Canada

Canada in One Paragraph

Canada produced 5.35 million barrels per day (b/d) of crude oil and equivalents in 2025, a record for the fifth straight year, according to the Canada Energy Regulator (CER, market snapshot of June 17, 2026, checked October 2026). Output climbed through the year to a monthly high of 5.64 million b/d in December 2025. Alberta supplied 83.8% of the national total, Saskatchewan 8.2%, Newfoundland and Labrador 4.5%, and British Columbia 2.8%. Most of that oil is heavy, most of it is exported, and almost all of the exports still go to the United States. What changed in 2024 and 2025 is the second door: the expanded Trans Mountain pipeline to the Pacific coast, which has given Canadian heavy crude a route to buyers other than U.S. refiners for the first time at scale.

That combination, record volumes plus a new outlet, explains most of what readers see in the price data. When Canadian supply grows faster than pipeline space out of Alberta, the discount on Western Canadian Select (WCS) to WTI widens. When new space opens, the discount narrows. Our WCS-WTI differential explainer walks through that mechanism in detail, and the Alberta production cap and takeaway analysis covers the 2019 curtailment episode that showed how tight the system can get.

The Production Record, Year by Year

Two federal agencies publish Canadian production, and they use different units. The CER reports barrels per day of crude oil and equivalents. Statistics Canada reports cubic metres, split by product type. Read together, they give a clear picture of where growth comes from.

Year	Total output (CER, million b/d)	Total output (StatCan, million m³)	Oil sands (StatCan, million m³)	Conventional crude (StatCan, million m³)
2013	3.6	n/a	n/a	n/a
2023	5.1	n/a	n/a	n/a
2024	5.14	298.8	195.5 (74.0 synthetic + 121.5 bitumen)	72.7
2025	5.35	310.9	203.1 (76.0 synthetic + 127.1 bitumen)	75.0

Sources: CER Provincial and Territorial Energy Profiles, Canada for 2013 and 2023; CER June 2026 market snapshot for 2024 and 2025 barrels per day; Statistics Canada crude oil year in review, 2024 and Canadian crude oil reaches new heights, 2025 (published June 2, 2026). All checked October 2026.

What the table says

• Oil sands carry the growth. In 2025, oil sands output (upgraded synthetic crude plus non-upgraded bitumen) was 203.1 million m³ of a 310.9 million m³ total, about 65%. The CER notes that Alberta's 2025 gain of 182,000 b/d was driven by non-upgraded bitumen.
• Bitumen is growing faster than synthetic crude. Non-upgraded bitumen rose 4.6% in 2025, synthetic crude 2.7%. More of the barrel is leaving Alberta as diluted bitumen rather than as upgraded light oil, which matters for which refineries can buy it.
• Conventional oil is close to its old high. Conventional production of 75.0 million m³ in 2025 sat just below the 2019 peak of 75.7 million m³, with heavy conventional crude at a record 26.4 million m³.
• The East Coast bounced back. Newfoundland and Labrador offshore output rose 14.5% in 2025 to 13.9 million m³, which Statistics Canada called the largest year-over-year gain in the current series, as platforms returned from extended 2024 maintenance.
• Diluent volumes are rising too. Equivalent products (condensate and pentanes plus, used mainly as diluent) reached 32.9 million m³, up 7.2%. Every extra barrel of bitumen shipped by pipeline needs diluent to flow.

Worked example: converting the two agencies' numbers

Statistics Canada's 2024 total of 298.8 million m³ can be checked against the CER's 5.14 million b/d. One cubic metre is about 6.2898 barrels, and 2024 had 366 days:

298.8 million m³ × 6.2898 = about 1,879 million barrels, divided by 366 days = about 5.13 million b/d.

That lands within 0.2% of the CER figure, so the two series describe the same oil. The small gap comes from rounding and from definitional detail, and the exercise is a useful habit: when two official sources seem to disagree on Canadian output, the unit is usually the reason.

Where the Oil Goes: Exports by Destination and Mode

Canada exports most of what it produces. In 2024, crude exports averaged 4.20 million b/d, up 5.4% on 2023, according to the CER's annual crude oil trade summary (checked October 2026). Heavy oil made up 3.33 million b/d, or 79%, and light oil 0.87 million b/d. The average export price was US$65.3 per barrel, unchanged from 2023, and the total export value was US$100.7 billion.

U.S. destination (2024)	Volume (million b/d)	Share of exports to the U.S.
PADD 2, Midwest	2.47	63%
PADD 3, Gulf Coast	0.69	18%
PADD 5, West Coast	0.38	10%
PADD 4, Rocky Mountains	0.26	7%
PADD 1, East Coast	0.14	4%
Total to the United States	3.93	93% of all crude exports

Source: CER annual trade summary for 2024. PADD shares of U.S.-bound volume are PetroEyes arithmetic from the CER volumes and may not sum to 100% because of rounding. For what each district is and why the Midwest dominates, see our PADD districts explainer.

