WTI Crude Oil Price

Canada vs US oil price (WTI): the pipeline that finally narrowed the WCS discount, the petro-loonie that didn't show up, and the Hormuz crisis that hit after the chart ends

The chart above is the West Texas Intermediate spot price — the same benchmark for both Canadian and American crude pricing — through February 9, 2026, where the latest reading is roughly $64.53/b. That snapshot is from a moment of relative calm: pre-OPEC unwinding bite, post-tariff rebound, and just before a major Middle East supply shock that hit in late February 2026 and sent forward forecasts up sharply. The Canada–US story embedded in this single price series is bigger than just WTI, because the real Canadian benchmark is Western Canadian Select, which trades at a discount to WTI that has been the single most consequential variable in Alberta's fiscal and political life for a decade. This page is about how that discount finally narrowed, why the petro-loonie did not come back to life, and what the $34 billion Trans Mountain pipeline actually delivered.

For the indicator definition see the WTI Oil Price indicator page. This page is about the Canada–US asymmetry that WTI alone cannot show.

The numbers

From the FRED WTI Cushing spot series:

• 2015-01-02: about $52.72.
• 2020-04-20 trough: −$36.98 (the May 2020 contract expiry collapse).
• 2022-03-08 peak: $123.64 (Russia-Ukraine war shock, before SPR releases).
• 2026-02-09 (latest): about $64.53.
• Series average: about $62.38 — below the long-term nominal mean of roughly $70–$75.

The negative print in April 2020 was a one-day technical event: Cushing was at 83% of working capacity, COVID demand had collapsed by roughly 29 mb/d, and long-only ETF holders were forced to liquidate the May contract because they could not take physical delivery. The CFTC interim report and EIA's Today in Energy piece both lay out the mechanics. It is the most important warning in the modern oil-market record about the difference between paper and physical positions. The 2022 peak was the early days of the Russia-Ukraine war before the US Strategic Petroleum Reserve releases pulled prices back. Everything in between is a fairly normal $50–$90 range.

The WCS discount is the real Canada–US oil story

WTI is what the chart shows, but WTI is not what most Canadian producers receive. Canadian heavy crude — primarily Alberta oil sands — sells as Western Canadian Select, and the WCS-WTI differential has historically run $15 to $20 per barrel on average. In bad years it has blown out further: through 2018 the differential briefly exceeded $40. The differential reflects three things: heavy versus light crude API gravity, sulphur content, and — most importantly — pipeline takeaway capacity. The lack of pipeline egress from Alberta meant Canadian producers were forced to accept whatever price US Midwest refiners offered. That left billions of dollars per year on the table.

The cleanest single fix to that problem was the Trans Mountain Expansion, which entered commercial service on May 1, 2024. Capacity tripled from 300,000 bpd to 890,000 bpd, with the new tidewater access at the Westridge Marine Terminal in Burnaby, BC, opening Canadian heavy crude to Asian and California markets for the first time at meaningful scale. The pipeline cost CAD$34 billion against an original estimate of $7.4 billion — a 4.6x overrun — and was effectively financed by the federal government after Ottawa bought the project from Kinder Morgan in 2018 for $4.5 billion when the original sponsor withdrew.

The early returns are real. The WCS-WTI differential averaged US$18.65 in 2023 and US$14.73 in 2024. RBC's Greg Pardy and CAPP both attribute roughly US$8 per barrel of the narrowing to TMX directly. Through the first year of operation (May 2024 to April 2025) Alberta Central estimates the narrower discount delivered roughly CAD$13 billion in additional producer revenues. RBC's 2026 Global Energy Outlook (Pardy, December 2025) projects a 2026 WCS-WTI differential of about US$14.25 per barrel, slightly wider seasonally than the 2024 average but still well inside the historical range. TMX utilization hit 87% in Q3 2025 with throughput averaging 777,000 bpd, and YTD-2025 throughput averaged 746,000 bpd versus 499,000 the same period prior year — a 49% jump in egress.

