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 $3.1 billion in the 2016-2017 fiscal year, accounting for 7.3% of the total Government of Alberta revenue.

  • Alberta was among the top 10 oil and gas producing jurisdictions in the world.
  • Alberta produced about 80% of Canada’s oil and 67% of Canada’s gas in 2016.
  • The mining, quarrying, and oil and gas extraction sector made up 27% of provincial GDP (Gross Domestic Product, the value of all goods and services) in 2016.

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 expenditures 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
  • water
  • power

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.

Comparing with others

Jurisdictions around the world receive value from the development of their resources. Countries, provinces and states collect value through taxes, state-ownership, production-sharing agreements or other contract terms.

Comparing the owner’s share of resource revenue is complex because resource ownership varies by jurisdiction. In Canada, provinces own most of the mineral resources. The provincial share includes revenues related to ownership such as royalties, bonuses and lease rentals in addition provincial corporate taxes.

In many countries, including Canada, the federal government shares the revenue through income taxes paid by oil and gas companies. The Government of Canada is not directly involved in the ownership of oil and gas resources in Alberta.

In the United States, private land-owners normally own mineral rights, and companies pay royalties, bonuses and rentals to private owners. In those jurisdictions, state and federal governments still collect revenue from resource development, typically through a ‘severance tax’ which is charged to produce oil and gas.

In other jurisdictions, such as Norway, mineral rights are owned by the federal government and developed by state-controlled entities. As a result government receives revenue both as the resource owner and as the developing company but also assumes the investor risk for the resource development.

Other significant differences that need to be considered in collecting value include:

  • what kind of resource is being developed
    • different geology
    • hydrocarbon types
  • 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

There are no countries from the Middle East being used for comparison purposes, other than Oman which is developing its heavy oil deposits in a similar manner to Alberta’s oil sands. They often compete indirectly with Alberta on oil and gas price, but unlike our closest neighbors the United States, and similar more open investment jurisdictions they are not really competitors for private capital investment from companies that invest in Alberta, or for companies in Alberta to invest in. Their resources are often quite different as well, and managed in very different ways – the most important being the Organization of Petroleum Exporting Countries (OPEC) and their strategies for production limitation and price maintenance.

The countries chosen for comparison purposes are ones that have historically competed with Alberta for capital investment and oil and gas activity, demonstrated through company investment in Alberta, or Alberta company investment in those jurisdictions. As well, some jurisdictions that have quite different resources and operations, but have been used as comparators in the past (e.g. Norway), have been included in as comparable a way as possible.

How revenue differs across jurisdictions

The following sections show how revenue from energy production in Alberta is shared over the entire life of a well or project. We compare revenue from Alberta’s energy production with other jurisdictions that have reasonably comparable energy resources, or, in the case of oil sands, energy resources that take large project-style investments.

The wells or projects chosen for each jurisdiction represent various “plays” which are areas that offer a combination of geology, geography and technology, or an exploration and development technique that currently attracts investment.

For example in Alberta, investment today and likely into the future is primarily in deep, long horizontal multi-stage fracture wells that access shale and other source rock.  Almost all oil and gas that was readily found through drilling cheaper vertical wells has been discovered and largely produced. Areas that were hotbeds of activity at different times, such as shallow natural gas are no longer targets of investment.

This is similar to the United States, where the “shale revolution” has changed industry dynamics, so we compare the states that compete directly with Alberta (including Texas and North Dakota).

We use a simplified approach that can provide a visual representation about how value from these resources is shared. This simple approach doesn't take into account timing, size of investment, cost of capital or other factors included in more complex measures, such as Internal Rate of Return and Profitability Index. We sometimes call this simple approach an "undiscounted" cash model, because it doesn't take into account the higher value of revenue available today (which could be invested to create a return) versus revenue in the future (which can’t be invested to create a return today so is worthless).

Share of revenue - oil

To help understand Albertans' share of oil revenues, 3 different price scenarios are considered - low case (WTI price of US $40 per barrel, or bbl), moderate case (WTI price of US $60/bbl), and high case (WTI price of US $80/bbl,/barrel).

For Alberta, both a moderate productivity well and a high productivity well are shown.  The Royalty Review Advisory Panel tested wells in several representative Alberta plays that were likely to be moderately economic (moderate productivity well) and highly economic (highly productive well). Comparisons are generally based around the moderately economic type of play. More uneconomic plays are not shown in this overview, as companies are much less likely to invest in them.

