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This section presents results of the EF2019 Reference Case projection. This projection should not be viewed as a prediction, but as a possible future based on the assumptions described in the Assumptions section. It is important to note that although these figures only show the results from one projection, 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 later in the report.


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.

Key economic variables are shown in Table 3[8]. Economic growth averages about 1.7% per year over the projection period in the Reference Case. Economic growth over the projection is generally slower than the 1990-2017 historical period for a variety of reasons, including an aging population and slower global economic growth.

Table 3: Historical economic indicators compared to the outlook
Economic Indicators 1990-2017 Reference Case
Real Gross Domestic Product 2.7% 1.7%
Population 1.0% 0.9%
Inflation 1.7% 2.05%
Exchange Rate (average) $0.81 $0.78
Residential Floor space 2.0% 1.2%
Commercial Floor space 1.8% 1.9%

Key Uncertainties: Macroeconomics

  • 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 the economic 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.

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Energy Demand

This section focuses mainly on end-use, or secondary energy demand, by sector of the economy. 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.

Overall, EF2019 projects Canadian end-use energy demand to grow moderately from now until 2040. Figure 5 breaks this down by sector, showing moderate growth in residential, commercial, and industrial demand, and a decline in transportation demand. Projected growth is slower than historical. This is due to a variety of factors, including slower economic growth, improved energy efficiency, and various policies and programs such as transportation emission standards and carbon pricing.

Figure 5 Total end-use demand grows slower in the projection than historyFigure 5

This chart compares historical, 1990 – 2017, and projected, 2018 – 2040, total end-use growth rates for each sector. The residential sector grew historically by 0.2% on average, while it is projected to grow by 0.3% over the projection period. The commercial sector grew on average by 1.4% historically, and is projected to grow by 0.6%. the industrial sector grew on average by 1.4% historically, and is projected to grow by 0.4%. Transportation grew on average by 1.2% historically, and is projected to decline by 0.6%. Total end-use demand grew on average by 1.2% historically, and is projected to increase by 0.2% on average throughout the projection period.

Figures 6 through 9 show energy use in each of the sectors individually. These results highlight several key dynamics in Canadian energy demand. There is a large diversity of fuels used and future trends across Canada’s energy system. The residential sector shows this particularly well. In Quebec, electricity is used as a primary fuel to heat homes, while in Alberta natural gas is dominant. Atlantic Canada and the Northern Territories rely more heavily on oil products and biomass, while other provinces have a more diverse mix. This diversity is a well-established part of Canada’s energy system (see the CER’s Provincial & Territorial Energy Profiles), affects household expenses on energy, and continues in the EF2019 projection.

The transportation sector has been dominated by oil products. Improved fuel economy, as well as electrification, cause transportation energy use to decline over the projection[9]. Commercial and industrial demand is dominated by natural gas and electricity, and show moderate growth. Demand also varies across provinces and territories.

Figure 6 Residential energy use is diverse across the countryFigure 6

This chart breakdown residential demand by fuel type form 2005 to 2040. Biomass demand falls from 164.8 PJ in 2005 to 162.8 in 2040. Electricity demand increases from 543.4 PJ in 2005 to 686.8 PJ in 2040. Natural gas demand increases from 464.6 PPJ in 2005 to 737.2 PJ in 2040. Oil product demand declines from 138.9 PJ in 2005 to 46 PJ in 2040. Solar and geothermal demand increases from 0 in 2005, and 0.6 in 2019, to 6.87 in 2040. Other demands decrease by 1.4 PJ in 2005 to 0.1 PJ in 2040.

Figure 7 Commercial energy demand grows steadilyFigure 7

This chart breakdown commercial demand by fuel type form 2005 to 2040. Biomass demand increases from 0.02 PJ in 2005 to 0.5 in 2040. Electricity demand increases from 370.6 PJ in 2005 to 562 PJ in 2040. Natural gas demand increases from 703 PPJ in 2005 to 731.4 PJ in 2040. Oil product demand declines from 228.8 PJ in 2005 to 222.3 PJ in 2040. Solar and geothermal demand increases from 0 in 2005, and 0.6 in 2019, to 8.4 in 2040.

Figure 8 Industrial demand increases, led by natural gasFigure 8

This chart breakdown industrial demand by fuel type form 2005 to 2040. Biomass demand falls from 470 PJ in 2005 to 350.4 in 2040. Electricity demand increases from 914 PJ in 2005 to 1029.3 PJ in 2040. Natural gas demand increases from 1991.4 PPJ in 2005 to 3056.8 PJ in 2040. Oil product demand increases from 1743.1 PJ in 2005 to 2135.8 PJ in 2040. Other demands decrease from 205.3 PJ in 2005 to 149.5 PJ in 2040.

