Key Findings

Canada’s Energy Transition
Low-carbon Electricity
Wind and
Solar
Diverse Electricity Grids
Crude Oil Production
Natural Gas Production
Fossil Fuel Demand

 Net-Zero Key Findings

Canada’s Energy Transition

1. In the Evolving Policies Scenario, combustion of fossil fuels whose emissions are not captured falls 62% from 2021 to 2050, while use of low and non-emitting energy sources increases. While this implies a significant reduction in GHG emissions by 2050, achieving net-zero will likely require more change than is included in this scenario.

Figure ES.2: Total Canadian Energy Use, Evolving Policies Scenario

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Figure ES.3: Unabated Fossil Fuel Use, Evolving Policies Scenario

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In the Evolving Policies Scenario, Canadians reduce their energy consumption and adopt lower carbon sources (Figure ES.2). Total primary energy use falls 21% from 2021 to 2050 as energy efficiency improves. Low and non-emitting sources–including renewables, nuclear, and fossil fuels with carbon-capture and storage (CCS)^{Definition *} grow to make up the strong majority of energy use. Unabated fossil fuel combustion (fossil fuel combustion without CCS) falls 19% from current levels by 2030, 45% by 2040, and 62% by 2050 (Figure ES.3).

Policy assumptions in the Evolving Policies Scenario are based on strengthening or expanding existing global and domestic policies at a pace consistent with recent trends. The Evolving Policies Scenario projections show significant changes in Canada’s energy system and imply large reductions in GHG emissions. However, given the remaining unabated fossil fuel demands in 2050, the Evolving Policies Scenario also signals the need for greater long-term change in order to reach Canada’s target of net-zero emissions by 2050. In addition to policy, many other factors we discuss in EF2021–such as global energy markets, technology, and consumer behaviour and preferences–will also influence future Canadian energy and emission trends.

Low-carbon Electricity

2. Canadians use more electricity, from increasingly low-carbon sources. Despite total energy use declining, electricity demand grows 47% from 2021 to 2050 in the Evolving Policies Scenario, much of it from new areas such as electric vehicles and hydrogen production. Canada’s electricity system also gets greener, going from 82% low and non-emitting in 2021 to 95% in 2050.

Figure ES.4: Electricity Demand by Sector, Evolving Policies Scenario

Figure ES.5: Electricity Generation by Source, Evolving Policies Scenario

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Compared to the past two decades when electricity use grew very slowly, electricity demand grows quickly over the projection period in the Evolving Policies Scenario. This increase is driven by increased electrification of the energy system. Total electricity demand increases by 47% from 2021 to 2050, or by about 263 terawatt hours (TWh) (Figure ES.4). Half of this increase is driven by increased electrification in the industrial, residential, and commercial sectors. The other half comes from electric vehicles in transportation and the production of hydrogen. In particular, by 2050, electric vehicles dominate Canada’s vehicle mix and increase electricity demand by 70 TWh. This results from the Evolving Policies Scenario assuming nearly all new passenger vehicles sold in 2035 are battery or plug-in hybrid electric vehicles.

As demand grows, Canadian electricity generation increases. Wind and solar generation provide much of this additional electricity over the projection period, given their low cost. Natural gas generation is increasingly equipped with CCS. Low and non-emitting electricity generation make up 82% of total generation in 2021, rising to 88% by 2030, 94% by 2040, and 95% by 2050.

Wind and Solar

3. Wind, solar, and battery storage dominate electric capacity additions in all six net-zero electricity scenarios, making up between 82-85% of added capacity. With rising levels of wind and solar, all scenarios require flexible generation sources to balance supply and demand. There are large differences in the types and capacities of flexible generation sources adopted among scenarios.

Figure ES.6: Cumulative Capacity Additions to 2050, All Net-Zero Electricity Scenarios

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The net-zero electricity scenarios each have a unique set of assumptions that examine many factors including technology, policies, level of electrification, and infrastructure. Figure ES.6 shows the net capacity additions for all six scenarios from 2019 to 2050. Consistent across all scenarios are large additions of wind and solar capacity, ranging from 100 gigawatts (GW) to 150 GW. These technologies are increasingly adopted due to their assumed low future costs in all scenarios. With large amounts of wind and solar capacity, power systems require additional flexible generating resources to balance supply and demand (given the variability of wind and sun conditions). Across the net-zero scenarios, the flexible generating resources are a combination of battery storage, natural gas-fired generation (with and without CCS), small modular nuclear reactors, hydropower, hydrogen-fired generation, biomass-fired generation with CCS, and transmission between provinces. The relative share of these flexible resources varies significantly across the scenarios, though the role of storage in balancing the grid increases dramatically in all scenarios.

Diverse Electricity Grids

4. The net-zero electricity scenarios suggest that Canadian power systems will continue to be very distinct across the country, even in a low-carbon future. In each net-zero electricity scenario, the ten provinces meet their electricity demands in diverse ways, with widely varying mixes of hydro, nuclear, fossil fuel with CCS, wind, solar, hydrogen, and biomass with CCS.