The jurisdictions with oil sectors that are most comparable to Alberta’s oil sector in terms of geology and capital competitiveness are Saskatchewan, North Dakota and Texas. However, to ensure comprehensive comparison, other select jurisdictions are also included in the comparison.

Figure 1. Split of a barrel of oil - U.S. $40/barrel WTI

  • At a $40/barrel WTI price, there is little profit in most jurisdictions, even for a highly productive Alberta well, because costs eat up most of the revenue.
  • Saskatchewan is somewhat more profitable, in part due to the wells that are competitors for Alberta being shallower long horizontal wells that have a lower drilling and operating cost than the Alberta wells.
  • Saskatchewan has a lower introductory royalty rate for new wells drilled leading to lower returns to the Crown.
  • In Texas both the resource owner and company take home a larger share of the undiscounted revenue, reflecting lower exploration and development costs in the state, combined with proximity to major North American markets.


Figure 2. Split of a barrel of oil - $60/barrel WTI

  • At a $60/barrel WTI price, costs still make up most of the barrel (81%) for a moderately economic oil well in Alberta.
  • In 2015, Alberta’s Royalty Review Advisory Panel’s report noted that Alberta is a higher-cost jurisdiction where a large part of the value in a barrel flows to service companies and the broader provincial economy. The panel recommended changes to the royalty framework, reflected in the Modernized Royalty Framework, to incent companies to lower their costs and innovate.
  • The information shown here reflects data that was available as of 2015 and, over time, under the new Modernized Royalty Framework this data will better reflect Alberta’s new royalty system. However, this should not be interpreted as a result for 2015, as the comparison is made for representative barrels reflecting the lifetime of projects.
  • At a $60/barrel WTI price, Alberta gets 16% of the value of a barrel through royalties and taxes, while 2% goes to the federal government and 2% to the company for the moderate well.
  • Companies in Saskatchewan, North Dakota and Texas continue to be more profitable than in Alberta, mostly because of lower costs in North Dakota and Texas, and a lower share of undiscounted revenue for the people of Saskatchewan.
  • In Saskatchewan, the wells that are competitors tend to have lower drilling and operating costs due to being shallower than Alberta wells.
  • Saskatchewan also has a lower introductory royalty rate for new wells drilled leading to lower returns to the Crown.

Figure 3. Split of a barrel of oil - $80/barrel WTI

  • At a $80/barrel WTI price, the split-of-the-barrel for oil looks better for both the private producer and for Alberta because costs are a smaller proportion at this higher price.
  • In Saskatchewan, the wells that are competitors tend to have lower drilling and operating costs due to being shallower than Alberta wells.
  • Saskatchewan also has a lower introductory royalty rate for new wells drilled leading to lower returns to the Crown.
  • High price scenarios improve profitability across all jurisdictions, but not proportionally when compared to lower price scenarios, because of cost inflation that goes with higher prices in all jurisdictions.

Share of revenue - natural gas

Three different Henry Hub price scenarios are considered - $2, $3, and $4 per thousand cubic feet (mcf). This is the price for dry gas. Most wells in Alberta that are potentially profitable also produce natural gas liquids such as propane, butanes and pentanes.

For Alberta, both a moderate productivity well and a high productivity well are shown. The Royalty Review Advisory Panel tested wells in several representative Alberta plays, including those likely to be moderately economic (moderate productivity well) and highly economic (highly productive well). Comparisons are based mostly on the moderately economic type of play. Plays that are generally uneconomic are not shown.

Jurisdictions with gas sectors that are most comparable to Alberta’s gas sector in terms of geology and capital competitiveness are British Columbia, Pennsylvania and Texas.

Figure 4. Split of a measure of natural gas - $2 U.S./mcf Henry Hub

  • Similar to other jurisdictions, there is not a lot of profit to share for a moderately economic natural gas well in Alberta at $2/mcf.
  • However, a highly productive natural gas well in Alberta can be profitable even at this low price, rising to the top of the pack for company share and to the highest for owners' share. We saw this in 2014 and 2015; while drilling dropped significantly some companies continued to drill, because they believed they had highly productive possibilities, particularly in areas with expected high natural gas liquids.