The 2025 Trump tariff shock had a 10% energy carve-out

When Donald Trump signed the three IEEPA tariff executive orders on February 1, 2025, Canadian energy got a special carve-out: 10% on Canadian energy imports versus 25% on most other Canadian goods. The carve-out reflected the dependence of US Midwest refineries on Canadian heavy crude — about 96% of Canadian crude exports go to the US, and US imports of Canadian crude hit a record 4.3 mmbpd in July 2024. Canada is roughly 60% of US gross crude imports. The Midwest refining configuration is built around heavy sour crude; substituting Mexican Maya or Venezuelan barrels would take years and would cost refiners more.

The market response was instructive. The WCS-WTI differential widened by about $2.50 per barrel to $14.25 in the week following the announcement. By March 10, 2025, the differential was back to $11.70 — the narrowest level since November 2024 — as the market priced in the carve-out and realised Canadian producers would absorb most of the cost by lowering offered prices into the US Midwest. The episode is the cleanest single illustration in years of the structural fact that US Midwest refineries have negotiating leverage over Canadian heavy producers, and pipeline diversification (TMX) only partly offsets it. See the CAD/USD compare page for the broader tariff timeline and the SCOTUS ruling that struck the IEEPA tariffs down on February 20, 2026.

The petro-loonie has gone missing

Historically, the Canadian dollar tracked WTI closely. BMO chief economist Doug Porter's rule of thumb: a $10 per barrel rise in WTI moved the loonie about 3 cents. Pre-2018 correlations between CAD/USD and WTI ran around 0.88. Through 2018–2024 they fell to roughly 0.75. In 2024–2025 they have, in the words of multiple bank desks, "essentially disappeared." The cleanest single 2025 illustration: WTI fell about 12% on the year and the CAD trade-weighted basket actually rose about 1.8% — a clean decoupling. Alberta Central's "The Canadian dollar: A petro-currency no more" and CIBC's published commentary on the relationship break (via BNN Bloomberg) are the two anchor sources.

The mechanism is structural. US shale has turned the United States into a net energy exporter, so both currencies now respond to oil price moves similarly. Canadian heavy crude trades at a WCS discount that absorbs much of the WTI move before it reaches Canadian producer cash flow. The Bank of Canada's policy divergence from the Fed in 2025 has dominated the FX channel that the petro-loonie used to occupy. And the Trans Mountain Expansion — which by restoring takeaway capacity should have helped the petro-loonie story — entered service at exactly the moment the broader correlation was breaking down. The relationship reasserts itself in supply-shock episodes (geopolitical events, war), but in normal demand-driven moves it is gone. Goldman Sachs has been the most explicit on this: oil-CAD correlation reasserts in supply shocks, not in normal trading.

Alberta's fiscal exposure is large and one-directional

Each $1 per barrel change in WTI is worth roughly $750 million in Alberta provincial revenue annually. That makes Alberta's budget arithmetic a near-direct function of the WTI assumption. Alberta Budget 2025 used a WTI assumption of $68/b; by Budget 2026 (released early 2026), the assumption was cut to $60/b with a forecast deficit of about $9.4 billion. The Fraser Institute's commentary on the Smith government budget was titled "Boom Turns to Bust." The Alberta Heritage Savings Trust Fund — Smith's signature fiscal-discipline vehicle, with a stated goal of $250 billion by 2050 versus a current fair value of about $31.9 billion — depends on royalty surpluses that only materialise above roughly $80 WTI. The province got CAD$2.8 billion deposited in 2025-26 from the prior year's surplus. Whether those deposits continue depends almost entirely on whether the post-Hormuz forecasts materialise.

The one-directional nature of the exposure is the trap. When WTI is at $80, Alberta runs surpluses and the Heritage Fund grows. At $65 the budget runs a mid-single-digit billion deficit. At $100 the surpluses are large enough that talk of an Alberta sovereign wealth fund becomes politically credible. The province has been below its breakeven assumption for most of 2025–early 2026, and its provincial fiscal projections for 2026–28 depend on whether forward forecasts (post-Hormuz) translate into realized prices in time to rescue the 2026-27 budget.

