Notice: On 2 December 2020, a note for additional clarity was added to Figures ES.8 and R.12 in this report.

Results

This section presents results of the EF2020 projections. The primary focus is the Evolving Scenario. These projections are not a prediction, but instead present possible future outcomes based on the assumptions described in the previous section. There are many factors and uncertainties that will influence future trends. Key uncertainties are included for each section.

For a description of the various ways to access the data supporting this discussion, see the Access and Explore Energy Futures Data section.

Macroeconomics

The economy is a key driver of the energy system. Economic growth, industrial output, inflation, exchange rates, and population growth all influence energy supply and demand trends.

In the near term, we assume that the impacts of COVID-19 are strongest in 2020, with gradual recovery beginning in 2021. As shown in Figure R.1, total GDP declines 6.0% in 2020,12 grows by 4.4% in 2021, and recovers to pre-pandemic levels in 2022.

The long-term projections for key economic variables are in Table R.1. Real economic growth averages 1.4% per year over the projection period in the Evolving Scenario. Economic growth over the projection is generally slower than the 1990-2018 historical period for a variety of reasons, including an aging population and slower global economic growth.

Key Uncertainties: Macroeconomics

COVID-19 pandemic recovery: Recovery from COVID-19 is a key uncertainty for global, North American, and Canadian macroeconomic growth.
International demand for Canadian goods: International demand for Canadian goods impacts export-oriented industries. Faster or slower economic growth in the U.S., Canada’s largest trading partner, would affect Canada’s economic growth and energy demand projections.
Global economic growth: Global economic growth affects many factors that are important for Canada’s economy, including commodity prices, and demand for Canadian energy and non-energy exports.
Large infrastructure projects: Projects in the mining, oil, natural gas, and electricity sectors affect the macroeconomic projections in a number of provinces. The pace of these developments is uncertain and could lead to higher or lower economic growth, and impact energy trends.

Table R.1: Economic Indicators, History, Evolving and Reference Scenarios

Average annual % growth unless otherwise noted.

Economic Indicators	1990-2018	Evolving Scenario (2019-2050)	Reference Scenario (2019-2050)
Real Gross Domestic Product	2.7%	1.41%	1.56%
Population	1.0%	0.8%	0.8%
Inflation	1.7%	1.9%	2.0%
Exchange Rate ($C/US$), average	$0.81	$0.77	0.79
Residential Floor space	2.1%	1.5%	1.5%
Commercial Floor space	1.8%	1.6%	1.7%

Energy Demand

This section focuses on end-use, or secondary energy demand, when looking at energy use by sector of the economy. It focuses on primary energy demand when looking at economy-wide energy use. End-use demand includes electricity, while the fuel used in generating electricity is accounted for in primary demand. Historical data is sourced primarily from Statistics Canada’s Report on Energy Supply and Demand in Canada. That data is supplemented with additional details from ECCC, Natural Resources Canada, and various provincial data sources.

In the near term, energy use follows macroeconomic trends and declines 5.6% in 2020, and then recovers in the next two years. Following the recovery, the Evolving Scenario projects Canadian energy use to decline until 2050. Figures R.2 and R.3 break energy use down by sector, showing declines in all sectors. The largest declines are in the industrial (including upstream oil and gas) and transportation sectors. These declines are due to factors such as improved energy efficiency, gradual electrification of the transportation sector,13 and various policies like carbon pricing. Economic growth and near-term increases in crude oil and natural gas production (discussed later in this section) provide some upward pressure on energy use. However, economic growth is slower than historical trends, and crude oil and natural gas production eventually declines. In the Reference Scenario, lack of additional climate policy action beyond current policies, higher crude oil and natural gas production, and less electrification leads to moderate demand growth in the projection, although at levels lower than recent history.

Energy use trends vary by sector, and within the sectors they vary by energy type. See Figure R.4. These trends result from several drivers, including macroeconomics, energy production trends, energy efficiency improvements, policies, technology advancements, and market developments. The transportation sector undergoes a notable shift. RPPs such as gasoline, diesel, and jet fuel have historically dominated the transportation sector, and this begins to change in the Evolving Scenario. Improved fuel economy, as well as electrification, cause transportation energy use to decline over the projection. For passenger transportation, electric vehicles grow gradually from a small share of personal vehicles to an important part of the transportation mix. Driven by falling costs, as well as steadily increasing policy support, ZEVs, including battery electric and plug-in hybrid electric, represent one out of every two passenger vehicles purchased by 2050. Electric freight, particularly light-to-mid-duty, and hydrogen-powered freight (mid-to-heavy duty), and increasingly electrified public transportation (electric bussing) grow steadily in the 2030s and 2040s.

Figure R2 End-use Demand Declines in All Sectors in the Evolving Scenario

Key Trends: Energy Demand

Energy use declines in the Evolving Scenario, and grows slowly in the Reference Scenario.
Historical growth rates are higher than both scenarios.
The mix of energy sources that Canadians use continues to change. Use of natural gas and renewables increases; coal and RPP use declines.
Energy use grows slower than population and GDP, implying a decline in energy use per person and per dollar of economic activity.

