Fact finder
Alberta oil by the numbers
64 key facts from the library's guides, each with the year it describes. Numbers link to the exact source in the guide they come from.
Oil sands
Alberta's Oil Sands: The Complete Guide
- Area: oil sands underlie about 142,200 km² of northern Alberta, spread across the Athabasca, Cold Lake and Peace River deposits [1].
- Output (2024): raw bitumen production averaged 3,557.8 thousand barrels per day (565.4 thousand m³/d). In situ wells supplied 52 per cent and mines 48 per cent [2].
- Output (2025): Canadian oil sands production hit a record of about 3.5 million barrels per day, up roughly 5 per cent from 2024 [3][4].
- Reserves: the Government of Alberta puts proven oil sands reserves at about 158.9 billion barrels [1]. About 20 per cent of the recoverable resource is shallow enough to mine, and the other 80 per cent needs in situ (in-place) methods [1].
- Royalties (2024–25): oil sands royalties came to about $17 billion, the Alberta government's largest single source of revenue that year [5][6].
- Emissions (2024): oil sands production emitted 92 megatonnes (Mt) of CO₂ equivalent, up from 33 Mt in 2005 [7]. Emissions per barrel fell to 59 kg CO₂e in 2025, about 31 per cent below 2009 [8].
- Tailings (2024): fluid tailings stored at oil sands mines totalled about 1,505 million m³, up from 1,075 million m³ in 2014 [9].
Policy
Who Owns Alberta's Oil? Mineral Rights, Royalties and Regulation Explained
- The provincial Crown owns about 81% of Alberta's mineral rights on behalf of Albertans; the remaining 19% is held by the federal government, individuals and corporations [1][2].
- Alberta took control of its Crown lands and minerals from Ottawa under the Natural Resources Transfer Agreement, which took effect on October 1, 1930 [3][4].
- Crown petroleum and natural gas rights are sold at sealed-bid public offerings held about every two weeks; the highest cash bonus bid wins [5][6].
- Under the Modernized Royalty Framework (wells spud from January 1, 2017), a well pays a flat 5% royalty until its revenue equals a cost allowance called C*, then a price-sensitive rate of up to 40% [7][8].
- Oil sands projects pay 1% to 9% of gross revenue before payout, and after payout the greater of that or 25% to 40% of net revenue, both scaled to the price of West Texas Intermediate (WTI) in Canadian dollars [9].
- Non-renewable resource revenue was $22.0 billion in fiscal 2024-25, including $17.2 billion in bitumen royalties [10].
- The Alberta Energy Regulator (AER) took over from the Energy Resources Conservation Board on June 17, 2013; the regulator's lineage goes back to a conservation board created in 1938 [11][12].
- The AER estimated total oil and gas closure liability at $36.6 billion at the end of 2024, with about 78,000 inactive wells [13].
Careers
Working in Alberta's Oil and Gas Industry: Jobs, Training and Safety Tickets
- Jobs (2025): Alberta's mining and oil and gas extraction industry employed 140,200 people in 2025, or 5.4 per cent of all jobs in the province, down 6.7 per cent from 2024 [1].
- The long swing: Statistics Canada estimates put the same industry at 172,100 workers in 2014, 125,000 in 2020 and 150,200 in 2024 [2]. From January to August 2026 employment averaged about 135,900 (calculated from monthly estimates) [3].
- Pay (2025): employees in Alberta's combined forestry, fishing, mining and oil and gas group earned an average of $58.84 an hour, against $37.35 across all industries, and the group averaged 46.5 hours of work a week [1].
- Hiring outlook: Careers in Energy projects a national net hiring requirement of 72,600 energy workers by 2035, most of it to replace 54,200 workers eligible to retire [4].
- Tickets: an H2S Alive certificate from Energy Safety Canada is valid for three years [5]. Alberta law also requires a site-specific orientation before a worker's first day on an oil, gas or geothermal work site [6].
- Safety record (2024): the mining and petroleum development sector had a lost-time claim rate of 0.34 per 100 person-years, far below the provincial 1.35, but a fatality rate of 11.65 per 100,000 person-years, above the provincial 8.25 [7].
- Automation: all ore at Suncor's Base Plant mines is now hauled by driverless trucks, a fleet of almost 120 in 2025 [8].
