Enfinite’s collocated eReserve4 and eReserve6 battery energy storage systems (BESS) situated southeast of the Town of Hardisty, Alta.Enfinite/Handout
The Monarch, Vulcan and Coaldale solar farms in sunny southern Alberta started generating power last year, new entrants in a boom in renewables development that has changed the makeup of the provincial grid and may now may face a slowdown as the provincial government hits pause.
The projects were built by a joint venture of the Athabasca Chipewyan First Nation and Vancouver-based real estate and green-energy developer Concord Pacific Group at a cost of $140-million. They were designed to be much more efficient than they are today and are about to fulfill that promise.
The missing piece has been the ability to save up some of the power they generate. The partners are among six green-energy developers selected by the federal government to get funding, and will use the $45.8-million to add 15 megawatt, or 34 megawatt-hour, batteries to each solar farm.
This adds to a list of storage projects proposed by companies large and small in Alberta that tallies into the hundreds of millions of dollars and stands to play a major role decarbonizing the grid if government moves to slow the renewables industry do not derail proposals.
Terry Hui, Concord Pacific’s chief executive, said the batteries will allow the projects to feed the grid at almost all hours, smoothing out the well-known variability of solar generation. It’s expected to mean a 20-per-cent increase in output when commercial operations begin around the end of this year. The federal support and falling costs of the technology make it a solid proposition, he said.
“It’s good technology, but it was too expensive before. Now, with the government support and better battery technology that’s available, it makes a lot more sense,” Mr. Hui said in an interview.
There are now more than three dozen energy storage projects in the queue to be built in Alberta. Storage, in the forms of batteries, pumped hydro, compressed air and hydrogen, gets less attention than generation. With the province’s last coal-fired power plant slated to shut down in the coming months – seven years ahead of schedule – natural gas and renewables have made up the difference.
But are investments in danger? Industry proponents insist storage is key to Alberta moving to a low-carbon electricity network while helping to maintain its reliability. The technology helps smooth out the stop-and-start nature of wind and solar – the equipment is charged when power is generated, and feeds the grid when needed.
Alberta Premier Danielle Smith’s UCP government shocked the renewable energy industry last week, when it imposed a seven-month freeze on renewable project approvals. The government says it will use the time to review where projects can be built, how to ensure installations are cleaned up when they reach the end of their commercial lives and how the surge in wind and solar affects the grid. Industry supporters said the move is short-sighted and risks diverting investment capital to other jurisdictions.
Ms. Smith was already pushing back against Ottawa’s plan for a net-zero power grid by 2035, saying it would damage the provincial economy and pile massive costs onto consumers. She wants the province to shoot for a 2050 target instead.
The Alberta Electric System Operator (AESO) concluded last year that paths to decarbonization by 2035 all carry major risks because of policy uncertainty, the need for numerous regulatory approvals for projects, timelines for technology commercialization and potential supply chain problems. AESO estimates the cost of additional generation and transmission at $44-billion to $52-billion through 2041. Even then, it said, meeting a net-zero goal will require buying offsets to make up for emissions that can’t be abated.
The Pembina Institute disagrees. The energy and environment research body issued a report in June that said a net-zero grid is not just possible, but getting there will make the system more efficient and cost $27-billion to $28-billion less than under the AESO’s scenario. One of the keys will be a big buildup in energy storage capacity.
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The AESO currently sees that capacity quintupling to 500 megawatts (MW) by 2027, but Pembina predicts a much steeper increase. Jason Wang, a senior analyst with the group, points out the system operator had previously been conservative forecasting renewables – their generation capacity is now at a level it did not expect for another decade. “We think the AESO has recognized that more batteries are coming than they previously expected, and that number will be beat again,” Mr. Wang said.
Adding up projects that have been financed and are waiting for regulatory approvals, capacity could climb to around 900 MW in the next two years, if they all get built, Mr. Wang said. That could put the province on track for Pembina’s most ambitious decarbonization scenario, one in which storage capacity equals a quarter of installed wind and solar capacity by 2035, and the grid hits net zero. Also key to the target: a greater proportion of renewable energy and expanded interties with British Columbia and Montana to boost capacity to import and export power.