Figure 5. Split of a measure of natural gas - $3/mcf

  • Even at $3/mcf, a moderately economic well in Alberta remains uneconomic due to high operating costs, including high transportation costs. At $3/mcf the gas well is marginal on its own. Alberta takes 6%, while costs account up to 98%.
  • Such wells can be economic if they also produce some oil and other higher value hydrocarbon liquids.
  • British Columbia gas is more favorable. However, when it is compared to Pennsylvania, the profitability is not very attractive. In Texas most of the value goes to the private landowners who negotiate individual agreements. The state relies on a severance tax on production from the private land.
  • The highly productive natural gas well can offer a good return to a company and resource owners at $3/mcf (and liquid prices tied to oil at $60/bbl WTI price)

Figure 6. Split of a measure of natural gas - $4/mcf

  • High quality wells in Alberta are able to deliver superior splits to the company and resource owners. They continue to compete well with other jurisdictions in returns to the resource owner and company.
  • High case price scenarios improve profitability across all jurisdictions, but not proportionally compared to lower price scenarios, because of cost inflation associated with higher prices.

Share of revenue - oil sands and similar investments

Three different price scenarios are considered. As with oil scenarios, WTI prices of U.S. $40, $60, and $80 per barrel are considered. Also, because no 2 projects are alike, 4 different Alberta oil sands projects are represented - 3 different Steam Assisted Gravity Drainage (SAGD) projects of varying size, and an oil sands mine.

Oil sands are unique. However, although not strictly comparable in an apples-to-apples sense to Alberta's oil sands, offshore Norwegian oil platforms, Alaska off-shore developments and Venezuela heavy oil have some similarities. They are all large, high-cost, long-term investments that generally are project-based rather than based on individual well investments.

Figure 7. Split of a barrel – U.S. $40/barrel WTI for oil sands and other large investment projects

  • At $40/barrel WTI price a SAGD project of any size in Alberta can produce a higher share of undiscounted revenue for the company than is possible in Venezuela or Alaska.
  • However, there are minimal returns to the owner and none for the company developing an oil sands mine at lower prices.
  • Costs once again are a significant portion of the barrel for all key comparables.
  • Because of tidewater access, Venezuela can charge undiscounted global prices. However, Venezuela’s above ground political risks would offset the potentially low-cost advantage of its vast resources. Discount rates in Venezuela would need to be adjusted for risk factors related to political instability and other above ground issues.
  • Operating and capital costs in Norway take up far less of the barrel when compared to Alberta’s oil sands or its unconventional oil. Corporate share is similar.

Figure 8. Split of a barrel of oil – U.S. $60/barrel WTI

  • A 35,000 barrels-a-day SAGD oil sands project is attractive for an investor. The government’s portion (federal plus provincial) at 19% is balanced by a 14% share taken by the company.
  • Costs again are relatively high in Alberta. Only Alaska has higher costs due to its landscape and climate. At $60/barrel WTI price, Norway’s state take is 30%, which is higher than the 19% for the oil sands. Again, that is because costs generally take up a greater percentage of a barrel in Alberta compared to Norway.
  • As well, Norway has tidewater access, so it can sell oil at full global prices. By comparison, Alberta’s landlocked oils are significantly discounted.

Figure 9. Split of a barrel of oil – U.S.$80/barrel WTI

  • At $80/barrel WTI price all Alberta projects are providing revenue to both the company and the resource owner.
  • Compared to our key comparators Alberta is in the middle of the pack in return to the owners (Albertans) and returns to companies.
  • Venezuela’s government takes the most, which it can do largely as a function of low cost structure.
  • Norway also takes a high proportion as well, because of its favourable coastal access and lower sensitivity to inflationary forces.


Oil production

Alberta is one of the top 10 producers of crude oil in the world. In 2016, the province produced about 3.1 million barrels of oil and equivalent per day (bbl/d). This was 80% of Canada’s oil production and about 4% of the global production.

Figure 10. Provincial oil production

In 2016, total Alberta crude oil and equivalent production was about the same as in 2015 at about 3.1 million barrels/day (bbl/d).

Oil prices significantly declined in late 2014, and remained relatively low throughout 2015 and 2016. The oil price decline had a much more significant impact on conventional oil than on oil sands production. Conventional oil production declined by 16% from 2015 to 2016, from 530 thousand bbl/d to 444 thousand bbl/d.

