All net-zero scenarios point to two developments over the next few decades: first, the electricity sector itself will be fully decarbonized; second, electricity demand will grow sharply, especially in net-zero scenarios, to meet increased demand from activities formerly powered by fossil fuels. As a result, this sector needs to evolve significantly over the next decades.
9.1.1 Evolving toward a lower carbon mix
Canada’s current electricity generation is dominated by hydro and nuclear generation, making it one of the OECD countries with the lowest GHG emissions per kWh generated. By 2040, thermal generation with fossil fuels, which accounts for only about 20% of the current mix, is reduced by half in absolute terms for CP30, and almost disappears in all net-zero reduction scenarios. The main difference across scenarios is the amount of demand for electricity, associated with the electrification of new sectors. In the various scenarios, demand increases more quickly in tighter schedules to reach net-zero, to then converge around similar levels once net-zero is reached (2060).
Figure 9.1- Electricity generation #
Figure 9.1 also shows that the replacement of fossil thermal production and the increase in total electricity demand are provided primarily by a balance of wind and nuclear for CP30, while across GHG reduction scenarios it is met overwhelmingly by wind, followed—to a substantially lesser extent—by solar. Hydroelectricity shrinks in terms of its role in the overall mix as its output remains more or less constant across time and scenarios. Nuclear also remains at similar levels although this hides a transformation in the technology used, with more SMRs as part of this generation starting in 2050.
9.1.2 Sensitivity analysis
With a strong flexible base-load generation and considerable hydroelectric reservoirs, Canada will not be required to build up as much renewable capacity as other countries. However, uncertainties remain about (i) the technical and economic constraints of integrating such large shares of variable generation, (ii) the costs of battery storage capacity, and (iii) the development of nuclear SMRs, making relevant a sensitivity analysis based on parameters aiming to provide the planned increase in demand. Two alternative scenarios, both based on NZ50, are considered:
- IntA: maximum electricity generation from variable renewable sources capped at 30% of the total mix and limited storage capacity.
- IntB: maximum electricity generation from variable renewable sources capped at 30% of the total mix, limited storage capacity, investments in nuclear capped at NZ50 levels, and with firm/guaranteed capacity in each province that can be met through interconnections with neighbouring jurisdictions.
Both scenarios explore how the model accommodates a sizeable share of variable generation, but this is more constrained in terms of its role in the overall mix. In IntA, more limited storage capacity can be compensated through any form of baseload generation, which tends to favour nuclear generation. In IntB, compensation must be accomplished through increased hydro generation and/or additional interprovincial exchanges rather than additional nuclear investment.
By design, both alternative scenarios show less variable electricity generation capacity installed over time. In IntA, this is compensated by more nuclear capacity; in IntB, by more hydro. In IntA, growth in nuclear stems from new SMRs, some existing conventional generation, and new advanced reactor powerplants, a result of more investment not allowed in IntB.
Electricity generation, which is determined by demand, presents an almost identical evolution over time for the three scenarios considered here. With electricity demand growing strongly after 2030, scenarios start diverging in terms of production and installed capacity, as seen from 2040. By 2050, electricity production remains dominated by hydroelectricity, which accounts for 33% of the total for NZ50 and IntA but reaches 39% in IntB. This increase in hydro production is accompanied by hydrogen, which represents 5% of electricity production against zero for the two other scenarios, and thermal, which increases from 1% to 2.4% by 2050 in this scenario. These increases are mainly at the expense of nuclear (7% vs. 14% in NZ50) and wind (25% vs. 29%). Since hydro expansion is constrained in IntA, changes with respect to NZ50 occur in the other energy production sources. In 2050, by construction, nuclear increases to 29%, a share similar to hydroelectricity, while wind and solar shrink but remain important at 18% and 7% of total production respectively.
Differences in production capacity are more dramatic since this capacity is determined by the energy source and its capacity factor, i.e., the fraction of peak power produced in a year, which varies according to production source. For example, while the total electricity production is multiplied by 2.1 between 2016 and 2050, to reach 1,341,000 TWh, production capacity is multiplied by 3.4, moving from 147 to 489 GW for NZ50. Favouring nuclear, with a capacity factor above 90%, IntA sees its capacity multiplied by only 2.7 (406 GW), while IntB, which preserves more variable sources, falls in-between at 448 GW. By 2050, nuclear capacity in IntA is projected to reach 50 GW, compared with 25 GW for NZ50 and 13 GW for IntB. This is sufficient to reduce the need for renewable capacity from 239 GW to 155 GW in IntA,
with a collateral reduction in storage capacity from 68 to 45 GW. For IntB, hydro capacity increases from 89 to 107 GW, half at the expense of nuclear. While variable renewables capacity is also reduced by 63 GW with respect to NZ50, it is also partly compensated by 8 GW of hydrogen power capacity and a slight increase of 2 GW in fossil thermal.
Interprovincial exchanges are also used to balance demand and generation in IntB. Interprovincial electricity trade already rises by 15% in 2040 in IntB (compared with NZ50), while in 2050 and 2060 this figure is 42% and 63% of NZ50 levels respectively. This provides grid resilience without additional baseload generation capacity and in fact results in less generation overall, suggesting an improvement in overall grid efficiency.
These changes are also associated with different consumption profiles. Total final energy consumption in the sectors is similar across the three scenarios. However, electricity consumption is 6% less in IntB for 2050, while natural gas consumption is up in IntB (+23%), as is hydrogen use (+30%).
In the building sector, this results in three important changes in IntB, which uses more hydrogen (174PJ compared with 3PJ in NZ50 for 2050), natural gas (81PJ instead of 53PJ), and geothermal and concentrated solar (51PJ compared with 6PJ in NZ50). These changes become sizeable around 2040 and remain so afterward, with hydrogen use increasing chiefly in the commercial sector.
In the industry sector, 2050 sees slightly more electricity (+4%) and natural gas (+17%) in IntB than in IntA, but less bioenergy (-15%) and much less hydrogen (-22%). The transport sector sees IntA result in levels similar to NZ50, although while the total is similar for IntB, the latter uses less electricity (-7% compared with NZ50), gasoline (-9%), and bioenergy (-3%), while consuming more natural gas (+17%) and much more hydrogen (+50%). However, after 2050, hydrogen levels converge across IntA, IntB and NZ50. These changes primarily affect merchandise transport.
Lastly, more emissions are captured through BECCS hydrogen production, given the higher use in IntB (12MtCO2e in 2050 compared with NZ50). This requires biomass to be used here instead of BECCS electricity generation, compensating most of this change. In other words, more negative emissions result from the increase in BECCS hydrogen production, while BECCS electricity generation decreases by around 8MtCO2e as a result. More capture also occurs in electricity generation in IntB, given the more significant use of natural gas, resulting in similar net emissions from power production across the three scenarios.
General observations:
- Strong dependence on variable energy sources for electricity requires a massive increase in capacity for production and storage to compensate for lower capacity factors and misalignments between production and consumption.
- Constraints on storage and variable generation favour nuclear from a cost optimal allocation perspective, but uncertainties about SMRs and social acceptability must be treated with care.
- A significant quantity of electricity generation and production capacity installed can be avoided through increased provincial interconnections.
- Favouring hydro generation and interprovincial connections over nuclear to balance variable renewables leads to different sectoral profiles where hydrogen use and natural gas are also increased.