Canada Oil Production by Province and Oil Sands

Canada produced 4.79 million barrels a day of crude oil in 2025, or 5.36 million with condensate and pentanes plus, according to Statistics Canada table 25-10-0063-01 (release of October 30, 2026). Oil sands supplied 73.0% of the crude and Alberta 84.7%; Saskatchewan made 9.1% and offshore Newfoundland and Labrador 5.0%.

The oil sands share is the part that moved. In 2016 the oil sands made 67.1% of a 3.60 million barrel a day total; by 2025 the total had grown 33% and 91% of that growth came from bitumen and synthetic crude, with conventional heavy and light oil adding 106 thousand barrels a day. Alberta alone added 1,201 thousand barrels a day over the nine years, which is 101% of the national gain of 1,191 thousand, because the rest of the country netted out slightly negative. Saskatchewan produced 24 thousand barrels a day less in 2025 than in 2016.

Which "Canada oil production" number a reader meets depends on three choices: whether condensate and pentanes plus are counted, whether bitumen is counted before or after upgrading, and which months are averaged. The Canada Energy Regulator prints 5.35 million barrels a day for crude oil and equivalent in 2025, within 8 thousand barrels a day of the Statistics Canada 5.358 computed here. The Alberta Energy Regulator counts raw bitumen alone at 3.718 million barrels a day. The sections below set out each basis, the provinces, the oil sands arithmetic and where the oil goes.

Canada's output from 2016 to 2026

Statistics Canada publishes the monthly series as volumes in cubic metres and in barrels, side by side, for Canada and each province. The table's barrel figures divided by the table's cubic-metre figures give 6.2898 barrels per cubic metre in every cell above 100,000 cubic metres, so no separate conversion factor is needed here (the barrel itself is covered on the barrel of oil page): each daily rate in this article is the table's barrel total for the period divided by the days in it. Table 1 sets the annual averages for 2016 to 2025 beside the first eight months of 2025 and 2026, the months the latest release covers.

Output rose in every year except 2020. From 4.252 million barrels a day in 2019 it fell 5.2% to 4.033 in 2020, then passed the 2019 level in 2021 at 4.295. Between 2021 and 2025 it grew 0.495 million barrels a day, and the oil sands column grew 0.396 of that. The last full year is up 4.0% on 2024 for crude oil and 4.3% for crude oil and equivalent. January to August 2026 is 3.2% above the same months of 2025 on crude oil, with oil sands up 2.6% and light and medium conventional up 5.7%, which is why the oil sands share of 72.3% in 2026 sits slightly below the 72.8% of the same months a year earlier.

The table holds history only. What it shows is that the 2016 to 2025 growth was concentrated in a single stream. The conventional lines moved from 1.186 to 1.292 million barrels a day over nine years, up 8.9%, while the oil sands lines moved from 2.414 to 3.499, up 44.9%. For the price side of that story, the Alberta page on production, the dropped emissions cap and pipeline limits tracks how full the export pipelines ran, and the WCS to WTI differential shows what the heavy barrel sold for.

Three headline numbers for 2025

The table's structure explains why published totals differ. Statistics Canada's note 2 says "Total supply could be calculated by adding Crude oil production, Equivalent products production, and Imports." So the table itself treats crude oil production (the heavy, light and medium, bitumen and synthetic lines) and equivalent products (condensate and pentanes plus) as separate blocks. Table 2 puts the same year on three bases.

The first row is the narrowest and the one Statistics Canada labels crude oil production: 4.791 million barrels a day. The second adds 0.567 million of condensate and pentanes plus, a stream that has more than doubled from 0.268 in 2016, and lands at 5.358, which is 8 thousand barrels a day above the CER's published 5.35. The third replaces the synthetic crude oil volume with the bitumen volume sent to upgraders. Upgrading turns 86.5% of the cubic metres sent into synthetic crude in 2025 (Table 4), so counting the bitumen instead adds 0.205 million barrels a day and gives 5.563.

The third basis is not an invented number. The CER's Alberta energy profile gives Alberta's 2023 total as 4.3 million barrels a day "including condensate and pentanes plus", and lists its parts: 3.4 million of oil sands raw bitumen, 373.8 thousand of conventional light oil, 145.4 thousand of conventional heavy oil and 368.9 thousand of condensate and pentanes plus. Adding those components gives 4.29 million, which fits a raw bitumen basis for the 4.3. Statistics Canada's own Alberta lines for 2023 sum to 4.117 million on the net basis and 4.312 million on the raw bitumen basis. The profile does not state which basis it uses; reading it as raw bitumen is the writer's inference from the arithmetic. The practical rule is simple: when a figure for Alberta looks about 0.2 million barrels a day higher than another, check whether bitumen was counted before upgrading.

