Unlock the full potential of distributed energy resources

Distributed energy resources have a critical role in helping Canadians achieve net zero

As Canada sets goals 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 Meeting 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 an opportunity to shape a more prosperous and efficient economy.²

The industry and government will be challenged to find new ways to match supply to growing demand while managing network constraints at the lowest cost​. As the energy system decarbonizes and traditional fossil fuel energy sources are expected to be significantly reduced or phased out, alternative options from non-emitting resources, such as distributed energy resources (DERs), are increasingly needed.

The role of DERs in the new clean economy is more than just providing additional supply and managing peak demand. Renewable energy affects power quality in the distribution grid, leading to increased risk of blackouts. To maintain grid stability, temporary changes to energy consumption and generation are needed to balance demand and supply. Most DERs are good candidates for providing these services, as they’re localized and can respond quickly to meet flexibility requirements.

Although there are various definitions of DERs by regulatory bodies, such as the US Federal Energy Regulatory Commission and European Commission, the Smart Electric Power Alliance’s (SEPA’s) definition of DERs is closer to our point of view. 

According to SEPA, DERs are physical and virtual assets that are deployed across the distribution grid, typically close to load and behind the meter, which can be used individually or in aggregate to provide value to the grid, individual customers or both. Some examples of DERs are solar panels, battery energy storage systems, energy efficiency programs and demand management.

DERs can be in front of the meter directly connected to the distribution lines; these DERs are called “grid-scale” DERs. If the DERs are located behind the meter, then they’re called customer energy resources (CERs) and demand response. Each DER represents unique characteristics and value to the energy ecosystem (e.g. load, storage, voltage/frequency regulation)​.

The International Energy Agency (IEA) defines demand response as balancing the demand on power grids by encouraging customers to shift electricity demand to times when electricity is more plentiful or other demand is lower, typically through prices or monetary incentives. Demand response is an important source of flexibility, along with CERs, for managing the impact of growing electricity demand on the stability and reliability of electricity grids.³

The IEA estimates demand response could represent 25% of flexibility needs globally by 2050.⁴ In its Pathway scenario,⁵ the Independent Electricity System Operator expects demand response capacity will increase from 2% to 7% of Ontario’s total installed capacity by 2050.⁶ The 7% participation in 2050 may reduce the need for future grid investments by $23 to $29 billion. In this example, the savings represent approximately 5% of the reported $425 billion investment needed to decarbonize the Canadian grid by 2050.⁷

Although DERs contribute to some cost savings by acting as non-wire alternatives on the grid, their most significant role is in customer participation and allowing demand-side flexibility.

Instead of focusing only on the supply side, which is normally managed by utilities, customers can play a proactive role by controlling how and when they use their energy-consuming appliances, such as air conditioners and heat pumps. For commercial customers, this includes large machinery, refrigeration systems and other controllable loads.

We use the term “prosumer” to refer to customers who both produce and consume energy. This is made possible by the rise of new connected technologies and the steady increase of more renewable power, like solar, into our electrical grid. Prosumers owning energy-producing CERs can also control their generation patterns to make economic decisions that are beneficial to them.

Demand-side flexibility refers to the ability of prosumers or consumers to change their consumption and generation patterns based on external signals. The objective is to unlock the economic opportunities of DERs and increase system value through aggregation and virtual power plants (VPPs). As an example, prosumers can choose to sell the excess electricity generated from their solar panels to the grid or store it in their batteries, depending on the wholesale price. On the demand side, industrial customers can also decide to optimize their production, balancing throughput, electricity usage costs and incentives from demand response participation.

The installed capacity of DERs in Canada in 2023 reached 20.4GW,⁸ with an increase of 2.1GW in total installed capacity. On the other hand, total installed CER capacity reached 1.5GW, an increase of 226MW, in that same period. Canada’s total DER and CER installed capacity is expected to reach 58GW by 2035.⁹

When we look at more mature markets like the United Kingdom, installed capacity of DERs and CERs reached around 50GW in 2023, an increase of 2.5GW from the previous year.¹⁰ The United Kingdom has higher installed capacity than Canada on DERs and CERs. More importantly, their enabling regulation is fostering a higher increase, especially in CERs such as commercial rooftop photovoltaic devices and battery storage. Although we’ll likely reach the same installed capacity of DERs and CERs in Canada by 2035, these numbers won’t mean much if the installed capacity is off-grid and not able to participate in energy markets.