Figure R3 End-Use Energy Consumption Peaks in 2019 and Declines over the Long Term in the Evolving Scenario

In this analysis, primary demand is the total amount of energy used in Canada. Primary demand is calculated by adding the energy used to generate electricity to total end-use demand, and then subtracting the end-use demand for electricity.

Figure R.5 illustrates the projection of primary demand by fuel for the Evolving Scenario, compared with total primary demand in the Reference Scenario. In the Evolving Scenario, total demand gradually falls, driven by declining fossil fuel use. Coal demand declines considerably due to declining coal-fired power generation. Oil demand falls along with improving energy efficiency and electrification of the transportation sector. Demand for non-energy oil products, such as asphalt, lubricants, and feedstocks are relatively stable, which supports overall demand of oil products. Natural gas demand sees significant growth in the near term, driven by increasing crude oil and natural gas production (both large users of natural gas) as well as its increasing role in power generation.

Driven by increased electrification at the end-use level, overall electricity demand rises steadily in the Evolving Scenario. This leads to stable demand for nuclear power and growth in renewable power as major hydro projects are completed, and wind and solar costs continue to fall. Renewables become an increasingly important part of the energy mix. Increased blending of renewable fuels in liquid fuels and natural gas also support increasing renewable demand.

Energy use grows much slower than both the economy and Canada’s population, implying energy intensity–measured in energy use per capita or per $ of real GDP–declines. This is summarized in Figure R.6. From 2019 to 2050, real GDP increases over 60% and population increases over 30% in the Evolving Scenario. Primary energy use declines 18%. These different trends imply that energy use per $ of real GDP declines nearly 50% from 2019 to 2050, while energy use per person declines nearly 37%.

Figure R4 End-Use Energy Demand Trends Vary by Sector and By Fuel

Figure R5 Primary Demand Gradually Declines and Renewables Account For a Larger Share in the Evolving Scenario

Figure R6 The Economy Grows Faster than Energy Use, and Energy Intensity Declines in the Evolving Scenario

Key Uncertainties: Energy Demand

Technological influences: The impacts of technology on the energy system can be substantial and difficult to predict. The Evolving Scenario continues the momentum for increased use of established technologies, and allows for the adoption of new technologies. The pace and type of new technological adoption may differ significantly from those assumed in the Evolving Scenario.
Oil and natural gas industry transformations: In the past decade, the oil and natural gas industry has undergone rapid transformations in both the types of resources extracted and the technologies used to extract them. Depending on the future development of these resources and technologies, the energy used in this sector may be higher or lower than this projection.
Alternative fuels and new end-uses: The Evolving Scenario shows a shift towards electricity, supported by increasing use of renewables. It also features moderate adoption of hydrogen and renewable natural gas. Faster electrification of the economy, or growth in alternative fuels, could lead to different trends compared to those shown here.

Crude Oil

Crude oil is produced in Canada for domestic refining as well as for exports. In 2019, Canadian crude oil production averaged 4.9 million barrels per day (MMb/d) (784 thousand cubic metres per day (10³m³/d)). Recent growth has been dominated by new oil sands facilities coming online. Production is mostly in Alberta, with additional volumes in Saskatchewan and offshore Newfoundland and Labrador.14

Figure R.7 shows the outlook for Canadian crude oil production by type in the Evolving Scenario, compared to total Reference Scenario production. Canadian crude oil production in the Evolving Scenario peaks at 5.8 MMb/d in 2039 and declines to 5.3 MMb/d (836 10³m³/d) in 2050, an increase of 7% from 2019. For comparison, production peaks at 7.2 MMb/d (1 137 10³m³/d) in 2045 in the Reference Scenario, driven by higher crude oil price assumptions and a lack of future domestic and global climate policy action.

Key Trends: Crude Oil

Production grows through much of the projection period, peaking in 2039 at just over 5.8 MMb/d. Assumptions of increased takeaway capacity from western Canada and prices underpin this growth. Longer term, lower assumed crude oil prices lead to declines in production.
From 2019 to 2040, crude oil production increases 20%. Between 2040 and 2050 production decreases by 8%.
In situ bitumen production grows 37% over the projection period.
Mined bitumen production peaks in 2026 at 1.7 MMb/d, declining thereafter to 1.5 MMb/d by 2050.

Figure R7 Total Crude Oil Production Peaks in 2039 and then Declines through 2050 in the Evolving Scenario

Production growth in the oil sands continues in the near term, led by new phases of existing in situ projects. It peaks in 2039 and declines slightly through 2050 in the Evolving Scenario, as shown in Figure R.8. These additions are profitable given Evolving Scenario price levels and technology improvements that increase productivity.

Conventional, tight, and shale production is classified as light or heavy, depending on the API gravity of the oil. In 2019, 49% of western Canadian conventional production was heavy, 51% was light. Near-term production in these categories is stable primarily due to increases in tight light oil production in Alberta along with growing heavy oil production in Saskatchewan. Tight oil growth is based on producers’ preference to target wells which have higher initial production rates and a quicker return on investment. Growth in Saskatchewan’s heavy oil production is due to the low cost and low decline rates of heavy oil reservoirs in that province. See Figure R.9.

