Alberta Oil Production, the Emissions Cap, and Pipeline Limits

Alberta produced about 4.15 million barrels of oil a day in 2025, roughly 0.33 million more than in 2023, and kept rising into 2026. Two policy facts sit on top of that growth. The Trans Mountain Expansion raised westbound pipeline capacity from about 300,000 to about 890,000 barrels a day on May 1, 2024. And Ottawa proposed a cap on oil and gas emissions for 2030 to 2032 in 2024, which its own analysis said would trim national oil output by about 0.9 percent, then committed in a November 27, 2025 agreement with Alberta not to implement it. This page lays out those three numbers from their official sources, shows how they interact, and marks where the honest answer is still "it depends".

What follows uses the Government of Alberta's production data, the Canada Energy Regulator's pipeline profile, and the federal government's published regulatory analysis.

How much oil Alberta produces, year by year

The Government of Alberta's economic dashboard publishes monthly oil production split into conventional oil and non-conventional oil, which it defines as unprocessed bitumen plus synthetic oil (dashboard updated October 1, 2026; checked October 2026). The volumes are monthly totals in cubic metres. Converting at 6.2898 barrels per cubic metre and dividing by the days in each month gives these annual averages:

Three things stand out. Growth has been steady rather than explosive: from 3.523 million barrels a day in 2019 to 4.147 million in 2025 is 0.624 million, about 18 percent in six years, with only the 2020 pandemic year breaking the line. The non-conventional side, bitumen and synthetic crude from the oil sands, carries the province: about 84 percent of 2025 output. And conventional oil, often written off as a declining legacy business, rose every year from 2021 to 2026, reaching 0.648 million barrels a day in 2025, about 16 percent of the total. Its contribution to growth is small in barrels but not zero, and it does not run through the same mining and in-situ projects the emissions debate focuses on.

Monthly figures move around more than annual ones. In 2026 the total ran at 3.993 million barrels a day in May and 4.398 million in July, a swing of about 0.4 million within two months. The dashboard gives volumes, not causes, and planned maintenance or unplanned outages at a single large site can move a month on their own, so one weak or strong month says little about the trend. Use twelve-month averages for anything structural.

Set side by side, the two years show a pattern the annual table hides. May was the weakest month in both years, 3.606 million barrels a day in 2025 and 3.993 million in 2026, and in both cases the conventional line barely moved, so the dip came from the non-conventional side, the oil sands. Like for like, the first eight months of 2026 averaged 4.188 million barrels a day against 4.077 million a year earlier, a gain of about 0.11 million, or 2.7 percent: slower than the jump from 2024 to 2025, and a reminder that the growth rate, not just the level, is what matters for pipeline space.

What the Trans Mountain Expansion changed

The Canada Energy Regulator's pipeline profile (checked October 2026) sets out the basic facts. The Trans Mountain system carries crude oil and refined products from Edmonton to refineries and terminals in British Columbia and Washington State, and ships crude to offshore markets in Asia and the US west coast through the Westridge Marine Terminal in Burnaby. Its nameplate capacity was about 300,000 barrels a day before the expansion and has been about 890,000 barrels a day since the Trans Mountain Expansion Project came online on May 1, 2024. Tolls are charged on an interim basis and remain subject to an ongoing CER hearing, according to the profile's transportation-cost section (updated May 2026).

Before 2024, almost all Alberta crude that left Canada went south, by pipeline or rail, to US refiners. Westridge gave Alberta heavy crude a tidewater outlet of meaningful size for the first time, so a cargo can now be offered to refiners on the US west coast or in Asia instead of only to the US Midwest and Gulf Coast. That is the economic point of the project: more buyers for the same barrel.

Worked example: how much of the new pipe has production growth used?

A rough test compares production growth with the new capacity. The expansion added about 590,000 barrels a day (890,000 minus 300,000). Alberta's average output rose from 3.819 million barrels a day in 2023, the last full year before the expansion, to 4.188 million in the first eight months of 2026, an increase of about 0.369 million. On this simple measure, production growth equals about 63 percent of the added capacity.

