Results

This section presents results of the EF2021 projections. The primary focus is the Evolving Policies 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 discussed in each section.

For a description of the various ways to access the data supporting this discussion, including full data tables for both the Evolving and Current Policies scenarios, 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, the economy continues its gradual recovery from the COVID-19 pandemic. As shown in Figure R.1, total real gross domestic product (GDP)^{Definition *} declined 5.3% in 2020, and grows by 5.7% in 2021.

Figure R.1: GDP Growth Rebounds Following a Steep Decline in 2020

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The long-term projections for key economic variables are in Figure R.2. Economic growth (adjusted for inflation) averages 1.6% per year over the projection period in both the Evolving Policies Scenario, and the Current Policies Scenario, with the Current Policies Scenario slightly higher. Economic growth over the projection is generally slower than the 1990 to 2018 historical period for a variety of reasons, including an aging population and slower global economic growth.

Figure R.2: Economic Indicators, Evolving and Current Policies Scenarios (2019-2050)

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Energy Demand

This section first discusses secondary^{Definition *} (or “end-use”) energy demand projections by reviewing energy use by sector of the economy, before turning to our economy wide primary energy demand^{Definition *} projections. End-use demand includes electricity and hydrogen, while the fuel used to produce electricity and hydrogen is accounted for in primary energy demand. Historical data is sourced primarily from Statistics Canada’s Report on Energy Supply and Demand in Canada. This data is supplemented with additional details from Environment and Climate Change Canada (ECCC), Natural Resources Canada, and various provincial data sources.

View our data on energy demand by region, sector, fuel source, and scenario in our interactive visualization tool, Exploring Canada’s Energy Future.

Explore a summary of energy demand in our EF2021 Fact Sheets: Energy Demand.

In the near term, energy use follows macroeconomic trends. We estimate that demand declined 8% in 2020, and project it to increase in 2021 and 2022. In the long term, the Evolving Policies Scenario projects Canadian energy use to decline to 2050. Figures R.3 and R.4 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, increasing electrification of the transportation sector,^Footnote 16 and various policies, like carbon pricing. Partially offsetting these factors, economic growth and a near-term increase in crude oil production provide some upward pressure on energy use. However, economic growth is slower than historical trends, and crude oil and natural gas production eventually declines. The Current Policies Scenario sees moderate demand growth over the projection period (though at levels lower than recent history) due to the lack of additional climate policy action beyond current policies, higher crude oil and natural gas production, and less electrification.

Figure R.3: End-use Demand Declines in All Sectors in the Evolving Policies Scenario

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Figure R.4: End-use Energy Consumption Peaks in 2019 and Declines over the Long Term in the Evolving Policies Scenario

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Energy use trends vary by sector and by energy type in the Evolving Policies Scenario (See Figure R.5). These trends result from many different drivers, including macroeconomics, energy production trends, energy efficiency improvements, policies, technology advancements, and market developments. Highlights include:

• In the residential and commercial sectors, improving efficiency of devices and building envelopes reduces overall energy consumption. Rising carbon prices and improving technology drive penetration of heat pump technology in buildings, reducing natural gas use. Blending of renewable natural gas and hydrogen into natural gas streams also reduces natural gas use. This is driven by a combination of policy assumptions (see the “Scenarios and Assumptions” section), and economics in the longer term as carbon prices increase and technology costs fall.
• In the industrial sector, trends vary by industry. The oil and gas sector becomes more efficient, and production growth slows and eventually peaks for crude oil production, while natural gas production stays relatively steady and then declines. Solvent-assisted production in in situ^{Definition *} oil sands helps improve energy intensity significantly in the latter half of the projection period. In the longer term, hydrogen reduces natural gas use, especially in key sectors such as iron and steel, cement, refining, as well as the oil and gas sectors. At the same time, increasing use of CCS puts upward pressure on energy demand as the CCS process requires energy.
• The transportation sector undergoes a notable low-carbon transition. Refined petroleum products (RPPs)^{Definition *} like gasoline, diesel, and jet fuel have historically dominated the transportation sector, and this begins to change in the Evolving Policies Scenario. The Evolving Policies Scenario assumes that the recently announced Federal goal for all new vehicle sales to be Zero-Emission Vehicles (ZEVs)^{Definition *} by 2035 is achieved, and that adequate supplies of battery and plug-in hybrid electric vehicles will exist and meet demand.^Footnote 17 This substantially reduces gasoline demands in the projection. Electric freight, particularly light-to-mid-duty, hydrogen-powered freight (mid-to-heavy duty), and increasingly electrified public transportation (electric bussing) grow steadily in the 2030s and 2040s. Biofuels blending into gasoline and diesel increases from current levels in both scenarios, driven by policies like the Federal Clean Fuel Regulation.

