Oil Prices and Alberta's Economy: WTI, WCS and the Provincial Budget

How crude oil is priced

Oil is a global commodity traded in U.S. dollars. Alberta produces a large volume, but it is still a "price taker": its barrels are valued against prices set at trading hubs in the United States and overseas, then adjusted for quality, location and currency. Understanding Alberta's oil income starts with those reference prices, called benchmarks.

The benchmarks

• West Texas Intermediate (WTI). The main benchmark for light sweet crude in North America, specifying delivery at Cushing, Oklahoma ^[1]. WTI has an API gravity of about 40 degrees and less than 0.5% sulphur ^[9]. The widely quoted WTI price is the front-month futures contract on the New York Mercantile Exchange (NYMEX), with Cushing as the underlying physical market ^[9].
• Brent. The main benchmark for light sweet crude in international markets, tied to the Sullom Voe terminal in the United Kingdom ^[1]. Unlike WTI, Brent futures settle financially rather than by physical delivery ^[6].
• Western Canadian Select (WCS). A heavy, sour blend created in 2004, when producers agreed to blend conventional heavy crude and oil sands bitumen at a storage terminal in Hardisty, Alberta, to simplify logistics ^[10]. WCS has an API gravity of 20.5 to 21.5 degrees and 3.0% to 3.5% sulphur ^[9]. Its price is roughly what Canadian heavy-oil producers receive for non-upgraded production ^[10].
• Edmonton light (Mixed Sweet Blend, or MSW). The main Canadian benchmark for light sweet crude, blended at Edmonton and often called Edmonton Par ^[1][11]. Its five-year average quality is about 42 API with about 0.42% sulphur ^[11].
• Synthetic crude oil (SCO). A light crude produced by upgrading bitumen, with delivery at Edmonton ^[1]. About 48% of Alberta's raw bitumen was upgraded in the province in 2024 ^[9].

Natural Resources Canada also publishes an "implied bitumen" price. It assumes WCS is 70% bitumen and 30% condensate, and subtracts the value of the condensate to estimate what raw bitumen is worth before it is thinned to flow through pipelines ^[1]. The ranking of these prices shows how quality and location work. In December 2020, for example, the monthly averages in Canadian dollars per cubic metre were: Brent 401, WTI 379, synthetic 345, Edmonton light 332, WCS 270 and implied bitumen 222 ^[1]. One cubic metre is about 6.29 barrels.

Futures and physical barrels

A futures contract is an agreement, usually for a given month, to deliver a set amount of crude on a specified future date at a particular location, which for WTI is Cushing ^[6]. WTI futures require the holder to take physical delivery soon after the contract expires or face large fines and fees, so financial traders who cannot take delivery must sell before expiry ^[6]. Brent contracts, by contrast, settle in cash ^[6]. Published benchmark prices, such as those Natural Resources Canada converts into Canadian dollars, are futures settlement prices for delivery in the prompt month ^[1].

Physical barrels in Alberta change hands in contracts that reference those benchmarks. Heavy barrels are usually discussed as a discount to WTI, and that gap has its own name: the differential ^[10].

The differential

WCS sells below WTI for two reasons. Heavy oil yields less gasoline and diesel and costs more to refine, and Hardisty is far from the U.S. refineries that buy most Canadian heavy crude, so shipping costs come off the price ^[10]. Between 2013 and 2017, WCS averaged US$16.72 a barrel below WTI ^[10].

The discount widens sharply when Alberta produces more oil than pipelines can carry. In 2018 it averaged US$26.81, and on some trading days in October 2018 it exceeded US$50, because production outran the combined capacity of pipelines and rail ^[12]. After the Trans Mountain Expansion (TMX) started in May 2024, the average discount narrowed to US$14.73 in 2024 from US$18.65 in 2023 ^[9]. In fiscal 2024-25 it averaged US$13.06 ^[13]. The other guide in this series, Getting Alberta oil to market, covers pipelines and egress in detail.

Why the exchange rate matters

Oil is priced in U.S. dollars, but Alberta's producers pay most costs, royalties and taxes in Canadian dollars. To convert, divide the U.S. price by the value of the loonie. At a WTI price of US$73.50 and a dollar worth 73.0 U.S. cents, a barrel is worth C$100.68; at 72.1 cents it is worth C$101.94 (illustrative arithmetic). That is why the province says a weaker Canadian dollar increases the value of energy exports priced in U.S. dollars, and a stronger one reduces it ^[2].

