Royalty definition

A royalty is the price 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 manager, the Alberta government sets conditions and royalties for development.

Each producing oil or gas well, or oil sands project, has its own royalty rate. Determined by volume produced, the resource market price and development costs.

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. Value added technology can also increase resource value.

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's sold for. When we produce more or the price rises, the more value there is 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 won't 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

The Modernized Royalty Framework (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, liquid and natural gas wells spud on or after January 1, 2017, and to non-project crude bitumen wells spud on or after January 1, 2017 (since royalties for these wells are calculated based on Crown royalty volume determined under crude oil formulas). 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, 2016 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.

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 extracted and in stream components.)
  • Gas cost allowance or freehold mineral tax.

The Royalty Guarantee Act, which came into effect on July 18, 2019, provides certainty that no major changes will be made to the current oil and gas royalty structure for a period of at least 10 years.

Oil sands royalty framework

  • Applies to oil sands Royalty Projects (mines or wells) that approved under the Oil Sands Royalty Regulation, 2009.
  • A “revenue minus cost” approach. This means a flat royalty rate of 1-9% 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- 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.

Crude oil and gas royalty framework

  • Created in 2016 the MRF applies to oil and gas wells drilled after December 31, 2016.
  • Uses a “revenue minus cost” approach and harmonizes the gross revenue royalty treatment across hydrocarbons. Crude oil and pentanes have a rate of 5-40% and methane, ethane, propane and butane have a rate of 5- 36%.

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 0-40%, pentanes were at 40%, methane and ethane were at 5-36% and propane and butane were at 30%.

Industry information

Resources

Definitions

Term

Definition

Alberta Capital Cost
Index (ACCI)

The ACCI tracks year-over-year inflationary or deflationary changes in the industry. The ACCI will initially be set to 1.00 in 2017, and allowed to “float” on an annual basis as a function of changes in industry costs. For example, if the ACCI is estimated at 0.97 for subsequent years, it will mean that capital costs are 3% lower than they were in 2017.
C* C*, also known as the Drilling and Completion Cost Allowance, represents completed well costs. It is a calculated value based on vertical depth, lateral length and the amount of proppant placed. The same C* is used regardless of hydrocarbon target, vertical depth or lateral length. C* is expressed as a dollar amount. The royalty rate is a flat 5% until the cumulative revenue generated by a well equals its C*, after that royalty rates will be based on a sliding scale based on commodity prices and well production.
TLL Total lateral length (TLL) is the combined length of all laterals in the well. TLL is calculated by using the Total Measured Depth (TMD) of the first well event, adding the length of each additional leg from the last unique kickoff point for that leg, and subtracting the deepest TVD from this amount. This can be expressed in the following formula.

TLL = TMDevent0 + [(TMDevent1 - Kickoff pointevent1) + (TMDevent2 - Kickoff pointevent2) + …] - TVDMAX

TPP Total Proppant Placed (TPP) is the total amount of proppant used to stimulate a well. A proppant is a solid material, typically sand, used to stimulate a well during its completion. It holds the fractures that have been opened (see the chart below for proppant equivalency factors).
TVD True Vertical Depth (TVD) is the vertical depth of a well. It is measured as vertical distance in a perpendicular line from the kelly bushing of a well (top) to the base of the bore of the well.
Maturity Threshold Maturity threshold recognizes that as a well matures its production level declines. After the maturity threshold, royalty rates decrease to avoid early shut-in.

The maturity threshold applies when monthly production from the well is below the equivalent of 194 cubic metres (approximately 40 barrels of oil equivalent per day). The 194 cubic meters (m3) equivalent value is the sum of all products from a well, and not individual streams. The maturity threshold in gas equivalent volumes is 345.5 thousand cubic metres (e3m3) per month (approximately 400 Mcf of gas equivalent per day). The conversion ratio between m3 liquids to e3m3 of gas is 1.7811. If cumulative production is below this point, the quantity adjustment specified in the formulas reduces the royalty rate charged to a well, down to a minimum rate of 5%.

The maturity threshold is determined at the wellhead based on the natural gas and oil equivalent volumes for the oil, condensate and raw gas.

Maturity Thresholds recognize the difference in well economics for oil and gas wells based on different prices, costs and royalty rates.  The maturity threshold is calculated at the well level; once a well reaches the maturity threshold royalty rates for all hydrocarbons are reduced.

Equivalency factors for proppant types

If a well is stimulated using a proppant type other than sand, please 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 in order to qualify for the TPPe calculation.

Type of Completion

Equivalency
Factor

Definition

Sand (tonnes) 1 Naturally occurring unconsolidated sedimentary mineral material
Coated Sand (tonnes) 1.5 Sand that is treated with a permanent coating that improves its baseline conductivity by at least 50%, compared to the baseline conductivity of the same uncoated sand, under the same stress conditions.

This conductivity enhancement must be in accordance with ISO 135503-5 or its equivalent. The department may request independent laboratory tests as evidence of eligibility.

Engineered, manufactured
proppants (tonnes)
2.5 A manufactured product
Acid (cubic metres 10 x (acid concentration)
0.75
1.5
2.8
Examples of acid completions
7.5% concentration
15% concentration
28% concentration

Contact

Connect with the technical team supporting industry for Alberta Oil and Natural Gas royalties:

Hours: 8:15 am to 4:30 pm (open Monday to Friday, closed statutory holidays)
Email: [email protected]

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