Figure R.5: End-Use Energy Demand Trends Vary by Sector and By Fuel in the Evolving Policies Scenario

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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 and hydrogen to total end-use demand, and then subtracting the end-use demand for electricity and hydrogen. Primary demand is higher than end-use demand due to factors such as heat loss in thermal electric generation, and the energy required for the hydrogen production process. This implies that it takes more than one unit of natural gas or coal to produce the same energy unit of electricity, and similarly more than one unit of natural gas or renewables to produce one energy unit of hydrogen.

Figure R.6 shows primary demand by fuel for the Evolving Policies Scenario, compared with total primary demand in the Current Policies Scenario. In the Evolving Policies Scenario, total demand gradually falls, driven by declining fossil fuel use. Coal demand declines considerably due to the phase out of coal-fired power generation. RPP 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. Natural gas demand grows slowly to about 2025, driven by increasing crude oil production as well as its increasing role in power generation. From 2025 to 2050 total natural gas demand steadily declines, as less is used for crude oil and natural gas production (due to both increased efficiency and, eventually, less production), energy efficiency improves, renewables replace some natural gas in power generation, and renewable natural gas and hydrogen are blended into the natural gas stream. Increasing natural gas use to produce hydrogen, as well as adding CCS to natural gas use in industrial electricity generation and power, partially offsets this decline.

Driven by increased electrification at the end-use level, overall electricity demand rises steadily in the Evolving Policies Scenario. This demand leads to stable production of 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.

Figure R.6: Primary Demand Gradually Declines and Renewables Account for a Larger Share in the Evolving Policies Scenario Energy Mix

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Energy use falls while both the economy and Canada’s population grow, implying that energy intensity–measured in energy use per capita or per $ of real GDP–declines significantly. This is shown in Figure R.7. From 2019 to 2050, real GDP increases 60% and population increases over 27% in the Evolving Policies Scenario. Primary energy use declines 25%. These different trends imply that energy use per $ of real GDP declines over 50% from 2019 to 2050, while energy use per person declines over 40% in the Evolving Policies Scenario.

Figure R.7: The Economy Grows Faster than Energy Use, and Energy Intensity Declines in both the Evolving Policies Scenario and the Current Policies Scenario

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Crude Oil

Crude oil^{Definition *} is produced in Canada for domestic refining as well as for export. In 2019, Canadian crude oil production averaged 4.9 million barrels per day (MMb/d) (784 thousand cubic metres per day (10³m³/d)). Production declined by 5% in 2020, largely due to the COVID-19 pandemic, but had returned to 2019 levels by the end of 2020. In recent years, most production growth has been concentrated in the oil sands. Regionally, most production is in Alberta, with additional volumes in Saskatchewan and offshore Newfoundland and Labrador.^Footnote 18

Figure R.8 shows Canadian crude oil production by type in the Evolving Policies Scenario, compared to total Current Policies Scenario production. Canadian crude oil production in the Evolving Policies Scenario peaks at 5.8 MMb/d (930 10³m³/d) in 2032 and declines to 4.8 MMb/d (756 10³m³/d) in 2050, a decrease of 4% from 2021. For comparison, production peaks at 6.7 MMb/d (1 064 10³m³/d) in 2044 in the Current Policies Scenario, driven by higher crude oil price assumptions and other assumptions related to the lack of future domestic and global climate policy action.