The two prices are linked. Lower oil prices tend to weigh on the loonie, which partly cushions the Canadian-dollar price when oil falls ^[2]. The loonie averaged 100.7 U.S. cents in fiscal 2011-12 and 71.9 cents in 2024-25 ^[14][2], so the same U.S. price was worth far more in Canadian dollars in the later year.

What moves world oil prices

World prices reflect current supply and demand and, just as important, what traders expect supply and demand to be in future months. Several forces recur.

• OPEC and OPEC+. OPEC members produce about 35% of the world's crude and supply about half of the oil traded internationally. The group sets production targets, and prices tend to rise when it lowers them ^[15]. Its spare capacity, oil that can be brought to market quickly, acts as a cushion against disruptions ^[15]. Since late 2016 OPEC has coordinated output with other large producers, including Russia, under the "OPEC+" label ^[16][17]. OPEC+ held back about 1.4 million barrels per day of supply in 2024 and began increasing output in April 2025 ^[9].
• Non-OPEC supply. U.S. production reached a record 13.2 million barrels per day in 2024 ^[9]. Growth in U.S. shale oil was one of the main reasons the market became oversupplied in 2014 ^[18].
• Inventories. Stored oil is the balancing point between supply and demand. Rising stocks signal that production exceeds consumption and tend to push spot prices down ^[19].
• Recessions. Oil demand falls with economic activity. U.S. crude consumption fell 9% from 2007 to 2009 during the financial crisis ^[17].
• Geopolitics and disruptions. Wars, sanctions and damaged infrastructure can remove supply suddenly. Alberta's budget lists refinery and pipeline outages, storage levels, trading activity, OPEC+ decisions, geopolitical events, sanctions and weather among the forces that make its forecasts uncertain ^[2].

Even professionals miss. Budget 2025 assumed WTI would average US$69.00 in 2025; it averaged US$64.81, and the private-sector average forecast was similarly high ^[2].

Price shocks at a glance

The April 2020 event shows how futures and physical markets interact. Demand collapsed during pandemic lockdowns while storage at Cushing filled: commercial inventories there rose by 27 million barrels between March 13 and May 1, 2020, reaching 83% of working capacity ^[26]. Traders who could not take delivery had to sell before the contract expired on April 21, so the May contract fell US$55.90 in a single day; in effect, sellers paid buyers to take the oil ^[6]. The June contract closed that day at US$20.43 ^[6]. The price climbed back to about US$40 by July 1, 2020 ^[26].

The 2026 shock was a supply event. By the end of March the Brent price had risen about 65% in a month, its largest monthly rise on record, and global supply fell by an estimated 10.1 million barrels per day that month ^[27]. Brent peaked at US$118 on April 29, then fell to US$72 on June 26 after a June 17 memorandum between the United States and Iran sought to reopen the strait ^[25]. Fighting flared again in September, pushing WTI back above US$92 on September 7, 2026 ^[24].

Alberta's budget and the price of oil

The province records royalties, land sale bonuses, rentals and fees as non-renewable resource revenue (NRR). The mechanics of royalties are explained in Who owns Alberta's oil?; this section looks at how prices flow into the budget.

In 2024-25, NRR was $22.0 billion. Bitumen royalties from the oil sands supplied $17.2 billion of that, about 78%. Conventional crude royalties were $3.0 billion, natural gas and by-products $1.2 billion, land lease sales $385 million and rentals and fees $178 million ^[2].

Why royalties are so sensitive to price

Two features magnify price swings. First, oil sands royalty rates themselves rise with the WTI price in Canadian dollars. Before payout, a project pays 1% of gross revenue when WTI is C$55 or less, rising to 9% at C$120 or more. After payout it pays the greater of that or a net revenue royalty of 25% to 40% over the same price range ^[28]. Using that formula, at Budget 2026's assumptions (US$60.50 and 73.0 cents, or about C$82.88) the rates are about 4.4% of gross and 31.4% of net revenue; at the August update's forecast (US$73.50 and 72.1 cents, about C$101.94) they are about 6.8% and 35.8% (illustrative calculation) ^[28][2][3].

