Royalty overview

Royalty definition

A royalty is the share the resource owner charges developers.

Albertans own 81% of the province’s mineral rights and the Alberta government manages those resources on their behalf. The remaining 19% is owned by the federal government, individuals and corporations.

As the resource owner, the Alberta government sets conditions and royalties for resource development.

Each producing oil or gas well, or oil sands project, has its own royalty rate which is determined by production volume and the resource market price.

Resource value

Value comes from:

• royalties
• land sale bonuses (payments to government for the right to develop the resource)
• jobs and economic activity generated by the sector
• taxes paid by companies and people working in the sector

The value of Alberta’s oil and gas resources is shared between Albertans, as owners, and the companies developing these resources.

Production costs

Extracting Alberta’s oil and gas resources and transporting them to market is expensive. These costs affect the value we share with resource companies.

Factors influencing revenue

Revenue from selling our energy depends on how much is produced and the price it is sold for. When more is produced or the price rises, or both, there is more value to share.

Factors influencing costs

The cost to produce and transport our resources also affects our share of the value. The higher the cost, the less value is available. Costs are influenced by:

• upfront and capital investments (explorations, engineering, processing and transportation)
• operating costs (power, heat, labour, reporting and maintenance)
• regulatory compliance costs (taxes, carbon levies, reporting, reclamation, remediation, surface access and other fees which would include bonuses paid to acquire development rights from the province)

The cost to develop resources can differ greatly between and within jurisdictions, depending on local conditions at the time. If investors cannot recover their costs and make a return on their investment, they will not invest, and the resource will not generate jobs or economic value. All current royalty frameworks encourage industry to innovate and reduce capital and operating costs, which will increase value no matter what oil prices are.

Alberta’s royalty framework

Modernized Royalty Framework (MRF)

The MRF came into effect January 1, 2017. MRF was developed based on recommendations from the Alberta Royalty Review Advisory Panel which submitted its Alberta at a Crossroads report on Alberta’s royalties to government after a six-month review process.

The MRF:

• applies to crude oil, non-project crude bitumen, natural gas liquids and natural gas wells spud on or after January 1, 2017
  • Wells spud before July 13, 2016, will continue to operate under the previous royalty framework until December 31, 2026.
  • Wells spud during the early election period (July 13 to December 31, 2016) that did not elect to opt in early to the MRF or did not meet the criteria will continue to operate under the previous royalty framework until December 31, 2026.
• uses an ‘emulated revenue minus cost’ approach and harmonizes the gross revenue royalty treatment across hydrocarbons
  • Royalty rates for crude oil, condensate and pentanes range from 5 to 40%.
  • Royalty rates for methane, ethane, propane and butane range from 5 to 36%.

The MRF did not impact:

• the calculation of par prices – Oil will continue to be based on the 4 density categories and natural gas will continue to be based on the liquids extracted and in stream components.
• gas cost allowance or freehold mineral tax

Oil sands royalty framework

The framework:

• applies to oil sands Royalty Projects (mines or wells) that are approved under the Oil Sands Royalty Regulation, 2009
• uses a 'revenue minus cost' approach – This means a flat royalty rate of 1 to 9% of gross revenue will apply until a mine or well’s allowable costs have been covered (pre-payout). After the costs are covered (post-payout) the royalty rate is the greater of 25 to 40% net revenue, and pre-payout rate.

Royalties depend on if the project is in a pre-payout phase or post-payout phase (after initial costs are recovered). Royalties increase in the post-payout phase.

Royalty guarantee

The Royalty Guarantee Act came into effect on July 18, 2019, and amends the Mines and Minerals Act. It guarantees that for a period of at least 10 years:

• no major changes to the oil and gas royalty structure will occur
• when a well starts producing, it will be under the same royalty structure for that same period of time
• the current royalty structure, rules and processes remain in place to provide flexibility for government and industry to adjust to market changes and technology advancements, including the ability to:
  • make regular required adjustments, such as setting monthly par prices
  • provide incentives, when appropriate

Alberta royalty framework

• Created in 2007 and applies to oil and gas wells drilled before December 31, 2016.
• Wells drilled before this date are grandfathered to the end of 2026, at which point they move to the MRF.
• The gross revenue royalty treatment had a crude oil royalty rate of 0 to 40%, pentanes were at 40%, methane and ethane were at 5 to 36% and propane and butane were at 30%.

Industry information

Resources

• MRF Guidelines : principles and procedures
• MRF Overview
• MRF technical briefing
• MRF formulas
• Royalty related oil information bulletins
• Revenue Forecasting Process fact sheet and MRF information sessions
• C-Star visual and MRF presentation
• Alberta Royalty Framework (ARF) Formulas for wells spud on or after January 1, 2011 and before December 31, 2016 – Conventional oil, natural gas
• ARF Oil Graphs
• ARF Natural Gas Graphs

Equivalency factors for proppant types

If a well is stimulated using a proppant type other than sand, use the equivalency factors below in the chart to determine the tonnage. All carrier fluids and additives are not considered in calculating the TPPe (Total Proppant Place Equivalent) with the exception of when an acid only fracture occurs. In this case, acid as the carrier fluid cannot be used in combination with any other proppant types to qualify for the TPPe calculation. All acid fractures require approval by Alberta Energy and Minerals in order to qualify for the TPPe calculation.

Table 1. Definition of types of completions

Contact

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