On November 27, 2025, Prime Minister Mark Carney and Alberta Premier Danielle Smith signed the Canada–Alberta Memorandum of Understanding, an agreement that ties the fate of a major new bitumen pipeline to the West Coast to the most ambitious oil-sands decarbonization plan ever attempted in Canada.

The headline commitment of the MOU is the private-sector construction of at least one new pipeline capable of moving one million barrels or more per day of “low-emission” Alberta diluted bitumen (or dilbit) to a deep-water terminal on British Columbia’s coast for export, primarily to Asia. This would come on top of the recently completed 300,000 to 400,000 barrels per day Trans Mountain Expansion (TMX). 

The MOU will also require amending the federal Oil Tanker Moratorium Act, which imposes a complete ban on tanker traffic carrying more than 12,500 metric tonnes of crude oil or “persistent” oils (e.g., diluted bitumen/dilbit, heavy fuel oil, certain refined products) as cargo in the defined moratorium zone.

In exchange, Ottawa has agreed to scrap its proposed oil-and-gas emissions cap, exempt Alberta from the Clean Electricity Regulations, and let the province’s carbon price rise more gradually, provided the Pathways Alliance delivers verifiable, large-scale carbon capture and storage (CCS) starting in 2027.

The deal has already been denounced by many coastal and interior First Nations in British Columbia (BC) as a betrayal and by environmental groups as climate surrender. Supporters call it the only realistic path to keep Alberta’s oil competitive in a decarbonizing world.

So here’s the question we’re tackling this week with data, not dogma: In an era when global oil demand is widely expected to peak within the next decade, does it still make economic and strategic sense for Canada to double down on getting land-locked bitumen to tidewater?

Memorandum of Understanding Explained

A Memorandum of Understanding (MOU) is a formal but non-binding agreement that spells out shared intentions and commitments between parties. Essentially, it is a written roadmap for cooperation.

The Canada–Alberta MOU is a political accord between Ottawa and Edmonton that signals serious intent to align policies, fast-track major projects, and hold each other accountable, while leaving room for detailed, legally binding agreements later.

Understanding The Particulars of The MOU

The Canada-Alberta MOU opens with the following preface:

At this pivotal global moment, Canada and Alberta, working closely with Indigenous Peoples and industry, must work together cooperatively, and within their respective jurisdictions, to foster the conditions necessary for infrastructure, including pipelines, rail, power generation, a strong and integrated transmission grid, ports and other means that will unlock and grow natural resource production and transportation in Western Canada. As a result, Canada will be able to reach its international export goals and develop new technologies including Artificial Intelligence (AI), and, through innovation and intergovernmental cooperation, be a source of clean energy to lower global greenhouse gas (GHG) emissions.

The MOU reaffirms the shared goal of net-zero GHG emissions by 2050 and aims to unlock the growth potential of Western Canada’s oil, gas (including LNG), renewables, critical minerals, and other global-demand resources.

Core Objectives

• Unlock Western Canada’s oil, gas, LNG, renewables and critical minerals

• Grow exports and jobs while slashing emissions intensity

• Deliver affordable, reliable, net-zero electricity by 2050 (including for AI data centres)

• Cut red tape and cap major-project approvals at two years

• Ensure meaningful Indigenous consultation, equity stakes and economic benefits

Beyond the headline grabbing pipeline, the MOU commits both governments to three additional megaprojects: the Pathways Alliance carbon-capture network (the world’s largest planned Carbon Capture, Utilization, and Storage (CCUS) system), thousands of megawatts of AI computing power, and major transmission interties with British Columbia and Saskatchewan.

Alberta’s Key Commitments

• Advance an Indigenous-co-owned dilbit pipeline to the West Coast for Asian export

• Expand carbon-capture incentives and CCUS ecosystem

• Backstop Indigenous ownership in pipeline and Pathways Alliance projects

• Secure tangible benefits for British Columbia

Federal Government’s Key Commitments

• Eliminate the oil-and-gas emissions cap

• Suspend Clean Electricity Regulations in Alberta

• Recognise Alberta’s TIER carbon pricing system

• Declare a new West Coast bitumen pipeline a national-interest priority

• Streamline approvals and amend the Oil Tanker Moratorium Act if needed

• Extend CCUS investment tax credits and Indigenous loan guarantees

• Remove Competition Act “greenwashing” provisions

• Consult Alberta in good faith on any measures affecting its industries

Joint Commitments (highlights)

• Make pipeline approval and construction explicitly contingent on verifiable Phase-1 CCUS delivery by the Pathways Alliance — and vice versa — through a binding tri-lateral MOU to be signed by 1 April 2026, with enforcement mechanisms whose legal durability remains untested.

