Alberta’s power market in Q1 2026: A quarter of low prices, congestion, and unprofitability

The first quarter of 2026 presented a dynamic and often challenging landscape for Alberta’s wholesale electricity market. While overall prices saw a significant dip, the quarter was marked by a stark contrast between an expensive January and record-low prices in February, alongside acute price volatility due to supply constraints, unexpected outages, and mounting transmission challenges.

Let’s break down the key takeaways from the Market Surveillance Administrator’s (MSA) Wholesale Market Report for Q1 2026.

A tale of two mini-seasons: January spikes while February plummets

Q1 2026 saw the average pool price settle at $32.15/MWh. While this represents a notable 19% decrease from the overall Q1 average last year, it hides a massive shift in monthly performance:

• The January buck: January did not follow the low-price trend. Driven by higher natural gas prices, more thermal outages, and slightly higher demand, the average pool price in January was $39.44/MWh, a significant 30% increase year-over-year.
• The February collapse: Conversely, February prices completely tanked, averaging just $22.39/MWh. This marked a 60% drop compared to February 2025 and stands as the lowest average price for February on record when adjusted for inflation. According to the report, the downward pressure that eventually won out across the quarter as a whole was heavily influenced by a combination of key market drivers:

• • • Mild winter weather: A lack of major cold snaps across January and February prevented severe seasonal peak demand spikes. However, underlying grid demand actually increased by 1.5% year-over-year across the whole quarter due to population growth and rising oilsands production.
    • Abundant supply: A massive surge in wind and solar output added significant downward pressure on the market.
    • Depressed fuel costs: Lower natural gas prices in February and March directly suppressed thermal generation costs.
    • Declining exports: A year-over-year reduction in outward power flows left more energy trapped within the province.

Increased capacity from Suncor’s Base Plant cogeneration asset (which averaged 780 MW of availability compared to 530 MW in Q1 2025) added further downward weight to the latter half of the quarter.

Price spikes amidst supply challenges

Natural gas restrictions in March

The market experienced severe upward pressure on pool prices during two distinct pipeline outages near Fort McMurray (March 7–11 and March 26). Interruptible gas supply dropped to 0%, forcing local thermal generators to heavily curb their availability. Combined with low intermittent renewable supply during evening peaks, prices skyrocketed, maxing out at $949/MWh on March 26.

Wind outages and generator trips (March 25)

Unexpected turbine icing cut actual wind generation down to 1,300 MW against a day-ahead forecast of 2,650 MW. Because the error happened too quickly to bring long-lead-time gas plants online, the grid was caught off guard. When the 466 MW Cascade 1 gas unit simultaneously tripped offline, the available market supply cushion plummeted to a critical 160 MW, the lowest point of the entire quarter.

The Shepard Energy Centre outage (January 5)

The quarter’s highest daily average pool price ($363/MWh) occurred on January 5. Prices climbed on this day following an unscheduled outage at the Shepard generation asset, which took 810 MW of capacity offline. Because the trip was sudden and wind/solar generation dropped below what the AESO forecasted, the market lacked sufficient notice to ramp up offline gas-fired steam assets.

Alberta lends a hand to BC, faces profitability woes

Beyond internal market dynamics, Alberta’s grid also stepped up to support regional grid stability. Just before 01:00 MST on March 8, a catastrophic transmission fault in British Columbia isolated major generating stations, causing the BC grid to shed 2,600 MW of generation and 900 MW of load. Alberta’s interties automatically responded, providing 425 MW of emergency power for approximately 18 minutes to help stabilize the Western Interconnection.

However, the report highlights a deeply concerning operational trend for internal generation assets:

• Unprofitable market conditions: A net revenue analysis modeling generic generation technologies (combined cycle, simple cycle gas, wind, and solar) indicated that every single asset class operated at a loss over the quarter due to low pool prices.
• Explosive transmission congestion: The total volume of constrained intermittent generation surged to 561 GWh in Q1, a staggering 250% increase year-over-year. At least 1 MWh of renewable generation was actively curtailed in 58% of hours, showcasing severe transmission constraints.
• Locational marginal prices (LMP): Looking ahead to the AESO’s planned market overhaul, the MSA ran a counterfactual 2021 – 2025 scenario. The data shows that LMP would have slashed revenue for highly congested wind/solar assets in the southeast while resulting in higher prices for unconstrained assets across the rest of the province.
• Batteries cool off-peak volatility: On a positive note, energy storage assets actively boosted competition by bidding into regulating reserves during off-peak windows, successfully lowering clearing costs in that segment.