View our data on crude oil production by region, type, and scenario in our interactive visualization tool, Exploring Canada’s Energy Future.

Explore a summary of oil production in our EF2021 Fact Sheets: Oil Sands Production and Conventional, Tight, and Shale Oil Production.

Figure R.8: Total Crude Oil Production Peaks in 2032 and then Declines through 2050 in the Evolving Policies Scenario

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Production growth in the oil sands continues in the near term, peaking in 2032 and declining slightly through 2050 in the Evolving Policies Scenario. Figure R.9 shows Evolving Policies Scenario oil sands production by type, while Figure R.10 shows it by vintage. Growth is dominated by in situ projects. Most production growth in this scenario are expansions to existing projects, which are profitable given Evolving Policies Scenario price levels and technology improvements that increase productivity.

Conventional^{Definition *}, tight^{Definition *}, and shale^{Definition *} production is classified as light^{Definition *} or heavy^{Definition *}, depending on the API gravity^{Definition *} of the oil. In 2020, 51% of western Canadian conventional production was heavy and 49% was light. Near-term growth in production in these categories is primarily due to increases in light oil production in Alberta, along with growing heavy oil production in Saskatchewan. Light oil, particularly 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 the province (Figure R.11).

The majority of condensate^{Definition *} production has and is projected to come 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 (Figure R.12). Condensate is used as a diluent^{Definition *} for bitumen and heavy oil.

Newfoundland offshore production in the Evolving and Current Policies scenarios steadily declines as shown in Figure R.13. We assume no new discoveries in the Evolving Policies Scenario. Additional discoveries and developments could change these trends. In the Current Policies Scenario, we assume new discoveries are made and start producing oil beginning in 2032.

Figure R.9: Oil Sands Production Peaks in 2032 and then Declines throughout the Projection Period in the Evolving Policies Scenario

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Figure R.10: Oil Sands Production: Existing vs. Projected Additions in the Evolving Policies Scenario

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Figure R.11: Conventional, Tight, and Shale Oil Production Decreases Steadily over the Projection in the Evolving Policies Scenario After a Brief Increase Over the Next Five Years

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Figure R.12: Condensate Production Driven by Increasing Diluent Demand in the Evolving Policies Scenario

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Figure R.13: Newfoundland Offshore Oil Production Steadily Declines to 2050 in the Evolving Policies Scenario

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A key issue for Canada’s energy system over the last number of years was the availability of crude oil export pipeline and rail capacity. This has implications for Canadian oil pricing and production trends. When total export capacity is very full, it can lead to widening differentials, particularly when there are unexpected outages. Figure R.14 is an illustrative comparison of our crude oil supply projections and the level of total export capacity that would be provided by existing pipeline capacity, planned pipeline expansions, and structural rail.^Footnote 19 Making this comparison allows us to get an understanding of whether pipeline constraints might impact crude oil production in our scenarios. However, we do not adjust our crude oil production projections based on potential constraints.

In the Evolving Policies Scenario, crude oil available for export from western Canada stays below the total hypothetical export capacity throughout the projection period. However, into the mid-2030s the difference between capacity and supply is small. EF2021 does not assess whether in this scenario, additional pipeline capacity would be required to avoid constraining Canadian crude oil production below what is projected throughout the projection period.

In the Current Policies Scenario, supply exceeds capacity through much of the projection period. This clearly suggests that without additional pipeline capacity, production would be constrained below what is projected.

EF2021 does not explore the complexities of how pipeline infrastructure interacts with energy supply and demand outcomes. For example, some spare pipeline capacity can benefit crude oil producers by providing flexibility to access higher value markets or avoid the impacts of maintenance or unforeseen outages. It’s also possible that excess capacity and long-term underutilization of pipelines could result in higher pipeline tolls for crude oil producers. Analysis of these considerations is beyond the scope of EF2021. We caution readers from drawing definitive conclusions from the illustrative comparison shown Figure R.14.