Figure 9 Transportation demand declines as energy efficiency improves steadilyFigure 9

This chart breaksdown transportation demand by fuel type from 2005 to 2040. Aviation fuel demand increase from 255.7 PJ in 2005 to 320.5 PJ in 2040. Gasoline demand decreases from 1354.1 PJ in 2005 to 1062 PJ in 2040. Diesel demand falls from 745.1 PJ in 2005 to 622.3 PJ in 2040. Biofuels demand increases from 11.1 PJ in 2005 to 89.3 PJ in 2040. Electricity demand increases from 3.5 PJ in 2005 to 64.8 PJ by 2040. Heavy fuel oil demand decreases from 83 PJ in 2005 to 30.3 PJ in 2040. LPG demand increases from 11.9 PJ in 2005 to 13 PJ in 2040. Lubricant demand remains relatively flat increasing only 0.02 PJ from its 2005 demand of 2.1 PJ. Natural gas demand increases from 1.8 PJ in 2005 to 58.5 PJ in 2040.

Heating and cooling strategies in the clean energy transition

In May 2019, the International Energy Agency (IEA) and the NEB released the outcomes of their collaborative research on Canada’s buildings sector. Heating and cooling strategies in the clean energy transition: Outlooks and lessons from Canada’s provinces and territories provides estimates of how Canada’s buildings sector could evolve in the IEA’s Reference Technology Scenario and lower-carbon Clean Technology Scenario.

Energy use and emissions from Canada’s building sector could decline significantly between now and 2050 using known technology solutions. Reduced energy expenditures provide incentive to improve energy efficiency and adopt new technologies. However, these alone will not be enough to achieve the Clean Technology Scenario, and additional policy action would be necessary.

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.

As shown in Figure 10, the share of natural gas increases the most, a result of natural gas use for power generation and for oil sands production. Coal’s share of primary demand falls considerably due to declining coal-fired power generation.

Figure 10 Primary demand grows moderately, led by natural gasFigure 10

This chart compares primary demands by fuel in 2017 to demands in 2040. Natural gas demand increases from 4670 PJ in 2017 to  5645 in 2040. RPP and NGL demand declines from 4739 PJ in 2017 to 4482 PJ in 2040. Coal, coke and oven gas demand decreases from 738 PJ in 2017 to 167 PJ in 2040. Hydro demand increases from 1407 PJ in 2017 to 1582 PJ in 2040. Nuclear demand declines from 1056 PJ in 2017 to 1003 PJ in 2040. Other renewables increases from 916 PJ in 2017 to 1080 PJ in 2040.

Energy use grows much slower than both the economy and Canada’s population, implying energy intensity–measured in energy use per capita or per $ GDP–declines. This is summarized in Figure 11. From 2018 to 2040, real GDP increases over 40%, and population increases over 20%. Primary energy use increases less than 5%. These different trends imply that energy use per $ GDP declines nearly 30% from 2018 to 2040, while energy use per person declines over 15%.

Figure 11 The economy grows faster than energy use, and energy intensity declines Figure 11

This chart shows key economic indicators and energy intensity growth from 2018 – 2040. Real GDP, population, and primary energy use are projected to increase by 43.5%, 21.2% and 1.8% respectively. Energy use per person and energy use per $ real GDP are expected to decline by 16.1% and 29.1%, respectively.

Key Uncertainties: Energy Demand

  • Technological influences: The impacts of technology on the energy system can be substantial and difficult to predict. The Reference Case assumes modest growth of emerging technologies.

  • 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. The most notable example of this would be the trend of the steam to oil ratio (SOR) for in situ oil sands development, which will have a substantial effect on future natural gas demand in Alberta.

  • Electrification: New sources of electricity demand could have large implications for future trends. This includes a shift towards electricity delivering energy services currently provided by other fuels, such as heating and transportation. It also includes new uses, such as cryptocurrency mining.

  • Climate policies: Several measures are announced but are currently in initial stages of development, such as the proposed Canadian Clean Fuel Standard. These policies are not included in EF2019 and could impact energy trends as they are implemented. Likewise, small or large changes to existing policies, or changes in policy direction, could also impact the trends shown in the Reference Case projections.

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Crude Oil

Canada produces crude oil for domestic refining as well as for exports. In 2018, Canadian crude oil production averaged 4.8 million barrels per day (MMb/d) (761 thousand cubic metres per day (103m3/d)). Growth in recent years has been dominated by new oil sands facilities coming online.

