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Alberta'S Deregulated Grid Is Bracing For 11 Gw Of New DemandWhile Alberta’s historical energy legacy has been defined by coal and crude oil, the Canadian province has embraced renewables and carbon capture over the past two decades, and is now exploring small modular nuclear reactors as part of a conscious realignment with the global energy transition. More recently, with more than 11 GW of data center demand queued up—exceeding Alberta’s current peak consumption—the province is confronting a new balancing act where reliability and economic competitiveness are fundamental priorities. For more than a century, Alberta’s energy sector has powered the province’s economy and defined its global identity. The discovery of oil at Turner Valley in 1914—and later, the historic Leduc No. 1 well in 1947—cemented Alberta’s role as a cornerstone of Canada’s energy future. Development of the province’s vast oilsands, which today account for 98% of Canada’s established oil reserves, began in earnest in the 1960s and accelerated in the early 2000s with advances in extraction technologies and rising global oil prices. The deposits—primarily located in the Athabasca, Peace River, and Cold Lake regions—have made Alberta one of the world’s largest holders of recoverable oil. 1. Located near Edmonton, Alberta, Capital Power’s 1,857-MW Genesee Generating Station was fully repowered from coal to natural gas in December 2024. Courtesy: Capital Power Coal, too, played a dominant role in Alberta’s electricity mix, supplying more than 80% of the province’s power well into the early 2000s. That share steadily declined as natural gas and renewables gained ground—dropping to 47% by 2018 and just 17% by 2022. In June 2024, more than five years ahead of Alberta’s coal phaseout deadline, the province officially marked the end of coal-fired power with the full conversion of Captial Power’s Genesee Generating Station to natural gas (Figure 1). The CA$1.6 billion project repowered Genesee Units 1 and 2, a combined 860-MW initially commissioned in 1994 and 1989, respectively, with Mitsubishi Power M501JAC gas turbines, adding 512 MW. Capital Power completed the coal-to-gas conversion of the 2005-opened 466-MW Unit 3 to a 525-MW gas-powered unit in 2022. Capital Power, in May 2024, discontinued its proposed Genesee Carbon Capture and Storage (CCS) Project, citing economic infeasibility despite confirming the technology’s viability for future decarbonization. The transition, however, is far from complete, as Rick Christiaanse, CEO of Invest Alberta, told POWER in March. Alberta, like other regions in North America, is grappling with a complex convergence of pressures. Reliability remains a core concern. In January 2024, a severe cold snap pushed Alberta to a new record peak demand of 12,384 MW, triggering escalating Energy Emergency Alerts (EEAs) and culminating in an EEA3 on January 13. At temperatures below –40C, more than 9,000 MW of the province’s generating capacity was offline or unavailable, forcing the Alberta Electric System Operator (AESO) to deploy all contingency reserves and issue an emergency alert asking Albertans to reduce usage—a move that cut demand by about 350 MW and helped avert rotating outages. However, just months later, on April 5, 2024, the province faced its first firm load shed since 2013, when about 4,000 MW of thermal capacity and 400 MW of expected wind failed to materialize, prompting the AESO to order 244 MW of demand to be shed despite moderate system demand. In its 2023 flagship reliability requirements report, AESO outlined declining system strength in areas with high renewable penetration, rising ramping needs, and reduced frequency response due to fewer synchronous generators. The report warned that Alberta’s grid was undergoing a “rapid transformation” and identified three priority areas—frequency stability, system strength, and flexibility capability—all of which were under growing strain as more inverter-based renewables were being brought online and large, dispatchable fossil assets were expected to retire or be derated. Without targeted interventions, AESO cautioned, the province could face greater difficulty maintaining reliability as demand rises and supply characteristics shift. 2. Located north of Fort McMurray, Alberta, Suncor’s 856-MW Base Plant is among the province’s largest cogeneration facilities. A CA$1.4 billion upgrade replaced three coke-fired boilers with two high-efficiency natural gas units, which became fully operational in late 2024. The facility supplies electricity and steam for oilsands operations while exporting approximately 800 MW to Alberta’s grid. Courtesy: Suncor Energy The implications are steep for Alberta, a province of just over four million people, where industrial users consume roughly half of total electricity generation. As of April 2025, Alberta’s installed generating capacity stood at 23,164 MW, but real-time output reflects that the province leans heavily on 6 GW of installed cogeneration capacity (Figure 2) distributed across more than 40 industrial facilities, followed by 5.7 GW of wind from over 60 wind farms, and 3.9 GW of gas-fired combined cycle capacity from roughly a dozen major plants. Alberta’s gas-fired steam fleet, once the workhorse of the grid, still accounts for more than 3 GW of capacity across nine plants. The province also has 1.8 GW of solar capacity spread across more than 50 sites, and battery storage—while still nascent—is growing, with 190 MW of installed capacity across 10 projects. In April, Alberta’s internal load hovered above 9.2 GW, supported by 10 GW of net generation and 953 MW of imports—primarily from British Columbia. According to Christiaanse, the province has strengthened its baseload position with nearly 2 GW of new capacity from the Genesee repowering. The flexibility to evolve Alberta’s supply mix so rapidly stems largely from its unique power market structure. Unlike most other Canadian provinces, Alberta operates a fully deregulated electricity market—an open, competitive environment where private developers can build, own, and operate generation without requiring government approval or long-term utility contracts. “We strongly believe in the