Currently, the majority of condensate production comes from Alberta. Growth in condensate production in the projection period occurs in Alberta and B.C., as producers focus on liquids-rich natural gas plays like the Montney Formation and the Duvernay. See Figure R.10. Condensate is used in a number of industrial processes, most notably as a diluent for bitumen and heavy oil.

Newfoundland offshore production in the Evolving Scenario gradually declines as shown in Figure R.11. We assume no new discoveries in the Evolving Scenario. Additional discoveries and developments could change these trends.

Figure R8 Oil Sands Production Growth Peaks in 2039 and then Declines Slightly throughout the Projection Period in the Evolving Scenario

Figure 9 Conventional Oil Production Decreases Steadily over the Projection in the Evolving Scenario after a Brief COVID-19 Recovery Increase in 2021

Figure R10 Condensate Production Driven by Increasing Diluent Demand in the Evolving Scenario

Figure R11 Newfoundland Offshore Oil Production Increases in the Near Term and then Steadily Declines to 2050 in the Evolving Scenario

A recent trend in Canadian oil markets15 has been production growth in the WCSB outpacing increases in pipeline capacity. Figure R.12 provides a detailed look at available supply from the WCSB and takeaway capacity in the Evolving Scenario. The available capacity of a pipeline is the volume of crude oil it can safely transport while considering the type of crude being transported, planned and unplanned outages, downstream constraints and pressure restrictions, among other factors.16

Crude-by-rail volumes are included as companies may choose to export crude oil by rail due to a number of reasons. These include existing contractual commitments, ownership of the required infrastructure, and arrangements with specific refineries.

Figure R12 Crude Oil Pipeline Capacity vs. Total Supply Available for Export in the Evolving and Reference Scenarios

The assumed capacities and in-service dates of additions to existing systems are as announced by the operators of those pipelines. Likewise, the capacity and timing of the three pipelines included in Table R.2 are as per the announcements of the operators.

Table R.2: Announced Crude Oil Capacity Additions

	Enbridge Line 3	Keystone XL	Trans Mountain Expansion
Announced in-service date	2019	2023	2022
Expected date at full capacity	2021	2023	2023
Full Capacity (Mb/d)	370	830	540

Dive Into Crude Oil Production

Data and analysis on crude oil production and other commodities is available by region, type, and scenario. Visit our visualization tool, Exploring Canada’s Energy Future. A dedicated summary of oil production is also available in our Fact Sheets: Oil Sands Production, and Conventional, Tight, and Shale Oil Production.

New Technology in Oil Sands Production

In the Evolving Scenario, we assume that technological improvement in extraction and upgrading methods of existing projects continues on the same pace as recent history. This improvement leads to significantly improved per-barrel emissions.

Much of the growth in oil sands production is in the form of expansions to existing facilities. By the end of the projection, facility expansions make up 15% of all oil sands production, or just over 600 Mb/d. Growth also comes from new facilities. No new oil sands mining or upgrading facilities come online over the projection period. However, new in situ facilities make up 8% or 340 Mb/d of total oil sands production from 2019 to 2050. We assume new or expanded facilities, which begin production after 2025, use the following technologies1 to lower their emissions intensity:

Steam and pure solvents: The injection of heated solvents (typically a mixture of natural gas liquids (NGLs)) into the reservoir to replace the steam generation units currently in use, lowering emissions. This process also leaves some of the less desirable components within bitumen (asphaltenes) in the reservoir.

In-pit extraction: A technique, currently being developed by Canadian Natural Resources Limited at its Horizon Oil Sands mine, which involves separating oil sands ore into its component parts within the extraction pit of the operation. This method requires comparatively less heavy equipment and electric power, resulting in less emissions per barrel.

Each of these processes also has the potential to reduce the per barrel cost to produce bitumen, helping to offset the higher environmental compliance costs and lower commodity prices assumed in this scenario. Pure solvents have the potential to reduce per barrel costs by up to $3.40, while in-pit extraction could lower costs by $2.00 per barrel.

Each of the processes described above has the potential to increase the productivity of projects compared to conventional in situ projects. The estimates vary, with some showing no significant productivity uplift and others, like MEG Energy’s eMVAPEX, showing an uplift of up to 76%. For the purposes of our projections, we have chosen to not model a production uplift associated with the technologies.

1 There are many potential technologies to reduce the emissions intensity of oil sands production. See the “Towards Net-Zero” section on oil sands production for further details.