Marketable oil sands production increased by about 2% from 2015 to 2016, and was about 2.4 million bbl/d in 2016.  Most of the increase in marketable oil sands production was due to the start-up of oil sands projects that were sanctioned or started construction prior to the decrease in oil prices. The production in condensate and pentanes plus also went up by 20% from 184 thousand bbl/d from 2015 to 222 thousand bbl/d in 2016.

Table 1. Crude oil production including lease condensate in 2016

Rank Country Million barrels/day % of total production
1 Russia 10.6 13.1%
2 Saudi Arabia 10.5 13.0%
3 United States 8.9 11.0%
4 Iraq 4.5 5.5%
5 Iran 4.0 4.9%
6 China 4.0 4.9%
7 United Arab Emirates 3.1 3.9%
8 Alberta 3.1 3.8%
9 Kuwait 2.9 3.6%
10 Brazil 2.5 3.1%


Natural gas production

Alberta also is one of the top 10 producers of natural gas in the world. In 2016, production increased slightly from about 10.1 billion cubic feet per day (Bcf/d) in 2015 to about 10.2 Bcf/d in 2016, a 0.4% increase despite relatively low gas prices in 2016. This was 67% of Canada’s gas production and 3% of global production.

Figure 11. Provincial natural gas production

Table 2. Top natural gas producers in 2016

Rank Country Bcf/day % of total production
1 United States 72.3 21.1%
2 Russian Federation 55.9 16.3%
3 Iran 19.5 5.7%
4 Qatar 17.5 5.1%
5 China 13.4 3.9%
6 Norway 11.3 3.3%
7 Saudi Arabia 10.6 3.1%
8 Alberta 10.2 3.0%
9 Algeria 8.8 2.6%
10 Australia 8.8 2.6%


Revenue Albertans are receiving from their resource

Total non-renewable resource revenue from oil, gas and oil sands development was $3.1 billion in 2016-17 fiscal year. This is up from $2.8 billion in the previous fiscal year, but down from $8.9 billion in 2014-15. The overall increase in non-renewable resources revenues from 2015-16 to 2016-17 was primarily driven by an increase in bitumen royalty, which went up from $1.2 billion to about $1.5 billion. However, despite the increase in 2016-17, the 2016-17 royalty revenue in Alberta, aside from the 2015-16 result, was still the lowest since the 1998-99 fiscal year. Alberta's non-renewable resource revenue was impacted by the oil price environment, as the oil prices remained relatively low in 2015 and 2016.

In the most recent 10 fiscal years, up to and including 2016-17, non-renewable resource revenues made up on average 20% of total Government of Alberta revenue.

Figure 12. Breakdown of Alberta’s non-renewable resource revenue, 2016-17

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).

In British Columbia, the largest portion of the non-renewable resource revenue is attributable to Crown Land Tenure. In 2016-17, non-renewable resource revenue made up about 2.5% of the province's total revenue. The majority of Saskatchewan’s non-renewable resource revenue in 206-17, or 57%, came from oil. In 2016-17, the share of Saskatchewan’s non-renewable resource revenue as a percentage totally government revenue was virtually the same as Alberta’s, at 7.3%.

Figure 13. Breakdown of British Columbia’s non-renewable resource revenue, 2016-17.

Chart showing non-renewable resource revenue in British Columbia.

Figure 14. Breakdown of Saskatchewan’s non-renewable resource revenue, 2016-17

Chart showing non-renewable resource revenue in Saskatchewan.

Energy sector and Alberta’s economy

In 2016, the energy sector made up more than a quarter of Alberta’s Gross Domestic Product (GDP).

Figure 15. Share of GDP

Share of GDP

*Numbers don't add up due to rounding

From 2015 to 2016, the mining, quarrying, and oil and gas extraction sector’s value declined by about 5%. The total GDP of Alberta’s economy also declined by about 4% over this time period.

Overall, from 2012 to 2016, the share of the Mining, Quarrying, and Oil and Gas Extraction sector has been fairly consistent, staying in the 27% to 28% range.

Figure 16. Oil and gas contribution to the GDP of oil and gas producing provinces

Oil and gas contribution to the gross domestic product to oil and gas producing provinces, 2015-16