The Modernized Royalty Framework (MRF) 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 Crossroads report on Alberta’s royalties to government after a six-month review process. Formulas were finalized on April 21, 2016.
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 will not impact:
- royalties on production from an approved Oil Sands Royalty Project, under the Oil Sands Royalty Regulation, 2009
- 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.
- Alberta modernized royalty framework Guidelines : principles and procedures
- Royalty Guarantee Act(2019) (PDF, 303 KB)
- Alberta's Modernized Royalty Framework Overview (2017)
- Technical briefing, Modernizing Alberta's Royalty Framework (2017)
- The 2017 modernized royalty framework formulas include:
- Drilling and Completion Cost Allowance (C*) for new and re-entered wells
- Crude Oil, Pentane Plus, Field Condensate and Bitumen from Non-project wells
- Natural Gas (Methane) and Ethane
- Propane (extracted and in stream components)
- Butane (extracted and in stream components)
- Royalty related information bulletins
- Revenue Forecasting Process (2015) fact sheet MRF information sessions (2016)
- C-Star visual (PDF, 205 KB) and MRF overview
- Alberta Royalty Framework Formulas (for wells spud on or after January 1, 2011 and before December 31, 2016)
- Conventional oil
- Natural gas
- Alberta Royalty Framework; Oil Graphs (PDF, 131 KB)
- Alberta Royalty Framework; Natural Gas Graphs (PDF, 103 KB)
- Oil and Gas royalty calculators
- Royalty Framework Calculator for wells spud on or after January 1, 2017 (effective January 2017 for wells spud on or after January 1, 2017 or those approved to opt-in early to the Modernized Royalty Framework (MRF), also known as C*)
- A Post C* calculator is also available
- Royalty Framework calculator for 2011 for wells up to and including December 31, 2016 (effective January 2011 for wells spud up to an including December 31, 2016 for the Adjusted Alberta Royalty Framework (ARF))
- Old Oil Royalty calculators (note dates)
Alberta Capital Cost
|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
|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.
|2.5||A manufactured product|
|Acid (cubic metres||10 x (acid concentration)
|Examples of acid completions
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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