Key Uncertainties: Crude Oil Production

Future crude oil demand: COVID-19 continues to add uncertainty to both short and long-term projections. The extent to which global economies return to energy consumption levels more typical of the previous five year average, and the timing of that return, is a major uncertainty for future crude oil demand. Future global climate action and its impact on global crude oil demand and prices is another important uncertainty.
Technological development in the oil sands: The need to reduce GHG emissions and costs are two significant factors in the future development of oil sands facilities. Technologies are currently being developed to address both of these factors although their potential adoption is uncertain. As in previous editions of Energy Futures, EF2020 assumes that companies continue to work towards lowering both the cost, and GHG emissions, of their operations.
Western Canadian takeaway capacity: EF2020 assumes that over the projection period additional takeaway capacity is available to transport increasing production. This additional capacity is in the form of new pipeline infrastructure. In addition, technological advances that either increase the amount of oil that can flow on existing infrastructure, or decrease the amount of diluent required to transport bitumen, could play a larger role in the future.
ESG considerations: The investment community is shifting its attention towards firms that align with their values on ESG performance criteria.17 Organizations that embed ESG frameworks into their fundamental values can strengthen their resilience to economic and environmental pressures.18 The extent and nature to which ESG considerations alter future upstream investment trends could affect future production trends.

Natural Gas

In Canada, natural gas is produced for domestic use and exports. In 2019, Canadian marketable natural gas production averaged 15.7 Bcf/d or 445 million cubic metres per day (10⁶m³/d).

Natural gas production in Alberta has been relatively flat over the last few years, while B.C. production has been steadily increasing since 2010. This increase has been driven by a variety of factors including:

Drilling to evaluate natural gas resources expected to supply LNG exports off of Canada’s west coast.
NGLs in the Montney tight gas play driving drilling and production despite lower natural gas prices.

In the Evolving Scenario, natural gas production from new wells is just enough to keep pace with the declining production from existing wells in the near term. As a result, total production is level until 2025. In the longer term, rising prices and the onset of LNG exports support higher capital expenditure and production growth. This leads to more natural gas wells and production in the WCSB, with total Canadian production peaking in 2040 at 18.4 Bcf/d (521.4 10⁶m³/d). After 2040, we assume no new additional LNG exports, and prices are too low to support adequate drilling to keep up with existing well declines. This results in production continuously decreasing to 16.8 Bcf/d (474.4 10⁶m³/d) by 2050, as shown in Figure R.13. Without additional production to feed LNG exports, production would continuously decline over the projection period to 13.0 Bcf/d (369 10⁶m³/d) in 2050.

In the Reference Scenario, higher gas prices and higher LNG export assumptions lead to continued increasing natural gas production in the longer term, reaching 23.5 Bcf/d (665.0 10⁶m³/d) by 2045 and then levelling off. Reference Scenario projections are driven by higher prices, a lack of future domestic and global climate action, and higher assumed LNG exports.

Figure R13 Total Natural Gas Production Peaks in 2040 in the Evolving Scenario and Increases in the Long Term in the Reference Scenario

Figure R.14 shows production of natural gas by type in the Evolving Scenario. Production growth is led by tight natural gas produced from the Montney Formation, both in Alberta and B.C. Tight natural gas production from the Montney Formation has grown significantly over the past five years. Alberta Deep Basin tight natural gas production declines moderately. There is some small growth in shale gas from the Duvernay and Horn River shales, and solution gas declines slightly. Conventional gas and coal bed methane production declines significantly over the projection period.

Natural gas exports have increased over the last several years, mostly to the western U.S. Imports of natural gas have been relatively steady over the last decade, ranging from 2-3 Bcf/d (56-85 10⁶m³/d). Imports could potentially rise as pipeline capacity increases from the Appalachian Basin in northeastern U.S. to Dawn, Ontario.

Projected net pipeline exports, which is calculated as Canadian natural gas production less Canadian demand,19 is shown in Figure R.15 for the Evolving Scenario. It also shows Canadian demand, production and assumed LNG exports. In the early 2020’s, increasing Canadian natural gas demand and stable production lead to shrinking net exports.20 As domestic demand declines and production ramps up after 2025, net exports start to increase. LNG exports make up the majority of net export increases. The remaining net exports are pipeline exports to the U.S., some of which could also end up as additional LNG exports from U.S. terminals.

Figure R14 Natural Gas Production by Type Remains Steady, while the Montney Formation Continues to Increase, in the Evolving Scenario

Key Trends: Natural Gas

Natural gas production levels off in the near term due to modest prices.
Assumptions on LNG export projects, infrastructure developments, and long-term prices are the drivers for production increasing to 2040, and then declining.
The majority of the production growth comes from Montney Formation in the form of tight gas.

Figure R15 Natural Gas Supply and Demand Balance sees the Increasing Importance of LNG Exports as Domestic Demand Declines in the Long Term in the Evolving Scenario

Key Uncertainties: Natural Gas Production

Future natural gas prices: Prices could be higher or lower, which would lead to different production results under both EF2020 scenarios.
Canadian natural gas price discounts: This analysis assumes that over the long term, all energy production will find markets and infrastructure will be built as needed. Several capacity expansions are planned in the WCSB to debottleneck pipelines and increase exports. Increased differentials for Canadian natural gas relative to Henry Hub could reduce gas production in the longer term.
LNG exports: It is possible that global market conditions and the costs of constructing a new LNG export capacity may change in the future, influencing future volumes of LNG exports from Canada in both EF2020 scenarios.
ESG considerations: The investment community is shifting its attention towards firms that align with their values on ESG performance criteria.21 Organizations that embed ESG frameworks into their fundamental values can strengthen their resilience to economic and environmental pressures.22 The extent and nature to which ESG considerations alter future upstream investment trends could affect future production trends.

