America's Record Oil Exports Are Made in Canada

I. The largest disruption in history

On February 28, 2026, the United States and Israel launched coordinated airstrikes on Iran. Iran's Revolutionary Guard declared the Strait of Hormuz closed. Within days, tanker traffic through the world's most critical energy chokepoint dropped to near zero. [10]

The strait normally carries roughly 20 million barrels per day of crude oil and petroleum products — approximately 20% of global petroleum liquids consumption. By mid-March, Gulf producers including Iraq, Kuwait, Saudi Arabia, and the UAE had collectively cut production by at least 10 million barrels per day because once local storage filled, they had no choice but to shut in wells. [11]

The historical comparison set matters. The 1973 Arab oil embargo removed approximately 4 million barrels per day, roughly 7% of global supply. It tripled prices and triggered a global recession. The 1979 Iranian Revolution disrupted about 5 million b/d. The 1990 Gulf War caused a 75% price spike but lasted only two months. The Hormuz closure is larger than all of them. [12]

This disruption hit a market that was expected to be oversupplied. In January 2026, global observed oil inventories stood at more than 8.2 billion barrels, the highest since February 2021. The EIA's prior forecast projected a global surplus. The speed of the reversal, from expected glut to the largest supply shock in recorded history, is itself without modern precedent. [13]

Six weeks in, the strait is still not functionally open. A ceasefire was announced in early April but has not been implemented. As of April 9, Abu Dhabi National Oil Company CEO Sultan Al Jaber confirmed that 230 loaded tankers remained waiting inside the Gulf. On April 12, only 17 vessels crossed, compared to roughly 130 daily transits before the war. On April 13, following the collapse of negotiations in Pakistan, President Trump announced a U.S. naval blockade targeting Iranian-linked shipping near the strait. [14] [15] [16]

II. The cascade

The disruption extends well beyond crude oil. The Strait of Hormuz is a chokepoint for a significant share of global fertilizer, LNG, industrial chemicals, and shipping traffic.

Fertilizer and food. More than 30% of global urea trade originates from Gulf countries and transits the strait. Urea prices surged from approximately $475 to $680 per metric ton during the North American spring planting window. The UN Food and Agriculture Organization warned that a global food crisis could develop if normal traffic does not resume. [17] [18] [19] [44]

LNG. The strait accounts for approximately one-fifth of global LNG supply. Iranian strikes on Qatar's Ras Laffan LNG complex caused a 17% reduction in production capacity, with repairs estimated to require three to five years. Asian LNG spot prices rose by over 140%. [11]

Industrial commodities. Nearly half of all global seaborne sulfur trade passes through the strait. Methanol, aluminium, synthetic graphite, and helium have all been disrupted, the last of which is critical to semiconductor manufacturing and has doubled in price. [20] [21]

Shipping. Dun & Bradstreet data showed more than 44,000 businesses across 174 economies had at least one shipment exposed as of March 12. Approximately 80% of affected entities were small and micro-businesses. [22]

In Canada, gasoline has approached $2 per litre and diesel is near $2.50. Five-year Government of Canada bond yields jumped from 2.7% to 3.2% in March, raising fixed-rate mortgage costs even as the Bank of Canada held steady. Trevor Tombe at the University of Calgary estimated that the typical household faces nearly $1,000 in added annual costs, a $17-billion hit to Canadian consumers in aggregate. The pain falls disproportionately on lower-income households and families with children. [8] [23] [24]

III. Who is filling the gap

When global supply is suddenly constrained, the countries that can move barrels to market fastest capture the premium. In this crisis, one country has responded at scale.