• Deliver a durable, globally competitive industrial carbon price ($130/t minimum, clear escalators, 75% methane cut by 2035)

• Engage British Columbia in trilateral talks and offer it substantial benefits

• Provide meaningful consultation and accommodation with Indigenous nations in Alberta and British Columbia

• Streamline regulatory processes across all jurisdictions (target: max 2-year approvals)

First Principles

Whether you support or oppose pipelines, a critical question is “does this multi-decade, multi-hundred-billion-dollar bet actually make financial sense for Canada?” To answer that, we need to start with what we’re actually selling.

Dilbit, or diluted bitumen, is ultra-heavy oil from the oil sands mixed with lighter hydrocarbons (e.g. natural gas condensate or naphtha) so it can flow through a pipeline. Once it reaches a marine terminal, the same dilution that makes pipeline transport possible also allows it to be loaded onto tankers for overseas shipment. 

In its natural form, bitumen is so thick it barely moves. The famous Pitch Drop Experiment at the University of Queensland, started in 1927, has measured only nine drops in nearly a century. That’s why bitumen must be mixed with lighter hydrocarbons to make it flow.

Once it reaches a refinery, the diluent is stripped off and recycled, leaving raw bitumen. Most people think that bitumen then just becomes gasoline or diesel. Some of it does, but the majority of global bitumen demand has nothing to do with burning it.

The Demand Math

Global oil demand isn’t collapsing overnight, but it is slowing, as emerging markets electrify rapidly. According to Kingsmill Bond and the team at Ember, 63% of new electricity demand in the Global South has already leapfrogged U.S. solar penetration, while ASEAN countries and Bangladesh now outpace America in final-energy electrification. Electric vehicles, e-fuels, and efficiency gains are eroding gasoline and diesel demand first.

The IEA’s November 2025 Oil Market Report forecasts roughly 700 kb/d growth in 2025–2026, slowing to a plateau of ~105.5 mb/d by 2030, which is a ~2.5 mb/d increase from 2024, but with annual gains dropping near zero post-2026.

Use Cases For Bitumen

While transportation fuel demand may decline over the next five to ten years, bitumen is largely insulated as 65–75% of it never reaches an engine. Its largest global use is asphalt, which is the material paving roads in emerging markets at record rates. The remainder feeds roofing shingles, waterproofing, adhesives, carbon black for tires and plastics, industrial coatings, and a growing range of advanced materials, including experimental battery electrodes. In many applications, bitumen commands higher value per barrel than light crude, thanks to its unique combination of adhesive strength, waterproofing, and carbon-rich properties.

If the business case for a new dilbit pipeline rested solely on supplying transport fuels, it would be hard to justify. But led by China and India, Asia-Pacific infrastructure demand is booming, with bitumen consumption forecasted to reach 103 million tons in 2025 and grow 3–5% annually to 119 million tons by 2030. Even as light crude for transport peaks, bitumen’s “sticky” demand remains.

A pipeline to the coast could therefore make economic sense, allowing Alberta’s ~3–4 million bpd of bitumen to reach premium Asian buyers rather than being sold at a discount to US Midwest buyers. This could capture a $5–10/bbl price uplift, equating to ~$2–5 billion per year in additional GDP at 1 mb/d, with upside of $10–20 billion as volumes ramp.

Alternatives To Bitumen

Canadian bitumen, primarily from Alberta’s oil sands, is widely used for road asphalt because it produces a highly durable, heavy-duty binder. It excels under extreme conditions such as high-traffic highways, scorching summers, frigid winters, and heavy axle loads.

But could there be a better alternative? That depends on your priorities: cost, performance, environmental impact, local availability, or supply security.

• Performance: For maximum durability in severe climates, Canadian bitumen remains among the best industrial-scale options. Polymer-modified bitumen can outperform straight oil-sands bitumen, but at a 30–100% cost premium.

• Lower carbon or political considerations: Some regions experiment with Middle Eastern heavy crude blended with high recycled asphalt content (RAP) and warm-mix additives, or 10–30% bio-binder replacements (particularly in Europe). These approaches can cost 2–5 times more than Canadian bitumen and still raise questions about durability and supply.