Natural Gas Liquids

NGLs are produced along with natural gas. Natural gas production is the main source of NGL production in Canada. Demand for certain NGLs adds value to natural gas production and has been a driver of its increase. Raw natural gas at a wellhead is comprised primarily of methane, but often contains NGLs ethane, propane, butanes, condensate and other pentanes. In 2019, 1 193 Mb/d (190 10³m³/d) of NGLs were produced in Canada.

Figure R.16 shows that NGL production grows 40% over the projection period in the Evolving Scenario. Growth is dominated by condensate, which doubles to 2050. Condensate demand has, and will continue to, influence natural gas drilling to focus on NGL-rich plays. Condensate, along with butanes, are added to bitumen as a diluent to enable it to flow in pipelines and be loaded on to rail cars.

Propane and butanes production follows natural gas production, and increases over the projection period in the Evolving Scenario. Demand for these NGLs increases in the medium term as petrochemical use in Alberta and propane and butanes exports rise.

Additional Detail on Crude Oil, Natural Gas, and NGL Projections

For additional data on crude, oil natural and NGL production, see the EF2020 Data Appendices. These datasets includege additional geographical and monthly detail on production and drilling trends.

Further information about these and other EF2020 datasets can be found in the "Access and Explore Energy Futures Data" Section.

The majority of ethane is extracted at large natural gas processing facilities located on major natural gas pipelines in Alberta and B.C. In 2019, ethane made up 19% of NGL production. Ethane production increases slowly over the Evolving Scenario projection to 2050, as its recovery from the natural gas stream is essentially constrained by the capacity of the petrochemical facilities in Alberta. Ethane produced in excess of this capacity is reinjected back into the natural gas pipeline system to be consumed by end users as natural gas.

Figure R16 Condensate Leads Natural Gas Liquids Production Growth in the Evolving Scenario

Key Uncertainties: Natural Gas Liquids

Natural gas: NGLs are a by-product of natural gas production, and as such, any uncertainty discussed in the Natural Gas section applies for NGL projections.
Oil sands: The rate of oil sands and other heavy oil production growth, and the amount of blending, will affect the demand for condensate and butanes required for diluent. Likewise, the use of solvents to reduce steam requirements in the oil sands could impact demand and prices for propane and butanes and influence the degree to which they are targeted by future natural gas drilling.
Petrochemical development: There is potential for ethane and propane recovery to increase further if there is an increase in petrochemical capacity requiring either as feedstock. This could result from government programs, such as royalty credit incentives for petrochemical facilities in Alberta’s Petrochemicals Diversification Program.
Global LPG export market: Several large-scale facilities have been approved by provincial and federal regulators to export LPG from B.C.’s coast. Propane exports from one facility began in May 2019 and butanes also became part of the LPG mix in April 2020. Over the outlook period, propane will likely be the majority of exported LPG. The amount and composition of the LPG stream exported at these terminals could impact domestic NGL prices and the attractiveness of drilling for NGL-rich natural gas.

Electricity

In the Evolving Scenario, electricity demand grows steadily at the end use level, as shown in Figure R.17. This is driven by growth in all sectors, in particular the transportation sector where electrification provides an alternative in a sector long dominated by RPP use. Currently, electricity makes up approximately 16% of Canada’s end-use energy demand. In the Evolving Scenario, electricity demand increases at an average annual rate of 1% over the projection period, which raises electricity’s share of end-use demand to 27% by 2050. See Figure R.18. Electricity demand grows approximately 35% over the projection period, despite overall energy use decrease, as previously discussed in the energy demand section.

Figure R18 Share of Electricity in End-use Demand by Sector and Total in the Evolving Scenario

Electricity demand influences the growth, and mix, of fuels and technologies used to generate electricity. Canada has considerable renewable resource potential including hydro, wind, biomass, and solar. Over the past decade, there have been significant changes in Canadian electricity capacity and generation trends, and it continues to evolve in the EF2020 projections. Figure R.19 shows total Canadian installed capacity by fuel type, and Figure R.20 shows electric generation by fuel type.

In the earlier part of the projection, renewables and natural gas replace phased-out coal generation. In the longer term, falling costs lead to large growth in non-hydro renewables such as wind and solar. The share of renewable and nuclear generation increases from 81% currently to 90% in 2050.23

Figure R19 Electricity Installed Capacity Grows Significantly in the Evolving Scenario

Figure R20 Electricity Installed Capacity Grows Significantly in the Evolving Scenario

The increase in non-hydro renewables is driven by falling costs, technological improvements, as well as improved integration of variable renewable energy (VRE) sources such as wind and solar. Figure R.21 shows that by 2050, total non-hydro renewable capacity in the Evolving Scenario is over triple 2018 levels. Total wind capacity rises to 40 GW and total solar capacity rises to 20 GW.

