How energy storage will fit into Alberta’s future electrical grid

This article was written by Emma Graney and was published in the Globe & Mail on June 21, 2024.

By this fall, Alberta will know what its overhauled electricity system will look like, and how energy storage, a vital component of energy security, will be factored into future-proofing the grid. Energy storage systems allow power to be captured at one time and distributed later, to help smooth out demand and avoid price spikes. In a world increasingly pivoting to renewables to reduce greenhouse-gas emissions, storage is crucial to making sure the lights stay on when the sun’s not shining and there’s no wind.

Nicole LeBlanc, vice-president of markets with the Alberta Electric System Operator, is confident that long- and short-term storage from various technologies will be part of Alberta’s future grid mix.

It’s just a matter of figuring out how big that slice is.

The technology works, she said in a recent interview. Now it’s all about making it economically attractive enough to entice developers to invest.

Alberta’s power market is unique in Canada, in that it relies on the private sector to bear the risks and responsibilities of adding new capacity.

Unlike in other provinces, there is no centrally administered planning mechanism. Instead, companies are driven mainly by the revenue they make from market volatility, or when the price of power spikes.

That’s a double-edged sword when it comes to building storage.

While it’s relatively easy for energy storage companies to partner with renewables developers, investment decisions are tough in the face of uncertainty around how the new system will host storage and guarantee the returns that multi-decade projects bank on.

As Alberta develops its future system, it must be clear about capacity requirements and build revenue streams that match the life of storage assets, said Vittoria Bellissimo, president and chief executive of the Canadian Renewable Energy Association.

“There is some movement to compensate energy storage providers for these services, but it’s not enough to get projects off the ground,” she said in an interview.

Storage already linked into Alberta’s grid helped avoid a catastrophic failure during a brutal cold snap in January. The AESO issued a series of alerts at the time, after natural-gas-fired power plants went offline and a shortage of wind, coupled with winter’s long periods of darkness, meant renewables did little to ease extreme pressure on the grid.

Power deployed from storage didn’t directly provide energy during the crisis, Ms. LeBlanc said. But it gave the system operator the confidence to import power at higher levels than it otherwise would have done, by alleviating fears of system failure should the connections with other providers be overloaded.

Utilities Minister Nathan Neudorf told media recently that storage “serves a tremendous purpose” for Alberta’s power system, and can provide muchneeded grid resiliency – as long as it doesn’t add to consumers’ power bills.

One of the companies eyeing opportunities in Alberta is Montreal-based RheEnergise Ltd.

It has developed a pumped hydro energy storage technology that uses a high-density slurry inside a closed-loop system. That makes it far smaller and cheaper than traditional pumped hydro, in which water is pushed uphill to a reservoir via wind or solar power, then released downhill to drive a turbine to produce power when it’s needed.

Doing away with those siting and cost requirements – and reusing the same water for 30 years – means it can be rolled out quickly and at high volumes, company co-founder Tamás Bertényi said in an interview.

The company is currently building a demonstration project in the United Kingdom, and Mr. Bertényi said Australia, Chile and the U.S. – along with Alberta – offer huge energy storage opportunities.

“If you look at who really moved the needle in the last 20, 30 years in terms of wind and solar deployment, it’s coming from smaller commercial developers – they’re the real driving force on energy transition,” he said. “We want to make our energy storage technology work for those people, because that’s going to be the key to really achieving scale.”

Pumped hydro is currently the most widely used storage. But deployment of lithium-ion batteries is ramping up, owing to plummeting costs that have dropped more than 90 per cent since 2010, and bounds in technology that have improved the energy density and lifetimes of batteries. Numerous other technologies also show promise, including thermal from concentrated solar power and compressed air systems.

The U.S. energy storage market set a capacity installation record in the first quarter of 2024, increasing 84 per cent from the year prior, according to the U.S. Energy Storage Monitor report released this week by analyst Wood Mackenzie and the American Clean Power Association. Nevada, California and Texas accounted for 90 per cent of that new capacity.

Australia, too, is deploying energy storage at a rapid clip, and last year set a record for installed battery storage capacity.

Storage isn’t a salve for all electricity systems, particularly in parts of Canada that rely heavily on hydropower (which is in itself a form of power storage). But in jurisdictions with a more diverse energy mix, the technology can play a critical role, Ms. Bellissimo said.

Ontario is in the midst of procuring almost three gigawatts of storage for its system, for example. In Saskatchewan’s capital, Regina, the province’s power provider, has built a utility-scale battery energy storage system, and on the West Coast, BC Hydro is looking to advance utility-scale batteries to add 50 megawatts of additional capacity as early as 2027.