Second, more oil sands projects have reached payout over time; five did so in 2021 alone, which raised their royalty rates ^[14]. After payout the royalty is usually a share of revenue minus costs. Because costs do not rise in step with prices, profits tend to swing more than prices do, and so does a royalty based on them. Corporate income tax behaves similarly: stronger corporate profits added $545 million to the 2026-27 corporate tax forecast in August 2026 ^[3].

Budget 2026 assumptions

Budget 2026, released on February 26, 2026, was built on a weak oil outlook ^[29]. The Fiscal Plan expected strong supply growth and rising inventories to hold prices down, after WTI averaged below US$58 in December 2025, its lowest monthly average since February 2021 ^[2].

Source: Budget 2026 Fiscal Plan ^[2].

On those numbers the province forecast NRR of $13.2 billion in 2026-27, 18% of total revenue, and deficits of $9.4 billion, $7.6 billion and $6.9 billion over the three plan years ^[2]. The Fiscal Plan calculated that, with all other assumptions unchanged, the budget would balance at a WTI price of about US$74 in 2026-27 and US$77 in 2027-28 ^[2].

The published sensitivities

Every budget includes a table of rules of thumb. These are Budget 2026's estimates of the full-year effect of each change on the fiscal plan, in millions of dollars ^[2]:

The government cautions that these figures depend on current price levels, that they vary significantly at different prices and that they exclude land sales ^[2]. It also notes that the sensitivities have increased significantly over the last several years ^[2].

The August 2026 update

The first-quarter update, released on August 27, 2026, showed how quickly the picture can change ^[3]. War in the Middle East from late February pushed WTI to an average of US$93 in April to June, while the differential averaged US$14.60 and the loonie 72.3 cents ^[3]. The province raised its full-year WTI forecast to US$73.50, expecting prices to ease as shipping through the Strait of Hormuz recovers, and widened its differential forecast to US$14.80 because of competition from U.S. Strategic Petroleum Reserve releases and Venezuelan heavy crude ^[3].

The results:

• NRR was forecast at $23.0 billion, $9.7 billion above budget, including bitumen royalties of $18 billion (up $8.3 billion) and crude oil royalties of $3.1 billion (up $1 billion) ^[3].
• Total revenue was forecast at $86.3 billion, $11.7 billion above budget ^[3].
• The bottom line moved from a $9.4 billion deficit to a $2.0 billion surplus ^[3].

As a rough check (illustrative), Budget 2026's rules of thumb predict about $8 billion: US$13 more on WTI (about +$8.8 billion), a loonie 0.9 cents weaker (about +$0.4 billion) and a differential US$1.80 wider (about −$1.2 billion). The actual upgrade to resource revenue alone was larger, a reminder that sensitivities are approximations that grow less reliable for big moves ^[2][3].

Final results for 2025-26 were delayed: the government said health-system restructuring needed more time to close the books ^[3]. The last published estimate for 2025-26, from the third quarter, was NRR of $16.3 billion ^[2].

Resource revenue over time

Oil money arrives in waves. The table shows recent fiscal years using final (actual) results.

Sources: prices, exchange rates, revenue and surplus from the Budget 2026 historical fiscal summary ^[2]; differentials from year-end reports ^{[14][23][30][13]}. The 2020-21 differential is derived from the 2021-22 report, which says the 2021-22 average of US$13.56 was US$2.98 wider than the year before ^[14]. Shares are calculated from the government's revenue figures.

Looking further back, NRR was 30.3% of revenue in 2008-09, when WTI averaged US$85.94, and 26.8% in 2011-12, calculated from the 2021-22 year-end report ^[14]. It then fell to 18.1% in 2014-15 and 6.5% in 2015-16 as WTI averaged US$45.00 ^[2]. It stayed in single digits or low double digits until the 2021 rebound ^[2][14]. In the mid-1980s, by contrast, energy revenue was about 50% larger than all provincial tax revenue combined ^[31].

The 2022-23 peak shows the upside. As the Russia-Ukraine war lifted prices, WTI averaged US$89.69 and bitumen royalties alone reached $16.9 billion ^[23]. The downside is just as clear: in 2015-16, NRR was $2.8 billion, less than a third of its level two years earlier ^[2].