Figure R21 Increasing Capacity of Non-Hydro Renewables in the Evolving Scenario

The integration of increasing levels of variable resources such as wind and solar is supported in a number of ways in the Evolving Scenario. Other forms of energy, such as hydropower and natural gas, help back up non-hydro renewables. In the Evolving Scenario, interconnection between many provinces increases, including between Manitoba-Saskatchewan, and Alberta-B.C. This increased ability to exchange power helps regions integrate larger amounts of variable energy. Finally, the Evolving Scenario includes around 3 GW of utility-scale battery storage. This is based on the falling costs of storage, as well as the falling costs of renewables, especially solar. Storage is especially critical for large additions of solar.

As the proportion of VRE increases, variations in generation from hour-to-hour and minute-to-minute become increasingly important in balancing electricity production and use. Figure R.22 illustrates simulated generation, for 24 hour periods in winter and summer, for the 2030 and 2050 electricity mix in the Evolving Scenario. The provinces are generally grouped by region. Manitoba, B.C., and Quebec are grouped together given they have similar hydro-dominated mixes.

As wind and solar generation vary throughout these simulated days, other generation sources fill in to meet requirements. For regions that have low shares of non-hydro renewables, the generation mix remains fairly constant. The mix and generation levels vary seasonally, with considerably more solar generation in the summer months.

The hourly generation projections presented here are simulations and represent one particular sample from many different outcomes. They are not a definitive statement on what will happen in the future, but rather an illustration of one potential outcome. Electricity demand, solar irradiation, and wind speed can vary greatly hour-to-hour and day-to-day, resulting in many different possible electricity demand and renewable generation outcomes.

Figure 22 Simulated Hourly Electricity Profiles, 2030 and 2050

Utility Scale Battery Storage

The Evolving Scenario includes a gradual uptake of utility scale battery storage, reaching nearly 3 GW of national capacity by 2050. This is driven by a variety of factors, including falling costs of batteries and variable renewable energy, and continued climate action.

An important potential use for storage is in the integration of more variable renewable energy. The figure below provides a simulated example of how this could work. It is based on the Evolving Scenario capacity mix for Alberta in 2050, for a day with high levels of wind generation. In this example, large amounts of mid-day solar energy, and significant wind generation, lead to excess generation. Without storage, this renewable generation would be unused (curtailed), but when storage is available it can be used to charge the batteries (shown in purple/grey pattern). Later in the day, when solar generation declines, the energy that was stored earlier in the batteries can be discharged to offset natural gas generation, which would otherwise be needed to meet load requirements (shown in yellow/maroon pattern).

Simulated Example of Storage Allowing for More Renewable Integration in Alberta, 2050

In addition to integrating renewables, storage has many other potential applications. This includes voltage regulation and grid operations, allowing for economic arbitrage (charging when power is low cost to sell when prices are higher), and contributing to system efficiencies (for example, charging with more efficient, but less flexible combined cycle natural gas generation, and discharging to reduce the need for more flexible, but less efficient, simple cycle natural gas generation).

(1) Excludes own use generation, such as industrial cogeneration.

Canada is a net exporter of electricity to the U.S., and large amounts of electricity are also traded between provinces, mainly in eastern Canada. By connecting the electricity grids of different regions, grid operators can take advantage of regional differences in electricity mixes, available variable renewable energy, and periods of peak electricity demand. Figure R.23 shows projected net exports out of Canada, as well as aggregate interprovincial trade volumes. Trade remains relatively small when compared to total generation.24

Figure 23 Net Exports of Electricity and Interprovincial Trade Trend Higher than 2019 in the Evolving Scenario

Key Trends: Electricity Generation

Technologies enabling Canada’s transition to a low carbon economy make inroads across the energy system, particularly in electricity generation.
Natural gas and renewable generation is added, and most nuclear will be refurbished.
Coal will be largely phased out.
The share of renewable and nuclear generation increases from 81% currently, to 90% in 2050.

Key Uncertainties: Electricity Generation

Future capital cost declines of generating facilities: The capital costs associated with different generating technologies is an important factor in determining what type of facilities are built. This is especially true with rapidly changing technologies such as wind, solar, and battery storage.
Electricity demand growth: This is important in determining future electricity supply. As a result, the uncertainties identified in the energy demand section are uncertainties that also apply to the electricity supply projections.
Export market developments: Climate policies, fuel prices, electrification and power sector decarbonization in export markets could impact future projects and transmission intertie developments.

Coal

There are two main types of coal produced in Canada: thermal and metallurgical. Canadian thermal coal production is linked to the use of coal in the electricity sector, particularly in Alberta, Saskatchewan, and Nova Scotia. Metallurgical coal is primarily used for steel manufacturing domestically and internationally. Much of Canada’s metallurgical coal production is exported and future production trends are linked to global metallurgical coal demand and prices.

