Alberta Capital Spending Hits Nine-Year High of C$30.9 Billion as Canada's 2025 Crude Output Breaks Record at 5.35 Million bpd

Canada set a new crude oil production record in 2025, averaging 5.35 million barrels per day across the year, driven by Alberta's growing oil sands output. Alberta's capital investment in oil and gas reached C$30.9 billion in 2024, a nine-year high, according to the Alberta Energy Regulator. Two Canada Energy Regulator data releases published in recent weeks document how the Trans Mountain Expansion has reshaped where those barrels flow, shifting volume from rail to pipelines at a pace not seen since 2012.

Record Production Driven by Alberta Bitumen

The Canada Energy Regulator confirmed in a June 17, 2026 market snapshot that Canadian crude oil and equivalents averaged 5.35 million bpd in 2025, up from the prior record of 5.14 million bpd in 2024. December 2025 set the monthly peak at 5.64 million bpd. Alberta led the national increase, adding 182,000 bpd of non-upgraded bitumen, a 4% year-over-year gain. Newfoundland and Labrador grew 15% and British Columbia added 7%, while Saskatchewan declined 3%.

The AER's 2025 Alberta Energy Outlook, published June 25, 2026, reported C$30.9 billion in capital investment across Alberta's oil, gas, oil sands, and emerging resources sectors in 2024. The regulator described it as a nine-year high. Bitumen represents two-thirds of Canada's total oil-equivalent output, and Alberta accounts for 84% of the national total.

Trans Mountain Expansion Redirects Crude Flows

The CER's June 24 pipeline throughput snapshot showed the Trans Mountain system moved 761,000 barrels per day in 2025, up from 555,000 bpd in 2024. That 37% increase reflects the first full operating year of the Trans Mountain Expansion, which added 590,000 bpd of capacity when it entered service in May 2024. November 2025 set the monthly throughput peak at 855,000 bpd, representing 96% utilization. The Enbridge Mainline separately ran at 3.08 million bpd and 95.2% utilization over the same period.

Trans Mountain's Pacific outlet, the Westridge Marine Terminal in Burnaby, British Columbia, now carries 206,000 more barrels per day than it did before the expansion. Those additional barrels reach Asia-Pacific refiners in China, South Korea, Japan, and India, diversifying Alberta's export corridor beyond the United States Midwest. Greater Pacific Basin access reduces the structural basis for Alberta crude pricing at a discount to WTI over the long term.

Crude by Rail Falls to 13-Year Low

The same pipeline additions made crude-by-rail largely uneconomic. Canadian crude-by-rail exports averaged 77,200 barrels per day in 2025, the lowest since 2012, per a CER snapshot published April 8, 2026. Rail's share of total crude exports fell to 1.8%. That figure compares with a February 2020 peak of 412,000 bpd when pipeline capacity was fully subscribed. The WTI-WCS price differential averaged $13.84 USD per barrel in 2024, per CER data, and rail volumes contract when that spread narrows below the economics of incremental logistics cost, CER analysts noted.

Current Market Context and Key Producers

WTI crude was trading at $71.05 per barrel as of late morning on July 10, per OilPrice.com with an 11-minute delay. WCS traded at $57.99 per barrel on July 9 with a $14.40 discount to WTI on that session, as reported by Oil Authority. Applying the same differential to today's WTI implies WCS near $56.65 per barrel on July 10, though the WCS-WTI spread varies daily with logistics and refinery demand.

The major operators driving Alberta's capital investment record include Suncor Energy, Canadian Natural Resources, and Imperial Oil. Imperial is majority-owned by ExxonMobil and operates the Kearl oil sands mine and the Cold Lake in-situ facility. Enbridge operates the Mainline that carries the bulk of Alberta's pipeline export volumes.

Gas Reserves Upgrade and Emerging Resources

The AER's June 2026 outlook also disclosed that Canada's natural gas reserves have more than doubled, lifting the country's global reserves ranking from 15th to 9th. The full updated reserves assessment by McDaniel and Associates Consultants Ltd. is not yet incorporated in the current production forecast and is expected to be finalized later in 2026. The AER projects Alberta hydrogen production to increase from 2.6 million tonnes per year in 2024 to 4.4 million tonnes by 2034, representing an average 6% annual growth rate.