How Alberta's Move to Nodal Pricing Reshapes Asset Revenues

Alberta's Restructured Energy Market swaps a single pool price for locational marginal pricing in 2028, while supply, demand, and policy are all shifting at once. We teamed up with Power Advisory for a webinar on what that looks like in practice, and why it matters well beyond the province.

Power Advisory is an electricity market consulting firm with offices in Calgary, Toronto, and Boston. Many of its team previously worked at the AESO, the Market Surveillance Administrator, the Alberta Utilities Commission, and the IESO. They produce a subscription price forecast for Alberta out to 2060, updated each April and October, that tracks the province's move to the restructured energy market (REM).

Here's what they found.

Why Alberta’s Energy Market is Changing

Since 2020, about 5 GW of coal has retired or converted to gas, and gas capacity has nearly doubled from about 7.7 GW to 14 GW. Wind has roughly tripled to about 5.7 GW, and solar has gone from almost nothing to about 1.9 GW.

For now, supply is comfortable, with about 23.4 GW installed against a peak of about 12.8 GW. Year-to-date 2026 prices sit at about $32/MWh.

The connection list tells a different story, with 14.85 GW of supply and a whopping 23.14 GW of demand waiting to connect. That's more load than today's entire peak, and roughly 90% of it is data centers. How much of it actually connects is a big uncertainty. Still, the direction of travel is hard to ignore, and a single uniform price can't signal where new supply and load should go.

Key Changes Under Alberta's Restructured Energy Market

The biggest shift is the LMP itself. An LMP is what it costs to serve one more megawatt of load at a specific spot on the grid. Every node gets its own price, built from three pieces.

• Reference bus price. The same everywhere on the system.
• Congestion component. Moves the price up or down based on transmission constraints.
• Loss component. Reflects power lost getting to that location.

Any of these can be negative, so LMPs can be too. Loads pay the ALP pay a load-weighted average of LMPs instead of their own node's price but can opt to pat the LMP instead.

How Nodal Pricing Changes Asset Revenues

Power Advisory's PLEXOS® model represents Alberta at the nodal level, including the transmission system, interties, and generator attributes and offers. Early results show LMPs are sensitive to the local balance of load and generation, react to transmission expansion decisions, and run lower in congested areas until new infrastructure eases the constraints. Three findings stood out.

1. Same starting price, very different paychecks

Two nodes can share the same $86.06/MWh reference price and still end up far apart. At a node far from load centers with frequent outflow constraints, an $18.44 congestion charge and a $4.23 loss charge drag the LMP down to $63.39/MWh. A strongly connected node close to load centers barely budges, landing at $85.18/MWh. Today, the uniform pool price ignores congestion and losses are settled separately. Under REM, both show up right there in the price.

2. R30 hits solar hardest, per megawatt hour

R30 costs are allocated to load, wind, and solar, and solar pays the most per MWh. By 2035, Power Advisory's forecast has solar at $3.44/MWh, compared with $1.55 for wind and $0.54 for load. Blame winter. Solar output drops right as the evening demand ramp kicks in, when R30 volumes and prices peak. Winter solar output is also lower, so those costs get spread over fewer megawatt hours. The flip side is that controllable, dispatchable generators like thermal pick up a brand new revenue stream.

3. Location and technology shape capture prices

In Power Advisory's illustrative forecast for 2031 to 2033, wind in the Hanna planning area captures roughly $60 to $65/MWh, while Medicine Hat wind sits closer to $45 to $50/MWh. Solar flips the script, with Medicine Hat edging out Hanna by about $1 to $2/MWh. Individual assets can stray further from these area averages based on local transmission, capacity factor, generation profile, and how closely their output tracks nearby assets.

None of these are unique to Alberta. They show up anywhere transmission can't keep pace with renewables.

What Data Centers and Carbon Policy Mean for Alberta Power Prices

Power Advisory published its Base Case forecast in April 2026, just before the federal-provincial carbon MOU Implementation Agreement arrived in May. The agreement sets a price floor for TIER credits from 2030 to 2040, but it also slows the annual tightening of the high-performance benchmark from 2% to 1%. Taken together, thermal generators face lower carbon compliance costs. Since thermal is the main price setter in Alberta, the Alberta load price drops too. Thermal real net revenues rise about 1%, and renewables gain less than 1% as higher carbon prices lift environmental attribute revenues. Power Advisory has since updated its Base Case to use the MOU price floor.

Data centers are the bigger wild card. In a deliberately simple stress test, Power Advisory moved data center load up or down by 500 MW and held everything else steady. If supply doesn't respond, adding 500 MW raises long-run prices by about 30%, while losing 500 MW cuts them by about 20%. That gap holds all the way through 2050.

Alberta's bring your own generation (BYOG) requirement, which applies to loads over 75 MW, should in theory keep things balanced. The catch is that BYOG covers capacity, not energy. Data centers use more power in summer for cooling, just as thermal plants get derated in the heat, and the mismatch flips in winter. Prices only stay put if generation exactly matches load, outages are fully backed up, and summer derates are offset by load reductions. Those conditions won't line up perfectly in practice, so BYOG loads will still move prices.

How to Model a Nodal Power Market

In a single pool price, a transmission constraint disappears into the average. In a nodal market, it becomes the price gap between your asset and the load it serves. Approximate it, and you distort the signals your investment decisions depend on.

PLEXOS® captures physical constraints, market rules, and economic drivers in one consistent framework. It splits each nodal price into energy, congestion, and loss components, and its Available Transfer Capability analysis helps developers and large loads like data centers find nodes with lower curtailment or load-shed risk. More than 50 transmission and system operators use it globally. With regulators and boards expecting transparent, auditable assumptions, that means defending a proven methodology, not a black box.

Lessons for Power Markets Beyond Alberta

Alberta's shift is a preview of questions power markets around the world are already wrestling with. As renewables outpace transmission, flexibility gets its own price tag, and large loads crowd into connection queues, where an asset sits on the grid matters more than ever. Whether you're facing a market redesign or already operating in a nodal market, the lesson is the same. The teams that understand their locational exposure early will be best placed to act.