Decision-support tool · Trade-off
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Quebec Energy Simulator (2025-2050)
Beta version 0.5.3
Current scenario:
Scenario result
Indicators for
First capacity shortfall
Energy balance in 2035
Rise in average cost by 2035
GHGs avoided in 2035
GHGs avoided outside Quebec in 2035
Neighboring grids
Average carbon intensity of the electricity consumed, in grams of CO₂ equivalent per kWh, including the life cycle of power plants and imports.
In Quebec, day by day
Energy balance
Reading this chart: colors, hatching, axis
- Needs: needs without savings, Quebec plus exports. Everything in color must reach this line.
- Energy savings, the “virtual power plant”: each TWh saved is a TWh that does not have to be generated. They stack on top of generation.
- In gray, existing supply: hydro, existing wind, Labrador (1969 contract). In color, what is added.
- Hatched blue: depends on the option chosen for Churchill Falls.
- Hatched red: remaining needs to be met, through temporary imports or other solutions, as in Hydro-Québec’s supply balances.
- Band under the years: gap between supply and needs, green for a surplus, rust for a shortfall.
- Axis: TWh per year, one step per year. It starts at 100 TWh.
Winter peak, on a very cold morning
Reading this chart: colors, hatching, axis
- Needs: peak needs without savings, reserve included. Everything in color must reach this line.
- Energy savings, the “virtual power plant”: each GW saved at the peak is a GW that does not have to be supplied. They stack on top of generation.
- In gray, existing supply, counted by its contribution to the peak. In color, what is added.
- Hatched blue: depends on the option chosen for Churchill Falls.
- Dotted gray: short-term purchases from neighboring markets.
- Purples: batteries, peaking thermal generation and demand management.
- Hatched red: remaining needs to be met, through temporary imports or other solutions, as in Hydro-Québec’s supply balances.
- Band under the years: gap between supply and needs, green for a surplus, rust for a shortfall.
- Axis: GW available on a very cold morning, one step per winter. It starts at 30 GW.
Average cost and price paid
Reading this chart: the red area
¢/kWh in 2025 dollars. The red area, where the cost exceeds the cap, is the gap that must be financed some other way: the government, debt or other customers.
Bills of typical households in 2035
2025 dollars, before taxes: at 2025 rates, in 2035.
Your decisions
Start from a scenario
Adjust
Construction rates start after a commissioning delay. A decision taken today takes effect after a lead time of 1 to 15 years depending on the source, shown under each slider.
Conditions2 settingsThese are not decisions: water inflows and duration, to test weather and climate
Benchmarks and sources
Benchmarks: −42 TWh in 2023, −35 in 2024 and −33 in 2025 compared with normal (Hydro-Québec, 2025 financial results, in French). The annual model does not represent multi-year reservoirs, which absorb part of a dry spell: the effect of a short episode is probably overstated here. Since 1943, the reservoirs have received on average enough water to generate 222.4 TWh a year, and three years this low in a row had not been seen since 1961-1963 (État de l’énergie au Québec 2026, chart 13, p. 19, in French).
Assumptions and sources
The parameters and assumptions used, with their sources.
| Parameter | Value | Status | Source |
|---|---|---|---|
| Demand and peak | |||
| Electricity sales in Quebec in 2025, weather-normalized | 182 TWh | Derived from sources | Hydro-Québec forecasts sales of 182 TWh in Quebec in 2026 (Supply Plan 2027-2041); 184.9 TWh in 2025, a cold year. Source |
| Winter peak demand 2025-2026 (normalized forecast) | 40 599 MW | Sourced | 2025 progress report on the supply plan: 40 599 MW for winter 2025-2026. Action Plan 2035 cites an average peak of about 41 500 MW; record of 43 134 MW in February 2023. Source |
| Required reserve margin at peak | 12% | Sourced | 2025 progress report: reserve of 4 725 MW for 40 599 MW of peak demand in 2025-2026 (11.6%). Source |
| Peak reduction per TWh saved | 167 MW per TWh/yr | Derived from sources | 3 500 MW of capacity for 21 TWh of energy savings by 2035 (Action Plan 2035). Source |
| Weight of large projects at peak | 125 MW per TWh/yr (range: 100 to 135) | Modelling assumption | Calculation: 1 TWh per year consumed at a capacity factor of 85 to 100% requires 114 to 134 MW; 125 MW corresponds to about 90%. |
