How to meet rising electricity demand in Canada

As Canada sets goals for energy transition and to achieve a net-zero economy by 2050, demand for electricity will continue to increase. By 2050, electricity should represent 40 to 45% of the Canadian energy mix (compared to 18% today) and will be the dominant end-use energy source.¹

What will be the main drivers of this electricity growth? We expect trends towards electrification will continue. All new light-duty vehicle sales in Canada are expected to be zero-emission vehicles by 2035,² and electric heat pumps should become the main heating system, representing 50% of residential heating by 2050.³ In the industrial sector, we expect to see increasing use of technologies such as electric arc furnaces and infrared dryers, as well as low-carbon hydrogen (demand is expected to grow from 0.5 MT today to 8.5 MT in 2050) and nuclear small modular reactors.

In the next two decades, we’ll also see new demand coming from emerging industrial sectors. These include battery manufacturers, carbon capture utilization and storage facilities, data centres and quantum computing, vertical farming and biotechnology.

Demographic shifts and evolving economic dynamics will also be important factors. Even if economic growth in the coming years is slower than the historical average, energy use will still increase due to a growing and aging population and global economic growth. Here in Canada, the population is expected to jump from 40 million in 2023 to 43 to 52 million by 2050.⁴

To meet Canada’s increasing electricity demand is a complex and multi-faceted challenge. But with a jump from an estimated 600 TWh produced in 2023 to a 1,300 TWh forecast in 2050, it’s also a critical opportunity to shape a more prosperous and efficient economy.

Grid operators can play a leading role in driving this transformation by understanding the key areas of opportunity and developing electrification strategies, supporting the reduction of energy intensity and implementing innovative solutions.

Transform grid planning

Network planning is a priority and must be done properly to ensure long-term grid development and optimize capital expenditure allocation. Currently, to prepare a grid investment plan, power utilities conduct studies (also known as integrated resource plans) every one to five years. These studies forecast demand and identify the type and location of energy resources needed, typically around ten years into the future.

However, the clean electricity transition in Canada will require a shift in grid planning. This is because older approaches rely on traditional planning processes that struggle to accommodate uncertainty and the speed of demand changes. This new approach must take into account the following elements: the increase in renewable and intermittent generation, the increased role of distributed resources, the necessity of a system-wide energy planning approach and the need to bring together targets for multiple sectors that link to the power sector.

Navigate between short-term and future needs

To meet net-zero goals by 2050, utilities must adopt a “backward-thinking mindset” to build the grid according to future requirements and avoid the trap of a suboptimal system. Short-term needs (around five years) are usually well known. But a strong focus on short-term planning can overemphasize the importance of current business and incremental evolution and prevent required transformation.

Medium- and long-term needs (5 to 20 years) are more volatile and related to future regulation, politics and the economic context. Long-term planning is easier to completely disconnect from current business, as it can be anchored in a future that’s very different from today.

Match peak demand

The main function of a grid operator is to balance the grid and make sure that every millisecond, power supply equals demand.

This increase in peak demand is a natural outcome of increasing use of devices that require more electricity during a certain period. For example, electric vehicles typically draw relatively large amounts of electricity over a short period when owners plug them in. And greater use of heat pumps means that overall electricity demand will be more sensitive to weather patterns than it is now.

Canadian electric utilities must find new ways to manage peak demand and network constraints. Electricity system operators have three main methods to do this: implicit flexibility (tariffs), network flexibility (smart grids) and flexibility services (generation and demand-side).

In the past, flexibility services have mainly been supplied by generators. But with the phasing out of some traditional flexibility providers, such as gas-fired power plants, there will be a need to replace these resources. Electricity system operators will also need to unlock even more flexibility within the system because of growing intermittent supply with limited capacity value (for example, wind and solar), as well as increasing grid congestion.

Historically, the utilities sector has focused on building more capacity to meet increasing demand. However, the scale, pace and technological advancements of the energy transition will require a more balanced and sustainable approach.

Support action on reducing energy demand

When we think about solutions to achieve net zero, reducing energy intensity should be the number-one priority. Actions on energy demand can be taken by all businesses now—and are already profitable. PwC’s latest research in collaboration with the World Economic Forum’s International Business Council shows the extraordinary potential of demand‑side action. It offers a short-term cost‑efficient 31% reduction of demand, shared across all economic sectors.

Canadian power utilities have a vital role to play in supporting efforts to reduce energy intensity through energy savings and efficiency, as well as value chain collaboration initiatives. In parallel, they’ll need to educate their customers and provide more advanced tools to help them manage their energy consumption.

Take advantage of demand-side flexibility

As the energy system decarbonizes and traditional flexibility sources are phased out, alternative options, such as demand-side flexibility, will be needed. Demand-side flexibility refers to the ability of customers to change their consumption and generation patterns based on external signals. The objective is to unlock the economic opportunities of distributed energy resources (DERs)⁵  and maximize system value through aggregation and virtual power plants.

The International Energy Agency estimates battery storage systems and demand response could represent 55% of global flexibility needs by 2050.⁶ In its Pathway scenario, the Independent Electricity System Operator expects storage and demand response capacity will increase from 3% to 10% of Ontario’s total capacity by 2050.⁷

Demand-side flexibility services are a cost-effective way to balance the grid, and they also provide the ability to defer capital investments. But full integration of demand-side flexibility services into the energy system will require the proper market structure, regulation and incentives. The system benefits of DERs can only be realized if markets are properly designed and market participants receive fair compensation. Power utilities must also develop the capabilities and use technology to monitor and control their customers’ flexibility actions, as well as encourage positive behaviours.

Reinforce planning models

Electrification of final uses (when and where electrification efforts across sectors will occur) and rising levels of DERs will introduce new uncertainties. This is because these technologies bring a more complex supply/demand pattern to the grid. In Ontario, DER participation in the energy system is anticipated to grow seven times by 2032, as market barriers lessen.⁸

Grid planning at the distribution and local levels must reflect this new complexity, but also identify additional values (e.g. resilience, outage mitigation) and opportunities for local system optimization (e.g. grid investment deferrals, optimal storage locations). More complex simulations will be needed to merge data sources and scenarios and determine their impact on grid behaviour. These simulations will use, for example, electrification scenario forecasts, DER penetration and adoption drivers, load profile calculations and impact on local capacity.

Even if electric utilities continue to plan for a baseline expansion, they’ll need to add flexibility to their models for uncertain outcomes. Local and probabilistic planning models need to be strengthened to better reflect factors such as electric vehicle deployment and customer DER adoption.

Understand electricity constraints and develop industrial symbiosis

Easy and unlimited access to electricity for all must come to an end, at least in the short and medium term. Because of a lack of abundant resources, we must think about the sector as being driven by constraints rather than by customer demand.

The question then becomes: Who should benefit from low-carbon electricity? This is a complex challenge with many criteria to consider. These include economics (e.g. impact on local, regional or national GDP), politics, job creation, decarbonization, affordability and quality of service. Defining the proper strategy will require a closer relationship between power utilities, governments, regulators and customers to ensure consistency and predictability in the long term.

Electricity demand must be considered as just one part of local energy needs. New industrial hubs and residential areas should be built in a way that minimizes electricity use. Geothermy, district heating, industrial symbiosis (i.e. sharing outputs and inputs within complementary industrial activities) and other levers will help power utilities ensure economic growth with restricted electricity demand.

To achieve this, utilities must rethink their business model and build key partnerships with the business ecosystem and local communities. This process will also require the reconfiguration of the asset base to include stand-alone power systems (microgrids) to manage system health while materially reducing capital expenditure for remote areas.