that happening.”
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