Our own Alberta page uses a fourth cut. It reports Alberta at 4.15 million barrels a day for 2025 from the Government of Alberta's economic dashboard. Statistics Canada's Alberta crude oil production line is 4.059 million and its Alberta condensate line 0.088 million, which sum to 4.147, the same 4.15 to two decimals. The dashboard series therefore appears to be crude oil plus condensate, without pentanes plus; that match is this page's arithmetic, not a statement from the Government of Alberta. Statistics Canada's pentanes plus line adds a further 334 thousand barrels a day for Alberta.

Production by province

The table's geography is Canada, an Atlantic provinces aggregate, nine provinces and the Northwest Territories, and crude oil production is reported for seven of the places in it: Alberta, Saskatchewan, Newfoundland and Labrador, British Columbia, Manitoba, Ontario and the Northwest Territories. Nova Scotia, New Brunswick and Quebec have no crude oil production line (Nova Scotia has a condensate line, suppressed in every month). The seven reporting provinces sum to the Canada figure within 1 cubic metre for 2025, so the table is a complete provincial split of crude oil production for that year.

Alberta's share rose from 79.4% in 2016 to 80.8% in 2020 and 84.7% in 2025. Its production grew 1,201 thousand barrels a day while the rest of the country together fell by 11 thousand. Saskatchewan's output was nearly flat in barrels, 459 thousand in 2016 and 435 thousand in 2025, so its share slid from 12.8% to 9.1% as the denominator grew. The CER's Market Snapshot for 2025 reports the same ordering with shares of crude oil and equivalent, and Table 10 below compares them.

Newfoundland and Labrador is the volatile one. Its offshore fields produced 210 thousand barrels a day in 2016, 284 thousand in 2020 (a 7.0% share), 200 thousand in 2023 and 240 thousand in 2025, up 15% on 2024's 209 thousand. The CER's August 2026 snapshot on the province's offshore fields lists the outages: one refit took Terra Nova offline in January 2020 and production there resumed in November 2023, and the refit of the SeaRose vessel took White Rose and North Amethyst offline in January 2024, with production resuming in March 2025. The 2025 gain of 15% follows that restart on the writer's reading; the table itself gives no cause. The snapshot also puts early 2026 output at about 285 to 310 thousand barrels a day, a CER figure from field-level regulator data that this page does not recompute.

British Columbia's crude oil line fell from 23.1 to 11.3 thousand barrels a day between 2016 and 2025, while its condensate and pentanes plus lines together came to 138 thousand in 2025, more than ten times its crude oil; the province's oil story in this table is mostly a liquids-from-gas story. Manitoba produced 40.9 thousand barrels a day, almost unchanged from 40.1 in 2016. Ontario's 0.52 thousand and the Northwest Territories' 3.5 thousand (9.0 in 2016) are small enough that they only matter as a check on the total.

Inside the oil sands numbers

Four lines in the table describe the oil sands chain. In-situ bitumen is produced by wells, mined bitumen by surface mining. Some of the bitumen from both is "sent for further processing", meaning to an upgrader, which turns it into synthetic crude oil. What is left is non-upgraded bitumen, which leaves the field as bitumen. Note 3 states that non-upgraded production "is equal to the sum of In-Situ crude bitumen production and mined crude bitumen production, less the amount of crude bitumen sent for further processing". Table 4 carries those lines through four periods. All four lines are Alberta's: in every year, the table's in-situ, mined, sent and synthetic lines for Canada equal its Alberta lines, and Saskatchewan carries no bitumen line.

Raw bitumen output reached 3.704 million barrels a day in 2025: 1.936 from in-situ wells and 1.767 from mines, a split of 52% to 48%. In 2016 the split was 55% to 45%, so mining gained share: in-situ output grew 39% over the nine years against 54% for mining. Bitumen sent to upgraders grew 44%, to 1.514 million barrels a day, and synthetic crude grew 41%, to 1.309. Non-upgraded bitumen grew 47%, to 2.190: of the 1.164 million barrels a day of added raw bitumen, 39% went to upgraders and the rest left the field as bitumen. That is also the stream the CER names for 2025: its snapshot says Alberta's 182 thousand barrel a day gain was "driven by growing non-upgraded bitumen production".

