About Royalties


On behalf of Albertans, the Government of Alberta is the owner of 81% of the mineral rights in the province, which includes oil and gas. When companies develop the resources, they must pay the province - that's called a royalty. As resource owner, the Alberta government sets the terms and conditions for development and the royalty rates. Albertans can access more information on the new royalty systemexternal link iconon the Alberta government’s website. This will help Albertans understand the value received from royalties for crude oil, natural gas and oil sands.

Alberta’s Modernized Royalty Framework

This framework came into effect January 1, 2017. The framework was developed based on recommendations from the Alberta Royalty Review Advisory Panel which submitted its Alberta at a Crossroadsexternal link icon report on Alberta’s royalties to government after a six-month review process. Formulas were finalized on April 21, 2016and on July 11, 2016, the government announced  two new royalty programs.

Strategic Programs under Alberta’s Modernized Royalty Framework

You can subscribe for updates to royalty content or if you have technical questions please contact
oil.gas.royalty@gov.ab.ca.  
Royalty Formulas, Charts, Tables and Curves for wells spud* up to and including December 31, 2016

          Royalty Calculators

Royalty related information bulletins

Additional Information: 

Frequently Asked Questions

What kind of wells do these new formulas apply to?

The Modernized Royalty Framework 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 Modernized Royalty Framework will not impact royalties on production from an approved Oil Sands Royalty Project, under the Oil Sands Royalty Regulation, 2009.

What is 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.

Why is there a difference in the formula when wells are deeper than 2000 metres?

Costs per meter drilled increase at greater depths. The formula was adjusted to recognize these additional costs.

How is revenue determined for the drawdown of C*? 

Revenue from a well will be tracked by multiplying production volumes of the various hydrocarbons by their respective commodity par prices, as published by Alberta Energy.

What is 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.

What is 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.

What is 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

What is 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.

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)      1Naturally occurring unconsolidated
sedimentary mineral material
 Resin Coated Sand (tonnes)     1.5

Sand that is treated with a permanent
coating that improves its physical
properties, such as for example
size/shape uniformity, stress
distribution, crush resistance,
brittleness or  resistance to thermal degradation 

Engineered, manufactured
proppants (tonnes)
     2.5 A manufactured product

 Acid (cubic metres)

Examples of acid completions

  
7.5% concentration
15% concentration
28% concentration

10 x (acid concentration)




0.75
1.5
2.8 

 

 

What is the 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.

Is the maturity threshold the same for all hydrocarbons?

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.

Has the calculation of monthly par prices changed under the Modernized Royalty Framework?

No, the calculation of the par prices has not changed under the Modernized Royalty Framework. For oil , they will continue to be based on the four density categories. For natural gas, they will continue to be based on the extracted and in stream components.

Will there be changes to the Gas Cost Allowance under the Modernized Royalty Framework?

There will be no changes to the Gas Cost Allowance due to the implementation of the Modernized Royalty Framework.

Under the Modernized Royalty Framework, are there any changes to the treatment of Freehold Mineral Rights?

The Government of Alberta’s treatment of Freehold mineral rights is unchanged by the announcement of the Modernized Royalty Framework. The Government of Alberta continues to levy a Freehold Mineral Tax.