Who Owns Alberta's Oil? Mineral Rights, Royalties and Regulation Explained

This guide is general information, not legal, tax or investment advice. Rules change; check the primary sources linked below before relying on any figure.

Who owns the minerals: Crown, freehold and federal

In Alberta, owning land and owning what lies beneath it are two separate things. Mineral rights are a distinct property interest that can be held by someone other than the surface owner.

The provincial Crown, meaning the Government of Alberta acting on behalf of all Albertans, owns about 81% of the province's mineral rights, which includes most of its oil, natural gas and oil sands ^[1][2]. Government material describes this as roughly 53.7 million hectares verify ^[14]. The remaining 19% breaks down into two groups: land where the federal government holds the minerals (national parks and First Nations reserve lands) and "freehold" rights owned privately by individuals and companies ^[1][2]. Alberta's freehold mineral tax guidance puts the privately owned share at about 8% ^[15].

Why is it split this way? When Alberta became a province in 1905, Ottawa kept control of its Crown lands and natural resources, unlike the older provinces. That changed with the Natural Resources Transfer Agreement, signed on December 14, 1929, and in force from October 1, 1930, which transferred the Crown's interest in lands, mines, minerals and associated royalties to the province ^[4][3]. By then, much of the settled south and centre of the province had already been granted to homesteaders, railway companies and the Hudson's Bay Company, sometimes with mineral rights attached. Those early grants are the origin of most freehold minerals today ^[15]. Most freehold rights are now held by corporations, religious organizations and trusts rather than individual families verify ^[2].

Ownership determines who collects the royalty. When a company produces oil or gas from Crown minerals, the royalty goes to the province. When it produces from freehold minerals, it pays a royalty negotiated privately with the freehold owner, and the province levies a separate annual freehold mineral tax on production from those titles ^[15]. Freehold leases are private contracts; Alberta's Farmers' Advocate material notes that lessor royalties commonly range from about 10% to 22.5% and that primary terms are typically around three years verify ^[16].

How companies acquire Crown rights: public offerings, licences and leases

The Ministry of Energy and Minerals issues "agreements" that give a company the exclusive right to explore for and produce Crown minerals in a defined area, for a defined term, in return for bonus payments, annual rent and royalties.

Public offerings. Crown petroleum and natural gas rights are sold at public offerings (commonly called land sales), held about every two weeks, roughly 24 times a year ^[5][17]. What goes on sale is driven by industry: the contents of each sale are set by companies' requests to post specific parcels ^[5]. Bids are sealed, and each parcel is awarded to the highest cash bonus bidder ^[5][6]. The minimum acceptable bid for both licences and leases has been $35 per hectare since October 23, 2020; a successful bid also carries a $625 issuance fee and first-year rent of $3.50 per hectare (minimum $50) ^[6]. Only the winning company and the bonus it paid are published ^[6].

Combined petroleum and natural gas and oil sands sales raised about $473.6 million in calendar 2024 and $407.2 million in calendar 2025 ^[18].

Licences versus leases. The province issues two main kinds of petroleum and natural gas agreement ^[5][17]:

• A licence is an exploration-stage agreement. Its initial term is two years in the Plains region, four years in the Northern region and five years in the Foothills region, reflecting how hard and expensive drilling is in each. The holder "validates" the licence by drilling; validated lands carry into a five-year intermediate term ^[5].
• A lease has a five-year primary term, a form the Crown introduced in 1976 ^[17].

At the end of a lease's primary term, or a licence's intermediate term, the agreement expires unless the holder shows the lands are producing or capable of producing, in which case they are "continued" indefinitely ^[17][19]. Continuation is not all-or-nothing. Under deep rights reversion, formations below the deepest productive zone return to the Crown, and since January 1, 2009, shallow rights reversion has also severed rights above the shallowest productive zone when a lease is continued ^[17].

Oil sands tenure. Oil sands rights are sold under a separate regime. A primary oil sands lease runs 15 years, and continued leases that are not producing can be held only by paying escalating rent. The Oil Sands Tenure Regulation, 2020 eliminated the older oil sands permit as an agreement type ^[20].

Royalties on conventional oil and gas: the Modernized Royalty Framework

A royalty is the owner's share of production. Alberta's government describes royalties as the share of production from resources the Crown owns on behalf of Albertans, and it sets the rates as the owner, not as a taxing authority ^[21]. Each producing well or oil sands project has its own rate, driven by production volume and market price. The Crown takes its royalty on conventional crude oil in kind, as barrels, and collects its share of most other products in cash ^[21]. A separate bitumen royalty-in-kind program exists for oil sands royalties ^[22].