OPEC+ began unwinding its cuts in 2025

The OPEC+ supply story moved from cuts to unwinding through 2025. The starting position was 2.2 mb/d of voluntary cuts by 8 countries (Saudi, Russia, Iraq, UAE, Kuwait, Kazakhstan, Algeria, Oman) plus a separate 1.65 mb/d voluntary layer. On March 3, 2025 the group announced the 2.2 mb/d unwind would begin in April. The actual unwind path: 135 kb/d/month additions in April, accelerated to 411 kb/d in May and June. By September 2025 the entire 2.2 mb/d was back. October 2025 began unwinding the 1.65 mb/d layer at 137 kb/d per month. On November 2, 2025 the group paused production increments for January–March 2026 on seasonal grounds. The cleanest summary: the cartel's voluntary supply restraint has largely unwound, leaving Saudi Arabia and Russia with much smaller spare-capacity buffers heading into 2026.

US shale has plateaued

The US Energy Information Administration's pre-Hormuz Short-Term Energy Outlook had US crude production at about 13.42 mmbpd in 2025 and 13.37 mmbpd in 2026 — essentially flat with a slight decline. Permian production at 6.6 mmbpd in 2026 is down from a 2025 peak; the gap between new well production and legacy decline has shrunk to essentially zero, which is the EIA's working definition of a basin peak. Permian breakevens are around $62 (Midland) and $64 (Delaware) per Dallas Fed Energy Survey 2025 data. Permian rig counts have dropped from a 2024 average of 308 to about 250 in 2025. The "drill baby drill" framing of early 2025 has not played out: industry response has been muted because investors continue to demand discipline over growth. Trump tariffs raised recession fears, lowering global oil prices, which further weakened the case for adding Permian rigs.

The implication for the Canada–US comparison: the US shale machine that broke the petro-loonie no longer has growth-side leverage on global oil prices. The marginal barrel of supply now comes from OPEC+ adjusting its quotas (when it has spare capacity), not from US shale adding rigs.

The Hormuz crisis that hit after the chart ends

The chart on this page ends on February 9, 2026. Eleven days later the United States and Israel launched military operations against Iran (Operation Epic Fury, late February 2026), and the Strait of Hormuz was effectively closed for several weeks. Pre-crisis forecasts had WTI averaging about $58.49 in 2026 (Scotiabank forward curve, January 15, 2026) or $73.61 (EIA pre-Hormuz). Post-crisis forecasts moved sharply. The EIA's March 2026 STEO put 2026 WTI at about $74, with a Q2 2026 spike to $84.56 and Brent peaking at $115 in Q2 2026. Goldman Sachs raised its 2026 WTI forecast to $79 from $72; JPMorgan put Brent at $110 in March-April 2026 with a fall back below $80 by Q3 if Hormuz reopens, and $150 if closure extends to mid-May. The IEA characterized the event as the "largest supply disruption in the history of the global oil market" in its March 2026 Oil Market Report.

For the chart on this page, what matters is that the latest reading is from before the shock. If the chart updates past mid-February 2026, expect a sharp upward spike followed by mean reversion contingent on how quickly the Strait reopens. The relevant Q1 2026 STEO gives a quarterly path of $72.60 (Q1) → $84.56 (Q2) → $71.45 (Q3) → $66.00 (Q4), so the post-crisis baseline implies higher full-year prices than the data through Feb 9, 2026 suggest.

The Carney–Smith MOU and the politics underneath

On November 27, 2025, Mark Carney signed a Memorandum of Understanding with Alberta Premier Danielle Smith in Calgary on a new oil pipeline to the BC coast, with exemptions from federal environmental law. Steven Guilbeault, the former federal Environment Minister who oversaw the carbon-pricing framework Carney had already partially dismantled, resigned over the deal. Bloomberg's coverage and Guilbeault's own framing: the MOU is "fueling Quebec separatism," with the Parti Québécois leading polls in Quebec by 20 points heading into the next provincial election. At the United Conservative Party convention shortly after, Smith was booed by her own base when defending the MOU and her position of "an independent Alberta within a united Canada."