| Share of sufficiency applied to electrified transport and heating | 100% (range: 50 to 100%) | Modelling assumption | Assumption: the same sufficiency rate applies to kilometres driven and to converted heating. Range of 50 to 100% of the general rate. |
| Electric transport | |||
| Fleet of personal vehicles | 5 000 000 vehicles | Sourced | 5 million personal vehicles. Source |
| Annual consumption of an electric vehicle | 3 150 kWh/yr | Sourced | 15 000 km per year at 21 kWh/100 km. Source |
| Share of the fleet electrified in 2025 | 7% | Derived from sources | 403 138 light electric vehicles registered as of June 30, 2025, about 29% of them plug-in hybrids; i.e. about 7% of the 5 million vehicles in all-electric equivalent. Source |
| Impact of an electric vehicle at the winter peak | 1.20 kW | Sourced | Hydro-Québec estimated the average impact at 0.6 kW per vehicle; the CFIB put it at 1.2 to 1.5 kW if the peak occurs in the evening (uncontrolled charging, 2017). CFIB value used, twice Hydro-Québec’s. Source |
| Gasoline used by a combustion vehicle | 1 335 L/yr | Derived from sources | 15 000 km per year at 8.9 L/100 km, the average consumption of a vehicle in Canada (Canada Energy Regulator, 2017). Source |
| Emissions per litre of gasoline | 2.30 kg CO₂/L | Sourced | Burning one litre of gasoline produces about 2.3 kg of CO₂ (Natural Resources Canada). Source |
| Energy content of a litre of gasoline | 8.90 kWh/L | Sourced | A litre of gasoline contains energy equivalent to 8.9 kWh of electricity (Natural Resources Canada). Source |
| Buildings, industry and hydrogen | |||
| Fossil energy used to heat buildings | 32 TWh | Derived from sources | Order of magnitude: natural gas accounts for 8% of energy in the residential sector and 27% in the commercial and institutional sector; heating oil for about 4% of residential. Source |
| Electricity needed to replace fossil heating | 0.32 kWh of electricity per kWh of fossil fuel (range: 0.27 to 0.80) | Modelling assumption | Assumption: fossil heating at 80% efficiency replaced by a heat pump. Hydro-Québec cites an efficiency one to three times higher than baseboard heaters; the range runs from an efficient heat pump (0.27) to resistance heating (0.8). Source |
| Weight of electric heating at peak | 500 MW per TWh/yr | To be validated | Order of magnitude. |
| Emissions from fossil heating | 0.19 Mt per TWh | Derived from sources | Natural gas: 1 891 g of CO₂ per m³, i.e. about 0.18 Mt per TWh; No. 2 light fuel oil, used for heating: 2 735 g of CO₂e per litre for 10.69 kWh, i.e. about 0.26 Mt per TWh; weighted by the share of gas in buildings. Source |
| Fossil energy replaced per TWh of electricity (industrial processes) | 1.40 TWh of fossil fuel per TWh of electricity (range: 1 to 3) | Derived from sources | Quebec industry loses 34% of the energy it consumes at the point of use, versus 75% for transportation (État de l’énergie au Québec 2026, p. 40); an electric process loses much less. Pareto’s calculation: 1 kWh of electricity replaces about 1.4 kWh of fuel, less for very high-temperature heat, more with an industrial heat pump. Source |
| Emissions from the fossil fuels replaced (industrial processes) | 0.20 Mt per TWh of fossil fuel | Derived from sources | Natural gas: about 0.18 Mt per TWh; fuel oil: about 0.26 Mt per TWh. Natural gas dominates industrial heat: weighted value of 0.20 Mt per TWh. Source |
| Weight of industrial process electrification at peak | 110 MW per TWh/yr (range: 60 to 130) | Modelling assumption | Assumption: a fairly steady load (continuous processes), part of which can be shifted off-peak. Stored heat, such as that of a thermal battery charged at night, can be curtailed at peak and would lower this weight; since no Quebec installation is documented, the value does not account for it. |
| Fossil energy replaced per TWh of electricity (trucks, buses, off-road equipment) | 2.50 TWh of fossil fuel per TWh of electricity (range: 2.10 to 2.90) | Derived from sources | In real-world operation, 91 European battery-electric trucks use 65% less energy than an average diesel truck and 53% less than the best diesel (ICCT, Ragon, 2025), a ratio of 2.1 to 2.9. A value of 2.5 allows for winter: STM buses use 26% more in the cold (Concordia, 2025). Source |
| Emissions from the diesel replaced (trucks, buses, off-road equipment) | 0.26 Mt per TWh of fossil fuel | Derived from sources | Diesel: 2 730 g of CO₂ per litre for about 10.7 kWh, i.e. about 0.26 Mt per TWh. Source |
| Weight of truck and bus electrification at peak | 100 MW per TWh/yr (range: 60 to 150) | Modelling assumption | Assumption: charging mostly at the depot, at night, off-peak, but some buses and delivery trucks also charge during the day. Hydro-Québec uses separate charging profiles for each vehicle category, without publishing them (Supply Plan 2027-2041, p. 17). Source |