Figure ES.7: Electricity Generation Share by Technology, Main Net-Zero Electricity Scenario

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Figure ES.7 shows the generation mix for each province in the main net-zero electricity scenario. In British Columbia (B.C.), Manitoba, Quebec, and Newfoundland and Labrador, electricity generation continues to be primarily hydropower. Nuclear power remains limited to Ontario and New Brunswick and represents about 41% and 24%, respectively, of those provinces’ electricity supply in 2050.

Natural gas-fired electricity generation remains a relatively important share, about 15%, of the electricity supply of Alberta and Saskatchewan in the main net-zero electricity scenario. However, by 2050, the vast majority of this generation utilizes CCS technology. In many other provinces, although the generation share is small, natural gas units nonetheless provide flexible capacity required to maintain system reliability.

Transmission between provinces is a key factor that enables the electricity system to reach net-zero. For example, in the Base net-zero electricity scenario, increased transmission occurs in western Canada, where hydroelectric generation from B.C. and Manitoba helps Alberta and Saskatchewan decarbonize.

While we continue to see diversity between the various provincial electricity systems in each net-zero electricity scenario, results vary somewhat between cases. In a scenario where transmission expansions are limited, Alberta and Saskatchewan use more generation from natural gas with CCS. By contrast, in the Higher Carbon Price scenario, natural gas with CCS is lower in these provinces as small modular reactors make inroads in western Canada. Meanwhile, in the Hydrogen scenario there is a 26% reduction of all types of natural gas-fired generation relative to the main net-zero electricity scenario in 2050, and the flexible nature of hydrogen-fired generation means battery storage falls by 32%. In the Bioenergy with CCS (BECCS) scenario, the availability of biomass CCS units for electricity generation partially displaces all other generation technologies in Alberta and Saskatchewan. Due to the carbon removal capability of biomass CCS, the electricity system in Canada becomes a net negative emissions economic sector in the BECCS scenario.

Crude Oil Production

5. In the Evolving Policies Scenario, crude oil production grows much more slowly than in the past decade, rising 16% to a peak of 5.8 MMb/d in 2032. Afterwards, production declines slowly to 2050. As crude oil available for export from western Canada increases over the next decade , it comes close to filling the level of total export capacity that would be provided by existing pipeline capacity, planned pipeline expansions, and structural rail.

Figure ES.8: Crude Oil Production, Evolving and Current Policies Scenarios

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Figure ES.9: Oil sands Production from Currently Producing Facilities, Expanded, and New Facilities, Evolving Policies Scenario

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Canadian crude oil^{Definition *} production recovered to pre-pandemic levels by late 2020, after steep reductions in the spring of 2020. In both scenarios, production increases in the near term, but long-term trends differ significantly based on scenario assumptions, such as future price levels and domestic climate policy.

In the Evolving Policies Scenario, Canadian production growth slows over the next decade peaking at 5.8 million barrels per day (MMb/d) in 2032, up from 5.0 MMb/d in 2021 (Figure ES.8). After 2032, production declines steadily, reaching 4.8 MMb/d in 2050. In the Evolving Policies Scenario, the assumed Brent crude oil^{Definition *} price gradually falls from an annual average of US$68 per barrel in 2021 to US$40 per barrel in 2050 (2020 dollars, adjusted for inflation).

Canadian crude oil production levels are resilient through to 2050 despite the Evolving Policies Scenario’s relatively low prices and steadily more ambitious climate policies. This largely stems from the nature of the oil sands^{Definition *} facilities, which are long-lived and have low operating costs once built. Throughout the projection period, the vast majority of oil sands production is from facilities that are producing today (Figure ES.9).

Future global climate policy, and how it affects global crude oil markets, will be important for Canadian production. The Current Policies Scenario assumes higher global oil prices than the Evolving Policies Scenario, premised on there being higher global oil demand. The Brent crude oil price stays at US$70 per barrel through much of the projection period and Canadian production increases more rapidly, plateauing in 2040 at 6.7 MMb/d. Conversely, some recent global net-zero scenarios, such as the International Energy Agency’s Net Zero Emissions by 2050 scenario in World Energy Outlook 2021, show rapidly declining global oil demand, which could lead to significantly lower Canadian production levels compared to the Evolving Policies Scenario.

Figure ES.10: Illustrative Export Capacity from Pipelines and Structural Rail, vs. Total Crude Oil Supply Available from the Western Canadian Sedimentary Basin (WCSB), Evolving and Current Policies Scenarios

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A key issue for Canadian oil pricing and production trends over the last number of years was the availability of crude oil export pipeline and rail capacity. In the Evolving Policies Scenario, crude oil available for export from western Canada comes very close to, but stays slightly below the illustrative total export capacity provided by existing plus planned pipeline capacity and structural rail, as shown in Figure ES.10. EF2021 does not assess whether additional pipeline capacity would be required to avoid constraining Canadian crude oil production below levels projected in the Evolving Policies Scenario. In the Current Policies Scenario, however, production would clearly be constrained below projected levels without additional pipeline capacity, as supply significantly exceeds the illustrative total export capacity through much of the projection period. Our crude oil supply projections are not adjusted to reflect potential pipeline constraints in either scenario.