The yield row shows how much volume the upgraders return. Synthetic crude oil was 86.5% of the cubic metres of bitumen sent in 2025 and 88.1% in 2016, and it stayed between 86.2% and 88.1% in every full year of the table. The yield was 87.2% to 88.1% in 2016 to 2022 and 86.2% to 86.5% in 2023 to 2025, but the table does not say why it slipped. Statistics Canada also does not say how the volume lost is defined, whether gases and coke, process use or measurement basis; the loss is the difference between two published lines, and the table's note 6 warns that deliveries "do not add to total supply due to losses, other uses and inventory changes."

The mined and in-situ split matters for what follows. The Alberta Energy Regulator's ST98 outlook (September 2026 update) reports the same 2025 pattern in its own units: total in-situ and mined bitumen of 590.8 thousand cubic metres a day, of which in-situ 309.9 and mined 281.0. The AER glossary defines nonupgraded bitumen as "crude bitumen that is blended with a lighter-viscosity product (referred to as a diluent) to meet specifications for transport through pipelines." Statistics Canada's line is a derived volume by the identity above, and it lists condensate and pentanes plus, the common diluents, separately as equivalent products; whether the table's non-upgraded line includes any diluent is not stated, and the identity suggests it does not. That is a reading, and the next section's equivalents line is where diluent volumes would sit.

Conventional oil by province

Conventional output is 1,292 thousand barrels a day in 2025, split between a light and medium line of 837 thousand and a heavy line of 455 thousand. Table 5 sets each province's 2025 output by type.

Alberta has the largest conventional output at 560 thousand barrels a day, 43% of the Canadian conventional total, but it is a small part of Alberta's own 4,059 thousand. Saskatchewan's 435 thousand is 34% of the conventional total and all of its crude; Statistics Canada lists no bitumen line for the province. Within Saskatchewan the mix has changed: heavy crude held at 289 thousand barrels a day against 285 thousand in 2016, while light and medium fell from 175 thousand to 146 thousand. About 66% of the province's barrels are in the heavy line, the grade whose discount is the subject of the WCS differential page.

Offshore Newfoundland and Labrador supplies 19% of conventional output, all of it in the light and medium line in this table. The CER's snapshot states that Hebron, which began producing in 2017, is "the province's first heavy-oil field". Statistics Canada lists no heavy line for the province at all. Which classification Statistics Canada applies to Hebron is not stated in the table's notes; the Canadian heavy total in Table 5 therefore reflects the table's classification, not the CER's description of that field. Anyone comparing heavy-oil totals across agencies should keep that in mind.

Condensate and pentanes plus

The table's "equivalent products" block holds two lines. Condensate is, per note 4, lease and plant condensate; pentanes plus is the heavier fraction recovered at gas plants. Neither is counted as crude oil in the table's structure; natural gas liquids explained covers the US side of these gas-plant liquids. Canadian output of the two lines combined was 567 thousand barrels a day in 2025 against 268 thousand in 2016, up 111% and growing faster than crude oil itself (33%). They now equal 11.8% of crude oil production.

Alberta produced 88 thousand barrels a day of condensate and 334 thousand of pentanes plus in 2025, British Columbia 138 thousand of the two together. That leaves 7 thousand barrels a day that the Canada line carries and the two named provinces do not: Saskatchewan, Ontario, Nova Scotia and the Atlantic aggregate have their condensate lines suppressed in every month, and Saskatchewan and the Northwest Territories likewise for pentanes plus. This is why the provincial shares in Table 10 on a crude and equivalent basis are computed with the visible equivalents only, and why the totals there are labelled as such.

The CER's Alberta profile links the two streams: it says the Southern Lights and Cochin pipelines carry condensate from the U.S. to Edmonton and Fort Saskatchewan, "where it is then used as diluent in oil sands projects". That is a statement about imports, a line the table reports separately (Canada imported 0.763 million barrels a day of crude oil and equivalent products in 2025). The table does not say how much domestic condensate and pentanes plus is used as diluent. The equivalents block should therefore be read as "other liquids that arrive with the oil", not as a measure of diluent.

Seasonal lows and the record months

The annual averages hide a repeating pattern. In every one of the 11 years in Table 6, the lowest month for crude oil production was April or May. The highest month fell in November or December in 10 of the 10 full years. Output in 2025 ranged from 4.251 million barrels a day in May to 5.048 in December, a spread of 19%.

The table gives no reasons for any month. For spring 2016 Statistics Canada did publish reasons, below. The repeated timing is suggestive, since a low in the same two spring months in all 11 years looks more like scheduled work than a market response, but that is the writer's reading, not a statement in the data. Our Alberta page reaches the same position from the Government of Alberta series: it shows the dip but not its cause. What the table does support is the size of the effect. In May 2026 crude oil production was 4.692 million barrels a day, 7.0% below the 5.047 of July 2026. A reader who takes a single spring month as the trend understates the year.

