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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 owner, the Alberta government sets conditions and royalties for 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.
Value comes from:
- 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.
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 we produce more or the price rises, or both, 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 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.
- applies to crude oil, non-project crude bitumen, liquid 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 a ‘revenue minus cost’ approach and harmonizes the gross revenue royalty treatment across hydrocarbons
- Royalty rates for crude oil, condensate and pentanes ranges from 5 to 40, and methane, ethane, propane and butane have rates ranging 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 sand royalty framework
- applies to oil sands Royalty Projects (mines or wells) that 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.
- 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%.
- 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 (PDF, 209 KB) 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 (PDF, 134 KB)
- ARF Natural Gas Graphs (PDF, 103 KB)
Table 1. Definitions
|Alberta Capital Cost Index (ACCI)||The ACCI tracks year-over-year inflationary or deflationary changes in the industry. The ACCI was 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. Proppant holds the fractures open (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 (m3) – approximately 40 barrels of oil equivalent per day. The 194 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 threshold 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, 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.
Table 2. Definition of types of completions
|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.
|2.5||A manufactured product|
|Acid (m3)||10 x (acid concentration)
|Examples of acid completions:
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