How the barrels travel

Mode (2024)	Volume (million b/d)	Share of exports	Change vs 2023
Pipeline	3.75	89%	+2%
Marine	0.36	9%	+72%
Rail	0.09	2%	-10%

Source: CER annual trade summary, 2024.

The marine line is the one that moved. Tanker exports had fallen to 0.21 million b/d in 2023 before the Trans Mountain Expansion opened, then rose to 0.36 million b/d in 2024. The CER attributes 75% of the 2024 increase in exports to marine vessels and 70% of it to markets outside the United States.

2025: the first annual fall in exports to the U.S. since 2020

Statistics Canada's 2025 review shows the shift continuing. Total crude and equivalent exports hit a record 249.9 million m³, up 2.5%, but exports to the United States fell 4.0% to 222.7 million m³, the first annual decrease since 2020. Exports to other countries rose 132.6% to 27.2 million m³, or 10.9% of the total, against an average of 2.8% for 2016 to 2024.

That last ratio is the clearest single measure of what the new pipeline did. Before 2024, roughly one barrel in 36 left Canada for a non-U.S. buyer. In 2025 it was about one in nine. The U.S. side of the same trade is visible in EIA import data: U.S. crude imports from Canada averaged 3.91 million b/d in 2025, down from 4.06 million b/d in 2024, while still making up about 63% of all U.S. crude imports (EIA imports by country of origin, checked October 2026). Our U.S. oil imports by country explainer covers the U.S. view of this table.

Trans Mountain: Why One Pipeline Changed the Export Mix

The Trans Mountain system runs from Edmonton, Alberta, to Burnaby, British Columbia, with deliveries at Kamloops, Sumas, and the Westridge Marine Terminal in Burnaby, where crude is loaded onto tankers for Asia and the U.S. West Coast. According to the CER's Trans Mountain pipeline profile (checked October 2026):

• The original 1953 line was about 1,150 km long, with nameplate capacity of approximately 300,000 b/d.
• The expansion came online on May 1, 2024, raising capacity to approximately 890,000 b/d.
• The CER-regulated system now totals 1,492 km, including all segments regardless of operating status.

Before the expansion, nearly every barrel of Alberta crude that left the country had to be sold to a U.S. refinery, mostly by pipeline into the Midwest. That gave buyers in PADD 2 and PADD 3 a strong hand in setting the WCS discount. A west coast tanker route does not replace the U.S. market, which still takes more than 85% of exports, but it gives sellers an alternative at the margin, and the margin is where differentials are set.

Reading the effect without overclaiming

Three cautions apply when attributing price moves to the new line:

1. Correlation is not the whole story. The WCS discount also responds to U.S. Gulf Coast heavy crude supply from Mexico and Venezuela, refinery outages, and diluent costs.
2. Capacity is not throughput. The CER notes that physical capacity can at times be higher than stated operational capacity, and throughput varies month to month. Check the CER throughput dashboard rather than assuming the line runs full.
3. Space fills. The CER's 2025 production snapshot notes that output kept growing to fill the new capacity. If production growth continues, the pre-2024 pattern of tight takeaway can return without another expansion.

Reserves: Large, Mostly Bitumen

Canada holds about 11% of world oil reserves, and as of 2020 only Venezuela and Saudi Arabia held more, according to the CER's national energy profile. Natural Resources Canada's oil resources page gives a total of 171.0 billion barrels of proven reserves, of which 166.3 billion barrels are in Alberta's oil sands and 4.7 billion barrels are conventional, offshore and tight oil, though the department attributes that figure to 2015 data from the Alberta Energy Regulator and industry. The Alberta Energy Regulator published a full update of the province's reserves in its 2026 Alberta Energy Outlook (ST98) in September 2026; readers who need a current reserves number should use that report rather than older summaries. All checked October 2026.

The practical point is the mix. Roughly 97% of the proven figure is bitumen, which is why Canadian supply growth comes from oil sands projects with long lives and slow declines rather than from short-cycle wells. That profile is the opposite of U.S. shale, and it is one reason Canadian output has risen steadily even through price downturns.

The Oil Sands: Two Ways to Get Bitumen Out

Bitumen in the Athabasca, Cold Lake, and Peace River deposits is too heavy to flow on its own at reservoir temperature. Producers use two broad methods:

• Surface mining for shallow deposits. Ore is dug, mixed with hot water to separate the bitumen, and either upgraded on site into synthetic crude oil or diluted for pipeline shipment.
• In situ recovery for deeper deposits, mainly steam-assisted gravity drainage (SAGD), in which steam injected through one horizontal well heats the bitumen so it drains to a second well below.