Figure 12 shows the outlook for Canadian crude oil production. By 2040, Canadian crude oil production in the Reference Case is around 7 MMb/d (1 130 103m3/d), growing by 49% from 2018. Production is largely located in Alberta, with additional volumes in Saskatchewan and offshore Newfoundland and Labrador.[10]

Figure 12 Total crude oil production continues to increaseFigure 12

This chart shows total crude oil production by type. Eastern Canadian production declines from 0.3 MMb/d in 2005 to 0.1 MMb/d by 2040. WCSB condensate production grows from 0.2 MMb/d in 2005 to 0.9 MMb/d by 2040. WCSB conventional light production grows from 0.5 MMb/d in 2005 to 0.8 MMb/d by 2040. WCSB conventional heavy production grows from 0.6 MMb/d in 2005 to 0.8 MMb/d by 2040. Mined bitumen production grows from 0.6 MMb/d in 2005 to 1.7 MMb/d by 2040. In situ bitumen production grows from 0.4 MMb/d in 2005 to 2.7 MMb/d by 2040.

Figures 13 through 16 show the various forms of crude oil produced in Canada currently, and projected in EF2019. Although oil sands production dominates growth, Canada produces a wide variety of crude oil types across the country.

Production growth in the oil sands continues, led by new phases of existing in situ projects. These additions are economic given Reference Case price levels. Production growth also comes from technology improvements that increase productivity. In the near-term, the Alberta government’s curtailment program has led some projects to delay when they were scheduled to come online. This leads to faster growth in the 2027-2033 period.

Conventional production is classified as light or heavy, depending on the API gravity of the oil. In 2018, 48% of western Canadian conventional production was heavy, 52% was light. Growth in non-oil sands production is due primarily 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.

Condensate comes primarily from natural gas wells and is removed from the gas stream either at the well head or at processing plants before the gas is sent to its intended market. Once removed, the condensate is used in a number of industrial processes, most notably as a diluent for bitumen and heavy oil. Currently, the majority of condensate production comes from Alberta. Much of the growth in condensate production in the projection period occurs in B.C., as producers focus on liquids-rich natural gas plays like the Montney.

Offshore production in the Reference Case increases in the near term as Hebron continues to ramp up and new wells from existing facilities are brought online. A new offshore discovery adds production in 2028, with a second new discovery in 2034. Hebron is the only project in Newfoundland’s offshore that produces heavy oil. Other projects produce either light or medium grade oil.

Figure 13 Oil sands production from in situ continues to increaseFigure 13

This chart shows oil sands production by type from 2005 to 2040. Mined bitumen grows from 0.6 MMb/d in 2005 to 1.7 MMb/d by 2040. In situ bitumen production grows from 0.4 MMb/d to 2.7 MMb/d by 2040

Figure 14 Conventional oil production increases in Western Canada, mostly Alberta light and Saskatchewan heavyFigure 14

This graph shows Canadian conventional oil production from 2005 to 2040 in the Reference Case. Total production in 2005 was 1.03 million b/d and the majority of production was made up by Alberta light oil and Saskatchewan heavy oil. By 2040 total production increases to 1.6 million b/d, with the majority continuing to be Saskatchewan heavy oil and Alberta light oil.

Figure 15 Condensate production follows natural gas production growth and increasing diluent demand Figure 15

This graph shows condensate production in Canada from 2010 to 2040 in the Reference Case. In 2005 condensate production was 31 thousand b/d and this increases to 740 thousand b/d in 2040.

Figure 16 Newfoundland offshore oil production increases in the near term and steadily declines Figure 16

This chart shows Newfoundland offshore oil production from 2005 to 2040. Production grows from 0.3 Mb/d in 2005 to 0.31 in 2023. Production then declines reaching 0.1 Mb/d in 2040.

Figures 17 and 18 illustrate the projections for crude oil exports in EF2019. Exports of crude oil are the difference between the net available oil supply[11] and the domestic disposition[12] of crude oil. Given growing supply and slowly declining domestic use of crude oil, crude oil exports increase over the outlook period.

Figure 17 Light balance projects increasing light oil exportsFigure 17

This chart shows the light oil supply versus light oil exports. Domestic light oil supply grows from 1.5 MMb/d in 2010 to 2.3 MMb/d in 2040. Domestic disposition grows from 0.7 Mb/d in 2010 to 0.8 MMb/d in 2040. Exports grow from 0.8 MMb/d in 2010 to 1.5 MMb/d in 2040.