The estimate needs three caveats before it means anything. First, pipelines carry blended barrels: bitumen is usually diluted with lighter hydrocarbons to flow, so the volume shipped is larger than the bitumen produced, and pipeline space fills faster than raw production numbers suggest. Second, not all Alberta production needs export pipe: some is refined or upgraded in the province. Third, other routes matter: the main Enbridge system to the US, other export lines, and rail all compete for the same barrels. The precise utilization of every route is in the CER's quarterly throughput data, which is the place to check before accepting any claim that the system is "full" or "half empty".

How full the export pipes actually ran

The CER publishes monthly throughput and capacity for each major pipeline it regulates as open data, so the question the worked example leaves open can be answered from the source. Averaging those monthly figures by year for the three largest export routes out of western Canada gives the table below. Trans Mountain's throughput is the sum of its three delivery points (Burnaby, the Sumas border point to Washington State, and the Westridge dock); Keystone is measured where it crosses into the United States at Haskett, Manitoba; and the Enbridge Mainline at Gretna, Manitoba.

Three things stand out. Before the expansion, Trans Mountain ran at 99 percent of its capacity in 2023; it was full. After it, the system ran at 85 percent in 2025 and 88 percent in the first half of 2026, with the June 2026 month at about 865,000 barrels a day against 899,000 of capacity. The Westridge dock, the tidewater outlet that is the point of the project, averaged about 459 thousand barrels a day in 2025 against 41 thousand in 2023. Keystone and the Mainline, meanwhile, ran close to their limits throughout: Keystone at 96 to 100 percent and the Mainline at 95 to 96 percent from 2023.

Added together, the three routes had about 172 thousand barrels a day of unused capacity in 2023 and about 238 thousand in the first half of 2026: about 124 thousand on the Mainline, 108 thousand on Trans Mountain and 6 thousand on Keystone. In other words, a pipeline that added about 590,000 barrels a day of capacity had, two years later, left only about 66thousand barrels a day more room on these three systems than before it opened. The rest was taken up. Production growth, diluent in the blended barrels and volumes moved off other routes all fit that, and the CER data cannot split them. The CER's rail series gives the scale of one of those other routes: crude exports by rail averaged about 98,278 barrels a day in 2023, 77,158 in 2025 and 79,205 from January to August 2026, against a peak month of 411,991 in February 2020. Rail fell by roughly a fifth, not to zero.

The table does not cover every route. Express, the smaller lines and refinery demand inside Alberta are left out, and a monthly average hides weeks of apportionment, when shippers nominate more oil than a line can take and each is cut back pro rata. But it makes the earlier worked example concrete. Measured by the pipes' own throughput, the expansion bought western Canada a margin of a couple of hundred thousand barrels a day, not 590,000, and at the 2.7 percent growth rate of early 2026 that margin is about two years of production growth on its own, before diluent. That is arithmetic on stated inputs, not a forecast of when the pipes fill.

Why pipeline space shows up in the price of Alberta crude

Western Canadian Select, the heavy blend that sets the price for most Alberta crude, trades at a discount to WTI. Part of that gap is quality: WCS is heavier and higher in sulfur, so it yields less gasoline and diesel per barrel and needs more complex refineries. Part is transport: a barrel in Hardisty has to pay to reach a refinery, and the more expensive the marginal route, the wider the discount. When pipelines run full, the marginal barrel moves by rail or waits in storage, and the discount widens to cover that cost. When new pipe opens, the discount usually narrows. Our WCS-WTI differential explainer takes that mechanism apart with the price history, and the WTI vs Brent spread guide shows the same logic at work at Cushing and on the Gulf Coast.

The practical rule for readers: the differential is the market's running estimate of how tight takeaway capacity is. A narrowing differential with rising production means the pipes still have room. A widening one with rising production is the early warning that the next increment of growth is outrunning the routes.