The political-economy structure underneath: Canada's oil policy is now caught between three demands the Carney government cannot simultaneously satisfy. (1) Alberta wants pipelines and reduced regulation to convert post-Hormuz prices into provincial revenue. (2) Quebec wants the federal climate framework to remain credible. (3) The federal Liberals' coalition needs both. The Carney government's first-year answer was to kill the consumer carbon price (April 1, 2025), preserve the industrial Output-Based Pricing System at $65/tonne rising to $170/tonne by 2030, sign the MOU with Alberta, and unveil a Climate Competitiveness Strategy in November 2025. Whether that package holds depends on whether Quebec separatist polling subsides and whether the Carney government can make the new pipeline politically palatable in BC, where the existing tanker ban remains in force.

What to watch in 2026

1. EIA Short-Term Energy Outlook monthly. The post-Hormuz forecast revisions will be the cleanest single read on whether the supply disruption is treated as temporary or structural.
2. Trans Mountain Q1 2026 utilization (typically reported with the corporate quarterly). Watch whether throughput stays above 87% and whether Asian/California buyers continue to absorb the marginal barrel.
3. Alberta Q1, Q2, Q3 fiscal updates from the Smith government. Watch royalty receipts versus the $60 WTI assumption — if post-Hormuz prices average above $70, the Budget 2026 deficit shrinks materially; if Hormuz reopens fast and prices revert to $60, the deficit holds.
4. WCS-WTI differential monthly. RBC's 2026 forecast is about $14.25; CAPP's is closer to $11–$12. The gap is the cleanest measure of whether TMX is delivering sustained value.
5. OPEC+ monthly meetings. Watch the Q2 2026 unwinding-pause decision (set in November 2025) — does it extend into Q3 if post-Hormuz prices hold above $75?
6. Carney–Smith pipeline deal. Watch whether the MOU translates into actual permits, whether BC's tanker ban gets modified, and whether Quebec separatist polling forces a rethink.
7. CER monthly crude trade summary. The marker for whether Canadian exports continue diversifying away from the US Midwest into Asia and California.
8. Carbon price legal challenges. The federal industrial OBPS scheduled increase to $170/tonne by 2030 is the next political-economy battle, and the Climate Competitiveness Strategy provides the framework Carney is using to argue for it.

The stakes

WTI is the cleanest single price benchmark in the Canada–US relationship. It is the single largest variable in Alberta's provincial fiscal arithmetic, the single largest input into the Bank of Canada's commodity price index, and historically the strongest single driver of the Canadian dollar. In 2025–early 2026, the WTI–CAD link broke down for structural reasons that probably are not going to reverse: US shale plateau, Bank of Canada policy divergence, the WCS discount absorbing much of the price signal, and the heavy regional concentration of Canadian oil exports into a single US Midwest refining base. The Trans Mountain Expansion has finally narrowed the WCS discount by roughly $8 per barrel, delivering an estimated CAD$13 billion in extra producer revenue in its first year — but it has not restored the petro-loonie because the FX side of the relationship has moved on.

The short version: WTI sat at about $64.50 on the latest reading, the WCS discount has narrowed from $18.65 (2023) to $14.73 (2024) thanks to TMX, the petro-loonie correlation has disappeared, and Alberta's Budget 2026 is built on a $60 WTI assumption that may or may not survive contact with the post-Hormuz forecast curve. The 10% Trump tariff carve-out for Canadian energy proved that US Midwest refineries have structural negotiating leverage that pipeline diversification only partly offsets. And the Carney–Smith MOU points to the central political-economy bet of the Canadian oil story for the rest of the decade: that the Liberal coalition can simultaneously hold Alberta, Quebec, and BC together while building a second tidewater pipeline. Whether that bet pays off depends much less on WTI than it depends on whether the broader political coalition holds.