Two years break the pattern's scale. In 2016 the lowest month, May 2016, was 2.735 million barrels a day, and the highest, November 2016, was 4.052, a ratio of 1.48, the widest in the table. Synthetic crude oil production fell 65% between March and May 2016, from 0.987 to 0.350 million barrels a day. The table names no cause, but Statistics Canada's GDP release of July 29, 2016 does for the month: "The decrease in May was primarily due to lower non-conventional oil extraction, a consequence of the Fort McMurray wildfire and evacuation." The same release says the industry's output had already fallen in April "due to maintenance shutdowns at upgrader facilities", and the table's April 2016 synthetic crude figure of 0.615 million barrels a day is below March's 0.987. In 2020 the low of 3.532 in May and the high of 4.505 in December give a ratio of 1.28.

The record claims need care. The CER snapshot says production grew "to a high of 5.64 MMb/d in December 2025". The Statistics Canada table gives 5.646 for December 2025, which rounds to 5.65, and 5.650 for November 2025, the highest month of 2025. The three highest months in the table are November 2025 at 5.650, July 2026 at 5.650, December 2025 at 5.646. The highest month of crude oil alone is December 2025 at 5.048. The CER's series is its own compilation, and the small differences suggest different vintages or rounding; the snapshot and the table agree on the year's average and on the order of magnitude of the peak.

Where the oil goes after the wellhead

The table's disposition lines show what happens to the barrels. Canadian refineries took in 1.772 million barrels a day in 2025, against 1.594 in 2016. Exports were 4.307 million, 80% of crude oil and equivalent production. The ratio is a scale marker only: note 6 says deliveries and exports "do not add to total supply due to losses, other uses and inventory changes", and the table does not reconcile them.

89.1% of 2025 exports went to the United States, and 92% of that moved by pipeline; the "other modes of transport" line, 303 thousand barrels a day, is the remainder, a figure the table does not split between rail, truck and marine. US-bound exports in 2025 were 3.838 million barrels a day, down from 3.987 in 2024, even as total exports rose to 4.307. The difference is exports to other countries, which went from 40 thousand barrels a day in 2016 to 201 thousand in 2024 and 469 thousand in 2025, and in January to August 2026 reached 544 thousand. Their share of exports rose from 1.3% to 10.9%.

Table 8 shows where the increase comes from. Alberta's exports to other countries went from 0.03 thousand barrels a day in 2023 to 121 thousand in 2024 and 306 thousand in 2025, a volume that appears after the Trans Mountain Expansion entered service in May 2024. The CER describes the expansion as "nearly tripling the capacity of the Trans Mountain System to a total of 890 thousand barrels per day (Mb/d)" and says that "Since the startup of TMEP, Canadian crude oil exports to countries other than the U.S. have more than tripled." Newfoundland and Labrador's offshore exports to other countries are the other component, 163 thousand barrels a day in 2025 after 80 thousand in 2024. Alberta loaded 3.830 million of the 4.307 million barrels a day exported, 88.9%.

Domestic refining takes a different mix from what leaves. Table 9 sets 2016 against 2025.

Light and medium crude is the largest input at 39% of the 2025 total, though it fell from 0.859 to 0.694 million barrels a day, while heavy crude rose from 0.206 to 0.383 and synthetic crude from 0.440 to 0.601. Alberta's own refineries took 0.504 million barrels a day. Bitumen plus synthetic crude made 39% of refinery input in 2025 against 33% in 2016. For the pump-price side of Canadian refining, see Canada gas prices by province. For the US side of the same barrels, see US oil imports by country and US crude oil exports, and for the regions that receive Canadian crude, PADD districts.

Checking the table against CER and AER

Three outside documents report overlapping numbers: the CER Market Snapshot on 2025 production (released June 17, 2026), the CER's Alberta energy profile (page modified March 26, 2026, with 2023 production) and the AER's Alberta Energy Outlook, ST98 (updated September 2026). Table 10 lines each up against the Statistics Canada figure computed on the same basis.

The national and provincial shares agree to within 0.2 percentage points, and the 2025 national total to 8 thousand barrels a day. Alberta's year-on-year gain is the weakest match: 193 thousand barrels a day on the table's lines against the 182 the CER prints. The Alberta 2023 components match the CER profile to the decimal it prints, give or take 0.1 thousand barrels a day on the heavy and equivalents lines, which suggests the profile was built from the same Statistics Canada series. The AER's raw bitumen figure is 14.5 thousand barrels a day above the table's; its in-situ figure is 2.0 thousand cubic metres a day above the table's and its mined figure differs by 0.0. The 0.3% gap is therefore all in the in-situ line; neither document explains it.