AESO spokesperson Leif Sollid said the system operator, which has hosted an industry forum on storage for the past three years, can’t speculate on how the number of projects it expects could change over time, as it is driven by market interest.
Alberta currently has about 100 MW of storage capacity in operation, 90 MW of which is tied to the grid. Energy Storage Canada, which represents the industry, sees 2,500 MW more in various stages of development.
“It’s unlikely that everything there will get built, but that’s just showing what’s in development and the interest now,” said Robert Tremblay, Energy Storage Canada’s policy manager. “I think as we go through to 2035, we’ll see a significant number of new projects emerge.”
Currently there are 37 proposed storage projects at various stages of development, with in-service dates set for before October, 2026, according to AESO. Most are mated to new solar projects and some of the largest are being developed by Greengate Power Corp., Westbridge Renewable Energy Corp. and TC Energy Corp.
Seven are stand-alone, including a TransAlta Corp. battery project west of Calgary and a pumped hydro development in the Hinton-Edson region in the west-central part of the province. That system requires water reservoirs at different elevations, where the downward flow drives turbines when power is needed. It has the benefit of allowing for energy to be stored for days, rather than hours as with batteries. But it also requires large areas and the right topography.
Greengate built Canada’s largest solar farm near the town of Vulcan, Alta., and has another large project in the east of the province in the queue for regulatory approval, a 300 MW development with battery storage included. CEO Dan Balaban warns that the Alberta government’s decision to halt renewable power applications threatens to slow storage deployment, too.
“Energy storage is one of the lowest-cost and quickest-to-deploy solutions to address some of the grid stability and grid congestion issues that are being faced right now, and I think there’s a very strong future in theory for energy storage,” he said. “But there needs to be a framework to accommodate energy storage and encourage those projects to come onto the grid. This announcement puts a dark cloud over the entire industry until this is sorted out.”
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Yet Alberta’s growth has been part of a global trend. Battery storage deployment increased 52 per cent in 2022 from 2021, and the market could expand nearly six-fold, reaching US$72-billion by 2030 with a total capacity of 499.1 gigawatts, or 1,340 gigawatt-hours, according to Dublin-based Research and Markets. Meanwhile, the price per kilowatt hour has been on a steady decline as technology has improved.
Decarbonization isn’t the only benefit. As electric cars, heat pumps and other power-thirsty technology boosts electricity demand in the coming years, storage can also improve efficiency – pushing back some of the need to build major new transmission lines by sending extra juice into the parts of the network during times of high demand. Also, there has been so much renewable energy development in the windy and sunny southern part of Alberta that congestion is becoming a problem, so storage can provide a cushion.
Besides utility-size storage, there is also potential for smaller projects at the neighbourhood level designed to handle peak loads as electrification powers more of daily life, Mr. Tremblay said.
So far, grid-scale storage facilities not tied to individual generation projects have been slow to be built, partly because of a policy under which operators are charged the same as purchasers of power, and talks are now under way to change that. Enfinite Inc., which is owned by TD Asset Management, is an early entrant into the merchant storage game, with four projects now in operation in the province, and five more due online before the end of this year.
The company has been installing 20 MW banks of “Megapack” battery systems made by Tesla Inc. under a project it calls eReserve, to play a merchant role for the grid, said Jason White, Enfinite’s chief operating officer. He cautions that battery storage alone won’t get Alberta’s grid to net zero. But Enfinite’s strategy has been to push forward in the merchant storage business to gain the advantage of an early mover as conditions improve.
“People are kind of sitting back and waiting to see where things go. I think the ramp rate of energy storage in Alberta is not steep enough – it’s just not coming online as quickly as we probably could use it,” he said. “But that being said, I don’t think that storage is necessarily the silver bullet. It’s just a component of a new energy mix.”