How the royalty system optimizes returns for Albertans
The royalty framework helps Albertans benefit from the development of Alberta’s energy resources.
The Alberta government believes that management of Alberta's energy resources must result in the best possible returns to Albertans. Those returns include the revenue paid to government to support important public services, job opportunities for Albertans and managing the environmental and social impact of resource development—in other words, optimizing the value.
Alberta’s royalty framework encourages new processes and technologies to make development more efficient. Innovation and efficiency help reduce the costs of producing and selling Alberta’s oil and gas, and enhances the royalties.
Albertans can know they are receiving the best returns by understanding, among other things:
- the revenue from each barrel of oil and gas, in general, and for different types of wells and projects
- the total amount collected from non-renewable resources
- Alberta’s oil and gas production
- oil and gas sector contributions to Alberta’s economy
At a glance
Alberta’s royalty systems are sensitive to economic factors to maintain activity and production when prices are low, and obtain a larger share of revenues when prices are high.
Total revenue to the government from oil and gas development including royalties, rentals and fees, and mineral rights sales was $5 billion in the 2017-2018 fiscal year, accounting for almost 11% of the total Government of Alberta revenue. In the calendar year 2017, Alberta’s energy industry performance was as follows:
- Alberta was among the top 10 oil and gas producing jurisdictions in the world.
- Alberta produced about 80% of Canada’s oil and 68% of Canada’s gas in 2017.
- Energy sector made up 24% of provincial GDP (Gross Domestic Product, nominal percentage share) in 2017.
Getting a share of Alberta’s energy resources
For a simple approach to show what share Albertans are getting from energy resources, we can look at how the revenue of a barrel of oil, or some measure of natural gas, is shared between costs, the company developing the resource and the owners of the resource – in our case Albertans.
This includes both operating and capital costs.
Operating costs are the expenditures needed to maintain project operations. This includes:
- paying workers who operate the facilities
- maintaining roads and pipelines
- buying supplies and equipment
- other day-to-day operating costs
- municipal taxes
It can also include costs of cleaning or processing the oil or gas.
Capital costs refer to initial project investments such as:
- Buying new equipment and the costs of drilling wells
- building roads, pipelines, tanks and other necessary facilities
This may not reflect all company costs, such as overhead, or some investments in general infrastructure, so it doesn’t match company profitability overall. It is more of an indicator of whether a new well or project would be worth investing in, and the value to Albertans if the investment is made.
- what markets and prices are available
- market access
- transportation costs to market
- commodity price and volatility
- other economic factors
- other royalty systems, local taxes
- political risk and stability (some countries are less risky for investors than others)
- infrastructure – how well developed are roads, rail, pipelines, etc.
- scale of the project
- whether the project’s capital costs are in the thousands, millions or billions of dollars
Alberta is one of the top 10 producers of crude oil in the world. In 2017, the province produced about 3.4 million barrels of oil and equivalent per day (bbl/d). This was 80% of Canada’s oil production and 4% of the global production.
In 2017, total Alberta crude oil and equivalent production reached the record high 3.4 million barrels per day (bbl/d), a 10% increase compared to 3.1 million bbl/d in 2016.
The increase in marketable oil sands production in 2017 was driven both by the increase in non-upgraded bitumen and SCO. Despite a significant outage at Syncrude's upgrader, SCO production reached a major milestone in 2017, exceeding 1 million bbl/d for the first time. SCO production increased in 2017, as projects recovered from the Fort McMurray wildfires and Phase 3 started operations at CNRL’s Horizon upgrader. Non-upgraded bitumen production also registered an increase from 1.5 million bbl/d in 2016 to more than 1.6 million bbl/d in 2017, with major projects completing construction and higher growth in production from steam-assisted gravity drainage (SAGD) projects. The growth in production of non-upgraded bitumen is expected to continue to outpace that of upgraded bitumen mainly because two mines, the most recently completed Fort Hills and Kearl, do not have upgrading capabilities.
Table 1. Crude oil production including lease condensate in 2017
|Rank||Country||Million barrels/day||% of total production|
|8||United Arab Emirates||3.04||3.8%|
Natural gas production
Alberta also is one of the top 10 producers of natural gas in the world. In 2017, production increased from about 10.2 billion cubic feet per day (Bcf/d) in 2016 to about 10.7 Bcf/d in 2017, almost 5% increase despite relatively low gas prices in 2017. This was 68% of Canada’s gas production and 3% of global production.
The growth in Alberta’s gas production comes mainly from Petroleum Services Association of Canada (PSAC) areas AB2 (Foothills Front) and AB7 (Northwestern Alberta), in the most active parts of Montney and Duvernay plays (there is a significant overlap between AB2 and AB7 and Montney play, and AB7 and Duvernay play). These plays are experiencing higher drilling activity, driven by the presence of wet gas, which makes wells in these areas more economical due to the value of the natural gas liquids, and the higher initial productivity associated with horizontal drilling and hydraulic multistage fracturing. According to the Alberta Energy Regulator, consistent with the trend over the past few years, production from the wetter formations in PSAC area AB2 is forecast to account for most of the natural gas production in the near future, driven mainly by the demand for natural gas from power generation with the retirement of coal power plants beginning at the end of 2019.
Table 2. Top natural gas producers in 2017
|Rank||Country||Bcf/day||% of total production|
Revenue Albertans are receiving from their resource
Total non-renewable resource revenue from oil, gas and oil sands development was $5 billion in 2017-18 fiscal year. This is up from $3.1 billion in the previous fiscal year, $2.8 billion in 2015-16. The overall increase in non-renewable resources revenues from 2016-17 to 2017-18 was primarily driven by an increase in bitumen royalty, which went up from $21.5 billion to about $2.6 billion. Alberta's non-renewable resource revenue was impacted by the oil price environment, as the oil prices remained relatively low.
In the most recent 10 fiscal years, up to and including 2016-17, non-renewable resource revenues made up on average 18.5% of total Government of Alberta revenue.
Figure 12. Breakdown of Alberta’s non-renewable resource revenue, 2017-18
Comparing Alberta to other provinces that have oil and gas development demonstrates how revenue sources vary amongst different jurisdictions (based on comparable-financial statement items).
The majority of Saskatchewan’s non-renewable resource revenue in 2017-18, about $650 million or 57%, came from oil. In 2017-18, the share of Saskatchewan’s non-renewable resource revenue as a percentage totally government revenue was slightly lower than Alberta’s, at 8%.
The fiscal year 2017-18 information is not yet available for British Columbia. However, in 2016-17, non-renewable resource revenue of $1.3 billion made up about 2.5% of the province's total revenue with Crown Land Tenure accounting for almost half.
Figure 13. Breakdown of British Columbia’s non-renewable resource revenue, 2016-17.
Figure 14. Breakdown of Saskatchewan’s non-renewable resource revenue, 2017-18
Energy sector and Alberta’s economy
In 2017, the energy sector made up almost a quarter of Alberta’s Gross Domestic Product (GDP), when nominal percentage shares are considered. This is an increase from 20% in 2016.
Figure 15. Share of GDP
Figure 16. Energy Sector shares of GDP in oil and gas producing provinces