What the federal emissions cap proposed, and why it was dropped

Status as of October 28, 2026: the cap was never put into effect. The regulations were published as a proposal in Canada Gazette, Part I, on November 9, 2024 and never finalized in Part II. In the Canada-Alberta memorandum of understanding of November 27, 2025, under the commitments Canada made, the text reads: "Canada will not implement the Oil and Gas Emissions Cap, which has not yet been put into effect." The Pathways Plus memorandum of understanding, made as of July 2, 2026 between Canada, Alberta and the oil sands companies, records that Canada stated in Budget 2025 that effective carbon markets, stronger methane regulations and carbon capture at scale "would obviate the need for the previously proposed oil and natural gas emissions cap". The design and the government's impact analysis below are kept as a record of what the proposal would have done, because they are still the only official estimate of how an emissions ceiling would have interacted with Alberta's output.

Environment and Climate Change Canada announced the proposed Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations on November 4, 2024, and the comment period closed on January 8, 2025, according to the government's cap page (checked October 2026). The proposal and its Regulatory Impact Analysis Statement were published in Canada Gazette, Part I, on November 9, 2024. The main design numbers, as written there:

Two features of the design were often missed. It was a cap-and-trade system with flexibility built in, so "27 percent below 2026" was the allowance level, not the most the sector could legally have emitted; the legal upper bound sat higher, at about 19 percent below 2019. And the megatonne figure was never fixed, because it was tied to 2026 reported emissions that will not be known until after 2026 ends. The government's cap page, last modified in March 2025, states the intent in the future tense it was written in: the cap "will put a limit on GHG pollution, not oil and gas production."

Would the cap have cut production? The official estimate and its limits

The Regulatory Impact Analysis Statement answered the production question with numbers. In its central case it estimated a 0.7 percent reduction in total oil and gas production over the first compliance period: 0.9 percent for oil and 0.3 percent for natural gas. It projects national GDP growth of 22.0 percent between 2019 and 2030 to 2032, against 22.1 percent without the regulations, an average GDP difference of about $1.2 billion, or 0.04 percent, with Alberta bearing most of it. On emissions, it estimates cumulative reductions of 13.4 Mt over 2030 to 2032: 20.2 Mt from oil and gas, partly offset by a 6.7 Mt increase elsewhere in the economy.

The argument on the other side was about timing, not arithmetic. Under the cap, emissions could have fallen in three ways: cleaner operations at the same output, buying flexibility, or producing less. The first route depended on large projects, carbon capture above all, being built and operating by 2030. Had they slipped, the regulation's own logic would have left the other two routes, and lower output would have become the adjustment. The impact analysis modelled the cap with its assumptions about those projects and left post-2032 carbon capture investment out of scope, so its 0.9 percent figure was a conditional estimate, not a guarantee. Both readings could have been right in different scenarios, and project construction, not rhetoric, would have decided between them.

Worked example: putting the 0.9 percent in barrels

The impact analysis gave percentages, not barrels, and its figures were national, not Alberta-only. As an illustration only, apply the 0.9 percent oil reduction to Alberta's 2025 average of 4.147 million barrels a day: 4.147 million times 0.009 is about 37,000 barrels a day. For scale, that is about 6 percent of the 590,000 barrels a day the Trans Mountain Expansion added, and about a tenth of the 0.369 million barrels a day of growth between 2023 and early 2026. On the government's central estimate, then, the cap would have been small next to the pipeline story. A scenario in which carbon capture slips badly would be larger, and that scenario is exactly what the official analysis did not quantify. With the cap set aside, the same arithmetic is a measure of how much the policy question mattered next to pipeline space, not a live risk.

The proposal's arithmetic can still be checked from the table: 156.6 Mt times 0.73 (27 percent below) is 114.3 Mt, matching the modelled 114 Mt cap. The gap between the 2026 baseline and the cap, about 42.6 Mt, is the reduction the sector would have needed to find through abatement, flexibility units, or lower output in each year of the first period.

The same numbers show why output growth would have made the target harder. The cap would have fixed total emissions at 73 percent of the 2026 level. Had sector output stayed flat to 2030, emissions per barrel would have needed to fall 27 percent. With output 5 percent higher by then, the required fall in emissions per unit of output would have risen to about 30.5 percent (1 minus 0.73 divided by 1.05); at 10 percent higher, about 33.6 percent. These growth rates are illustrations, not forecasts, but they make the trade-off concrete: every extra percent of output before 2030 would have had to be matched by a larger cut in emissions intensity, bought flexibility, or, failing both, less output. That was the mechanism behind both readings of the cap described above.