Figure 18 Heavy balance sees flat domestic demand and rising exportsFigure 18

This chart shows the heavy oil supply versus heavy oil exports. Domestic heavy oil supply grows from 1.5 MMb/d in 2010 to 4.7 MMb/d in 2040. Domestic disposition grows from 0.3 Mb/d in 2010 to 0.4 MMb/d in 2040. Exports grow from 1.3 MMb/d in 2010 to 4.3 MMb/d in 2040.

In recent years, production growth in the WCSB has outpaced growth in pipeline capacity. This has been a key trend in Canadian oil markets[13]. Figure 19 provides a detailed look at available supply from the WCSB and takeaway capacity. 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. This capacity is calculated by pipeline operators on a daily basis. The available capacity of existing pipeline systems is estimated by the CER using historical averages. The available capacity of new pipelines is estimated by comparing that pipeline to existing pipelines with similar characteristics.

Figure 19 Crude oil pipeline capacity vs. total supply available for exportFigure 19

This chart shows the current and announced crude oil export pipeline capacity versus the projected crude oil supply available for export. Existing pipeline capacity grows from 2.9 MMb/d in 2010 to 4.3 MMb/d in 2040. Announced pipeline capacity additions grow from 0 MMb/d in 2010 to 1.7 MMb/d in 2040. Crude oil exports by rail grow from 0 MMb/d in 2010 to 0.4 MMb/d in 2040. Crude oil available for export grows from 2.2 MMb/d to 6.2 MMb/d by 2040.

Crude-by-rail volumes are divided into two types, based on CER estimates: structural and variable. Structural refers to crude oil that is likely to be exported by rail regardless of a given WCS-WTI differential. Variable refers to crude oil rail exports supported by the WCS-WTI differential, and in response to potential pipeline constraints. Variable rail export volumes are minimal for much of the projection period, as new pipeline capacity is added. Post 2035, crude-by-rail export volumes increase, reaching volumes similar to current export levels.[14]

The volumes and timing of capacity additions to existing systems are as announced by the operators of those pipelines. Likewise, capacity and timing of the three pipelines included in Table 4 are as per the announcements of the operators.

Table 4: Assumed announced crude oil capacity additions
Enbridge Line 3 Keystone XL TransMountain Expansion
Expected in-service date 2020 2022 2023
Expected date at full capacity 2021 2023 2024
Full Capacity (Mb/d) 382 813 528

Note: Project timing assumptions were made early in the analysis phase, and may not reflect latest announcements. For example, recent announcements by Trans Mountain state that the Trans Mountain Expansion Project could be in-service as early as mid-2022.

What happens if assumed pipelines are not built?

The timing and magnitude of capacity additions, whether through the construction of new pipelines or increased utilization of existing ones, is uncertain. A number of other assumptions would be affected if the new pipeline projects assumed in EF2019 were significantly delayed or cancelled.

What could happen in such a scenario is difficult to predict. In fall 2018, production growth beyond available pipeline capacity and refinery maintenance in the U.S. led to a backlog of crude oil in Canada. This led to increasing storage levels, increased crude-by-rail volumes, and widening differentials between WCS and WTI. The differentials were wide enough for the Alberta government to enforce mandated curtailment volumes to reduce production levels, which brought the differential in line with historical norms. (Additional information is available: Western Canadian Crude Oil Supply, Markets, and Pipeline Capacity and Optimizing Oil Pipeline and Rail Capacity out of Western Canada – Advice to the Minister of Natural Resources).

These recent experiences show that Canadian price differentials, production, storage, and crude-by-rail volumes are sensitive to the availability of pipeline capacity. The exact nature of the impact will be related to the current market context, policy responses, and specific events including planned and unplanned outages. There could also be implications on other market factors, such as oil and gas investment, production and the adoption of new technology to increase the capacity of existing systems.

Key Uncertainties: Crude Oil

  • Future oil prices: Oil prices are a key driver of future Canadian oil production and a key uncertainty to the projections in EF2019. Oil prices could be higher or lower depending on demand and policy trends, technological developments and geopolitical events.

  • The pace of technological development in the oil sands: EF2019 assumes gradual technological improvement in the sector. Technology development could occur either more or less rapidly than assumed in this analysis and that could impact the oil sands production projection. Potential advances that could change the supply projections include solvent-based processes, other steam reduction technologies, and electrification.

  • Take away capacity: The existence of take away capacity, and market and policy responses to lack of capacity (such as Alberta’s recent and on-going production curtailment) will influence future production growth.

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Natural Gas

Canadian natural gas is produced for domestic use, as well as for exports. Canadian marketable natural gas production averaged over 16 Bcf/d or 457 million cubic metres per day (106m3/d) in 2018.

