Stikeman Elliott’s Langen says Albertans who bypass system still need connection to reliable power
The future of electricity distribution in Alberta will likely include dealing with forces now in place that sees an increasing number of consumers relying less on the grid, but must still need to be connected for when their alternative energy source isn’t available, says Dennis Langen, energy partner at Stikeman Elliott LLP in Calgary.
The adoption of innovations to manage supply and consumption — energy storage, energy efficiencies and smart tech — along with new sources of supply such as solar makes it possible for electricity consumers to temporarily avoid or bypass the grid, says Langen, who specializes in energy regulatory law. Collectively these innovations are called distributed energy resources, or “DER.”
For example, he says, a house fitted with solar panels could bypass the distribution grid whenever their solar generation is producing sufficient power to serve their needs. However, Langen notes that the house would still need to be connected to the grid to deal with times when solar energy is not available. “Distribution utilities have an obligation to provide service to all customers within their franchise area, even if they are using alternative sources,” Langen says.
However, Langen notes that this has the potential to “shifts more of the fixed costs” of the grid on to customers who are not using DERs. With growing rates of DER adoption, this could cause uncertainty on how distribution utilities determine rates for customer classes while balancing their obligations to provide service and recovering the revenue they need to cover their costs and be profitable.
In February, the Alberta Utilities Commission released its final report of its Distribution System Inquiry, which began in late 2018. The goal of the inquiry was a fact-finding mission to map out key issues affecting the future of the electric distribution grid in Alberta. It also was formed to assist in planning and developing a regulatory framework to accommodate the evolution of the province’s electricity system.
The commission’s work looked at potentially increased loads driven by the electrification of transportation and heating, weakened economic growth, a need to keep grid-supplied electricity affordable, and growing pressure to align rates with costs. It also looked at the increased adoption of DERs and how this trend will affect dynamic energy flows on the distribution system.
Langen says the commission found that Alberta has not yet experienced DERs adoption rates at sufficiently high levels to strain the distribution systems beyond manageable levels, though adoption of DERs will continue to increase in Alberta due to declining technology costs. However, there is uncertainty about the rate of adoption and its impact on the operations and revenue of the grid. Electricity rates may have to rise to offset this situation at the expense of those still mainly on the grid, Langen says, further driving the movement towards using DERs.
The industry and regulators will need to address these signals in pricing to leverage DERs to the advantage of Alberta, Langen adds. He notes that traditional rate structures for electric utilities look at how to recover total revenue requirement across various customer classes with the intention of sending accurate cost-based price signals to consumers.
With the transition to DERs and their increasing adoption, there is a clear need to consider how to evolve traditional rate structures to ensure a balance is struck between accurate price signals for electricity consumers and the transition. The goal says Langen, is to promote continued adoption of DERs while ensuring the distribution system is supported through a compatible rate design. This will ensure the grid is available and ready to supply electricity with DERs may not be.
The commission heard from stakeholders who recommended the transition to a rate structure that better reflect the costs of providing utility service, both in terms of the division of cost recovery among customers and the method of allocating those costs.
Concerning the division of recovering costs from customers, “unbundling distribution costs” into its components is one potential solution and develops different class-specific rates for certain DERs. Perhaps, says Langen, it would be a rate structure that charges a slightly higher rate for those who are regularly using their own power source through DERs but still need to tap into the grid when their alternate power source is unavailable. The overall shift would be away from the higher weighting of variable rates now and towards a rate structure that could include non-avoidable costs to maintain the infrastructure and variable avoidable charges that send a price signal able to affect future system costs through altering current behaviour.
The inevitable wider adoption of electric vehicles in the future has the potential for substantially greater loads on distribution systems, Langen says. While this may drive distribution utilities to make significant investments in new infrastructure, time-of-use rates, or rebates to provide an incentive for charging during off-peak hours could help minimize the grid investment needed.