For conventional oil and natural gas wells spud on or after January 1, 2017, royalties are set by the Modernized Royalty Framework (MRF) ^[7][23]. The framework was designed to act like a "revenue minus cost" royalty without requiring the government to audit every well's actual costs. It works in three phases.

1. Pre-payout (flat 5%). A well pays a 5% royalty on its gross revenue from all hydrocarbons until its cumulative revenue equals its Drilling and Completion Cost Allowance, known as C ^[7]. C is not the company's real cost. It is a formula-based proxy calculated from the well's vertical depth, horizontal lateral length and the amount of proppant (sand) placed during fracturing ^[7][24].
2. Post-C* (price-sensitive). Once revenue passes C*, rates rise with commodity prices. For crude oil, condensate and pentanes the rate ranges from 5% to 40%; for methane, ethane, propane and butane it ranges from 5% to 36% ^[8][25]. Each rate is built from a price component, set from reference ("par") prices published by the department, plus a quantity adjustment ^[25].
3. Maturity. When a well's production falls below a set maturity threshold, a volume-based adjustment lowers the rate toward a minimum of 5%, so that low-rate wells are not shut in early ^[8].

Wells spud before 2017 stayed under the older Alberta Royalty Framework unless their operators opted in to the MRF. That grandfathering ends on December 31, 2026, after which remaining older wells move to MRF post-C rates ^[21][26]. The department publishes calculators so owners and analysts can reproduce C and post-C* rates ^[24][27].

Oil sands royalties: pre-payout and post-payout

Oil sands projects, such as mines and in situ steam projects, are treated differently because they cost billions to build and then produce for decades. Royalties are calculated project by project, and the key concept is payout: the point at which a project's cumulative revenue first equals or exceeds its cumulative costs ^[9]. Those costs include a return allowance, an allowed cost representing a minimum return on the unrecovered investment, calculated with reference to the Bank of Canada long-term bond rate ^[28].

Before payout, a project pays a royalty on gross revenue. The rate is 1% when the price of WTI, converted to Canadian dollars, is $55 per barrel or less. It rises with each dollar above $55, reaching 9% when WTI is $120 per barrel or more ^[9][29].

After payout, a project pays whichever is higher of two calculations ^[9]:

• the same gross revenue royalty (1% to 9%), or
• a net revenue royalty of 25% to 40% of revenue minus allowed costs. The net rate is 25% when WTI is C$55 or less and rises to 40% at C$120 or more.

As an illustration of the formula (not a forecast), at a WTI price of C$87.50, halfway between the two thresholds, a pre-payout project would pay about 5% of gross revenue and a post-payout project would pay about 32.5% of net revenue, if that exceeds 5% of gross. The government publishes the applicable monthly rates ^[30].

Payout matters for provincial budgets. As large projects built in the 2000s and 2010s passed payout, more of the oil sands moved onto the higher net-revenue basis, which is one reason bitumen royalties now dominate Alberta's resource revenue ^[31].

What royalties bring in, and where the money goes

Alberta reports royalties as non-renewable resource revenue (NRR), which also includes land sale bonuses and rentals.

In 2024-25, conventional crude oil royalties were about $3.0 billion and natural gas and by-products royalties about $1.2 billion ^[10]; resource revenue helped produce an $8.3 billion surplus ^[36]. Then Budget 2026 assumed WTI at US$60.50 and forecast a $9.4 billion deficit for 2026-27 with NRR of $13.2 billion, about 18% of total revenue ^[34][33]. The first-quarter update released on August 27, 2026, after WTI averaged about US$93 in the first three months of the fiscal year, raised the NRR forecast by $9.7 billion, including $8.3 billion more in bitumen royalties, and projected a surplus of more than $2 billion ^[35].

The Heritage Savings Trust Fund. Alberta created the Heritage Savings Trust Fund in 1976 to save part of its resource wealth. It began with $1.5 billion ^[37]. From 1976 to 1983, 30% of non-renewable resource revenue went into the fund; this was cut to 15% in 1983 and stopped in 1987, by which point about $12 billion had been transferred ^[38]. For years afterwards most investment income was sent to general revenue rather than reinvested, so the fund grew slowly ^[38]. It was worth $31.9 billion at December 31, 2025 ^[37]. The government has set a goal of growing it to $250 billion by 2050, under the governance of the Heritage Fund Opportunities Corporation, and says investment income now stays in the fund unless Treasury Board authorizes a transfer verify ^[37].