Alberta natural gas production remained steady over the last few years, while B.C. production continued to ramp up. 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.
  • New natural gas processing plants helping to debottleneck some gas gathering systems.
  • Natural gas liquids in some natural gas plays driving drilling and production despite low prices.

In the near-term, natural gas production declines, given less drilling capital expenditures due to lower natural gas prices. Production from new wells won’t be able to keep pace with the declining production from existing wells. As a result, total production declines until 2023. In the longer term, rising prices and the onset of LNG exports leads to production growth. Exploration and development spending associated with LNG exports support higher capital expenditure. This leads to more natural gas wells and production in the WCSB. By 2040, natural gas production reaches 21 Bcf/d (606 106m3/d) (See Figure 20).

Figure 20 Total natural gas production by region continues to be dominated by Alberta and B.C.Figure 20

This graph shows Canadian natural gas production by province from 2005 to 2040 in the Reference Case. Total production in 2005 was 17.2 Bcf/d and this increases to 21.4 Bcf/d in 2040. Nearly all of this production comes from Alberta and British Columbia. In 2040 production in these provinces is 11.1 and 9.9 Bcf/d respectively.

Figure 21 shows production by type of natural gas. Production growth is led by tight natural gas produced from the Montney Formation. Tight natural gas production from the Montney formation has grown significantly over the past five years. Alberta Deep Basin tight natural gas production grows moderately, as well as some small shale gas growth from the Duvernay and Horn River shales, and solution gas. Conventional and coal bed methane production declines over the projection period.

Figure 21 Natural gas production by type increases led by production from the Montney Formation Figure 21

This graph shows natural gas production by type from 2005 to 2040 in the Reference Case. Total production in 2005 was 17.2 Bcf/d, with conventional gas making up the majority of production at 9.9 Bcf/d. In 2040 total gas production increases to 21.4 Bcf/d in 2040, with tight gas making up the majority of production at 17.3 Bcf/d.

Natural gas exports have increased over the last few years, mostly due to increasing exports to the Western U.S. Imports of natural gas have been stable over the last decade, hovering between 2-3 Bcf/d (55 106m3/d). Imports could potentially rise as pipeline capacity increases from the Appalachian Basin in northeastern U.S. to Dawn, Ontario. Net natural gas exports have increased slightly over the past few years.

Projected net pipeline exports, which is calculated as Canadian natural gas production less Canadian demand, is shown in Figure 22[15]. In the early 2020’s, declining production and Canadian natural gas demand growth leads to shrinking net exports. As production ramps up after 2023, production growth starts to outpace demand growth and net exports rise. By 2025, LNG exports begin to contribute to the growth in net exports.

Figure 22 Natural gas supply and demand balance sees net exports increasing the in the longer termFigure 22

This graph shows natural gas production, demand, assumed LNG exports, and net pipeline exports from 2015 to 2040 in the Reference Case. From 2015 to 2040 marketable production increases from 15.2 Bcf/d to 21.4 Bcf/d. Demand increases from 9.9 Bcf/d to 12.2 Bcf/d. LNG exports increase from 0 to 3.7 Bcf/d. Net exports in 2015 and 2040 are 5.5 Bcf/d, which fall over the first part of the projection then increase after 2026.

Key Uncertainties: Natural Gas

  • Future natural gas prices: Prices could be higher or lower, which would lead to different production results.

  • 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. Extended 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 commissioning a new LNG export facility or phase may change in the future, influencing future volumes of LNG exports in Canada.


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Natural Gas Liquids

Natural gas liquids (NGLs) are present with most natural gas production, and is the main source of NGL production in Canada. Demand for certain NGLs, like oil sands demand for condensate or the petrochemical demand for ethane, propane, and butanes, add value to natural gas production and drive its increase. Raw natural gas at a wellhead is comprised primarily of methane, but often contains ethane, propane, butane, condensate and other pentanes. In 2018, 1 158 Mb/d (184 103m3/d) of NGLs were produced in Canada.

Figure 23 shows that NGL production grows over 80% over the projection period. Growth is dominated by condensate, which more than doubles to 2040. Condensate demand and prices have influenced natural gas drilling to focus on NGL-rich plays. Condensate is added to bitumen as a diluent to enable it to flow in pipelines and rail cars.

Figure 23 Condensate and pentanes plus lead natural gas liquids production increaseFigure 23

This graph shows total natural gas liquids production from 2010 to 2040 in the Reference Case. Total production increases from 650 thousand b/d in 2010 to 1.8 million b/d in 2040. The majority of the increase in production comes from liquid condensate which increases from 40 thousand b/d in 2010 to 740 thousand b/d in 2040.