Figure R.24 shows Canadian production and consumption of coal in Canada in 2018. Thermal coal accounted for 88% of total Canadian coal consumption in 2018. In the Evolving Scenario, demand for thermal coal declines by 89% over the projection period, falling from 30 million tonnes in 2018 to just over 3 million tonnes in 2050. This declining trend is driven primarily by retirements of coal-fired generation capacity resulting from regulations to phase out traditional coal-fired power plants by 2030, while some industrial sector demand remains.

Domestic demand for metallurgical coal used in steel manufacturing declines from 2.5 million tonnes in 2018 to roughly 0.7 million tonnes by 2050. In the Evolving Scenario, total metallurgical coal production in Canada decreases from about 29 million tonnes in 2018 to 22 million tonnes by 2050. Total production declines from about 55 million tonnes in 2018 to 24.5 million tonnes in 2050.

Figure 24 Canadian Coal Production and Disposition Trends Driven by Falling Thermal Demand in the Evolving Scenario

Key Uncertainties: Coal

Prices and Global Development: Future price movements for metallurgical coal in the global coal markets, and the rate of development in export markets are key uncertainties for Canadian coal production.
Climate policies: Canadian climate policies, and the climate policies of coal importing countries, could have a significant impact on both Canadian thermal and metallurgical coal production.

Greenhouse Gas Emissions

Currently, energy use and GHG emissions in Canada are closely related. ECCC’s most recent official GHG projections are available through Canada’s National Reports to the United Nations Framework Convention on Climate Change.25

The majority of GHGs emitted in Canada are a result of fossil fuel combustion. Fossil fuels provide the vast majority of energy used to heat homes and businesses, transport goods and people, and power industrial equipment. Energy related emissions accounted for 82% of Canadian GHG emissions in 2018.26 The remaining emissions are from non-energy sources such as agricultural and industrial processes, and waste handling.

Key Trends: Fossil Fuel Use and GHG Emissions

Overall fossil fuel use declines in the Evolving Scenario.
Natural gas, oil, and coal each have a distinct future trend.
The emission intensity of fossil fuel use falls, driven by the phase out of coal, and the long-term adoption of carbon capture and storage (CCS).

Does the Evolving Scenario Meet Canada’s Climate Commitments?

The Evolving Scenario provides an energy supply and demand outlook for Canada under the general premise that the energy system continues to transition at its historical pace. This contrasts with the Reference Scenario, which projects the Canadian energy system as it looks today into the future. Recent ECCC projections show that Canada is making progress to reach near-term climate targets, particularly in its “With Additional Measures” scenario, and that more work needs to be done to achieve them. Since the Evolving Scenario includes a similar policy framework, readers can draw similar conclusions from our analysis of changing Canadian energy use trends in the Evolving Scenario. The Government of Canada has announced commitments to strengthen existing, and introduce new GHG-reducing measures, to exceed Canada’s 2030 emissions reduction goal and begin working toward achieving net-zero emissions by 2050.

It is also clear that Canada’s more ambitious goals, such as achieving net-zero by 2050, will require a faster transition than we have witnessed historically, and faster than is shown in the Evolving Scenario. Recognizing this fact, we have included the “Towards Net-Zero” section in EF2020.

EF2020 focuses on potential future outcomes for Canada’s energy system. It should not be viewed as an assessment, or a pathway, for meeting Canada’s climate commitments. ECCC produces the official analysis of Canada’s current emissions outlook and performance against its climate commitments. The most recent analysis can be found in ECCC’s 4th Biennial Report on Climate Change.

Figure R.25 shows total domestic Canadian consumption of fossil fuels in the Evolving Scenario, by fuel type (and compared with the Reference Scenario total), as well as growth relative to 2005 levels for the fuel types. From 2019 to 2050, total fossil fuel use declines 35% in the Evolving Scenario, but growth varies significantly across the different fuel types. Natural gas continues to grow quickly in the early part of the projection period, following its increased role in power generation and its use in rising oil sands production. Use of RPPs gradually declines throughout the projection period. In the earlier years, this is driven by efficiency improvements and increased blending of biofuels, and in the long term is driven by increased electrification of the transportation sector. Coal significantly declines over the projection, driven by its phase out from electricity generation by 2030.

Figure 25 Total Demand for Fossil Fuels Consistently Declines in the Evolving Scenario and Gradually Rises in the Reference Scenario

Figure R.26 shows the change in total domestic Canadian fossil fuel use per person and per dollar of real GDP by indexing these indicators to a base year (2005). Relative to 2005, both measures decline significantly. By 2050, fossil fuel use per person is about half of what it was in 2005, and fossil fuel use per dollar of real GDP declines over 60%.