Natural Gas Production

6. Investment in natural gas production is spurred by assumed liquefied natural gas (LNG) exports in both scenarios. In the Evolving Policies Scenario, nearly 40% of Canadian natural gas production is liquefied and exported to global markets by 2050. Despite considerable LNG-related production growth, natural gas production remains relatively stable through much of the projection period before declining gradually to reach 13.1 Bcf/d by 2050, 17% lower than current levels.

Figure ES.11: Total Natural Gas Production and LNG Export Assumptions, Evolving and Current Policies Scenarios

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In the Evolving Policies Scenario, natural gas production remains near current levels of approximately 15.5 billion cubic feet per day (Bcf/d) through much of the next two decades. We assume that LNG^{Definition *} exports grow over that period, starting with 1.8 Bcf/d by 2026 and reaching 4.9 Bcf/d by 2039 in the Evolving Policies Scenario. The additional investment in production to feed these LNG exports sustains overall production levels. Without LNG, production would otherwise decline given the assumed natural gas prices and the costs associated with assumed domestic climate policies. After 2040, with LNG exports assumed to stay flat, total production begins to decline, falling to 13.1 Bcf/d by 2050. Assumed Henry Hub^{Definition *} natural gas prices in the Evolving Policies Scenario steadily increase from US$3.00 per Million British Thermal Units (MMBtu) in 2021 to US$3.64/MMBtu by 2050 (2020 dollars, adjusted for inflation).

In the Current Policies Scenario, natural gas production is significantly higher. To reflect higher global and North American demand for natural gas due to the scenario’s lower climate action, we assume LNG exports increase to 7.1 Bcf/d by 2044 and the Henry Hub price reaches $4.40/MMBtu by 2050 (2020 dollars, adjusted for inflation). These two drivers, combined with less stringent domestic climate policies relative to the Evolving Policies Scenario, lead to natural gas production increasing steadily throughout the projection, reaching 22.2 Bcf/d in 2050, a 40% increase from 2021 production levels.

Figure ES.12: Natural Gas Production, Evolving and Current Policies Scenarios

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In both scenarios, natural gas production from the Montney Formation, which straddles the Alberta-British Columbia boundary and is rich in higher value natural gas liquids^{Definition *}, grows significantly. In many other regions, production is stable or declines throughout the projection. Much of the production growth related to LNG exports occurs in B.C. and production in B.C. surpasses that of Alberta by 2028.

Fossil Fuel Demand

7. As Canada’s energy system decarbonizes in the Evolving Policies Scenario, we use less fossil fuels. Coal becomes a negligible part of the energy mix. Use of oil-derived fuels declines, especially gasoline and diesel for transportation. After briefly rising in the near term, total natural gas use declines, and our consumption of natural gas is increasingly tied to the future of CCS. Natural gas with CCS for industrial uses, power generation, and hydrogen production are key demand growth areas.

Figure ES.13: Fossil Fuel Demand by Type, Evolving Policies Scenario

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Figure ES.14: Natural Gas Demand by Sector, Evolving Policies Scenario

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In the Evolving Policies Scenario, total Canadian fossil fuel use declines over 40% from 2021 to 2050. However, projections differ across the various fossil fuels. Canadian demand for natural gas has seen relatively strong growth over the last decade, driven by increased use in the oil sands and power generation as coal was phased out. In the Evolving Policies Scenario, gas demand grows over the next two years, as Alberta electricity producers aim to no longer use coal for electricity generation by 2023. Over the longer term, although natural gas remains an important part of Canada’s energy mix, total demand declines from around 13 Bcf/d in 2021 to 8.5 Bcf/d in 2050. Factors that reduce natural gas demand include: increasing use of renewables in power generation, renewable natural gas and hydrogen blended into gas streams, energy efficiency improvements, and declining crude oil and natural gas production (which itself requires natural gas). These declines are partially offset by applying CCS technology when using natural gas in industry, the power sector and to produce low-carbon hydrogen.

Coal consumption declines significantly over the projection, driven by its phase out from electricity generation. Coal drops to less than 1% of Canada’s energy mix by 2035, compared to 5% in 2019. Use of refined petroleum products (RPPs)^{Definition *} and NGLs gradually falls throughout most of the projection period, driven by declines in gasoline and diesel fuel demand. In the earlier years, this fall is driven by fuel efficiency improvements and increased blending of biofuels, and in the long term by increased use of electric and hydrogen vehicles in transportation. Demand for RPPs used for non-combustion purposes (petrochemical feedstocks, asphalt, lubricants, etc.), as well as for aviation fuel, is relatively steady throughout the projection.

Date modified:

2023-11-24