Canada
Power is provincial, not federal: two real markets in Alberta and Ontario, and a hydro-owning majority that never clears a price. Gas is the reverse. One basin, one benchmark, and a brand-new export route.
Overview
There is no Canadian power market. There are provincial ones, and only two of them clear on price. The rest is a Crown utility selling hydro at a regulated tariff.
Electricity is a provincial competence and the provinces went in opposite directions. Alberta runs an energy-only pool through the AESO: one price, set minute by minute, averaged to the hour. Ontario runs a centrally dispatched market through the IESO, which on 1 May 2025 moved to a day-ahead market with single-schedule dispatch and locational marginal pricing. Quebec, British Columbia and Manitoba are province-owned hydro systems where a regulator sets rates and no auction discovers anything.
The split matters commercially. Roughly 55% of Canadian generation is hydro, and most of it sits in the Crown-utility provinces, where it is never offered into a market. So the tradeable price signal lives in two provinces that resemble each other in no respect at all: a thermal, wind-heavy pool in Alberta, and a nuclear-based nodal market in Ontario.
Gas goes the other way. One integrated basin, the Western Canadian Sedimentary Basin, producing a record 19.0 Bcf/d in 2025, with 8.6 Bcf/d of that going to the United States by pipeline and, since June 2025, a first tranche moving to Asia as LNG.
Want Canadian power exposure? You are trading Alberta or Ontario. Want Canadian gas exposure? You are trading AECO/NIT basis, and increasingly the question of whether Kitimat offtake is big enough to tighten it.
Market structure
Two market provinces and several regulated ones. The federal regulator only touches what crosses a border.
Who does what
| Function | Body | Role |
|---|---|---|
| Alberta market and system operation | AESO | Energy-only pool, merit order, transmission planning |
| Alberta market conduct | MSA | Independent monitor of electricity and retail gas markets |
| Alberta utility regulation | AUC | Approves facilities, tariffs and ISO rules |
| Ontario market and system operation | IESO | Day-ahead and real-time markets, procurement, planning |
| Ontario rate regulation | OEB | Distribution and gas rates; Market Surveillance Panel |
| Interprovincial and export | CER | Federal permits for export lines and gas export licences |
Two market designs, one country
Alberta is energy-only. No capacity payment. The revenue case for a new plant rests on scarcity hours in the pool and whatever bilateral contract the developer can sign, which is an unusual design in North America and leaves Alberta prices structurally more volatile than any capacity-market jurisdiction. The province is not standing still. The AESO's restructured energy market, targeted at mid-2027, adds locational pricing, day-ahead reserve procurement and a new 30-minute ramping product, and lifts the offer cap from $1,000/MWh to $1,500/MWh.
Ontario went the other way. It used to dispatch on one set of prices and pay on another. Now it runs a single schedule, where the price that dispatches a unit is the price it settles at, with locational marginal pricing reflecting congestion and losses at each node. If you traded the old Ontario market on the view that the uniform price told you everything, start again.
The regulated majority
Quebec, British Columbia, Manitoba and Newfoundland and Labrador are dominated by provincially owned hydro utilities. No wholesale clearing price exists to trade. Exposure arrives through long-term contracts, intertie flows into neighbouring US markets, and rate cases before the Régie de l'énergie and the BC Utilities Commission. What moves these systems is hydrology.
Infrastructure — power and gas
The power system was built north to south, not east to west. The gas system was built around a single basin.
Power
Canada's grid is a set of provincial systems wired hard into the United States and only loosely to each other. There are 86 international power lines crossing the border, and in 2025 Canada exported 32.7 TWh while importing 22.1 TWh, a net export of 10.6 TWh. For most provinces the nearest liquid market lies south of the border.
Alberta
About 23,242 MW of installed capacity at the end of 2025, 61% gas and 24% wind, with 1,850 MW of solar. A December 2025 winter peak of 12,785 MW set a record.
Ontario
A nuclear-anchored system — 46.2% of 2025 generation — now running a nodal day-ahead and real-time market, with major refurbishments under way at the CANDU fleet.
Hydro provinces
Quebec, BC, Manitoba and Newfoundland and Labrador hold large storage reservoirs. Their output varies with precipitation, and that variation shows up in export flows to the US rather than in a domestic price.
Gas
Supply is almost entirely Western Canadian Sedimentary Basin, the Montney straddling the Alberta–British Columbia border. Alberta produced 11.3 Bcf/d in 2025 and British Columbia 7.4 Bcf/d. Gas gathers onto the NGTL system in Alberta, whose trading point AECO/NIT is the national benchmark, and onto the Westcoast system in north-east BC, whose trading point is Station 2. From there it runs east to Ontario and Quebec, south to the US, and now west to the LNG Canada terminal at Kitimat.
Schematic — system topology, not a geographic map. Provinces grouped by market design, not by location. The dominant electrical relationship for most provinces is southward into the US, not eastward across Canada. Trade figures: Canada Energy Regulator.
Demand and supply
More than half the generation mix is hydro. The gas business keeps setting production records, and a new export route has started to change what Alberta gas is worth.
