For a quarter of a century, Alberta’s electricity market has worked the same way: one province-wide price, set hour by hour, in an energy-only design. That’s the market most contracts, forecasts, and procurement strategies in the province were built around.
That design is being replaced.
On August 27, 2025, the AESO released the final design for Alberta’s Restructured Energy Market (REM): the product of more than two years of work and, by the AESO’s own account, the most extensive stakeholder engagement in its history, with over 230 organizations at the table. ISO rules go through stakeholder review this fall, and the new market is set to take effect in mid-2027.
That’s not a minor technical update. It’s a rebuild of how prices are set, how reliability is paid for, and who bears the cost of keeping the grid balanced.
What’s actually changing
Three changes matter most for how the market behaves day to day.
Locational marginal pricing (LMP) introduces prices that vary by location, reflecting local grid conditions and line losses, alongside the existing province-wide price. Most consumers keep paying the single Alberta-wide rate. But large, transmission-connected customers get a one-time option to opt into local pricing instead, and new generation is expected to price locationally by default, while existing generators get a window to elect otherwise. If your business is large enough to be eligible, that election is a real strategic decision, not a formality.
The price band is widening. The energy offer cap rises to $1,500/MWh in 2027 and $2,000/MWh by 2032. A new scarcity pricing mechanism sets an overall ceiling of $3,000/MWh. On the other end, the price floor, currently $0/MWh, moves to as low as $100/MWh by 2032, reflecting how often renewable generation is expected to push prices negative during periods of oversupply.
$0 to $1,500 becoming – $100 to $3,000. That’s a meaningfully wider range for any contract that references the pool price, whether or not you ever touch locational pricing directly.
A new real-time ramping product pays generators to be ready to increase output on short notice, useful for managing demand spikes and extreme weather. Its cost is split between consumers and generators based on who’s driving the need for it, which means this isn’t purely a generator-side cost.
Why this is a reliability story too: a genuinely positive one
Alongside the pricing changes, the REM adds tools aimed squarely at avoiding supply crunches: an enhanced day-ahead operating reserves market with more frequent procurement and wider eligibility, and a “reliability unit commitment” process that lets the AESO proactively bring slower-starting generation online when a 48-hour forecast shows the supply cushion running thin. Both are designed to catch a tightening system before it becomes an emergency, rather than reacting after the fact.
Worth noting what the REM doesn’t include: no capacity market, and no day-ahead energy market. Alberta is staying with its energy-only design, just adding more tools inside it.
What this means for how you buy
If your business isn’t large enough to qualify for locational pricing, the REM may feel like it’s happening at a level removed from your day-to-day contract. It isn’t, entirely. The province-wide price you do pay is still shaped by a market where the price band is wider, ramping costs are shared, and reserve procurement works differently than it does today.
Two businesses can hold structurally similar Alberta contracts and be in very different positions come mid-2027. One has already had its power purchase agreements reviewed for change-of-law language robust enough to handle a market redesign, and has a documented view on whether it qualifies for, and wants, locational pricing. The other finds out what its contract says about “material market changes” after the rules have already changed.
Neither position is unreasonable today, with implementation still roughly a year and a half out. But the AESO has published the final design, and ISO rules are in stakeholder review this fall : the details are no longer hypothetical. If you haven’t had your Alberta contracts checked for how they handle a market restructuring of this scale, that’s worth doing before mid-2027 arrives.