It is also important to note that the estimate of what total available pipeline capacity and the level of structural rail could be is uncertain and the result of many key assumptions. Table R.1 describes the infrastructure assumptions that underpin Figure R.14. Available capacity on existing pipeline systems could be higher or lower than reflected in Figure R.14, as pipeline systems evolve over time. The level of structural crude by rail could also be somewhat higher or lower than reflected in this figure.

Figure R.14: Illustrative Export Capacity from Pipelines and Structural Rail, Crude Oil Pipeline Capacity vs. Total Supply Available for Export in the Evolving and Current Policies Scenarios

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Table R.1: Pipeline Capacity Assumptions for Figure R.14

Global fossil fuel market dynamics and implications for Canadian production trends

The Evolving and Current Policies scenarios explore the impact of changing policy trends, both domestic and global, on the Canadian energy system. The results show that the different assumptions in the scenarios have a large effect on Canadian crude oil and natural gas production projections. This establishes future climate action–particularly global action, which impacts global demand and prices–as a key uncertainty for Canadian production levels. At a high level, the EF2021 production projections have a similar conclusion to global scenario work from the IEA, and companies such as BP and Shell: increasing levels of climate action will decrease production.

Over the past several years, there has been an increasing body of scenario analysis on what net-zero by 2050 means for the global energy system. Figure R.15 shows global oil and natural gas demand trends in a variety of scenarios that vary in their level of decarbonization. The range presented here is large and includes both business as usual and net-zero scenarios. For global oil demand, these scenarios have a range of 37% more to 73% lower compared to current levels by 2050. For natural gas, global demand ranges from 68% more to 54% less relative to current levels by 2050.

Figure R.15: Growth of Global Natural Gas and Oil Demand, Various International Scenarios by Other Organizations

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Description

Description: This graph compares several organization’s projections of oil and gas demand indexed to 2010 levels, where 2010 levels are equal to 1. By 2050, global gas demand is 1.0 in Shell Sky, 1.7 in BP Business-as-usual, 1.2 in BP Rapid, 0.8 in BP Net Zero, 1.6 in EIA 2021 Reference, 1.1 in IEA Announced NZ Pledges, 1.6 in IEA Stated Policies, 0.3 in IEA Net Zero by 2050, and 0.7 in IEA Sustainable Development. By 2050, global oil demand is 0.9 in Shell Sky, 1.0 in BP Business-as-usual, 0.6 in BP Rapid, 0.3 in BP Net Zero, 1.4 in EIA 2021 Reference, 0.9 in IEA Announced NZ Pledges, 1.2 in IEA Stated Policies, 0.3 in IEA Net Zero by 2050, and 0.5 in IEA Sustainable Development.

If the assumptions made in the global net-zero scenarios materialize, there will likely be significant impacts for global crude oil and natural gas markets. In the IEA’s Net Zero by 2050 scenario, the global crude and North American natural gas prices are significantly lower than the Evolving Policies Scenario assumptions. The Canadian Institute for Climate Choices Net Zero Report finds that only scenarios with high oil prices and high levels of carbon dioxide removals see Canadian oil production similar to current levels in the long term. These results suggest that in a net-zero world, there could be significant decreases in Canadian oil and natural gas production.

Canadian fossil fuel production in a net-zero world will depend on many factors, such as:

• market prices,
• the evolution of light and heavy oil refinery demand,
• the cost of reducing the upstream emissions of Canadian oil and natural gas production, and
• the extent to which low-carbon natural gas technologies (such as CCS-equipped hydrogen production, electricity generation and industrial use with CCS, and natural gas use for direct air capture) are implemented.

In addition, oil and natural gas production is itself a large user of energy in Canada. As a result, the uncertainty in future production trends is an uncertainty for Canadian energy demand and GHG emissions trends. In the Evolving Policies Scenario, the oil and gas sector makes up about 20% of the remaining unabated fossil fuel demand in Canada in 2050, down from approximately 30% today. The future of global oil and gas trends, and how they affect Canadian investment and production trends, will therefore likely be important for Canada’s own net-zero transition.