Statistics Canada's split between synthetic crude (upgraded, 76.0 million m³ in 2025) and non-upgraded bitumen (127.1 million m³) is the best public proxy for this choice. Upgraded synthetic crude is light and sweet and suits refineries without heavy-oil conversion units. Non-upgraded bitumen is shipped as dilbit, a blend with condensate, and needs a refinery with a coker. The faster growth of bitumen in 2025 means the export stream is getting heavier on average, which ties Canadian producers more closely to the coking refineries of the U.S. Midwest and Gulf Coast, and now to Asian buyers with similar equipment.

Refining at Home: Why Canada Exports Crude and Imports Some Too

Canada had 17 refineries with about 1.93 million b/d of total capacity as of 2024, according to the CER energy profile. They ran at about 89% utilization in 2023, processing 1.6 million b/d of crude. The largest is Irving Oil's refinery in Saint John, New Brunswick, at 320,000 b/d.

Province	Share of national refining capacity
Alberta	30%
Ontario	21%
Quebec	21%
New Brunswick	17%
Saskatchewan	8%
British Columbia	4%
Newfoundland and Labrador	1%

Source: CER Provincial and Territorial Energy Profiles, Canada (checked October 2026).

The geography explains a pattern that surprises many readers: Canada imported about 490,000 b/d of crude in 2023 (CER) while exporting about 4.0 million b/d. Refineries in Quebec and the Atlantic provinces sit far from Alberta, and pipeline access east is limited, so they buy part of their crude by sea. Western crude goes south because that is where the pipelines run. The country is a large net exporter, but individual regions behave like importers.

Natural Gas and LNG: The Second Export Business

Canada produced 17.9 billion cubic feet per day (Bcf/d) of natural gas in 2023, fifth in the world, with Alberta and British Columbia accounting for 98%, according to the CER. It consumed 11.9 Bcf/d, exported 8.1 Bcf/d, and imported 2.5 Bcf/d, for net export earnings of $10.1 billion in 2023. Canada's gas balance therefore looks like its oil balance: production well above domestic use, with the surplus sold abroad.

That changed in mid-2025. LNG Canada, the liquefaction terminal at Kitimat, British Columbia, marked one year of operations on June 30, 2026, and on September 28, 2026 announced a final investment decision on a second phase that would double capacity from 14 to 28 million tonnes a year (LNG Canada, checked October 2026). For the first time, Canadian gas can reach Asian buyers directly rather than only through the North American pipeline grid. Readers following the U.S. side of this market can compare it with our LNG export dynamics primer.

Rules of the Game: Provinces, Ottawa, and the Courts

Canada's constitution gives provinces ownership and primary control of natural resources within their borders, so royalties on oil sands and conventional oil are set by Alberta, Saskatchewan, and the other producing provinces. Interprovincial and international pipelines, along with environmental assessment of federal works, fall under federal jurisdiction, and the CER regulates those pipelines.

That split has produced repeated conflict over new infrastructure. The clearest recent example is the federal Impact Assessment Act. On October 13, 2023, the Supreme Court of Canada ruled in Reference re Impact Assessment Act, 2023 SCC 23 that the Act's "designated projects" scheme was unconstitutional, while upholding the sections that deal with projects carried out or financed by federal authorities (checked October 2026). The ruling did not remove federal review of interprovincial pipelines, which remain federal works, but it narrowed Ottawa's reach over projects that sit wholly inside a province.

For market readers, the regulatory question is mostly a timing question. Large pipelines in Canada have taken many years from proposal to service; Trans Mountain's expansion came online in May 2024. Any analysis that assumes new takeaway capacity on a short schedule should be treated with caution.

Edge Cases and Common Misreadings

• "Canada produces 5 million barrels of crude." The CER and Statistics Canada totals include condensate and pentanes plus used as diluent. Crude-only figures are lower. Always check whether a number says "crude oil and equivalents."
• "Exports equal production minus refinery runs." Not quite. Canada also imports crude (about 490,000 b/d in 2023) and moves some product between regions, so the arithmetic does not close neatly.
• "Trans Mountain sends all its oil to China." The CER describes Westridge shipments going to Asia and the U.S. West Coast. PADD 5 received 0.38 million b/d of Canadian crude in 2024, part of it by tanker. Country-level splits require customs or tanker-tracking data that the CER summary does not provide.
• "Production records mean prices are weak." Volume and price are separate. The 2024 average export price was unchanged from 2023 at US$65.3 even as volumes rose. The discount to WTI, not the absolute level, is the Canada-specific variable.
• Unit traps. CER figures in MMb/d, Statistics Canada figures in cubic metres, and LNG figures in tonnes per year all describe the same industry. Convert before comparing.