- Who works: women held 19.0 per cent of the industry's Alberta jobs in 2025 [1]. Careers in Energy's latest data put Indigenous people at 7.4 per cent of Canada's energy labour force, about twice their share of all workers [9].
- Scams: a common job scam asks you to pay for training or equipment for a job that does not exist [10].
Environment
Emissions, Methane and Carbon Capture in Alberta's Oil Industry
- Alberta total (2024): Alberta emitted 260.1 megatonnes (Mt) of carbon dioxide equivalent in 2024, up 3.6 per cent from 2005 and about 38 per cent of Canada's 685 Mt [1][2].
- Oil and gas share (2024): Oil and gas activities produced 153.6 Mt in Alberta, about 59 per cent of the provincial total (calculated from the inventory) [2].
- Oil sands (2024): Alberta's oil sands emitted 85.1 Mt, up from 29.6 Mt in 2005, while gas production and processing fell from 60.5 Mt to 39.2 Mt [2].
- Intensity (2025): Oil sands emissions per barrel fell for a 13th straight year, to 59 kg, yet total oil sands emissions still rose about 2 per cent, S&P Global estimates [3].
- Methane (2024): The Alberta Energy Regulator (AER) estimates upstream methane was 51 per cent below 2014 levels in 2024, beating the province's 45 per cent target three years early [4][5].
- Carbon price (2026): Alberta's industrial carbon price has been frozen at $95 per tonne since May 2025; a May 2026 federal-provincial deal sets it at $115 by 2030 and $130 by 2035 [6][7][8].
- Emissions cap (2025): Ottawa agreed on November 27, 2025, not to implement its proposed oil and gas emissions cap, which had never been finalized [9].
- Carbon capture (2026): Quest and the Alberta Carbon Trunk Line have stored more than 17 Mt of CO₂ since 2015, and the proposed Pathways project targets about 6 Mt a year by the mid-2030s [10][11].
Extraction
The Life of an Alberta Oil Well: From Licence to Reclamation
- Wells licensed (2025): The Alberta Energy Regulator (AER) issued 6,055 well licences in 2025, up from 5,701 in 2024; about 48% were for bitumen, 31% for crude oil and 21% for natural gas [1].
- Drilling pace (2025): About 8,419 wells were spudded in Alberta in 2025, and the province averaged 129 active drilling rigs per week, according to Baker Hughes counts compiled by the province [1].
- Horizontal is the norm: More than 99% of the 3,385 new crude oil wells placed on production in 2024 were horizontal [2].
- Groundwater protection: Alberta protects nonsaline groundwater (under 4,000 mg/L dissolved solids) to a maximum of 600 metres below ground, and surface casing must be cemented along its full length [3][4].
- Fracturing water (2024): Hydraulic fracturing used about 30 million m³ of make-up water in 2024, 99% of it nonsaline; only about 2% of the total water used was recycled [5].
- Steep early decline: The AER assumes new horizontal oil wells in most regions lose 32% to 56% of their output in their first year; in the heavy-oil northeast the figure is 14% [6].
- Closure spending (2024): Industry and the Orphan Well Association spent more than $1 billion on closure work in 2024, and the AER has set the mandatory industry closure quota at $750 million for each of 2025, 2026 and 2027 [7][8].
- The end state: About 170,000 wells in Alberta, some 37% of the total, have already been abandoned; a company remains responsible for surface reclamation issues for 25 years after its reclamation certificate is issued [9][10].
Markets
Oil Prices and Alberta's Economy: WTI, WCS and the Provincial Budget
- Two benchmarks matter most: West Texas Intermediate (WTI), delivered at Cushing, Oklahoma, is North America's main light-oil price, and Western Canadian Select (WCS), delivered at Hardisty, Alberta, is the main Canadian heavy-oil price [1].
- Budget 2026 assumption: For 2026-27 the province assumed WTI at US$60.50 a barrel, a WTI-WCS discount of US$13.00 and a dollar worth 73.0 U.S. cents [2].
- Rule of thumb: Each US$1 change in WTI moves provincial revenue by about $680 million over a year; a US$1 change in the heavy-oil discount moves it by about $670 million, and a one-cent move in the loonie by about $440 million (Budget 2026 estimates) [2].
- 2026 price shock: After war broke out in the Middle East in late February 2026, WTI averaged US$93 from April to June; the August 27, 2026 update turned a forecast $9.4 billion deficit into a $2.0 billion surplus [3].