• Cost and supply security: U.S. refiners increasingly rely on domestic heavy crudes and high RAP percentages rather than imported Canadian bitumen. However, Canadian heavy still dominates the PADD 2 (Midwest) market, and current trade and political dynamics are driving Canada to explore alternative markets—a key factor behind the west-coast dilbit pipeline MOU.

In short, at industrial scale for heavy-duty paving, Canadian bitumen continues to offer the best combination of performance, availability, and cost. No country has yet achieved a full “drop-in” replacement that matches its proven track record.

Politics, Environment, and Execution

Even with strong economics, robust international demand, and a signed MOU between the province of Alberta and the Canadian government, a new bitumen pipeline still faces significant political and environmental hurdles. A recent Angus Reid poll shows public sentiment is cautiously supportive, with 60% of Canadians and 53% of British Columbians backing new export pipelines. But opposition is deeply entrenched in key regions.

As of late 2025 no proponent, route, or terminal location has been identified, almost certainly to avoid triggering early regional pushback before financial, regulatory, and diplomatic groundwork is in place. Tanker traffic and spill behaviour remain major flashpoints and coastal communities remain wary of any increase in marine risk.

Indigenous opposition along the British Columbia coast is even more decisive. The Heiltsuk Nation has called any new dilbit export project a “non-starter,” the Union of BC Indian Chiefs has rejected the concept outright, and leaders from multiple nations, including Wet’suwet’en, Gitanyow, Lax Kw’alaams, Nisga’a, and Haisla, are already mobilizing. Without genuine partnership or consent from affected Indigenous communities, and without at least the support or acquiescence of the B.C. government (not a signatory to the Canada–Alberta MOU), the project is politically untenable.

Financing adds another major barrier. With global renewable investment surpassing $2.2 trillion in 2025 (more than double fossil-fuel investment) major Canadian banks and international lenders face net-zero constraints that limit participation in new oil-sands pipelines. Securing $20–30 billion of private capital will likely require substantial federal loan guarantees or leadership from Asian trading houses and sovereign wealth funds. Still, the strategic upside remains significant: diversifying beyond the U.S., enhancing energy security, supporting CCUS and SMR build-out, and delivering federal–provincial benefits such as grid interties and revenue-sharing intended to reduce regional friction.

Market Diversification Matters More Than Ever

Global oil markets are entering a period of persistent oversupply. Non-OPEC+ producers, especially the U.S., Brazil, Guyana, and Canada, are set to add 1.3–1.6 million barrels per day (mb/d) of new supply in 2025–26. That’s well above expected demand growth, meaning inventories are projected to build by 0.7–0.9 mb/d per year. 

If OPEC+ brings its 2.2 mb/d of voluntary cuts back to market more aggressively, prices could fall into the $50 range, putting additional pressure on Canadian producers already contending with a ~$15/bbl Western Canadian Select (WCS) discount. This is exactly why market access, and not just market price, has become Canada’s key competitive lever.

The first year of the Trans Mountain Expansion (TMX), which began operating in May 2024, proved this point. By reducing dependence on U.S. refineries and opening direct access to Asia, TMX generated over $10 billion in additional revenue for Canadian producers. Pipeline GDP grew 8.5%, and nearly 60% of TMX cargoes in its opening months were bound for Asian markets. A future pipeline with even modest capacity could double this diversification benefit.

The strategic advantage grows further when factoring in emissions, if the promised Pathways Alliance CCS project actually materialises. The Pathways Alliance claims its Phase-1 network will remove ~20 Mt of CO₂ per year by 2030, which would make Alberta’s bitumen among the lowest-emission heavy crudes on the planet and a credible “clean heavy” alternative to higher-carbon, geopolitically riskier barrels from Venezuela, Iraq, or Iran. 

The outcome of the Pathways Alliance, however, hinges on delivering a $16–25 billion CCUS megaproject (roughly the same capital cost as the pipeline itself). Even at the low end, it’s a bet-the-farm scale in a sector where flagship projects have routinely run 50–100 % over budget and years late (Boundary Dam, Petra Nova, Gorgon). Success is far from guaranteed.