U.S. Gulf Coast crude exports are projected to reach a record 5 million barrels per day in May 2026, up from roughly 3.97 million b/d in March. Kpler data showed 68 empty tankers en route to the U.S. as of mid-April, compared to a pre-war average of 27. Demand from Asian customers was projected to rise by 82%. [4]

In the physical spot market, refiners in Europe and Asia are paying record premiums for any non-Middle Eastern barrel that can load and ship. North Sea Forties crude reached $148.87 per barrel on April 13, a new all-time record, roughly $50 above Brent futures on the same day. U.S. WTI Midland crude delivered to Europe traded at a record $21.85 premium to Dated Brent. Nigerian grades were offered at record premiums exceeding $10. [7] [25]

Eric Nuttall, Senior Portfolio Manager at Ninepoint Partners, told BNN Bloomberg that global storage was heading not to critically low levels but to "no levels" in the coming days and weeks. He described the scramble as "COVID inverted," supply, not demand, collapsing. [26]

Then he said this: "Those countries that have deep inventories of adequate egress, they're really, really going to command a premium. It's really Canada's time to shine … the world needs more Canadian energy." [26]

The statement contains its own contradiction. Canada has the deep inventories. It does not have the adequate egress. Understanding why, and understanding who does have the egress, and where their feedstock comes from, is the core of this story.

IV. The sorting hub

The United States is not a crude oil surplus nation. Its refineries require approximately 16.5 million barrels per day to operate at capacity. The U.S. produces roughly 13.6 million. The deficit is made up by imports, and Canada is, by a wide margin, the largest single source. [27]

In 2024, Canadian crude exports to the U.S. averaged 3.93 million barrels per day, 93% of Canada's total crude exports and over 60% of all U.S. crude imports. Canada supplies roughly nine times more crude to the U.S. than the next-largest supplier, Mexico. [2] [3]

The bulk of these exports are heavy sour crude, primarily Western Canadian Select and similar grades from the Alberta oil sands. U.S. Gulf Coast refineries were built decades ago to process exactly this type of heavy feedstock. They cannot easily switch to light sweet crude without billions of dollars in retooling. They need Canadian heavy crude to operate. [28]

Here is the mechanism that matters: Canadian heavy crude fills the feedstock gap at U.S. refineries, allowing those refineries to run at capacity. That, in turn, frees up domestically produced U.S. light sweet crude for export. The U.S. is not simply exporting excess crude from a self-contained domestic surplus. Its export capacity depends on a refinery system that also imports large volumes of Canadian heavy crude. [27]

So what does this mean for the price Canada receives?

WCS for May delivery settled at $16.15 per barrel below WTI as of April 6. From 2008 through 2018, the historical average discount was approximately US$17. It briefly narrowed to $9–$11 after Trans Mountain expanded in 2024, but widened again as Alberta hit record production of 4.2 million b/d in early 2026, overwhelming even the expanded pipeline capacity, and the Iran war pushed WTI higher. [5] [29] [43]

On 4+ million barrels per day, a $16 discount represents roughly $65 million per day relative to the WTI benchmark. A significant portion of that discount reflects genuine quality and transportation cost differences: heavy sour crude has lower API gravity, higher sulfur content, and requires more complex (and costly) refining. Transportation from Alberta to the Gulf Coast adds further real cost. Even with unlimited pipeline capacity, WCS would not price at WTI parity. But the discount has historically exceeded what quality differentials alone would justify, because Canada's limited non-U.S. pipeline capacity means producers lack alternative buyers at scale. In our assessment, this creates what amounts to a captive-market dynamic: U.S. Gulf Coast refineries buy Canadian heavy at a discount that reflects both quality and constrained market access, refine it into products sold at global prices, and occupy the part of the value chain with direct access to the crisis premium. [29] [30]

This is not an argument that Canadian producers are unprofitable at current prices. WCS at roughly $97 per barrel ($113 WTI minus $16 discount) is historically strong. The argument is about relative price capture and market access: Canada is receiving less of the global crisis premium than it could under a different egress structure.

When the U.S. reports record crude exports during the Hormuz crisis, a material share of those barrels were made possible by Canadian heavy crude, purchased at a discount that Canada's infrastructure gap helps enforce, refined in American facilities, and re-exported at prices that Canadian producers cannot access directly. The U.S. built the refinery and export infrastructure. Canada did not build corresponding infrastructure to bypass the arrangement.

V. How the bottleneck was built

This section summarizes findings documented in detail in The Feedback Loop (March 10, 2026). Readers seeking the full evidentiary record, including 40 primary sources, are directed there. What follows is the consequence as measured against the current crisis.