The Alberta Energy Regulator: from 1938 to today

Alberta separates the owner role (the Ministry of Energy and Minerals, which sells rights and collects royalties) from the regulator role (the Alberta Energy Regulator, which decides whether and how development can proceed).

The regulator's lineage begins in 1938, when the province created the Petroleum and Natural Gas Conservation Board to enforce proper drilling and production practices and to stop the wasteful flaring of natural gas at Turner Valley ^[12]. Its successors included:

• 1971: the board's mandate expanded to pipelines, coal and electricity, and it became the Energy Resources Conservation Board (ERCB) ^[12].
• 1995: the ERCB merged with the Public Utilities Board to form the Alberta Energy and Utilities Board (EUB) ^[11].
• January 1, 2008: the EUB split into a revived ERCB for energy resources and the Alberta Utilities Commission for utilities ^[11].
• June 17, 2013: the Alberta Energy Regulator took over the ERCB's functions under the Responsible Energy Development Act (REDA) ^[11][39].

The 2013 change created a "single regulator." The AER took on the ERCB's work and the energy-related approvals previously handled by the environment ministry, so one body now oversees upstream oil, gas, oil sands and coal projects from application to reclamation ^[40]. Its mandate has since widened to include geothermal, mineral and carbon capture and storage activity ^[41]. The AER is funded by an administration fee levied on industry under REDA ^[42].

How it regulates. The AER issues licences for wells, pipelines and facilities, and sets detailed requirements in numbered directives. Examples include:

• Directive 056, the technical requirements for applying to build or operate wells, pipelines and facilities ^[43];
• Directive 060 on flaring, incinerating and venting at upstream wells and facilities ^[44];
• Directive 071 on emergency preparedness and response, with new editions in effect from February 2, 2026 ^[41];
• Directives 067 and 088, which govern who may hold licences and how their liabilities are managed (next section).

The AER inspects sites, responds to incidents, investigates and enforces its requirements; its public compliance dashboard reports on that work ^[45]. People who believe they may be "directly and adversely affected" by an application can file a statement of concern under section 32 of REDA and may later seek a regulatory appeal ^[46]. In May 2026 the AER amended its Rules of Practice, including requiring hearings to be discontinued if all directly affected participants withdraw, a change some environmental lawyers criticized as narrowing public participation ^[47][48].

Liability management: Directives 067 and 088

Every well, pipeline and facility eventually has to be permanently sealed (decommissioned, often still called "abandoned") and the land restored (reclaimed). Alberta's principle is that the licensee pays. The liability management framework exists to make sure licensees can actually do so.

On July 30, 2020, the provincial government announced a new framework to replace the AER's former Licensee Liability Rating system. The new approach rested on five pillars: licensee capability assessment, licensee special action, an inventory reduction program, legacy and post-closure sites, and an expanded mandate for the Orphan Well Association ^[49].

Directive 067: who may hold a licence. Directive 067 sets the eligibility requirements for acquiring and holding energy licences and approvals. The AER describes holding a licence as a privilege, not a right ^[50]. Licensees must submit financial information every year, keep a monitored regulatory contact, and notify the AER within 30 days of material changes such as defaulting on debt ^[50]. Revised editions of Directive 067 and Directive 068 (security deposits) were released on April 21, 2026, adding a definition of a "new licensee," requiring updated financial information at application and throughout the life cycle, and replacing the term "mandatory closure spend" with "licensee quota" ^[51].

Directive 088: licensee life-cycle management. Released on December 1, 2021, Directive 088 is the main instrument of the new framework ^[52][53]. It introduced:

• a holistic licensee assessment, supported by the Licensee Capability Assessment, that considers more than 40 factors including financial health, liability, operational and closure performance, and the remaining life of the resource ^[54];
• a Licensee Management Program that determines how each company is managed through the life cycle;
• an Inventory Reduction Program with mandatory closure quotas; and
• updated requirements for licence transfer applications ^[52].

Inventory reduction. Each year the AER sets an industry-wide closure spending requirement and allocates it to licensees in proportion to their share of inactive liability ^[55]. The requirement was $750 million for 2025 and remains at $750 million for 2026 ^[55][56].

Scale of the task. In its 2024 Liability Management Performance Report, the AER estimated total active and inactive liability at $36.6 billion as of December 31, 2024 ^[13]. Inactive wells numbered about 78,000, down from about 91,000 earlier in the decade, and roughly 34,000 wells had been inactive for ten years or more ^[13][57]. Critics argue that progress remains slow relative to the size of the inventory ^[57].