Power
Canada draws more of its electricity from hydro than almost any large economy, which lends the national statistics a calm they do not deserve. The volatility is in the two market provinces. In Alberta gas and wind set the price. In Ontario a large inflexible nuclear base leaves the margin to gas or an import.
Shares for 2025. Source: Low Carbon Power.
Gas
Production kept growing through a stretch of weak prices because the Montney is liquids-rich. Condensate revenue carries wells that gas alone would not. National output averaged 19.0 Bcf/d in 2025 and peaked at 20.0 Bcf/d in November.
Source: Canada Energy Regulator.
Against 19 Bcf/d of production, 0.3 Bcf/d is nothing. The constraint is what changed. For the first time Western Canadian gas has a buyer who is not the United States. AECO basis to Henry Hub has always been the price of being landlocked. Kitimat is the first real test of that.
Price setting mechanism
Two genuinely different clearing mechanisms in power. Then a gas benchmark that is really just a basis differential wearing a name.
Alberta — the minute-by-minute pool
Offers stack cheapest to dearest into a merit order. The highest-priced offer actually dispatched sets the system marginal price, recalculated every minute. The hour settles at the average of those 60 one-minute prices. Everything that cleared is paid it.
Two things follow. Averaging dilutes any short scarcity event inside the hour: a $999 spike lasting fifteen minutes lands as a pool price nearer $250. And with no capacity payment, those scarcity hours are the entire investment signal. Give the province a mild year and a strong wind fleet and the pool price falls apart. 2025 averaged $43.68/MWh, the lowest in eight years, with 8.1% of hours settling at zero.
Ontario — dispatch price equals settlement price
Before May 2025 Ontario dispatched units against one set of prices, settled them against a uniform provincial price, and trued up the difference with side payments. The renewed market runs a single schedule instead. Day-ahead produces financially binding positions, real-time dispatch runs on locational prices, and a generator settles at the node where it injects.
That moves where the risk sits. Congestion used to be socialised into uplift charges. It now shows up in the spread between nodes, which makes it hedgeable and makes ignoring it expensive. Consumers still pay the Global Adjustment, the charge reconciling contracted generator revenues with market revenue. In low-price periods it dwarfs the energy price.
Gas — AECO/NIT and Station 2
AECO/NIT is a virtual trading point on the NGTL system in Alberta. Station 2 is its north-east BC equivalent on the Westcoast system. Neither is a physical hub in the Henry Hub sense. They are receipt-point pools, and the price is best read as Henry Hub minus the cost of getting out of the basin. The basis is where the money is: AECO-C averaged Cdn$1.45/GJ in 2024, when the discount to Henry Hub widened to US$1.29/MMBtu, before recovering toward Cdn$2.71/GJ.
Canadian gas trades in C$ per gigajoule, not US$ per MMBtu. Between AECO and Henry Hub sit both a currency conversion and an energy-unit conversion. Invert either one and a wide basis will look narrow.
Regulatory regime
Provincial regulators own almost everything that matters here. Ottawa owns the border.
| Body | Remit |
|---|---|
| Canada Energy Regulator (CER) | Interprovincial and international pipelines, power export permits, gas export licences, national market data |
| Alberta Utilities Commission (AUC) | Approves ISO rules, transmission facilities and utility tariffs in Alberta |
| Market Surveillance Administrator (MSA) | Independent conduct monitor for Alberta electricity and retail gas |
| Ontario Energy Board (OEB) | Rate regulation, licensing, and the Market Surveillance Panel |
| Régie de l'énergie / BCUC | Set regulated rates in Quebec and British Columbia |
| Environment and Climate Change Canada | Emissions regulation of the generating fleet |
Where the federal government actually bites
Ottawa cannot design a provincial power market. It can regulate emissions from the plants running in one. The final Clean Electricity Regulations, published in December 2024, set a technology-neutral emissions limit on fossil generation and are projected to remove some 181 megatonnes of cumulative emissions from the sector between 2024 and 2050. They bite hardest on precisely the two provinces with markets, Alberta's gas fleet and Ontario's gas peakers. The hydro provinces were compliant the day they were built.
Conduct oversight
Alberta's Market Surveillance Administrator is an unusual animal: an independent statutory body that investigates and prosecutes market conduct, with published guidelines on offer behaviour and physical withholding. In an energy-only market run by a handful of large portfolios, the line between legitimate scarcity pricing and abuse is the central regulatory question, and in Alberta it gets litigated. Ontario keeps the equivalent function inside the OEB's Market Surveillance Panel.
What to watch
Three live files. Alberta's restructured energy market, targeted at mid-2027, bringing locational pricing and an offer cap rising in steps to $2,000/MWh by 2032. Ontario bedding down the renewed market while procuring new nuclear and storage. And the federal-provincial argument over emissions rules, which in Canada never stays settled. The constitutional division of powers means energy policy gets negotiated, never directed.
Key links
Primary sources for this market. Figures on this page are drawn from these and from published market data.