- Resource dependence swings: Non-renewable resource revenue was 6.5% of provincial revenue in 2015-16 but 33.2% in 2022-23, calculated from government figures [2].
- Economic weight: CAPP puts the broad oil and gas industry at about $88 billion, or 25%, of Alberta's GDP in 2024, with over 200,000 direct jobs and over 70% of the province's exports [4].
- Savings: The Heritage Savings Trust Fund was worth $31.9 billion on December 31, 2025, and the province's stated goal is $250 billion by 2050 [5].
- Negative oil: On April 20, 2020, the expiring May WTI futures contract closed at minus US$37.62 a barrel [6].
- At the pump: Alberta's 13-cent-per-litre fuel tax is suspended from October 1 to December 31, 2026, after WTI averaged US$90.54 over the review period [7][8].
Markets
Getting Alberta Oil to Market: Pipelines, Rail and the Price Discount
- Production and exports (2025): Canada produced a record 5.35 million barrels per day (bbl/d) of crude oil and equivalents in 2025, 83.8 per cent of it in Alberta, and exported about 4.3 million bbl/d [1][2].
- One main customer (2025): 90.1 per cent of Canada's crude exports went to the United States in 2025. The non-U.S. share, 10.9 per cent by Statistics Canada's count, was more than triple the 2016–2024 average [2][3].
- Biggest pipeline (2025): The Enbridge Mainline holds about 70 per cent of western Canada's oil export capacity. In 2025 it moved 3.08 million bbl/d at an average 95.2 per cent utilization [4][5].
- Trans Mountain (2024): The federally owned Trans Mountain Expansion entered service on May 1, 2024, raising capacity from about 300,000 to 890,000 bbl/d. Its final cost estimate was $34.2 billion [6][7].
- Rail (2025): Crude-by-rail exports averaged 77,200 bbl/d in 2025, the lowest since 2012, against a monthly record of 412,000 bbl/d in February 2020 [8].
- The discount (2018 and 2025): Alberta government price data show the WCS discount to WTI averaged about US$26.48 a barrel in 2018, with monthly averages above US$43 in November and December, and about US$11.76 in 2025 (annual averages calculated) [9].
- Royalty link (2026–27): Alberta's Budget 2026 estimates that each US$1 widening of the light-heavy differential cuts provincial revenue by about $670 million a year [10].
- Next pipeline (2026): Alberta's proposed West Coast Oil Pipeline, a 1 million bbl/d line to southern British Columbia, was referred to the federal Major Projects Office on July 2, 2026. It has no regulatory approval or final investment decision [11].
Processing
From Bitumen to Fuel: Upgrading and Refining in Alberta
- Upgraded output (2024): Alberta's four upgraders produced 196.6 thousand m³/d (1.24 million barrels per day) of upgraded bitumen, mostly synthetic crude oil, up 4.5 per cent from 2023 [1].
- Share upgraded (2024): About 48 per cent of the raw bitumen produced in Alberta was upgraded in the province. The Alberta Energy Regulator (AER) expects that share to fall to about 44 per cent by 2034, as raw bitumen output grows faster than upgrading capacity [2][1].
- Synthetic crude (2025): Statistics Canada reported 76.0 million m³ of synthetic crude oil in 2025, up 2.7 per cent. That averages roughly 1.31 million barrels per day (calculated) [3].
- Refining (2024): Alberta's five refineries processed about 575,000 barrels per day, a utilization rate of 103 per cent [4].
- Sturgeon Refinery: The province supplies 75 per cent of the refinery's bitumen and pays 75 per cent of its tolls under an agreement that runs to May 31, 2058. The plant's cost rose from $5.7 billion at the start of construction to $10.1 billion [5][6][7].
- Sturgeon finances (2026–27): Alberta's Budget 2026 forecasts a $313 million net loss for the Alberta Petroleum Marketing Commission, after a projected $604 million loss in 2025–26 [8].
- By-products (2025): Oil sands facilities produced about 2.9 million tonnes of sulphur, and the three coking upgraders held about 184 million tonnes of stockpiled petroleum coke at year end (calculated from AER data) [9][10].
Facts are drafts pending fact-check, like the guides they come from. Figures marked verify are still being checked.