Propane and butane production follows natural gas production, and increases over the projection period. Demand for these NGLs increases in the mid-term as petrochemical use in Alberta and propane and butane exports rise.

Ethane, the majority of which is extracted at large natural gas processing facilities located on major natural gas pipelines in Alberta and B.C., made up 22% of NGL production in 2018 . Ethane production increases slowly over the projection to 2040, as its recovery from the natural gas stream is essentially constrained related to the capacity of the petrochemical facilities in Alberta. Ethane produced in excess of this capacity is reinjected back into the pipeline system to be consumed by end users as natural gas.

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

For additional data on crude oil, natural gas and NGL production, see the EF2019 supplemental tables. These datasets include additional geographical and monthly detail on production and drilling trends.

Further information about these and other data sets is available in the “Access and Explore Energy Futures Data” section later in this report.

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 they are targeted by future natural gas drilling.

  • LNG composition: The amount of NGLs that remain in natural gas to be liquefied for LNG varies throughout the world. This can be specified in the contracts underpinning a liquefaction facility, the energy content required by the LNG importer, and the gas composition of the feedstock gas used by the LNG exporter.

  • Petrochemical development: There is potential for ethane and propane recovery to increase further if there is an uptick in incremental petrochemical capacity requiring either as feedstock. This includes incentives captured in the second phase of the Petrochemicals Diversification Program.

  • Global LPG export market: Canada has approved several large-scale facilities to export LPG from B.C.’s coast. Propane will likely be the dominant liquid exported. However, these facilities would have the potential to ship butanes and future market developments could present a scenario where butanes is a viable export product. The composition of the LPG stream exported at these terminals could impact domestic NGL prices and the attractiveness of drilling for NGL-rich natural gas.

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Canada’s diverse electricity generation mix varies significantly among provinces and territories, reflecting the type of energy available, economic viability, and policy choices. Over the past decade, there have been significant changes in Canadian electricity, and it continues to evolve in the EF2019 projection. From 2017 to 2040, electric capacity grows by 16%, driven by increases in renewables and natural gas to meet new demand growth and replace retiring units, mainly coal. Total Canadian electricity demand increases nearly 1% per year over the projection period. Nuclear power is a key part of Ontario and New Brunswick’s electricity systems, and over the projection period nuclear units in Ontario are refurbished, according to provincial plans. Figure 24 provides an overview of the electricity capacity mix across Canada in 2017 and projected to 2040.

Figure 24 Electric capacity mix varies by regionFigure 24

These pie charts illustrate trends in Canada’s generation capacity. The pie charts show provincial generation capacity share by fuel type in 2017 and 2040. Hydroelectricity provides the majority of electric capacity in Quebec, B.C., Manitoba, Newfoundland and Labrador, and Yukon. Alberta, Saskatchewan, and Nova Scotia have primarily thermal-based complemented by a growing non-hydro renewables. Thermal units that are fueled with refined products make up large shares of the Capacity mix in Northwest Territories (NWT) and Nunavut.

Canada has a relatively low emitting electricity grid. In 2017, 81% of its generation was from non-emitting sources. This is primarily due to its Canada’s large base of hydro power, which makes up the majority of electricity produced in B.C., Manitoba, Quebec, and Newfoundland and Labrador. There has also been a significant increase in non-hydro renewables. In 2005, wind and solar made up 0.2% of the electricity generation mix. By 2017 this share increased to 5%, and by 2040 increases to 10%.

Figure 25 shows projected growth in non-hydro renewables. This growth is supported by policy development, as well as improved economics. Over the outlook, installed capacity of wind nearly doubles, while solar more than doubles. Over the last several years, there have been some key policy changes in several provinces regarding renewable development. Alberta has recently terminated the former Renewable Energy Procurement program, which would have led to an additional 3 600 MW of guaranteed renewable additions[16]. Ontario also recently terminated feed-in-tariff and procurements of large renewable projects. These policy changes do not mean renewable development will stop in these regions, however. EF2019 assumptions on declining wind and solar costs support growth in renewable development, despite fewer direct policy initiatives.

Figure 25 Renewable capacity increases over the projectionFigure 25

This chart shows total non-hydro renewable capacity. Solar capacity increases from 2.9 GW in 2018 to 6.0 GW by 2040, wind capacity increases from 13.0 GW in 2018 to 23.8 GW by 2040, and Biomass capacity increases from 2.5 GW in 2017 to 3.2 GW by 2040.