The Trans Mountain Expansion, the only major new export pipeline to reach tidewater in over a decade, took 12 years and $34.2 billion to complete. It nearly tripled the pipeline's capacity to 890,000 barrels per day. As of April 2026, it is operating at near-record utilization. Analysts warned at the time of completion that Canada would overrun egress capacity again within one to two years. That timeline appears to be arriving: Alberta's record production is again pressing against the ceiling. [31] [5]

No LNG export terminal serves Canada's Atlantic coast. In August 2022, German Chancellor Olaf Scholz stood beside Prime Minister Justin Trudeau and asked for Canadian natural gas to replace Russian supply. Trudeau said there was not "a clear business case yet" for building a terminal. That same month, a federal briefing note showed no pipeline project application was before the regulator. [32] [31]

The feedback loop documented in our earlier article describes the mechanism: government constrained the regulatory environment through Bill C-48 (the Oil Tanker Moratorium Act) and Bill C-69 (the Impact Assessment Act, later found partially unconstitutional by the Supreme Court). A parallel financial framework, the Glasgow Financial Alliance for Net Zero, co-chaired by the man who now leads the country, classified gas pipelines as high-emitting assets requiring managed phaseout. Government then observed that the private sector had not proposed new projects. [31]

The result: oil and gas investment in 2025 accounted for less than half of what it was in 2014 as a share of GDP. RBC Economics noted that current investment is devoted to maintaining existing capacity, making it insensitive to oil price fluctuations. Even with physical crude at $148.87 per barrel, the structural incentive to invest in new Canadian export capacity has not changed, because the regulatory and financing environment has not changed. [9]

The U.S., by contrast, spent the last decade building out pipeline capacity, Gulf Coast export terminals, and LNG facilities. When the crisis hit, the infrastructure was ready. American exports surged. Canadian crude, discounted, constrained, routed through U.S. refineries, continued to flow on the same terms it always has, except the stakes are now measured in the largest supply disruption in history.

VI. What happens next

The trajectory depends on a small number of verifiable variables. Both cases are documented.

The case for resolution. A ceasefire technically exists, though implementation has not materialized. Saudi Arabia has restored East-West pipeline throughput. RBC Economics argues this shock is unlikely to reignite the broad, persistent inflation of 2022, because supply chains are in better condition and domestic demand is weaker. The Dallas Federal Reserve modeled a one-quarter disruption reducing global GDP growth by only 0.2 percentage points. Vanguard assessed the U.S. economy as "comparatively well-positioned" for a short-lived shock. [33] [34] [35]

The case for prolonged disruption. Oxford Economics modeled a scenario in which sustained closure tips the world into contraction, with global GDP growth falling to 1.4% and the U.S. and most advanced economies entering recession. Princeton Policy Advisors estimated a 10% cut in U.S. oil consumption implies a GDP decline of approximately 3%. Kpler's demand-destruction price of $160–$170 per barrel has not been reached. Energy-driven U.S. inflation is tracking toward 3.5%–4.0%, and the Atlanta Fed showed a nearly 20% probability of a rate hike, reversing pre-war expectations of cuts. [36] [37] [38] [39]

The infrastructure damage is permanent on any timeline. Qatar's Ras Laffan needs three to five years of repair. Nations that draw down strategic reserves will need to restock afterward, creating sustained demand that outlasts the conflict. Two deadlines converge in the next eight days: the May WTI futures contract expires April 21, and the U.S.-Iran ceasefire expires April 22. The WTI front-month/second-month backwardation has widened to $15.50 per barrel. Those two dates represent a potential flashpoint for extreme volatility. [11] [40]

Regardless of how the Hormuz crisis resolves, the sorting hub dynamic will persist. Canada's crude will continue flowing to U.S. refineries. The discount will continue to reflect the infrastructure constraint. The U.S. will continue to function as the intermediary between Canadian reserves and global markets. The only variable that changes this is new Canadian export infrastructure to non-U.S. markets, and that infrastructure does not exist at the scale required, is not under construction at the scale required, and under current regulatory and financing conditions, is not being proposed at the scale required. [9] [31]