Pipeline Route Options within Canadian Borders
Canada has explored the possibility of building a west-to-east oil pipeline entirely on Canadian soil. The most prominent proposal was Energy East, a 4,500+ km pipeline from Alberta to New Brunswick. As shown in the map below, it would have linked Alberta’s oil sands (Hardisty) to the Atlantic port of Saint John, NB, via Saskatchewan, Manitoba, Ontario, and Quebec. This route avoided U.S. territory, keeping the pipeline under Canadian jurisdiction. TransCanada (now TC Energy) planned to convert an existing gas pipeline for part of the route and build new sections through Quebec and into New Brunswick. The pipeline’s capacity would be around 1.1 million barrels per day, slated to be one of the longest in North America.
Map of the proposed Energy East pipeline route from Alberta to New Brunswick (Energy East – Wikipedia).
Building such a pipeline is technically feasible but faces significant challenges. Energy East was estimated to cost about C$15–24 billion and was actively pursued in the mid-2010s. However, it was cancelled in 2017 due to regulatory hurdles and opposition, particularly in Quebec. Public opinion in transit provinces was mixed – only about one-third of Quebecers supported the project then, compared to about half of Canadians outside Quebec. Concerns ranged from local environmental risks to climate impacts (discussed below). These factors and falling oil prices that hurt the business case led TC Energy to shelve the project in 2017.
Despite the setback, interest in a cross-Canada route persists. In 2020, a small company proposed a new 4,800 km “Canadian Prosperity Pipeline” (CP3) with Indigenous partnerships to revive the west-east route. Their concept includes a pipeline corridor to the Atlantic tidewater and a marine terminal at an even larger scale than Energy East. This suggests that the idea of a domestic export route remains viable. Indeed, a 2020 poll found that 71% of Quebecers preferred importing oil from Western Canada rather than abroad, suggesting growing local acceptance if concerns are addressed. In mid-2020, Irving Oil (New Brunswick) took the extraordinary step of shipping Alberta oil by sea – it chartered a tanker to carry Cenovus Energy’s Alberta crude from Vancouver (via the Panama Canal) to Saint John. This one-off 11,900 km voyage, which is over double the pipeline distance, underscored the demand and the extreme measures required to ship oil without a pipeline. It demonstrated that an all-Canadian route to the East Coast, if built, could dramatically shorten the supply line for Alberta’s oil to Atlantic Canada and Europe.
Regulatory and Environmental Hurdles
Any cross-country pipeline in Canada is subject to stringent regulations and rigorous environmental scrutiny. Federal law now requires extensive impact assessments, including effects on climate change and Indigenous rights, before approval. During the Energy East review, the regulator (the NEB, now the Canada Energy Regulator) was directed to consider upstream carbon emissions from oil production – estimated at over 30 million tonnes of CO₂ annually – as part of the project’s impact. This was supported by Ontario and Quebec, which insisted that the effects of greenhouse gases be evaluated. The additional climate test introduced uncertainty for the proponent; TransCanada cited “regulatory uncertainty” and the broadened scope of review as factors in its decision to cancel the project in 2017.
Environmental protection laws also pose route-specific challenges. For example, the initial Energy East plan included a tanker export terminal on the St. Lawrence River at Cacouna, Quebec. This was scrapped after scientists warned of harm to a local beluga whale. Likewise, crossing significant waterways, such as the Ottawa River and the St. Lawrence River, raised questions that TransCanada struggled to fully address in its application. Multiple municipalities, such as North Bay and Thunder Bay in Ontario, and some First Nations along the route outright opposed the pipeline through their territories. The federal regulator had to pause hearings in 2016 after it was discovered that NEB panel members had privately met with a TransCanada consultant, a procedural breach that further eroded public trust.