In the United Kingdom, Ofgem’s RIIO-ED2 price control is a vital part of realizing their ambitions to develop a more integrated, low-carbon system​. To support its goal of a smarter, more flexible energy system, it outlined a framework of outputs and incentives for distribution system operators and licence requirements that take into account flexibility requirements and flexibility procurement. In November 2022, Ofgem approved the United Kingdom’s electricity system operator to introduce a demand flexibility service to accelerate the transition to a smart, flexible power system through incentivizing end customers to shift their demand to avoid the peak.

In Australia, there are more than 3.8 million homes¹¹ now generating electricity domestically, and rooftop solar provided 11% of Australia’s electricity in the last year. In the state of South Australia, there have been multiple instances where rooftop solar generation was able to meet the state’s energy demand.¹² The local government has taken this achievement to the next level to enable grid stability and reliability. Some of the initiatives introduced include the following:

• South Australia’s Virtual Power Plant¹³ was introduced in 2018 to stabilize frequency levels in the grid. It’s helped with significant events, such as providing power in the event of catastrophic fire conditions, a power station trip and high/low frequency issues.

• Smarter Homes regulatory changes¹⁴ came into effect in 2020 to increase the amount of rooftop solar generation and to maintain the required supply and demand balance to avoid potential blackouts. This is achieved by allowing an authorized third party to remotely control rooftop solar systems and controlled loads during emergencies by disconnecting, reconnecting and managing output.

• The Energy Masters project is a trial to show customer and industry benefits on scaled demand flexibility by connecting residential smart appliances and energy management systems.

The 2030 Emissions Reduction Plan developed in 2022 outlined the Canadian federal government’s allocated investment of $9.1 billion in cleaner energy, such as electric vehicles, demand-side management and grid modernization. There are also various rebates and incentives at the provincial level to encourage customers to adopt solar panels and battery systems. However, these aren’t yet consistent across provinces, and policies on flexible energy systems are still in development.

The DER on its own will provide some cost reduction and increase energy security and resilience for customers. However, an electricity market and regulatory transformation is needed to unlock the full potential of DERs​. This transformation will allow aggregators to enter the market (enabling greater participation from smaller-scale DERs), compensate DERs and network operators for their services and incentivize customers.

The following three transformation actions are key to unlocking the full potential of DERs in Canada.

1. Advance flexibility markets for DERs

The role of flexibility is to balance supply and demand in the wholesale market, as well as to manage network constraints and congestion. Flexibility services refer to the ability to dynamically generate or reduce supply and/or demand to provide energy, capacity and ancillary services, such as frequency control, voltage support and operating reserve.

Provinces such as Alberta and Ontario operate an ancillary services market for transmission systems, which includes operating reserve, blackstart facilities and voltage control. These markets typically source flexibility services from smaller generators and grid-scale DERs (supply side) to support reliable operation of the transmission systems.

Flexibility markets for DERs would allow not only supply-side flexibility, but also demand-side flexibility by increasing participation from smaller-scale DERs and controllable loads. The market structure will incorporate VPPs and aggregators as one way to reduce entry barriers for these smaller DERs.

Creating flexibility markets, lowering barriers to market entry for DERs and opening the market for new entrants are key actions other developed economies have used to incentivize and increase DER participation. Similar actions that require policy changes must be implemented in Canada.

2. Establish an incentive model that’s beneficial for all parties

More work needs to be done to develop an incentive model for all DERs to increase participation. These incentive models will be different for “in front of the meter” and “behind the meter,” including prosumers, local distribution companies (LDCs)/retailers, DER investors and aggregators. The models must also promote clean energy generation and its integration into the grid.

One example of these incentives can be enabling bilateral agreements (corporate power purchase contracts) between DERs and consumers or LDCs. Regulations currently don’t allow bilateral agreements in some jurisdictions. Enabling bilateral agreements with DERs and LDCs/retailers in addition to incentivizing LDCs to capitalize DER service agreements will increase the usage of DERs, and bilateral agreements will result in easier and cheaper financing for DER investments.

We need policy and regulatory changes to redefine the role of the transmission system operator, moving from a traditional distribution company model to a total distribution system operator model. We also need to incentivize aggregators to encourage greater participation from DERs with smaller capacity and the use of VPPs.

3. Reward customers and protect their rights

The federal and provincial governments are currently providing significant funding and rebates to encourage installation of DERs and participation in demand response. These rewards need to be extended to incentivize integration of DERs into the grid and customers’ participation in flexible trading, either directly or through a third party. There must be clear rules and regulations to protect and securely share consumer data associated with DER usage, as well as beneficial arrangements to commercialize this valuable data.

Integrating customers’ energy resources into the grid and allowing third parties to access and control their assets exposes customers to privacy and security risks. Technical standards that take into account privacy and security risks will be essential to protect our critical infrastructure and consumer rights.