With distributed energy resources (DERs) moving swiftly from the margins to the mainstream in North America, Ontario can seize opportunities to enhance its own power system.
From a home battery pilot project in Vermont, to a virtual power plant in California, to a massive demand response program in the UK, DERs are already reducing carbon emissions, increasing community resilience, and helping grids delay or reduce their investments in costly new infrastructure.
What are DERs and how can they help Ontario speed the shift to a net-zero grid?
Today’s distributed energy resources generally fall into three categories:
- Power generation technologies like rooftop solar systems and small wind turbines;
- Energy storage systems like stationary batteries, or electric vehicles capable of bidirectional or “vehicle-to-everything” (V2X) charging;
- Load shifting via technologies like heat pumps, EV chargers, and electric water heaters paired with smart controls that help utilities enlist their customers to manage and minimize peak power consumption through demand response.
DERs come in different shapes and forms, and many of them can be combined as complementary resources (for example rooftop solar and storage). But they have a few essential points in common. As modular resources, DERs can:
- Supplement, replace, or offset future need for the large-scale, often high-emitting electricity sources the grid still depends on;
- Be brought online faster than large, grid-scale power generation, and often at a lower cost to users. They scale quickly to accommodate local population growth and incremental demand;
- Defer investments in transmission and distribution grids, in part by increasing utilization of our existing infrastructure;
- Make communities more resilient to the next hurricane, heat wave, flood, or wildfire by reducing reliance on long distance transmission and distribution systems.
Some communities are already aggregating different types of DERs and managing them as a single “virtual power plant” (VPP), achieving capacities similar to a small conventional generating station with no direct emissions, and potentially at much lower cost. One study modelled a VPP for a representative U.S. utility and found it could deliver the resource adequacy that grid planners need and users expect at 40 to 60% less cost than a high-emitting gas peaker plant.
How could DERs transform the grid?
Households and businesses are the big winners when distributed energy resources reduce a community’s reliance on large, centralized power plants.
With smaller, local energy assets that generate, store, or manage electricity closer to where it’s needed, municipal utilities can leverage devices their customers already have installed for some other purpose—heat pumps for space heating and cooling, or batteries for backup power, or smart chargers for powering their EVs. Those DERs can be deployed to help power and stabilize the local grid.
Ontario’s Independent Electricity System Operator (IESO) explored the potential of DERs last year, and the results were remarkable. The study by Montreal-based Dunsky Energy + Climate found that, when considering “real-world” conditions, DERs could supply 1.3 to 4.3 gigawatts (GW) of capacity in summer and 1.0 to 3.6 GW in winter by 2032. The total cost-effective potential of DERs in Ontario, however, stands at 4.1 to 18.9 GW of summer and 2.8 to 15.0 GW of winter capacity, enough to solve the province’s electricity shortage without building new gas plants.
The choices we make now will impact the decades to come. DERs can help prevent expensive, new generating stations, along with rising carbon emissions from natural gas. Today, the emissions in Ontario’s grid come from using gas-fired generating stations to meet peak demand. But the IESO’s plans call for those gas plants to be used much more frequently, leading to massive growth in carbon pollution over the next 10 to 12 years; a period when we need to bring our grid emissions close to zero.
How do we know DERs will work?
A growing number of utilities are running successful DER pilot projects. Some of the greatest hits so far include:
Vermont, Green Mountain Power
Vermont’s Bring Your Own Device program offers customers up to $10,500 toward the purchase of a home battery if they agree to share control over the device over a 10-year period. With 2,500 residential customers and more than 4,000 batteries signed up as last year, the utility has reduced energy costs across the system by $3 million per year.
California, Pacific Gas & Electric
PG&E depends on two virtual power plants using solar and storage to help it manage demand peaks brought on by heat waves and other extreme weather events. Electric vehicle pioneer Tesla pays more than 4,500 Powerwall battery customers $2 for every kilowatt-hour they deliver to the grid when PG&E calls for an emergency load reduction supplying up to 33 MW as needed during peak hours between May 1 and October 31. Rooftop solar giant Sunrun is working to attract 7,500 customers to deliver 30 MW back to the grid, offering a $750 up-front payment and a free smart thermostat if they agree to make their stored electricity available during the peak months of August, September, and October.
United Kingdom, Octopus Energy
Octopus Energy is the UK’s second largest energy supplier and is showing the rest of the world what innovation in the utility sector can achieve at scale. Its latest offering, “Saving Sessions”, saw a staggering 700,000 of its customers join its demand response program. The program was an overwhelming success for both customers and the utility, leading to more than 1.86 GWh of peak electricity savings (an average of 128 MW of load shifted per hour) while earning participating Octopus customers a combined £7 million ($12 million CAD) in rewards.
What Ontario needs to do
In May, the IESO announced plans for 739 MW of new storage capacity from seven projects, ranging in size from five to 300 MW. But that procurement will unfold alongside bigger-picture plans to expand four existing gas plants, build at least one new one, and install new nuclear power stations that will take many years to build and commission.
There are solutions available to residents and businesses which can both lower energy costs and limit emissions from gas-fired generation. In parallel with pursuing all cost-effective energy efficiency investments, it’s time to fully unlock the potential of the two-way grid. The IESO and OEB are already working to both integrate DERs into the provincial electricity market and within local distribution company (LDC) planning and operations. The IESO’s own research shows how much farther and faster we can go.
There’s no need, however, for LDCs and communities to wait until later this decade for these frameworks and incentives to materialize. DERs show that the best energy options are often built from the ground up, and LDCs are in a good position to identify and take advantage of those opportunities today. As communities around the world are already demonstrating, managing the energy transition is a significant challenge but can also be a massive opportunity. In a climate emergency compounded by an impending electricity shortage, there’s no time to wait.