Today, the Impact Assessment Act (2019) requirements are even more comprehensive, examining a project’s effects on communities, Indigenous peoples, climate targets, and biodiversity. Securing Indigenous consent is widely seen as essential. The new CP3 proposal explicitly plans for profit-sharing and partnerships with Indigenous communities to gain support, an approach informed by lessons from past projects. Even with local buy-in, however, a west-east pipeline would be subject to federal climate commitments, including Canada’s target of net-zero emissions by 2050, which raises questions about long-term oil expansion. In short, any East Coast pipeline must overcome formidable environmental reviews, align with climate policy, and convince skeptics that risks (spills, habitat, emissions) are manageable. Despite newfound political interest, these hurdles and economic factors explain why experts say a revival of Energy East is unlikely under current conditions. Our aim should be to align political interests and goals with national economic and financial goals for the good of all Canadians. We must ask what is more critical: sovereignty or sustainability? Without our sovereignty, there will be no sustainability, so let’s address first things first.
East Coast Refining Capacity and Infrastructure
One motivation for an East Coast pipeline is to supply Canadian refineries currently reliant on imported crude. Atlantic Canada’s refining hub is Irving Oil’s Saint John refinery in New Brunswick – the largest in the country, with a capacity of 320,000 barrels per day. This refinery typically processes light to medium crudes, most of which are imported via tankers from the North Sea, Saudi Arabia, the United States, and other regions. It cannot run Alberta’s ultra-heavy bitumen blend in large volumes. To refine Alberta’s heavy crude, you need a Coker refinery.
Understanding Alberta’s Heavy Crude
WCS is a blend comprising bitumen, conventional oil, synthetic crude, and condensate. Its density and sulfur content classify it as a heavy, sour crude, which traditionally requires more intensive refining processes. However, advancements in refining technology have enabled the efficient processing of such crudes into valuable petroleum products.
U.S. Refining Capacity and Infrastructure
As of January 2024, the United States boasts a substantial refining capacity, with numerous refineries in Texas and Oklahoma equipped with Coker units designed to process heavy crude oil. For instance, the Valero Refining Co. in Texas has a capacity of 225,000 barrels per day and significant coking capabilities.
What is a Coker? A Coker is a critical processing unit in petroleum refineries that handles the heaviest, lowest-value portions of crude oil. It is a thermal cracking unit that converts heavy residual oil from distillation into lighter, more valuable products. Because it uses extremely high temperatures, it is significantly more expensive to build and operate compared to refineries that refine sweet light crude and do not require a Coker. A modern Coker refinery will cost upward of $2 billion to build and is considerably more expensive to maintain and operate.
In fact, none of the three major refineries in Eastern Canada (Irving Saint John, Valero Québec, and Suncor Montréal) currently has a Coker unit capable of fully processing raw oil sands bitumen. Installing a Coker for heavy oil is a massive investment of approximately $2 billion. As of a few years ago, Irving and Valero had not announced interest in such upgrades, likely because they can access ample supplies of lighter crude that their facilities are configured for.
However, economics could shift if a pipeline brought steady deliveries of discounted Western Canadian heavy crude. Irving indicated it could process some oil sands crude and even speculated about adding a Coker if warranted. During the Energy East discussions, Irving Oil also planned a new $300 million marine export terminal at Saint John. The idea was to ship out excess Canadian crude to overseas markets from their deep-water port. In the meantime, Irving has shown a willingness to adapt. For example, the 2020 test shipment of Alberta oil via Panama was processed in Saint John, proving it can occasionally handle those barrels.
That said, to regularly run large volumes of Alberta’s heavy diluted bitumen, significant refinery reconfigurations, upgraded Cokers and blending strategies would be needed in the East. Irving’s refinery could likely co-refine some heavy with lighter crudes, but maximizing the use of Alberta’s oil would require capital investments. The pipeline itself could encourage this: “Having the line in place would help encourage [refineries] to reconfigure to handle heavy crude,” says the CP3 pipeline proponent. The prospect of guaranteed supply would justify upgrading refineries over time.
It’s also worth noting that Eastern Canada continues to import substantial oil, despite the country’s overall surplus. In 2018, for example, Canada imported about 1 barrel for every 7.5 barrels it produced. These imports, 0.6 million barrels per day, supplied Quebec and Atlantic refineries and primarily came from the U.S., as well as OPEC countries such as Saudi Arabia and Algeria. This paradox – exporting over 3 million barrels per day to the U.S. while Eastern Canada buys foreign oil – is due to insufficient east-west transportation infrastructure. A cross-country pipeline could replace most of the country’s foreign oil imports with domestic crude.