Inactive and orphan wells

Three terms are often confused:

• An inactive well has not produced, injected or disposed of fluids for six or twelve months, depending on its type and risk. It still has a solvent owner ^[58].
• A decommissioned (abandoned) well has been permanently sealed and taken out of service, but the site may not yet be reclaimed ^[58].
• An orphan is a well, pipeline or facility with no solvent, legally responsible party, which the AER designates to the Orphan Well Association (OWA) for closure ^[59][60].

The Orphan Well Association. The OWA is an industry-funded, non-profit organization that works closely with the AER; it was established in 2002 verify ^[61][62]. It is funded mainly by the orphan fund levy, which the AER charges licensees under section 73 of the Oil and Gas Conservation Act. The levy for 2026-27 is $154.56 million, up from $144.45 million the year before ^[63][60]. Governments have also stepped in: Alberta loaned $235 million to the OWA in 2017 ^[61], and Ottawa provided $1 billion to Alberta in 2020 for its Site Rehabilitation Program, part of which was later returned unspent verify ^[64].

The inventory. The OWA reported about 4,200 wells awaiting decommissioning at March 31, 2026. After the AER designated the sites of Long Run Exploration Ltd. to the OWA in April 2026, including 2,980 wells, the inventory reached 7,302 wells by July 2026, a record ^[65]. Its latest monthly figures, reported in September 2026, showed 7,370 wells needing decommissioning and 9,151 sites needing reclamation ^[66]. The OWA estimates the cost of dealing with its full inventory, including pipelines and facilities, at about $1.66 billion ^[65]. In 2025-26 its average cost was $28,800 to decommission a well and $27,700 to reclaim a site ^[66]. In September 2026, landowners and advocacy groups represented by Ecojustice filed for judicial review, arguing the AER has chronically underfunded the levy ^[60].

The Redwater decision (2019). The most important court ruling on this issue is Orphan Well Association v. Grant Thornton Ltd., 2019 SCC 5, released by the Supreme Court of Canada on January 31, 2019 ^[67][68]. Redwater Energy Corporation went bankrupt holding 127 oil wells plus pipelines and facilities, most of them spent and carrying cleanup costs larger than their value. Its trustee tried to keep the few valuable wells for secured creditors and disclaim the rest, arguing that federal bankruptcy law overrode the AER's orders ^[68]. The Supreme Court disagreed. It held that Alberta's regulatory regime could operate alongside the federal Bankruptcy and Insolvency Act without conflict, and that the AER's powers to impose end-of-life obligations survive bankruptcy and bind the trustee ^[69][70]. In practical terms, a bankrupt company's valuable assets must help pay to close its worthless ones before secured lenders are paid.

Landowners and surface rights

If you own land in Alberta, you almost certainly do not own the oil or gas beneath it, but you do own the surface, and anyone who needs that surface for a well, pipeline or access road must deal with you.

Surface leases. An operator normally negotiates a surface lease with the landowner (and any occupant, such as a tenant) that sets out the area used, a first-year payment and annual compensation. Under the Surface Rights Act, either party can seek a review of the annual rate at five-year intervals from the start of the lease or order ^[71].

When there is no agreement. A landowner cannot ultimately veto access by a licensed operator. If negotiations fail, the operator can apply to the Land and Property Rights Tribunal (LPRT) for a right of entry order, and the tribunal sets compensation ^[72][73]. Section 25 of the Act lists factors the tribunal may consider, including the market value of the land taken, loss of use, adverse effect on the rest of the property, nuisance, inconvenience and noise, and damage to the land ^[72]. The LPRT replaced the former Surface Rights Board and several other bodies on June 2, 2021 ^[73]. The Farmers' Advocate Office provides guidance to landowners on surface rights ^[74].

When a company stops paying. If an operator fails to pay annual rent, the landowner can apply to the LPRT under section 36 of the Surface Rights Act. The tribunal demands payment and, if the company does not comply, can terminate its right of entry and direct the Minister of Environment and Protected Areas to pay the landowner ^[75]. The province paid about $150 million in unpaid rent on companies' behalf between 2010 and 2024 and recovered only about $1.4 million ^[76]. Unpaid municipal property taxes owed by oil and gas companies were reported at nearly $254 million at the end of 2024 verify ^[77].

On August 6, 2026, following a record number of surface rights applications in 2025-26, the province announced a Surface Rights Advisory Panel of landowners, municipalities, industry and advocates to recommend improvements to the system ^[78].