What to Watch in the Data

1. Statistics Canada monthly energy releases, for the bitumen and synthetic split and the non-U.S. export share.
2. CER throughput data for Trans Mountain, to see whether the line is near full.
3. EIA weekly imports from Canada, a quick check on the U.S. side of the trade; our guide to the EIA weekly petroleum report shows where they sit.
4. The WCS discount to WTI, the price signal that combines all of the above.
5. AER's ST98 outlook, for Alberta's own ten-year supply forecast.

Frequently Asked Questions

How much oil does Canada produce?

The Canada Energy Regulator puts 2025 output at 5.35 million barrels per day of crude oil and equivalents, a record, up from 5.14 million b/d in 2024. Production reached 5.64 million b/d in December 2025. Statistics Canada reports the 2025 total as 310.9 million cubic metres.

What share of Canadian oil comes from the oil sands?

About two-thirds. Statistics Canada counted 203.1 million cubic metres of oil sands output (synthetic crude plus non-upgraded bitumen) in a 2025 total of 310.9 million cubic metres. Conventional production was 75.0 million cubic metres, and the rest was condensate and pentanes plus.

How much Canadian oil goes to the United States?

In 2024, 3.93 million b/d, or 93% of Canada's 4.20 million b/d of crude exports, went to the United States, with the Midwest (PADD 2) taking 2.47 million b/d (CER). In 2025, Statistics Canada reported that exports to the U.S. fell 4.0% while exports elsewhere more than doubled, reaching 10.9% of the total.

Why does Canada import oil if it exports so much?

Because of geography. Most crude is produced in Alberta and pipelines run south to the United States and west to the Pacific. Refineries in Quebec and Atlantic Canada are far from that supply and buy part of their crude by sea. The CER recorded crude imports of about 490,000 b/d in 2023.

What did the Trans Mountain Expansion change?

It raised the line's capacity from about 300,000 b/d to about 890,000 b/d when it came online on May 1, 2024 (CER). Tanker exports rose 72% in 2024, and in 2025 the share of crude exports going to countries other than the U.S. reached 10.9%, against a 2016 to 2024 average of 2.8% (Statistics Canada).

Is this page investment advice?

No. It is an educational summary of public data from Canadian and U.S. agencies, checked in October 2026. Figures will be revised, and nothing here is a recommendation to buy or sell any security or commodity.

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References

1. Canada Energy Regulator. "Market Snapshot: Canada sets new record in crude oil production in 2025." June 17, 2026. https://cer-rec.gc.ca/en/data-analysis/energy-markets/market-snapshots/2026/market-snapshot-canada-sets-new-record-in-crude-oil-production-in-2025.html
2. Canada Energy Regulator. "Market Snapshot: Annual Trade Summary, Crude Oil" (2024 data). 2025. https://cer-rec.gc.ca/en/data-analysis/energy-markets/market-snapshots/2025/market-snapshot-annual-trade-summary-crude-oil.html
3. Canada Energy Regulator. "Provincial and Territorial Energy Profiles: Canada." https://www.cer-rec.gc.ca/en/data-analysis/energy-markets/provincial-territorial-energy-profiles/provincial-territorial-energy-profiles-canada.html
4. Canada Energy Regulator. "Pipeline Profiles: Trans Mountain Expanded System." https://apps.cer-rec.gc.ca/PPS/en/pipeline-profiles/trans-mountain-expanded-system
5. Statistics Canada. "Another record year for Canadian crude oil: Crude oil year in review, 2024." https://statcan.gc.ca/o1/en/plus/7940-another-record-year-canadian-crude-oil-crude-oil-year-review-2024
6. Statistics Canada. "Canadian crude oil reaches new heights in 2025." June 2, 2026. https://www.statcan.gc.ca/o1/en/plus/9188-canadian-crude-oil-reaches-new-heights-2025
7. Natural Resources Canada. "Oil resources." https://natural-resources.canada.ca/energy-sources/fossil-fuels/oil-resources
8. Alberta Energy Regulator. "Alberta Energy Outlook (ST98)," updated September 2026. https://www.aer.ca/data-and-performance-reports/statistical-reports/alberta-energy-outlook-st98
9. U.S. Energy Information Administration. "U.S. Imports by Country of Origin," annual crude oil. https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_epc0_im0_mbblpd_a.htm
10. LNG Canada. "LNG Canada Announces Phase 2 Final Investment Decision." September 28, 2026. https://www.lngcanada.ca/news/lng-canada-announces-phase-2-final-investment-decision/
11. Supreme Court of Canada. Reference re Impact Assessment Act, 2023 SCC 23, October 13, 2023. https://decisions.scc-csc.ca/scc-csc/scc-csc/en/20102/1/document.do

All sources checked October 22, 2026.