Oil and gas in Alberta's economy

Output

Measured broadly, including extraction, support services, oil and gas engineering construction, refineries and pipelines, the oil and gas industry produced about $88 billion of GDP in 2024, roughly 25% of Alberta's total, according to CAPP's analysis of Statistics Canada data ^[4]. Narrower measures give smaller shares, so check definitions when comparing figures.

Oil and gas extraction has driven recent growth. Its output rose 3.7% in 2024 to a record, and it accounted for nearly 40% of Alberta's economic growth over the previous eight years ^[32]. Alberta's real GDP grew 2.7% in 2024, with mining, quarrying, and oil and gas extraction contributing 0.96 percentage points ^[33]. Alberta supplied 83.8% of Canada's crude oil and equivalent production in 2025 and added 182,000 barrels per day that year ^[34].

Investment

Capital spending responds to prices, with a lag. Total capital spending on crude oil, natural gas, oil sands and emerging resources in Alberta was $30.9 billion in 2024, according to the AER, including $16.8 billion for conventional oil and gas and $13.3 billion for the oil sands ^[9]. That remains below the 2014 peak ^[9]. Across Canada, oil and gas capital spending peaked at C$80.7 billion in 2014 and fell 57%, to C$34.9 billion, in 2016 after prices collapsed ^[35].

Conventional and oil sands investment respond differently. Conventional wells are short-cycle projects that can be drilled quickly when prices rise; oil sands projects take years to build and are less sensitive to short-term prices ^[3]. After the 2026 price spike, active drilling rigs in Alberta were up 24% year over year in July, and the province forecast oil and gas extraction investment to grow about 4.4% ($1.4 billion) in 2026 ^[3].

Jobs

The oil and gas industry accounted for over 200,000 direct jobs in Alberta in 2024, about 8% of employment, according to CAPP; direct jobs peaked at about 312,000 (14%) in 2013 ^[4]. Using Natural Resources Canada's estimate of about 1.5 indirect jobs per direct job, CAPP estimates roughly 500,000 direct and indirect jobs ^[4]. Definitions vary: the provincial government counted about 138,000 people in the upstream energy sector in 2022 ^[36]. For occupations, training and wages, see Careers in Alberta's oil and gas industry.

Exports

In 2024 Alberta exported about 4.7 million barrels of oil equivalent per day of oil and gas, worth $133 billion and over 70% of the province's total exports ^[4]. Nationally, energy exports to the United States (crude oil, refined products, natural gas and natural gas liquids) were worth $157.5 billion in 2025, or 20.2% of Canada's goods exports, and Canada supplied 63.4% of U.S. crude oil imports ^[37]. Since TMX began service, Canadian crude exports to countries other than the United States have more than tripled ^[38].

Boom and bust: how price crashes hit Alberta

The 1980s: the NEP and the 1986 collapse

World oil prices rose from about $4 to about $40 a barrel during the 1970s ^[39]. On October 28, 1980, federal Energy Minister Marc Lalonde introduced the National Energy Program (NEP), aiming at energy security, a larger federal and consumer share of oil revenue, and more Canadian ownership, through price controls, new production taxes and more federal regulation ^[40]. Premier Peter Lougheed's government cut oil production in protest ^[40], a compromise followed in September 1981, and the 1985 Western Accord ended the NEP and deregulated oil prices ^[41].

The NEP remains contested. Supporters saw it as a response to an energy crisis; Albertans widely viewed it as federal intrusion, and one provincial heritage encyclopedia cites estimates that Alberta lost $50 billion to $100 billion in revenue during the NEP era ^[40]. Others emphasize world markets: the price of oil peaked in 1980 and then fell as a glut built up ^[39]. Alberta suffered two recessions, in 1982-83 and 1986, that kept unemployment above 10% for about five years ^[42]; the unemployment rate reached 11.3% at the height of the 1980s recession ^[43], and mortgage foreclosures were widespread ^[39].