In the Reference Case, total Canadian electricity generation increases by over 90 terawatt hours (TW.h) from 2017 to 2040, an increase of about 14%. Hydro, other renewables, and natural gas lead this growth, while coal and nuclear generation decline. Figure 26 shows these trends by fuel type. Additional renewables and decline of coal reduces the overall emission intensity of Canada’s electricity mix. In 2017, Canada averaged 130 grams of CO2 equivalent per kilowatt hour (gCO2e/kW.h). In 2040, this falls to less than 80 gCO2e/kW.h, a decrease of about 40%.

Figure 26 Electricity generation by fuel shows coal phasing out, and more renewables and natural gas addedFigure 26

This graph shows total electricity generation by fuel type from 2005 to 2040. In 2005 total generation was 595.4 TW.h and this increases to 737.1 TW.h in 2040. The biggest fuel type is hydro and makes up 439.5 TW.h of generation in 2040.

As the proportion of variable renewable energy, such as wind and solar, increases, variations in generation from hour-to-hour and minute-to-minute become increasingly important in balancing electricity production and use. Figure 27 illustrates simulated generation, which includes interprovincial and international trade, for 24 hours in the four seasons across various regions in Canada in 2040. As wind and solar generation vary throughout the day, other generation sources fill in to meet load requirements. In addition, there is variability in the output of variable renewables across the seasons.  For regions that have low shares of non-hydro renewables, the generation mix remains fairly constant and non-hydro renewables are integrated in the system without significant changes to system operation.

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 show great variability hour-to-hour and day-to-day. This results in many different ways electricity demand and renewable generation can fall on any given day. The graphs below illustrate one way these variables could line up.

Figure 27 Hourly electricity generation by fuel source for a simulated day for various Canadian regions in 2040Figure 27

This panel of graphs shows the hourly generation fuel mix for a randomly chosen day in each given month and provincial region. Manitoba, British Columbia, Quebec and Atlantic Canada are dominated by hydro, while Alberta, Saskatchewan and Ontario have a more varied fuel mix.

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 periods of peak electricity demand.

Figure 28 shows potential for growth in net exports out of Canada, as well as aggregate interprovincial trade volumes. One of the reasons for increased interprovincial trade is the Maritime Link, which is a new energy loop for Atlantic Canada. This new transmission corridor will create stability and reduce reliance on fossil fuel generation in the region. The project will allow Nova Scotia to import more power from Newfoundland and Labrador, reducing the province’s coal generation. This link could also facilitate more renewable energy development in the region.

Figure 28 Net exports of electricity decrease by 2040 while interprovincial transfers remain steadyFigure 28

This graph shows interprovincial and international electricity trade from 2018 to 2040. In 2018 net exports and interprovincial transfers were 73.0 and 47.2 TW.h respectively. In 2040 net available for exports decrease to 66.9 TW.h and interprovincial trade increases to 54.4 TW.h.

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 less commercially mature technologies like wind, solar, and coal with CCS.

  • 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.

  • Future projects and developments: Climate policies, fuel prices, electrification and power sector decarbonization in export markets could impact future projects and transmission intertie developments.

  • Changes to capacity mix in export markets: Planned nuclear and coal retirement, and growing renewables, could impact capacity expansion plans, generation and flows between trading jurisdictions.

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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 29 shows Canadian production and consumption of coal in Canada in 2017. Thermal coal accounted for 88% of total Canadian coal consumption in 2017. In the Reference Case, demand for thermal coal declines by 89% over the projection period, falling from 30 million tonnes in 2017 to just over 3 million tonnes in 2040. 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.

Domestic demand for metallurgical coal used in steel manufacturing declines from 4.4 million tonnes in 2017 to just under 4 million tonnes by 2040. Global demand for metallurgical coal grows moderately over the projection period, resulting in steady growth in net exports from Canada. Total metallurgical coal production in Canada increases from about 30 million tonnes in 2017 to 30.5 million tonnes by 2040. Total production declines from about 61 million tonnes in 2017 to 38 million tonnes in 2040.

Figure 29 Canadian coal production and disposition trends driven by falling thermal demand Figure 29

This chart compares thermal and metallurgical coal demands, as well as net exports in 2017 to 2040. Thermal coal demand is expected to fall from 34.5 million tonnes in 2017 to 2.3 in 2040. Metallurgical coal demand and net exports are expected to increase from 3.1 million tonnes to 3.3, and from 23.3 million tonnes to 27, respectively.

Key Uncertainties: Coal

  • Prices: Future price movements in the global coal markets are a key uncertainty for Canadian coal exports.

  • 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.