| Gasoline replaced per TWh of electricity (small engines) | 10 TWh of fossil fuel per TWh of electricity (range: 9 to 14) | Derived from sources | For equal hours of use, CARB estimates 1.1 to 1.5 L of gasoline replaced per kWh of electricity, or 10 to 14 kWh of gasoline, depending on whether the equipment is commercial or residential (2021, appendix I, tables C-8 and C-9). Saidani and Kim (2021) give about 1 L versus 1 kWh per hour for a push mower, or 9 kWh. Value retained: 10, the lower of CARB’s two. Source |
| Hydrocarbon imports per TWh of fossil energy | 54 $M per TWh | Derived from sources | About $14 billion of hydrocarbons imported per year for about 258 TWh of fossil energy (52% of 496 TWh in 2022). Source |
| Hydrogen: electricity required compared with direct electrification (low end of range) | 2 times | Sourced | Hydrogen-based fuels require 2 to 14 times more electricity than direct electrification, depending on the use and technology (10 to 35% efficiency from electricity to useful energy). Source |
| Hydrogen: electricity required compared with direct electrification (high end of range) | 14 times | Sourced | Ueckerdt et al., Nature Climate Change, 2021. Source |
| Electricity used for green hydrogen in 2025 | 0.20 TWh per year | Derived from sources | Chair in Energy Sector Management, HEC Montréal, État de l’énergie au Québec 2026, table 6, p. 24: 23 MW of electrolyzers in operation, Air Liquide in Bécancour (20 MW, 8 200 kg of hydrogen per day) and Tulig Énergie at the Raglan mine (3 MW). Running continuously for a year: 23 MW × 8 760 h = 0.20 TWh. Already included in 2025 demand. Source |
| Electrolysis efficiency, compression and station included | 51% | Sourced | Quebec’s Ministère des Transports (2024), government test bench on fuel cell vehicles: 55.4 kWh per kg of hydrogen at the electrolyzer (p. 24), plus about 9 kWh/kg for compression and the station (p. 27), i.e. 64.8 kWh/kg; 33.3 kWh/kg (LHV) ÷ 64.8 = 51%. A value measured in Quebec, and the most cautious one available: the IEA gives 63% for electrolysis alone in 2024 (Global Hydrogen Review 2025, annex, p. 6). Conversion losses into synthetic fuels are not counted. Source |
| Emissions of the fuel that green hydrogen replaces (natural gas) | 0.18 Mt per TWh of fossil fuel | Derived from sources | Conservative choice: green hydrogen is assumed to replace natural gas, the less emitting of the two fuels used for industry (about 0.18 Mt per TWh, against 0.26 for diesel), which gives the smallest decarbonization potential. Source |
| Weight of hydrogen production at peak | 30 MW per TWh/yr (range: 0 to 125) | Modelling assumption | Assumption: electrolyzers largely interruptible during the winter peak; from 0 (fully interruptible) to 125 MW per TWh (continuous operation). |
| Existing resources | |||
| Energy available from existing resources, existing wind included, under normal water inflows (sales equivalent) | 212 TWh/yr | Derived from sources | Total sales (in and outside Quebec) in years with near-normal water inflows: 208.9 TWh (2018), 210.8 TWh (2021) and 216.2 TWh (2022, of which 180.6 in Quebec and 35.6 outside Quebec). Source |
| Benchmark: drop in water inflows observed in a dry year | 33 TWh/yr | Sourced | Hydro-Québec: inflows below normal by 42 TWh (2023), 35 TWh (2024) and 33 TWh (2025). Source |
| Capacity available at peak, existing resources | 45 850 MW | Derived from sources | 2024 progress report: demand of 45 603 MW, reserve included, for winter 2025-2026, of which 1 250 MW not covered by existing and committed resources; short-term markets can supply up to 1 500 MW. Hence about 44 350 + 1 500 MW. Source |
| Existing wind farms (included in existing resources) | 4 200 MW | Sourced | Installed wind capacity in Quebec: 4.2 GW in June 2026 (Canadian Renewable Energy Association). Shown separately in the charts. Source |
| Share of new production delivered to customers, after losses | 93% | Sourced | Overall loss rate of 7.3% used by Hydro-Québec to set its requirements (Régie decision D-2026-033). Source |
| Short-term capacity purchases from neighboring markets (included in existing capacity) | 1 500 MW | Sourced | Capacity contribution of neighboring and Quebec short-term markets, through capacity products or reserve sharing: 1 500 MW (2024 progress report). Source |
| New sources and lead times | |||