The 1986 collapse was a textbook supply shock. Saudi Arabia, which had been cutting its own output to support prices, abandoned that role and began raising production in December 1985 ^[21]. WTI's monthly average fell by half between January and July 1986 ^[20]. Alberta's real GDP shrank 2.8% in 1986 ^[44]. In the 1987 fiscal year resource revenue fell 63% and total provincial revenue 30%, and the province ran deficits for nine straight years; its net asset position of $12.6 billion in 1985 became net debt of $8.3 billion by 1994 ^[31]. Transfers of resource revenue to the Heritage Fund stopped in 1987 ^[45].

2008-09: the financial crisis

WTI fell about 79% in less than six months in late 2008 ^[17]. Alberta's real GDP fell 5.5% in 2009 ^[44], and NRR dropped from $11.9 billion in 2008-09 to $6.8 billion in 2009-10 ^[14].

2014-2016: the long slump

The 2014 crash lasted longer. Alberta's real GDP fell 3.7% in 2015 and 3.5% in 2016 ^[44]. The province lost a net 19,600 jobs in 2015, the worst year since 1982, with an estimated 40,000 energy-sector jobs cut, and the unemployment rate rose from 4.8% to 7% during that year ^[46]. NRR fell from $8.9 billion in 2014-15 to $2.8 billion in 2015-16, and the province ran deficits every year from 2015-16 to 2020-21 ^[2].

Employment did not fully return when prices recovered. Direct oil and gas jobs, about 312,000 in 2013, were about 200,000 in 2024 ^[4]. The Parkland Institute, an Alberta public-policy research centre, reported in 2020 that among the largest oil sands companies production had risen 23% since 2014 while jobs had fallen 23% ^[47]. Provincial economists point to a lasting industry emphasis on cost efficiency ^[32].

Then came a made-in-Alberta price problem. With pipelines full, the WCS discount blew out in late 2018 ^[12]. On December 2, 2018, the province announced a mandatory production cut of 325,000 barrels per day, 8.7% of output, starting January 1, 2019 ^[48]. Production was capped at 3.56 million barrels per day, and the cap was gradually raised during 2019 ^[49]. The differential averaged US$13.59 in 2019 ^[12]. No production limit was set after December 2020, and the policy formally ended on December 31, 2021 ^[50].

2020: the pandemic shock

In early 2020 lockdowns cut demand while OPEC+ briefly abandoned its output limits. WTI fell more than 80% between early January and late April ^[16]. Western Canadian producers shut in wells and slowed oil sands operations, cutting supply by an estimated 972,000 barrels per day by mid-May ^[16]. On June 26, 2020, only four rigs were drilling for oil in all of Canada, down from 84 a year earlier ^[51].

The economic damage was the worst in modern Alberta history. Real GDP by industry fell 8.2% in 2020, with mining, quarrying, and oil and gas extraction down 12.2% ^[52]. Employment fell 6.6%, the largest annual drop since records began in 1976, and the unemployment rate reached 11.4%, above the peak of the 1980s ^[43]. NRR fell to $3.1 billion in 2020-21 and the deficit reached $17.0 billion ^[2]. Two years later, with prices high, the province recorded NRR of $25.2 billion and an $11.6 billion surplus ^[2].

Saving the windfall: the Heritage Fund and fiscal rules

Because resource revenue is volatile and finite, Alberta has repeatedly tried to set some aside.

The Heritage Savings Trust Fund

The Alberta Heritage Savings Trust Fund Act received Royal Assent on May 19, 1976. In 1976-77 the fund received 30% of resource revenue, $620 million, plus a special $1.5 billion contribution ^[45]. The contribution rate was cut to 15% in the early 1980s, and deposits of resource revenue stopped in 1987 ^[31][45]. For decades most of the fund's earnings went to general revenue: since inception it has generated $53.6 billion in net income, of which only $10.7 billion was retained ^[2]. Critics note that Alberta saved less than 10% of the $130 billion in resource revenue it collected between 1970 and 2004 ^[31].

Policy has recently shifted. Legislation amended in 2022-23 requires the fund's income to stay in it unless Treasury Board authorizes a withdrawal ^[5]. The fund has retained more than $5.6 billion of net earnings since then and received $5.6 billion in new deposits, including $2.8 billion in 2025-26 from the 2024-25 surplus ^[2]. It reached a record $31.9 billion on December 31, 2025, with a five-year annualized return of 8.8% after fees ^[2][5]. The government's roadmap, released in January 2025, targets at least $250 billion by 2050, and the fund is now managed through the Heritage Fund Opportunities Corporation ^[2][5].