Figure 26 Fossil Fuel Demand per Person and per $ Real GDP Falls Steadily in the Evolving Scenario

Changing proportions of which fossil fuels are consumed leads to declining GHG emissions per unit of fossil fuel energy used in the Evolving Scenario, particularly with coal use declining to 2030. Deployment of carbon capture and storage (CCS) technology in industrial facilities also reduces the GHG intensity of fossil fuel use in the longer term. As shown in Figure R.27, in 2050 fossil fuel emission intensity is 19% lower than 2019, and 25% lower than 2005 in the Evolving Scenario. Accounting for reductions in non-combustion emissions, such as reducing methane emissions, as well as including emission credits purchased through international trading mechanisms (like Quebec’s emission trading with California) could further decrease emission intensity.

Figure 27 Fossil Fuel Emission Intensity Falls due to Higher Shares of Natural Gas, Less Coal, and Greater Adoption of CCS in the Evolving Scenario

Carbon Capture, Utilization and Storage

Canada has a number of commercial scale CCS projects. This includes the Boundary Dam power station that began operations in 2014, the Quest Project that captures CO₂ from Shell’s Scotford upgrader in Alberta, and the Alberta Carbon Trunk Line, a 240 km pipeline that will transport CO₂ from an industrial area north of Edmonton to enhanced oil recovery projects in central Alberta. The pipeline has an annual capacity of nearly 15 MT to allow for future CCS projects.

CCS could be an important part of the global energy transition. It is a technology group of great interest, but also one where the momentum has been mixed. The International Energy Agency (IEA’s) 2019 Tracking Clean Energy Progress categorizes CCS as “not on track”. The IEA’s recent Energy Technology Perspectives 2020 report underscores CCS’s importance as a key technology area to help the globe achieve deep decarbonization.

The Evolving Scenario assumes an increase in momentum for CCS in the latter half of the projection period. This is driven by an assumption of similar momentum globally, particularly as mid-century draws near, leading to overall technology development, learning, and cost reductions. In Canada, CCS deployment in the Evolving Scenario is supported by the assumed increases in carbon pricing shown in the “Scenarios and Assumptions” section. Costs of CCS are often measured in $ per tonne basis. Estimates are uncertain, and can vary significantly by the industry employing CCS. The Evolving Scenario assumes a gradual increase in carbon capture resulting in an additional 15 MT sequestered per year by 2040, rising to 30 MT by 2050.

Key Uncertainties: GHG Emissions

Technology development: Future adoption of low carbon technologies could alter these trends. Faster adoption of renewable energy, energy efficiency, battery storage, and other technologies could reduce fossil fuel use faster. Increased deployment of technologies such as CCS, could weaken the link between fossil fuel use and future emission trends, enabling greater levels of fossil fuel use to coexist with declining emission levels.
Future climate policies: The evolution of climate policies in Canada will be an important factor in fossil fuel consumption and GHG emission trends. Future developments in policies such as carbon pricing, energy and emission regulations, and support for emerging technologies could alter these projections.

[12] Projections were finalized in August 2020, so 2020 values are estimates.
[13] On an energy equivalent basis, EVs use less energy to travel a given distance than conventional vehicles. As EVs gain market share, the offsetting reduction in gasoline demand will be larger than the electricity added, leading to a net reduction. Additional details on EV efficiency and economics can be found in CER Market Snapshot: Levelized Costs of driving EVs and conventional vehicles.
[14] Information on crude oil ultimate potential and remaining reserves is available in the EF2020 Data Appendices.
[15] For more information see Western Canadian Crude Oil Supply, Markets, and Pipeline Capacity Optimizing Oil Pipeline and Rail Capacity out of Western Canada – Advice to the Minister of Natural Resources.
[16] In the case of Trans Mountain, the portion of pipeline capacity that is typically used to transport RPPs, 50 Mb/d, has been removed from that pipeline’s available capacity. Likewise, 5 Mb/d has also been removed from the future capacity of TMX.
[17] Responsible Investment Association, 2018 Canadian Responsible Investment Opportunity: Trends Report, pg. 12, October 2018.
[18] IPIECA, Oil and Gas Industry Guidance on Voluntary Sustainability Reporting, 8.
[19] This value of natural gas demand is lower than the primary natural gas demand value discussed earlier because it does not include non-marketed natural gas used directly by those that produce it. Examples of this include flared gas, natural gas produced and then consumed by in situ oil sands producers, and natural gas produced and consumed by offshore oil production.
[20] Net exports are equal to exports less imports. Declines in net exports do not necessarily equate to declines in exports.
[21] Responsible Investment Association, 2018 Canadian Responsible Investment Opportunity: Trends Report, pg. 12, October 2018
[22] IPIECA, Oil and Gas Industry Guidance on Voluntary Sustainability Reporting, 8.
[23] Renewable and nuclear shares refer to total electricity generation, including cogeneration.
[24] From 2010 to 2019, annual net exports average 49 TW.h, ranging between 25 and 64 TW.h.
[25] Data sets are also available through the Government of Canada’s Open Government portal.
[26] As defined in ECCC’s national inventory report, energy related emissions includes stationary combustion sources, transportation, fugitive sources, and CO₂ transport and storage.

Notice: On 2 December 2020, a note for additional clarity was added to Figures ES.8 and R.12 in this PDF.

Date modified:: 2023-07-14

Language selection

Search

Menu