Between 1988 and 2019, Canada spent $477 billion on foreign oil, a financial outflow a new pipeline could help retain domestically. The Irving refinery, for instance, could switch to Canadian feedstock if it is delivered economically, thereby improving Canada’s energy trade balance. Irving has publicly welcomed the idea of an energy corridor across Canada in principle, as it would secure long-term supply for them and potentially allow expansion. Some even floated the idea of building a second refinery in New Brunswick if Energy East had proceeded, although those plans never materialized.
In summary, the East Coast refining capacity exists and could absorb more Alberta oil; however, full utilization of heavy bitumen would likely require new refinery investments, such as Cokers. Absent that, any pipeline to Saint John might initially serve partly as an export pipeline, sending Alberta’s oil onward to Europe.
In the meantime, Alberta’s heavy crude oil remains a cornerstone of the U.S. refining sector, underscoring the deep interdependence between Canadian oil producers and American refiners. This relationship underscores the strategic importance of ongoing collaboration and infrastructure development in supporting the evolving energy needs of both nations. The cross-border cooperation strategy has benefited both countries for over a hundred years; however, now, America threatens to cancel Alberta’s access to American markets. Approximately 98% of Alberta’s exported oil is transported through the United States, either to be refined and consumed domestically or re-exported abroad. Danielle Smith desperately clings to this one-horse strategy, and the Trump administration blatantly ignores her pleas. Albertans do not learn from their mistakes. Before Biden’s presidency, they spent over a billion dollars on building their segment of the Keystone XL pipeline up to the U.S. border, despite the American government not having approved or completed their side of the pipeline. Smith’s attempt to change Trump’s mind while ignoring the possibility of working with Canada’s federal government to build an East-West pipeline will end badly for Alberta. Again.
Export Markets: Europe vs. Pacific Asia
One of the strategic arguments for an East Coast pipeline is to diversify Canada’s oil exports beyond the United States. The viability of sending Alberta’s heavy synthetic crude (bitumen-derived oil) to Europe versus to Pacific Asia depends on demand in those regions and the shipping logistics. Below is a comparison of the two market routes:
European Market (UK, France, Germany and others)
- Demand and Refining Needs: Historically, Europe has imported medium to heavy crude oil from Russia (Urals blend), the Middle East, and Africa. With Russian oil essentially banned, European refiners in countries such as Germany and France seek alternatives. Many European refineries are configured to process a mix of medium-sour crudes, similar to Western Canadian Select (WCS), a heavy sour blend. In fact, over half of Europe’s refineries are equipped to process heavy crude oil when it is available. For example, Spain’s Repsol refineries and Italy’s complexes have coking units designed for heavy grades. Refiners value heavy crude oil because it can yield more diesel and other products when processed with advanced refining units. Alberta’s synthetic/heavy oil could fit into this demand niche for heavy feedstock, especially given declines in heavy exports from Venezuela and Mexico.
- Evidence of Interest: There have been real-world trials – the first shipment of Canadian oil sands crude to Europe arrived in Spain (Bilbao) in 2014. Small volumes of Canadian heavy have intermittently flowed to Europe, often via U.S. Gulf Coast re-exports. In 2023, despite having minimal infrastructure, Europe, including the UK, France, Germany, and the Netherlands, among others, imported approximately 3% of Canada’s crude exports. This was only 120,000 barrels per day, but it suggests that European refiners are willing to accept Canadian oil when it becomes available. Spain has continued importing Canadian heavy sour barrels loaded from the U.S. Gulf. This indicates that if Canada could send oil directly to Europe from Saint John by tanker, refineries would be ready to buy – especially if the price is competitive.
- Shipping Logistics: The Atlantic voyage from Canada’s East Coast to Europe is relatively short. A tanker from New Brunswick can reach the UK or France in under 10 days. Saint John’s port is ice-free year-round and deep enough to handle large VLCC supertankers, which reduces per-barrel freight costs. Keeping the pipeline and shipping entirely in Canadian or international waters also avoids U.S. transit fees, tariffs, and export regulations. Overall, an eastward route offers a straightforward path into the European market.