Stabilization and debt rules

Alberta also used to hold a Contingency Account as a cushion. It held $16.8 billion at March 31, 2009, $6.5 billion at March 31, 2015 and nothing by March 31, 2020, after years of covering deficits ^[14].

The current framework, introduced in Budget 2023, requires balanced budgets with exceptions, limits growth in operating expense to population growth plus inflation, and caps in-year spending increases at a budgeted contingency ^[53][2]. Surplus cash is split: the first 50% must repay maturing debt or go to the Heritage Fund, and the other 50% goes to an Alberta Fund, which can be used only for further debt repayment, Heritage Fund savings or one-time initiatives that do not permanently raise spending ^[13]. From 2024-25 results, about $2.6 billion went to repay debt and about $2.6 billion to the Alberta Fund, which then provided $2.8 billion for the Heritage Fund in 2025-26 ^[13][2].

The rules bend when prices fall. The legislation allows a deficit when forecast revenue is below the previous year's third-quarter expense, and requires a return to balance within three years once a deficit is reported ^[2]. Budget 2026 used that exception and announced a review of the fiscal framework ^[2]. Even with a forecast surplus in 2026-27, the August update found no surplus cash to allocate after $4.3 billion in net negative cash adjustments, such as investment income kept inside the Heritage Fund and capital spending, and projected $2.3 billion in new borrowing ^[3]. Taxpayer-supported debt was $85.2 billion at March 31, 2025, and is now forecast at $94.8 billion at March 31, 2027, $14.1 billion below the budget estimate ^[2][3].

How oil prices reach Albertans

At the pump

Retail gasoline prices are built from four parts: the cost of crude oil, the refining margin, the marketing margin and taxes ^[54]. Crude is usually the largest part: across Canada from July 2016 to June 2017 it averaged about 40 cents of each litre, against 36 cents for taxes, 20 cents for refining and 14 cents for marketing ^[54]. Because Alberta refineries buy crude at market prices, high oil prices raise pump prices in Alberta too. Alberta's average price was 175.5 cents per litre on September 21, 2026 ^[8].

Governments have responded with tax changes:

• Alberta fuel tax. The provincial tax has been 13 cents per litre since April 1, 2024 ^[55]. Under the Fuel Tax Relief Program introduced in April 2022, the rate is set each quarter from the average WTI price: fully paused at US$90 or more, 4.5 cents at US$85 to US$89.99, 9 cents at US$80 to US$84.99, and 13 cents below US$80, with increases capped at 9 cents per quarter ^[55][56]. The tax was paused for all of 2023 and charged at 9 cents in early 2024; the program had saved drivers over $2 billion by March 2024 ^[56].
• 2026 relief. For July to September 2026, the province replaced the fuel tax relief with a one-time $100 Alberta Energy Rebate for adults with household income of $225,000 or less, saying it was worth 50% more than the average fuel tax savings ^[57]. The rebate added $357 million to forecast spending ^[3]. After WTI averaged US$90.54 from August 18 to September 15, the province suspended the full 13-cent tax from October 1 to December 31, 2026 ^[8][7].
• Federal measures. Ottawa removed the consumer fuel charge on April 1, 2025, by setting its rates to zero ^[58]. It also suspended the federal excise tax of 10 cents per litre on gasoline and 4 cents on diesel from April 20 to September 7, 2026, citing disruptions linked to the Middle East conflict ^[59].

High prices also feed inflation. The August update raised the forecast for Alberta consumer price growth in 2026 to 2.6%, from 2.1% at budget ^[3].

Through public revenue

Most of the money Alberta collects from oil flows through royalties. An illustration, not an official statistic: in 2024-25, bitumen royalties of $17.2 billion divided by raw bitumen output of about 3.45 million barrels per day works out to roughly $13.60 per barrel produced, and conventional crude royalties of $3.0 billion over about 536,000 barrels per day to roughly $15.50 per barrel ^[2]. Actual royalties vary widely by project, payout status and price, so these averages hide big differences.

Higher revenue can fund services, pay down debt or be saved, but it can also encourage spending that is hard to sustain when prices fall. That tension is why the province introduced expense limits and surplus-cash rules ^[53][13].