Natural Gas

In Canada, natural gas^{Definition *} is produced for domestic use and exports. In 2020, Canadian marketable natural gas production averaged 15.5 Bcf/d or 438 million cubic metres per day (10⁶>m³/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^{Definition *} exports off of Canada’s west coast.
• NGLs^{Definition *} in the Montney tight gas play driving drilling and production despite lower natural gas prices.
• Horizontal drilling and hydraulic fracturing^{Definition *} technological advancements.

In the Evolving Policies Scenario, natural gas production remains near 2020 levels of 15.5 Bcf/d through much of the next two decades. The additional investment in production to meet assumed LNG export volumes sustains production levels. Without these investments, production would otherwise decline, given the assumed North American natural gas prices and the costs associated with assumed domestic climate policies. After 2040, with LNG exports assumed to stay flat, total natural production begins to decline, falling to 13.1 Bcf/d by 2050. Much of the production growth related to LNG exports occurs in B.C., and production in B.C. surpasses that of Alberta by 2028.^Footnote 21

In the Current Policies Scenario, natural gas production continues increasing in the longer term, reaching 22.2 Bcf/d (627.4 10⁶>m³/d) by 2050. Current Policies Scenario projections are driven by assumptions of higher prices, a lack of future domestic and global climate action, and higher LNG exports.

View our data on natural gas production by region, type, and scenario in our interactive visualization tool, Exploring Canada’s Energy Future.

Explore a summary of gas production in our EF2021 Fact Sheets: Natural Gas Production and Natural Gas Liquids Supply and Disposition.

Figure R.16: Total Natural Gas Production Declines in the Evolving Policies Scenario and Increases in the Long Term in the Current Policies Scenario

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Figure R.17 shows production of natural gas by type in the Evolving Policies Scenario. Production is increasingly made up of tight natural gas^{Definition *} produced from the Montney Formation in Alberta and B.C., which has already grown significantly over the past five years. Alberta Deep Basin tight natural gas production declines. There are minimal amounts of shale gas^{Definition *} production from the Duvernay and Horn River shales, while solution gas^{Definition *} declines and coal bed methane^{Definition *} production declines significantly over the projection period.

Figure R.17: Natural Gas Production is Increasingly Made Up of Montney Formation Tight Gas in the Evolving Policies Scenario

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Figure R.18 illustrates total Evolving Policies Scenario production divided into production that would result from the market prices of the Evolving Policies Scenario, and additional production due to LNG exports. The additional LNG-related production is based on our assumption that 75% of LNG feedstock comes from incremental production that only exists because LNG export capacity exits. The other 25% of LNG feedstock is supplied by the market-driven production (i.e. production that occurs based on assumed North American gas prices). Figure R.18 shows that without additional production to feed LNG exports, production would continuously decline over the projection period to 9.5 Bcf/d (267.7 10⁶>m³/d) in 2050.

Figure R.18: LNG Exports Support Natural Gas Production in the Evolving Policies Scenario

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Natural gas exports to the western U.S. have increased over the last several years. Imports to Canada have been relatively steady over the last decade, ranging from 2-3 Bcf/d (57-85 10⁶>m³/d). Imports could potentially rise as pipeline capacity increases from the northeastern U.S. to Dawn, Ontario.

Figure R.19 breaks total marketable production in the Evolving Policies Scenario into a) Canadian marketable demand, b) the assumed LNG export volumes, and c) the remaining implied net exports. The remaining implied net exports is mostly by pipeline and calculated as Canadian natural gas production minus Canadian demand and LNG exports.^Footnote 22 Remaining implied net exports shrink throughout the projection period, resulting from the production, consumption, and LNG export trends discussed earlier in this section. Lower remaining implied net exports do not necessarily mean that non-LNG exports are falling, just that the difference between imports and non-LNG exports is smaller.

Figure R.19: Natural Gas Supply and Demand Balance sees the Increasing Importance of LNG Exports as Domestic Demand Declines in the Long Term in the Evolving Policies Scenario

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Natural Gas Liquids

Natural gas liquids (NGLs) are produced along with natural gas, as well as from oil sands and refinery processes. 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 natural gas drilling. Raw natural gas at a wellhead is comprised primarily of methane, but often contains NGLs such as ethane^{Definition *}, propane^{Definition *}, butane^{Definition *}, condensate and other pentanes^{Definition *}.