competitive deregulated market. It’s a distinct competitive advantage for us. A lot of Americans don’t realize that we mirror Texas pretty closely in terms of how we play in policy,” Christiaanse said. That flexibility has allowed the province to pragmatically pursue deep decarbonization independently, without relying on prescriptive federal mandates. The province, notably, has pushed back against Canada’s proposed Clean Electricity Regulations—which aim to create a net-zero electricity grid by 2035—arguing they are unrealistic and infringe on provincial jurisdiction. “We’re not going to be told how to do it,” Christiaanse said. “We believe in the market, and if the market is going to transition to clean energy, it’ll do it efficiently through competition.” Christiaanse stressed the province’s competitive stance has been a boon for its much-needed infrastructure development. While the province eliminated “about 34% of regulatory rules over the last few years,” it has attracted major infrastructure investment—including a recent CA$500 million transmission upgrade by Berkshire Hathaway Energy. Renewables make sense in some parts of the province. “People miss the fact that our southern part of our province gets almost as much sun as Cairo,” Christiaanse pointed out. However, the province is also exploring emerging technologies, including small modular reactors (SMRs) and carbon capture, to support both emissions reductions and economic resilience. In January 2024, Capital Power joined forces with Ontario Power Generation to examine the feasibility of a range of nuclear technologies, including GE Hitachi’s BWRX-300, looking at potentially bringing a reactor online by 2035. SMRs are receiving particular attention for their dual potential: decarbonizing industrial operations and replacing diesel generation in remote communities, including the First Nations. “We need that technology to decarbonize our oil and gas sector,” Christiaanse said. But rather than go it alone, Alberta is working with Ontario, Saskatchewan, and New Brunswick to leverage their nuclear expertise and accelerate deployment. “We’re not going to reinvent the whole situation about that,” Christiaanse said. In tandem, Alberta is also exploring geothermal. The province’s first conventional geothermal facility, the Alberta No. 1 project—also known as the Greenview Geothermal Power Plant—is being developed by Terrapin Geothermics. Located in the Municipal District of Greenview, the project will include a binary cycle power plant, a geothermal wellfield reaching depths of up to 4,000 meters, and district heating infrastructure designed to serve light industrial operations. The project is scheduled for completion in 2025, producing 10 MW of baseload electricity and 985 terajoules of thermal energy annually, using previously disturbed oil and gas land, and tapping Alberta’s legacy drilling expertise. Carbon capture, utilization, and storage (CCUS) also remains central to Alberta’s decarbonization strategy. The province hosts 27 CCUS projects to support oil sands, power, clean hydrogen, petrochemicals, cement, and steel. Christiaanse said J.P. Morgan has rated Alberta as the second-most promising region in the world for carbon storage. The province’s most lucrative prospects, for now, rest on the rapid development of large-scale data centers. Recent announcements underscore the scale of interest: eStruxture is developing a 90-MW facility in Rocky View County—Alberta’s largest to date—while Beacon AI has unveiled plans for at least five 400-MW campuses across the province, totaling 2 GW of capacity on over 1,600 acres. These projects, located near Calgary, Edmonton, and other industrial corridors, often feature co-located generation assets and are designed to support high-intensity artificial intelligence (AI) workloads. Meanwhile, Amazon has committed to sourcing power for its Alberta-based AWS operations through long-term power purchase agreements (PPAs) tied to landmark renewable projects like the 465-MW Travers Solar Farm and the 495-MW Buffalo Plains Wind Project, the latter now under construction. The province’s open market structure has also influenced how it plans to address this surge. To accommodate the more than 11 GW of data center–related interconnection requests—more than Alberta’s current peak load—the government has drawn a hard line on how hyperscalers can plug in. “If you want to bring a data center to Alberta, we’d love to have you. We have a great grid,” said Christiaanse. “But you need to bring your own power. Don’t come to us and say, ‘Oh, I want to do a data center, and I’ll just apply for power off your grid.’ ” Alberta’s policy framework requires data center developers to include co-located generation or behind-the-meter power supply—a model borrowed from the oilsands sector. “The oilsands sector did this for years,” he said. “We’re applying the same approach to new industries.” In some cases, onsite generation could even “go beyond what the data centers need” and support grid reliability, he noted. Alberta’s emerging position was formalized in the December 2024–published Alberta AI Data Centre Strategy, which outlines a three-pillar approach—scalable power capacity, sustainable cooling, and economic growth—to position Alberta as a global leader in AI-hosting infrastructure. The strategy notably champions Alberta’s deregulated power market, abundant natural gas supply, cold climate for efficient cooling, and streamlined regulatory timelines. It also pledges targeted support, including a concierge program for investors, designated industrial zones for faster permitting, and expanded partnerships with Indigenous and municipal stakeholders. Crucially, it reinforces Alberta’s commitment to accommodating both grid-connected and behind-the-meter models for new data centers—particularly those supporting AI and high-performance computing—while safeguarding affordability and system reliability for residents and legacy industries. —Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).

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01 May 2025

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France’S Electricity Network Workforce Is Short By 43,000 People

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