One more cross-check sits on the upgraders. The CER profile says Alberta's four upgraders "have the capacity to process approximately 1.4 MMb/d of bitumen". The table's bitumen sent for further processing was 1.417 million barrels a day in 2023, which fits that round figure, and 1.514 in 2025, which is above it. The profile's capacity number is a round figure on a page whose production data are from 2023, and the gap may reflect capacity added or debottlenecked since, or a different counting basis; neither document says which. It is noted only as a difference between two published figures, not as evidence of overload.

Reading the table's notes and gaps

Statistics Canada attaches seven notes to the table and one correction. The wording matters because several of them change what a comparison means. Table 11 gives each in full.

Three limits follow from the file itself. First, the CSV carries no preliminary or revised flags: the symbol and status columns hold only "x" (suppressed) and ".." (not available), and no row is marked "p" or "r". The most recent months may still be revised in later releases; the values here are the single vintage of October 30, 2026, and earlier vintages are not available for comparison. Second, the table is monthly and provincial, with no field-level or company-level detail, so the oil sands numbers cannot be split between Athabasca, Cold Lake and Peace River here; the AER's ST98 does that for Alberta, putting the Athabasca area at 88% of 2025 bitumen production. Third, the 2026 provincial rows for Ontario and the Northwest Territories are suppressed, so provincial totals for 2026 would not sum to the Canada line, and this page does not publish them.

The metadata also fixes the vocabulary. The table lists "Crude oil production" with two children, net field production of crude oil and synthetic crude oil production. Net field production in turn holds heavy, light and medium, and non-upgraded bitumen. Anyone who adds net field production to synthetic crude and then adds bitumen again counts the oil sands twice; the identities between these lines hold to within 4 cubic metres in every period used, which is rounding.

What the numbers do not say

The table is a statement of volumes. It does not carry prices, margins, reserves or costs, and nothing here says whether production will keep rising. Oil sands output depends on pipeline room and on the economics of mines and wells that run for decades, and the AER's September 2026 outlook gives its own account of 2025: production rose "driven largely by ongoing expansions and efficiency improvements at existing projects, as well as increased market access enabled by the Trans Mountain Expansion." The conventional lines moved far less: Saskatchewan's light and medium line fell from 175 to 146 thousand barrels a day between 2016 and 2025. The 2025 gain of 0.222 million barrels a day for crude oil and equivalent is larger than the gains of 2022, 2023 and 2024 and smaller than the 0.276 of 2021, and the table also shows a 5.2% fall in crude oil in 2020.

For readers using the numbers, a short rule set follows from the arithmetic above. Quote the year and the basis with the figure: 4.79 for 2025 crude oil production, 5.36 with equivalents, 5.56 with bitumen counted before upgrading. Use annual averages for comparisons across years and treat single months as seasonal samples. Use shares of crude oil production only for crude oil, because the equivalents are not split by province in the table. For the US side, US oil production by state is the matching view, and any comparison with Canada should first check that both count condensate and bitumen the same way. The Canada country page carries production, exports and reserves from a separate 2024 dataset.

Sources and check dates

Data and sources, all checked November 4, 2026: Statistics Canada, Table 25-10-0063-01, Supply and disposition of crude oil and equivalent (monthly, January 2016 to August 2026; release of October 30, 2026 08:30 per the Web Data Service cube metadata; CSV downloaded from 25100063-eng.zip with its metadata file). Canada Energy Regulator, Market Snapshot: Canada sets new record in crude oil production in 2025 (release date June 17, 2026); Alberta Energy Profile (page modified March 26, 2026; its production figures are for 2023); Market Snapshot on Newfoundland and Labrador offshore oil production (release date August 26, 2026); and Market Snapshot on the Trans Mountain Expansion (release date September 3, 2025). Statistics Canada, The Daily, Gross domestic product by industry, May 2016 (July 29, 2016). Alberta Energy Regulator, Alberta Energy Outlook (ST98), Crude Bitumen and the ST98 landing page with glossary (both updated September 2026). All daily rates, shares, ratios and differences are calculated from those inputs. Places left out of the provincial tables: Nova Scotia, New Brunswick and Quebec have no crude oil production line in the table, and Prince Edward Island, Yukon and Nunavut are not in it.