Figure R.20 shows that total NGL production grows around 10% to 2050 in the Evolving Policies Scenario, from the 1 159 Mb/d (184 10³m³/d) produced in 2020. Growth is dominated by condensate^{Definition *}, which grows 28% by 2050. 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. Condensate demand has, and will continue to, influence natural gas drilling to focus on NGL-rich plays.

Propane and butane production declines slightly over the projection period in the Evolving Policies Scenario. Demand for these NGLs increases in the medium term as demand from petrochemical producers in Alberta increases, which may affect export levels of propane and butane.

The majority of ethane is extracted at large natural gas processing facilities^{Definition *} located on major natural gas pipelines in Alberta and B.C. In 2020, ethane made up 20% of NGL production. Ethane production is flat in the Evolving Policies Scenario, as its recovery from the natural gas stream is constrained by the capacity of the ethane extraction and petrochemical facilities in Alberta, which is assumed to remain constant. 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, and these volumes do not count in our ethane production numbers.

In the Current Policies Scenario, total NGL production grows 70% to 1 967 Mb/d (313 10³m³/d). NGL production growth is due to natural gas production growth in this scenario. Condensate also has the most significant growth in this scenario–growing 121% over the projection, from 349 Mb/d (56 10³m³/d) in 2020 to 770 Mb/d (122 10³m³/d) in 2050.

Figure R.20: Condensate has an increasing share of NGL Production in the Evolving Policies Scenario

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Figure R.21 shows ethane that is extracted from the natural gas stream, and ethane that is not recovered (which includes ethane reinjected in the natural gas stream). Growth in ethane that is not recovered means there is growing potential to recover more ethane, in the event of future increases in the capacity of the ethane extraction and petrochemical facilities.^Footnote 24

Figure R.21: Ethane Potential

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Figure R.22 shows total propane production broken out into its disposition. There are various uses of propane in Canada in all sectors, and over the next few years, petrochemical demand is projected to increase with the start of The Heartland Complex.^Footnote 25 Propane exports to the U.S. have grown significantly this past decade as U.S. domestic demand and propane exports from the U.S. grew. In 2019, propane exports from the west coast of B.C. began, in the form of liquefied petroleum gas (LPG). These west coast exports could continue to increase, with potential for significant additional LPG projects and exports. Given recent export growth trends, and potential for petrochemical growth above what is projected, the Canadian propane market could see tightening in the longer term if propane production levels off then slightly declines, as projected in the Evolving Policies Scenario.

Figure R.22: Propane Disposition

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Electricity

In the Evolving Policies Scenario, electricity demand grows by 47% from 2021 to 2050, as shown in Figure R.23. This is driven by growth in all sectors, with transportation and hydrogen production being emerging growth areas. In transportation, electrification provides an alternative in a sector long-dominated by RPP^{Definition *} use. Hydrogen production is another growth area for electricity demand, as electricity is used in electrolysis to produce hydrogen.

Figure R.23: Electricity Demand Grows Steadily in the Evolving Policies Scenario

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Currently, electricity makes up approximately 16% of Canada’s end-use energy demand. In the Evolving Policies Scenario, end-use electricity demand (excluding electricity to produce hydrogen) increases at an average annual rate of 1% over the projection period, which raises electricity’s share of end-use demand to nearly 30% by 2050. See Figure R.24.^Footnote 26

Figure R.24: Share of Electricity in End-use Demand by Sector and Total in the Evolving Policies Scenario

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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 EF2021 projections. Figure R.25 shows total Canadian installed capacity by fuel type, and Figure R.26 shows electric generation by fuel type. In the earlier part of the projection, renewables and natural gas replace phased out coal generation.^Footnote 27 Coal falls faster than previous projections, as recent announcements from companies suggest coal will be phased out of the Alberta electricity mix by 2023. In the longer term, falling costs lead to large growth in non-hydro renewables such as wind and solar. Nuclear generation remains relatively stable overall in the projection, with some significant year-to-year variation because of Ontario’s nuclear refurbishments in the first half of the projection period. The share of low and non-emitting generation (renewables, nuclear, and fossil fuel with CCS) increases from 82% currently to 95% in 2050.^Footnote 28