- Challenges: Due to climate policies and rising vehicle electrification, European oil demand is mature or declining. The EU is also pushing to reduce the carbon intensity of fuels, and oil sands crude oil is carbon-intensive to produce. There may be political or regulatory resistance in Europe to importing heavy crude oil due to environmental concerns, as seen in debates over the EU Fuel Quality Directive. Additionally, competition for European markets is fierce, as they can easily import from the Middle East, the North Sea, West Africa, or the U.S. Gulf. Canadian crude oil would need to be attractively priced to gain market share, and traditionally, it has always been deeply discounted because Alberta is landlocked. There is no reason that at least partial discounting of Alberta’s WCS heavy crude would not continue even with an East-West pipeline. The expansion of the Trans Mountain pipeline and the consequential increase in Alberta’s oil production also demonstrated that markets are willing to pay more for WCS if it is offered with easy access.
The price differential between Western Canada Select (WCS) and West Texas Intermediate (WTI) narrowed by about $10 in Q4 2024 versus Q4 2023. Analysts estimate this price uplift increased oil revenues by $10 billion dollars since we began shipping oil through the expanded system. Trans Mountain News.
- While some European refineries can run heavy oil, others prefer lighter grades; Canada would be targeting a subset of refineries in the UK, Netherlands, Spain, Italy and possibly Germany’s coastal refineries that used Urals. Those refineries would still weigh Canadian oil’s quality against similar grades, such as Saudi Arabian Medium or Iraqi crude. In summary, Europe presents a viable market, particularly for heavy crude; however, volume growth may be moderate due to overall stagnant demand and increasing environmental scrutiny. Another draw might be for European countries to secure their supplies with historically reliable NATO partners, such as Canada.
Pacific Market (China, Japan, and Asia-Pacific)
- Demand and Refining Needs: The Asia-Pacific region, led by China and India, as well as refining centers in Japan and South Korea, has a growing appetite for crude oil, including heavy grades. China has built large, modern refineries equipped with Cokers and hydrocrackers to process very heavy, high-sulphur crudes, having previously imported Venezuelan, Iranian, and Mexican Maya crude.
- Japan, on the other hand, historically imports mostly lighter crudes from the Middle East, but some Japanese refineries can take heavy sour blends as part of their slate. Asia’s demand for transportation fuels is increasing, and complex Asian refineries are seeking discounted heavy feedstock to maximize their margins. Alberta’s heavy synthetic crude could fill a niche similar to Venezuelan or Mexican crude, whose supplies have been constrained. As evidence, India’s Reliance Industries – the world’s largest refinery complex – has been buying Canadian heavy oil (WCS) that was re-exported from the U.S. Gulf. Reliance even loaded a trial cargo of Canadian oil onto a VLCC from the U.S. West Coast, demonstrating direct interest; however, it found U.S. Gulf shipments cheaper due to current logistics.
- China, too, has begun transporting Canadian oil via new routes, with the Trans Mountain Expansion pipeline already enabling the shipment of 300,000 to 890,000 barrels per day from Vancouver to Pacific Rim countries, including China. This indicates solid demand in Asia if Canada can continue to deliver the oil.
On the first goal, crude oil production increased in 2024 as producers had greater capacity to ship, thanks to Trans Mountain’s expansion, and this production is set to grow further in 2025. According to industry analysts, total crude oil production in Canada reached 5.3 million bpd in December 2023, it hit 5.4 million bpd in December 2024 and is expected to reach 5.6 million bpd by December 2025. Trans Mountain News.
- Evidence of Market Access: Until now, Canada’s direct access to Asia was limited by pipeline capacity to the West Coast. The Trans Mountain Expansion (TMX) pipeline, completed in 2024, involved twinning the line to Vancouver and added 630,000 barrels of daily capacity to tidewater ports, providing Canadian producers with an economically viable and dedicated outlet to the Pacific Rim markets. Heavy crude cargoes from Alberta are already appearing in Asia, as spot shipments of Canadian heavy crude have picked up with the completion of TMX, amid a tight global supply of heavy crude due to OPEC cuts and reduced Venezuelan output. Asian buyers are eager for alternatives, especially after sanctions on Russia reshuffled crude flows. Japan’s government and industry have also expressed interest in supplies from friendly countries like Canada to improve their energy security. Therefore, the Pacific market for Alberta oil is already showing substantial growth.