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Greenhouse Gas Emissions

Currently, energy use and greenhouse gas (GHG) emissions in Canada are closely related. ECCC prepares and annually updates greenhouse gas emissions projections to 2030.[17]

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. Emissions from fossil fuels, including those used for the production of energy, accounted for 81% of Canadian GHG emissions in 2017. The remaining emissions are from non-energy sources such as agricultural and industrial processes, and waste.

Figure 30 shows the total demand for fossil fuels in the Reference Case. From 2018 to 2040, total fossil fuel use grows less than 1%, but growth varies significantly across the different fuel types. Natural gas use, the least GHG-intensive fossil fuel, increases by 18%. Oil product use declines by 7%, while coal use declines by nearly 75%.

Figure 30 Total demand for fossil fuels increases slowly, with rising natural gas and falling oil and coal useFigure 30

This chart shows fossil fuel use from 2005 to 2040. Coal and oil use decline from 12.92 PJ and 4776.8 PJ in 2017 to 167.2 PJ and 4482 PJ in 2040, respectively. Natural gas demand increases from 3627.8 PJ in 2005 to 5645 PJ in 2040.

While total fossil fuel consumption grows in the Reference Case, changing proportions of fossil fuels consumed leads to declining GHGs per unit of fossil fuel energy used, as shown in Figure 31. Deployment of CCS technology in power and industrial facilities also reduces the GHG intensity of fossil fuel use. In 2040, fossil fuel emission intensity is 7% lower than 2017, and 12% lower than 2005. Accounting for reductions in non-combustion emissions, such as reducing methane leaks, as well as including emission credits purchased through international trading mechanisms (like Quebec’s emission trading with California) could further decrease emission intensity.

Figure 31 Fossil Fuel Emission Intensity falls due to higher shares of natural gas and less coal Figure 31

This figure shows fossil fuel emission intensity from 2005 to 2040. In 2005, energy intensity was roughly 63 grams of CO2 per mega joule. This declines to roughly 55.3 grams of CO2 per mega joule by 2040.

Key Uncertainties: GHG Emissions

  • Technology development: Future adoption of low carbon technologies could alter the course of fossil fuel demands shown here. Increased deployment of technologies such as carbon capture, use and storage, could weaken the link between fossil fuel use and future emission trends.

  • Future climate policies: The evolution of climate policies in Canada will be an important factor in fossil fuel combustion and GHG emission trends. Future developments in policies such as carbon pricing, energy and emission regulations, and support for emerging technologies could all alter these fossil fuel projections.

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  • [8] Macroeconomic projections are developed by Stokes Economics.
  • [9] On an energy equivalent basis, electric vehicles use less energy to travel a given distance than conventional vehicles, all else being equal. This implies that as electric vehicles gain market share, the offsetting reduction in gasoline demand will be larger than the electricity added, leading to a net reduction. Additional details on electric vehicle efficiency and economics can be found in a recent CER Market Snapshot: Levelized Costs of driving EVs and conventional vehicles.
  • [10] Information on crude oil ultimate potential and remaining reserves is available in the EF2019 Data Appendices.
  • [11] All non-upgraded bitumen and nearly all conventional heavy oil must be blended with lighter hydrocarbons to reduce its viscosity and allow it to flow on pipelines. Bitumen that is transported by rail is generally blended as well, although sometimes at lower levels than for pipelines. The resulting blend of produced crude oil or bitumen, after accounting for production losses and any diluent recycling, is the net oil supply available for domestic and foreign markets.
  • [12] This is the volume of Canadian crude oil that is required for feedstock at Canadian refineries. This volume is influenced by a number of factors such as refined product demand and the amount of foreign oil that is processed within Canada. Economics at any particular refinery dictate whether that facility uses Canadian or foreign oil to produce the refined petroleum products needed to meet Canadian and foreign demand.
  • [13] For more information see Western Canadian Crude Oil Supply, Markets, and Pipeline Capacity and Optimizing Oil Pipeline and Rail Capacity out of Western Canada – Advice to the Minister of Natural Resources.
  • [14] Efficiency improvements, improved rail economics, and policy action are all potential uncertainties that could affect rail export volumes and the WCS-WTI differential. Given the many uncertainties, EF2019 assumes a constant WCS-WTI differential in the long term, as shown in Figure 1. However, additional rail volumes could require a wider differential to support them.
  • [15] 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.
  • [16] The Renewable Energy Procurement program was originally for 5 000 MW. Of that, 1 400 MW were previously awarded in 3 phases. These contracts remain in place and are included in the projections.
  • [17] Data sets are also available through the Government of Canada’s Open Government portal.
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