The outlook: what official forecasters assume

Forecasts are assumptions, not predictions, and every official source publishes ranges.

• Government of Alberta. Budget 2026 assumed WTI of US$60.50 in 2026-27, rising to US$67.00 in 2027-28 and US$67.50 in 2028-29, with the differential widening to US$14.30 as heavy supply grows ^[2]. Its high and low scenarios put 2026-27 WTI at US$70.00 and US$51.50 ^[2]. The August update raised the 2026-27 assumption to US$73.50 and expects prices to settle lower as the effects of the conflict on crude flows fade ^[3]. The province expects pipeline projects to add about 700,000 barrels per day of export capacity between 2026 and 2030 ^[2].
• Alberta Energy Regulator (ST98). The most recent edition posted on the AER's site when this guide was prepared was the 2025 edition, updated in June 2025 ^[60]. Its base case put WTI at US$68.00 in 2026, rising to US$76.50 by 2034, with the WTI-WCS differential at US$12.00 in 2026 and US$13.00 from 2027 ^[61]. It projected Alberta's crude oil and equivalent production growing from 4.3 million barrels per day in 2024 to 4.7 million by 2034 ^[9].
• Canada Energy Regulator (Canada's Energy Future 2026). The 2026 edition assumes a Brent price of US$75 by 2030 in its Current Measures scenario, US$95 in a Higher scenario, US$55 in a Lower scenario and US$70 in a Canada Net-zero scenario, in 2025 U.S. dollars ^[62]. The CER stresses that scenarios are not forecasts or predictions ^[62]. In Current Measures, Canadian crude production rises from 5.5 million barrels per day in 2024 to 5.8 million by 2030 and peaks around 6.1 million near 2040; oil sands output reaches 4.1 million barrels per day by 2050 ^[63].

The differences between these sources are a useful lesson in themselves. Each rests on different views of global demand, OPEC+ behaviour, technology and climate policy, and each has been wrong before. What they share is the conclusion that Alberta's public finances will stay closely tied to a price no Albertan controls.

FAQ

What is the difference between WTI and WCS? WTI is a light, low-sulphur crude priced at Cushing, Oklahoma, and is North America's main oil benchmark. WCS is a heavy, high-sulphur blend of bitumen and heavy crude priced at Hardisty, Alberta ^[1][9]. WCS sells at a discount because it is costlier to refine and far from its refinery markets ^[10].

Why does a weaker Canadian dollar help Alberta's budget? Oil is sold in U.S. dollars, so each U.S. dollar buys more Canadian dollars when the loonie falls. Budget 2026 estimated that a one-cent rise in the loonie cuts revenue by about $440 million a year, so a one-cent fall adds roughly the same ^[2].

How much does a US$1 change in oil prices affect Alberta's budget? Budget 2026 estimated about $680 million over a full year for each US$1 change in WTI, and about $670 million for each US$1 change in the WTI-WCS differential ^[2]. The effect is not exactly linear and depends on the price level ^[2].

What oil price does Alberta need to balance its budget? With all other Budget 2026 assumptions unchanged, the province calculated a break-even WTI price of about US$74 in 2026-27 and US$77 in 2027-28 ^[2]. Higher-than-expected prices in 2026 moved the forecast to a $2.0 billion surplus in August ^[3].

How much of Alberta's revenue comes from oil and gas? It swings widely. Non-renewable resource revenue was 33.2% of total revenue in 2022-23 but 6.5% in 2015-16, calculated from government figures ^[2]. The August 2026 update forecast $23.0 billion for 2026-27, about 27% of revenue ^[3].

Did oil prices really go below zero? Yes, for one contract on one day. On April 20, 2020, the expiring May WTI futures contract closed at minus US$37.62 because storage at Cushing was nearly full and holders could not take delivery ^[6][26]. The price was back to about US$40 by July 1, 2020 ^[26].

Why doesn't Alberta save more of its oil revenue? Deposits to the Heritage Fund stopped in 1987 and most of its income was spent for decades ^[45][2]. Since 2022-23 the fund keeps its earnings, and surplus cash rules direct part of any surplus to debt or savings ^[5][13]. Critics argue the province still saves too little in boom years ^[31].