Ottawa, Indigenous consultation and worker safety

Federal roles. The province owns and manages Crown resources, but Ottawa regulates infrastructure that crosses provincial or national borders. The Canada Energy Regulator (CER), established on August 28, 2019 under the Canadian Energy Regulator Act to replace the National Energy Board, oversees interprovincial and international pipelines and international power lines through their life cycle ^[79][80]. The Impact Assessment Act (2019) governs federal environmental assessment of major projects. On October 13, 2023, the Supreme Court of Canada found its "designated projects" scheme unconstitutional because it reached beyond federal jurisdiction ^[81]. The federal government proposed amendments in its 2024 budget legislation to refocus the Act on adverse effects within federal jurisdiction ^[82].

Climate policy is a live issue. In May 2025 Alberta froze its industrial carbon price under the TIER regulation at $95 per tonne ^[83]. In November 2025 Ottawa and Alberta signed a memorandum of understanding under which the federal government set aside its proposed oil and gas emissions cap and offered support for a new bitumen pipeline to the British Columbia coast, while Alberta agreed to raise its industrial carbon price to at least $130 per tonne and to tie the pipeline to the Pathways carbon capture project ^[84][85]. The two governments announced further steps on the pipeline proposal and Pathways on July 2, 2026 ^[86]. Supporters and critics disagree sharply about the agreement, and its implementation is still evolving.

Indigenous consultation. Alberta must consult First Nations and Metis Settlements when a provincial decision on land and resource management may adversely affect Treaty rights or traditional uses ^[87]. That duty is managed by the Aboriginal Consultation Office (ACO), which directs project proponents to consult affected communities and advises on whether consultation was adequate ^[88][87]. The AER itself has no jurisdiction to assess the adequacy of Crown consultation; instead, under joint operating procedures, the AER must request the ACO's advice before deciding an energy application that requires consultation ^[88][89].

Workplace safety. Worker safety at oil and gas sites falls under the Occupational Health and Safety Act, the OHS Regulation and the OHS Code ^[90]. Part 37 of the Code, now titled "Oil, Gas and Geothermal Energy," applies to exploration, drilling, extraction and well decommissioning ^[91]. Changes effective March 31, 2025 require wind direction indicators and atmospheric monitoring at oil and gas work sites where a harmful substance may be present ^[92]. Hydrogen sulphide (H2S), a toxic gas found in sour oil and gas, has an occupational exposure limit of 10 ppm over eight hours and a 15 ppm ceiling verify ^[93].

FAQ

Who owns the oil in Alberta?

Mostly the public. The provincial Crown owns about 81% of mineral rights on behalf of Albertans; the rest belongs to the federal government (parks and reserves) and to private freehold owners ^[1][2].

Do landowners in Alberta own the oil under their land?

Usually not. Mineral and surface rights are separate. Only about 8% of Alberta's mineral rights are privately (freehold) owned ^[15]. Most landowners own only the surface and are entitled to compensation for its use.

What royalty rate does Alberta charge on oil?

It depends on the resource and the price. Conventional wells under the Modernized Royalty Framework pay 5% until they reach a cost allowance (C*), then 5% to 40% depending on prices ^[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, scaled to WTI in Canadian dollars ^[9].

How much money does Alberta make from oil and gas royalties?

It varies widely. Non-renewable resource revenue was $25.2 billion in 2022-23 and $22.0 billion in 2024-25, but Budget 2026 forecast only $13.2 billion for 2026-27 before higher oil prices led to an upward revision of $9.7 billion in August 2026 ^[32][10][35].

Can I refuse to let an oil company drill on my land in Alberta?

Not ultimately. If you cannot reach a surface lease agreement, the operator can seek a right of entry order from the Land and Property Rights Tribunal, which also sets compensation ^[72][73].

Who pays to clean up orphan wells in Alberta?

Industry, mainly through the orphan fund levy that finances the Orphan Well Association: $154.56 million for 2026-27 ^[63]. Governments have supplemented this with loans and federal funding ^[61][64].

What does the Alberta Energy Regulator do?

The AER regulates oil, gas, oil sands and coal development, and more recently geothermal, mineral and carbon storage activity, from application to reclamation. It sets technical rules in directives, inspects sites and enforces compliance ^[40][41]. It does not set royalties; that is the Ministry of Energy and Minerals' job.

What was the Redwater decision?

A 2019 Supreme Court of Canada ruling that the AER's cleanup powers survive bankruptcy, so a bankrupt oil company's trustee must meet end-of-life obligations rather than distributing all value to secured creditors first ^[69][70].