The “Last Barrel” Concept

The concept of the “last barrel” captures the economic and strategic reality of oil production in a world of finite resources and shifting energy demand. It builds on the idea of peak oil, which is the point at which global production plateaus and begins to decline, but focuses specifically on the final, hardest-to-extract oil. As demand for oil and its derivatives, like bitumen, softens due to electrification, efficiency gains, and the global energy transition, producers face a stark choice. They can either continue pumping the most expensive, carbon-intensive, or geopolitically risky barrels, or acknowledge that some barrels can’t pay their way and write off stranded assets.

Risks from Declining Demand

Not all oil is created equal. Light, conventional crude is relatively easy to produce as it can be pumped out of the ground and transported ‘as-is’. Bitumen, on the other hand, is a thick, tar-like heavy hydrocarbon that is difficult to extract and must be cut with diluent before it can be transported. On top of this, production is energy-intensive, as surface mining requires the removal of large amounts of overburden, while in-situ methods, like steam-assisted gravity drainage (SAGD), consume enormous amounts of natural gas and water. 

Canada holds roughly 97% of recoverable reserves or roughly 165 billion barrels, with Alberta alone producing 3.5–4.0 million bbl/d. Extraction is highly sensitive to oil prices, with break-even costs typically between $50–80/bbl and payback periods stretching 10–20 years.

If demand declines, driven by reduced road construction in mature economies, the shift to electric vehicles, or global carbon policies, the first production cuts will hit regions where bitumen is:

• High-cost: Oil sands require $40–70/bbl versus $20–40/bbl for conventional heavy oil.

• Export-dependent: Limited pipeline access or steep discounts for exports (e.g., Western Canadian Select trades $10–20 below Brent).

• Small-scale or underdeveloped: Infrastructure or political instability prevents scaling.

• Environmentally pressured: Facing bans, lawsuits, or investor withdrawal due to emissions intensity.

Sequencing Global Shutdowns

Based on reserves, production profiles, and vulnerabilities, the global picture of potential shutdowns is uneven:

• Venezuela (Orinoco Belt, ~300B barrels recoverable): Already halved output due to political instability, sanctions, and poor infrastructure. Any demand decline could shutter remaining production by 2027–2030.

• United States (Utah, ~12–20B barrels): Small pilot operations face water scarcity, high costs, and regulatory hurdles. Likely to remain dormant or shutter permanently if markets soften.

• African producers (Congo, Madagascar): High logistics costs, undeveloped infrastructure, and dependence on foreign investment make early production vulnerable.

• Canada (Athabasca, ~165B barrels, 3.5M bbl/d): Scale, integration with U.S. refineries, and export infrastructure provide a buffer. Still, marginal in-situ wells could idle first, cutting 20–30% by 2035, while larger operations remain viable.

In terms of bitumen, Venezuela will likely see the first shuttered barrels, followed by smaller U.S. and African operations, while Canada is poised to produce the last barrel. This sequencing underscores a critical point: the energy transition hits hardest in fossil-dependent economies lacking diversification. For countries with large, integrated oil sands operations and strategic export capacity, like Canada, there remains a window of opportunity to monetize bitumen while investing in emissions reduction and low-carbon technologies.

A Narrow Window, Not a Blank Cheque

The Canada–Alberta MOU is neither a climate surrender nor an energy salvation. It’s a pragmatic, time-limited bargain, struck in the shrinking space between two realities: global oil demand is plateauing faster than most politicians admit, yet the world will still need heavy hydrocarbons, and the carbon-rich molecules unique to bitumen, for decades of roads, roofs, and industrial feedstocks in Asia.

If everything falls into place: the Pathways Alliance delivers a functioning $16–25 billion CCUS backbone on schedule; a private-sector proponent secures a route with genuine Indigenous partnership; British Columbia trades its veto for transformative benefits; and Asian buyers and sovereign funds write the cheques that Canadian banks won’t, then this pipeline could become the rare infrastructure project that funds the oil sands’ orderly decarbonization while locking in Canada’s last-mover advantage in a declining commodity.

But each of those “ifs” is enormous. History suggests that at least two will fail. Notably, the MOU ties the pipeline’s fate to CCUS milestones, giving opponents a single, verifiable point of leverage: miss the carbon-capture targets, and the project dies by contract. That mutually accountable mechanism is arguably the agreement’s most candid feature.

The real question isn’t whether Canada should “double down” on bitumen. It’s whether we can extract maximum value from a non-renewable resource while the window is open, and exercise the discipline to shut the tap when it closes. The MOU doesn’t answer that question. It simply buys the time and sets the rules for Canada to find out.