Wind and solar generation also increases in the Current Policies Scenario. However, given lower carbon prices and higher wind and solar costs, wind and solar increase to a lesser degree and there is a relatively higher share of natural gas generation compared to the Evolving Policies Scenario. In 2050, natural gas makes up 16% of total generation in the Current Policies Scenario. The share of renewables and non-emitting electricity increases to 83% by 2050, compared to 95% in the Evolving Policies Scenario.

Figure R.25: Electricity Capacity Grows Significantly in the Evolving Policies Scenario

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Figure R.26: Electric Generation Trends by Primary Fuel Type in the Evolving Policies Scenario

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The increase in non-hydro renewables is driven by falling costs, technological improvements, and improved integration of variable renewable energy^{Definition *} sources such as wind and solar. Figure R.27 shows that by 2050, wind and solar capacity is added in a variety of Canadian regions. Total wind capacity rises to over 57 GW and total solar capacity rises to 26 GW. Post 2030, solar is the fastest growing renewable.

Figure R.27: Increasing Capacity of Non-Hydro Renewables in the Evolving Policies Scenario

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Integration of increasing wind and solar–whose generation is variable due to changing wind and sun conditions–is supported in a number of ways in the Evolving Policies Scenario. Other forms of energy, such as hydropower and natural gas, help back up these non-hydro renewables. In the Evolving Policies Scenario, energy interconnection between provinces will increase, including between Manitoba-Saskatchewan and Alberta-B.C. This adds to significant trade in Eastern and Atlantic Canada, which could increase further if projects such as the proposed Atlantic Loop increase transmission capacity. This increased ability to exchange power helps regions integrate larger amounts of variable wind and solar energy. Finally, the Evolving Policies Scenario includes around 25 GW of utility scale battery storage. This level is based on the falling costs of storage, as well as the falling costs of renewables, especially solar. Storage is particularly critical for large additions of solar.

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.28 shows projected net exports out of Canada, as well as aggregate interprovincial trade volumes. Trade remains relatively small when compared to total generation.^Footnote 29

Figure R.28: Net Exports of Electricity and Interprovincial Trade

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View our data on electricity by region, source, and scenario in our interactive visualization tool, Exploring Canada’s Energy Future.

Explore a summary of electricity production in our EF2021 Fact Sheets: Electricity.

Hydrogen

In recent years there has been increasing interest in low-carbon hydrogen as an important fuel in Canada and the world’s transition to a low-carbon economy. Over the past few years, many countries including Canada, have released hydrogen strategies. EF2021 is the first edition of the Canada’s Energy Future series with a dedicated section on hydrogen supply and demand, and also introduces a hydrogen table in our online data appendix.

Our focus in this section is on hydrogen use as an energy carrier and produced by methods that emit little or no CO₂.^Footnote 30 In the Current Policies Scenario, we include only currently announced projects.

In the Evolving Policies Scenario, total hydrogen demand reaches 4.7 megatonnes (MT), or 565 PJ, by 2050, as shown in Figure R.29. This accounts for 6% of total end-use energy demand. By 2050, the industrial sector accounts for 65% of hydrogen use. In this sector, hydrogen is mainly used in steel manufacturing, oil sands production, and chemical and fertilizer production. The transportation sector accounts for 25% of hydrogen demand, mostly displacing diesel in long distance freight trucking and marine transportation. The final 10% of hydrogen is used in the residential and commercial sectors, where it is blended into the natural gas stream and used for space and water heating.