- Shipping Logistics: Shipping oil from Canada’s West Coast to Asia is a longer journey (20 days to China or 10–12 days to Japan by sea) than transatlantic routes. Moreover, Vancouver’s port has a constraint: the Westridge marine terminal can only accommodate smaller Aframax-class tankers with a capacity of 80-120,000 DWT due to harbour depth and navigation limits. This means each tanker carries a modest parcel, and for longer hauls to Asia, some shippers may opt to perform ship-to-ship transfers to larger vessels. For instance, Canadian crude loaded onto Aframax tankers in Vancouver can be retransferred to Very Large Crude Carriers (VLCCs) at an offshore location, such as one off the coast of California. This adds cost and complexity.
- Additionally, the Panama Canal is too small for the largest tankers and adds fees, so Pacific exports generally must sail the long way across the Pacific (not through Panama). On the positive side, once at sea, the route to Asia is straightforward, the ocean is open, and BC’s ports are ice-free. However, the net effect is that the transport cost per barrel to reach Asian refiners is higher than that of European ones from the East Coast. A recent analysis found that the new TMX pipeline toll, combined with ocean freight, is only marginally cheaper than routing oil via the U.S. Gulf Coast to Asia. This could somewhat limit the price advantage of Canadian crude oil in Asia but substantially increase the revenues going into Canadian producers’ pockets rather than those of American Gulf port shippers. There is no point in understanding how the U.S. presidency views this substantial transfer of wealth from the U.S. to Canada as being to their benefit. I am not sure Alberta’s premier understands this either.
- Challenges: While Asia’s demand growth is a big opportunity, Canada faces competition from other exporters. China and India are currently flouting international sanctions by purchasing heavily discounted Russian Urals and Middle Eastern crudes, which compete with Canadian heavy crude in terms of quality. Asian buyers are price-sensitive and will purchase Canadian oil primarily if it’s priced attractively or for diversification purposes. There are also diplomatic and trade considerations. For example, China shunned Canadian commodities during political spats in the past, though energy has remained mostly trade-driven. Japan and South Korea, being U.S. allies, may be more inclined to source from Canada, but their volumes are smaller than those of China and India. Another factor is that unlike an East Coast pipeline (which doesn’t yet exist), the West Coast TMX pipeline is a reality, so Pacific export capacity is finite (TMX 630,000 bps). Suppose that fills up with long-term contracts despite some Canadian producers having committed volumes. In that case, there is a ceiling on how much can flow to Asia unless future expansions or another pipeline, such as the Northern Gateway to Prince Rupert, which was cancelled in 2016, is given the green light.
In Summary, Europe and Pacific Asia present viable markets for Alberta’s heavy oil, but with distinct advantages and disadvantages. Europe offers proximity and established heavy-crude refineries, but it may become a shrinking market under pressure from climate change advocates. The threat of Russian expansion could change EU priorities. Survival has a way of prioritizing how we can cope today rather than deal with the future.
Asia offers growth and potentially significant demand, but Canada’s route to this market involves higher shipping costs and increased competition. A pipeline to Canada’s East Coast could open the European market and even parts of the Indian Ocean market via the Suez Canal. At the same time, the Trans Mountain route covers the Asia-Pacific markets. Canada would benefit from diversifying its exports in both directions – some to Europe via an East Coast route and others to Asia via TMX- rather than relying on an increasingly unreliable U.S. In either case, there is demand for Alberta’s “heavy synthetic” crude abroad. Countries with sophisticated refineries, such as China, India, and Spain, actively seek heavy oil when available and discounted. The key is having the infrastructure to deliver it cost-effectively.
Coming Soon! Deep Dive Reading: Who Needs Alberta’s Heavy Oil, and Why?