Where simple readings of this story go wrong

• Treating a proposed rule as law. The cap was published as a proposal in Canada Gazette Part I and never reached Part II, which is where final regulations become binding. A proposal can change or, as here, be withdrawn from the agenda: Canada committed on November 27, 2025 not to implement it.
• Reading pipeline capacity as production capacity. Nameplate capacity is the volume a pipeline can carry under design conditions; actual throughput depends on shipper contracts, blend quality, and maintenance. And pipeline barrels include diluent, so they are not the same as bitumen produced.
• Using one month as a trend. Alberta's 2026 monthly totals swung by about 0.4 million barrels a day between May and July. Annual averages are the right unit for structural claims.
• Mixing national and provincial figures. The federal impact estimates covered Canada's oil and gas sector; the production table on this page is Alberta only. Applying one to the other, as the worked example above does, is an illustration and should be labelled as one.
• Confusing emissions intensity with total emissions. Output can rise while emissions fall if intensity drops fast enough. The proposed cap would have limited total emissions, so the race between output growth and intensity improvement was what mattered.

What to watch, and where to find it

1. Monthly production. The Government of Alberta economic dashboard, split into conventional and non-conventional oil. Compare twelve-month averages.
2. Pipeline throughput. The CER pipeline profiles, updated quarterly, for Trans Mountain and the other export systems.
3. The differential. The WCS discount to WTI as the market's live read of takeaway tightness; see the differential explainer.
4. The policies that replaced the cap. The Pathways Plus memorandum of understanding names carbon markets, oil and gas methane regulations and carbon capture as the measures that made the cap unnecessary; Canada Gazette Part II is where any of them becomes binding regulation.
5. US demand for Canadian crude. Canada was the largest source of US gross petroleum imports in 2023, at 4.42 million barrels a day or 52 percent of the total, according to the EIA; our US oil imports by country guide shows how that flow is reported, and the Canada country profile covers the national picture.

Frequently asked questions

Data and sources, checked October 22, 2026: Government of Alberta, Economic Dashboard, oil production (updated October 1, 2026; monthly conventional and non-conventional oil volumes from its public data API, converted by PetroEyes from cubic metres to barrels at 6.2898 barrels per cubic metre and averaged by calendar days); Canada Energy Regulator, pipeline profile, Trans Mountain expanded system (nameplate capacity about 890 Mb/d; about 300 Mb/d before the Trans Mountain Expansion Project came online on May 1, 2024; Westridge Marine Terminal shipments to Asia and the US west coast; interim tolls subject to an ongoing hearing); Canada Energy Regulator, pipeline throughput and capacity open data for Trans Mountain, Keystone and the Enbridge Mainline (monthly through June 2026, downloaded October 24 and again, unchanged, October 28, 2026), and Canadian crude oil exports by rail, monthly data (page modified October 26, 2026, with monthly values through August 2026; checked October 28, 2026); Government of Canada, oil and gas emissions cap page (proposed regulations announced November 4, 2024; comment period closed January 8, 2025; page dated March 14, 2025, rechecked October 28, 2026); Prime Minister of Canada, Canada-Alberta Memorandum of Understanding backgrounder (November 27, 2025; commitment not to implement the Oil and Gas Emissions Cap; checked October 28, 2026); Privy Council Office, Major Projects Office, Pathways Plus memorandum of understanding (made as of July 2, 2026; page modified July 13, 2026; recital on the previously proposed cap; checked October 28, 2026); Canada Gazette, Part I, November 9, 2024, proposed Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations and Regulatory Impact Analysis Statement (cap design, modelled 114 Mt cap on a 156.6 Mt 2026 baseline, production, GDP, and emissions estimates, sector share of national emissions); EIA, How much petroleum does the United States import and export? (Canada 4.42 million b/d, 52 percent of US gross petroleum imports in 2023). Percentages, differences, and the barrel illustration are PetroEyes arithmetic on those figures.