Figure R.29: Hydrogen Demand by Sector

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Figure R.30 shows hydrogen demand by province. Hydrogen demand is the highest in Alberta, which accounts for 53% of total hydrogen demand in 2050. Alberta’s relatively high demand is due to its existing industrial makeup, and its ability to produce hydrogen from natural gas with CCS, which has relatively lower costs than electrolysis earlier in the projection period. Alberta’s future hydrogen use is mainly in oil sands production, where it is used to replace natural gas as a source of process heat. By 2050, hydrogen demand in Alberta’s industrial sector accounts for 76% of the province’s total demand.

Figure R.30: Hydrogen Demand by Region

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Given that we assume hydrogen is produced to meet local demands (with no international or inter-provincial trade), hydrogen production aligns with demand. Accordingly, in the Evolving Policies Scenario, Canada produces 4.7 MT of hydrogen by 2050, matching domestic demand, and Alberta is the largest producer (with 2.5 MT of production in 2050).

In the early years of the projection, natural gas with CCS is the dominant technology for hydrogen production. Electrolysis powered by electricity from the grid and dedicated renewables becomes cost competitive towards the end of the projection. By 2050, natural gas with CCS makes up 57% of total production (Figure R.31). Production from electrolysis powered by dedicated renewables and the grid make up 33% and 9% respectively. Most regions in Canada produce hydrogen using electrolysis powered by electricity from the grid or dedicated renewables. Ontario has the highest hydrogen production from electricity, with 54% of Canada’s electrolysis-based total. By 2050 close to 90 TWh of electricity is used to produce 1.8 MT of hydrogen. Similarly, natural gas with CCS uses over 422 PJ of natural gas to produce 2.69 MT of hydrogen.

Figure R.31: Hydrogen Production by Technology

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Greenhouse Gas Emissions

Currently, energy use and GHG emissions in Canada are closely related. ECCC produces Canada’s official emission projections for the United Nations Framework Convention on Climate Change.^Footnote 31

The majority of GHGs emitted in Canada are a result of fossil fuel combustion. Fossil fuels provide much of the 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.^Footnote 32 The remaining emissions are from non-energy sources such as agricultural and industrial processes and waste handling.

Figure R.32 breaks out total primary demand into unabated fossil fuel demand, which will make up the majority of Canadian GHG emissions, and low emission sources, which include renewable, nuclear, fossil fuels with CCS, and fossil fuels for non-combustion purposes.^Footnote 34 Relative to 2019 levels, unabated fossil fuel consumption is 19% lower in 2030, 45% lower in 2040, and 62% lower in 2050. Meanwhile, low-emission energy rises, and accounts for 67% of energy use in 2050, compared to just 31% in 2021.

Trends vary among fossil fuels. Coal consumption significantly declines over the projection, driven by its phase-out from electricity generation by 2030.^Footnote 35 Use of RPPs, such as gasoline and diesel, gradually declines throughout the projection period. In the earlier years, this decline is driven by efficiency improvements and increased blending of biofuels, and in the long term is driven by increased electrification of the transportation sector. Use of natural gas continues to grow in the very early part of the projection period, following its increased role in power generation and its use in rising oil sands production. In the longer term, its overall use falls but its use with CCS increases significantly for industrial and power generation use and low-carbon hydrogen production.

Figure R.32: Total Primary Demand by Type

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Changing proportions of which fossil fuels are consumed leads to declining combustion-related GHG emissions per unit of fossil fuel energy used in the Evolving Policies Scenario, particularly with coal use declining to 2030. Deployment of CCS technology in industrial facilities also reduces the GHG intensity of fossil fuel use in the longer term. As shown in Figure R.33, fossil fuel emission intensity in 2030 is 9% lower than 2019, and 16% lower than 2005 in the Evolving Policies Scenario. By 2050 it is 29% lower than 2019, and 35% lower than 2005 in the Evolving Policies Scenario. This decline drives emission reductions when combined with falling fossil fuel use, as 2030 total fossil fuel use is 16% lower than 2019, and 6% lower than 2005. By 2050, total fossil fuel use is 46% lower than 2019, and 40% lower than 2005. 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 R.33: Fossil Fuel Emission Intensity Falls due to Higher Shares of Natural Gas, Less Coal, and Greater Adoption of CCS in the Evolving Policies Scenario

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Date modified:

2023-11-26