| Wind already ordered, in addition to existing farms | 3 500 MW | To be validated | 3 500 MW ordered according to L’actualité (2024), some of which may already be in service and counted in the existing 4.2 GW: to be validated. Source |
| End of commissioning of the wind already ordered | 2029 | Derived from sources | Call for tenders A/O 2023-01: deliveries between December 1, 2027 and December 1, 2029. Source |
| Contribution of existing wind at the winter peak | 37% | Sourced | 1 484 MW of peak contribution for 4 000 MW of wind, in Hydro-Québec’s capacity balance. Source |
| Contribution of ordered and new wind at the winter peak | 21% | Sourced | Supply Plan 2027-2041: about 11 000 MW of wind added by 2041 contributes 2 300 MW to the capacity balance (21%). Action Plan 2035 used about 15%. Source |
| Wind capacity factor | 35% | Sourced | Average contractual capacity factor of 35.1% for 38 wind contracts; 33.0% observed at 18 wind farms (Hydro-Québec Distribution before the BAPE). The Régie uses 35%. Source |
| Capacity factor of new hydro plants | 59% | Derived from sources | Romaine complex: 1 550 MW for average annual output of 8 TWh (59%). Source |
| Capacity factor of uprating | 11% | Derived from sources | Supply Plan 2027-2041: 9 000 MW of hydroelectricity added by 2041 (capacity increases, pumped storage) for only 9 TWh of energy (about 11%), but 8 600 MW at peak. Source |
| Solar capacity factor | 17% | Derived from sources | Supply Plan 2027-2041: 2 750 MW of solar added by 2041 for 4 TWh (about 16.6%), with no contribution at peak. Source |
| Contribution of batteries at peak | 100% (range: 50 to 100%) | Derived from sources | Supply Plan 2027-2041: about 500 MW of batteries by 2035, counted as 500 MW in the capacity balance. Range kept for long-duration peaks. Source |
| Lead time: wind | 4 years | Sourced | Hydro-Québec: 3 to 5 years for onshore wind. Source |
| Lead time: new hydro plant | 15 years | Derived from sources | The PGIRE mentions a development cycle of about 15 years for new hydroelectric complexes. Hydro-Québec cites 8 to 10 years for construction; L’actualité (2024) speaks of about 20 years for a dam. Source |
| Lead time: uprating | 6 years (range: 4 to 8) | Modelling assumption | Assumption: Action Plan 2035, published in 2023, plans 2 000 MW of turbine-generator replacements by 2035. Source |
| Lead time: solar | 2 years | Sourced | Hydro-Québec: from 18 months to 5 years for solar. Source |
| Lead time: batteries | 2 years (range: 1 to 3) | Modelling assumption | Assumption: time to install grid-connected batteries. |
| Lead time: demand response | 1 year (range: 1 to 2) | Modelling assumption | Assumption: time to roll out demand response programs (rates, controlled thermostats). |
| Peaking thermal: upgraded Bécancour plant | 350 MW | Sourced | Supply Plan 2027-2041: upgrade of TCE’s plant in Bécancour into a 350 MW peaking plant fuelled by renewable gas. Source |
| Commissioning of the Bécancour peaking plant | 2030 | Sourced | The Bécancour gas turbine plant, under refurbishment, is expected to enter service as early as 2030. Source |
| Churchill Falls | |||
| Churchill Falls energy received by Hydro-Québec (sales equivalent) | 30 TWh/yr | Derived from sources | The existing Churchill Falls plant (5 428 MW) supplies about 15% of Hydro-Québec’s electricity, i.e. about 30 TWh. Source |
| Churchill Falls capacity purchased by Hydro-Québec | 4 800 MW | Sourced | The 1969 contract gives Hydro-Québec almost all of the output: 4 800 of the 5 428 MW, at 0.2 ¢/kWh since 1996. Source |
| Agreement: share of Churchill Falls renewed for Hydro-Québec after 2041 | 3 660 MW | Sourced | August 2026 framework agreement: renewal of the Churchill Falls contract for 51 years, for 3 660 MW (against about 4 800 MW today). Source |
| End of the 1969 contract (August 31) | 2041 | Sourced | 40-year contract renewed automatically only once, for 25 years, on September 1, 2016; it expires on August 31, 2041. Hydro-Québec remains a 34.2% shareholder of CF(L)Co. Source |
| Current price of Churchill Falls electricity | 0.20 ¢/kWh | Sourced | 0.2 ¢/kWh until 2041 under the 1969 contract. Source |
| Agreement: price of existing energy, 2027 to 2040 | 2 ¢/kWh (range: 1.80 to 5.10) | Modelling assumption | The 2026 agreement provides for a gradual price increase starting at 1.8 ¢/kWh in 2027; the announced average for existing energy is 5.1 ¢/kWh over the whole term. Value of 2 ¢ taken from the profile of the 2024 agreement. Source |
| Agreement: price of existing energy after 2041 | 7 ¢/kWh (range: 5.10 to 7.40) | Modelling assumption | Profile of the 2024 agreement (7 ¢/kWh from 2041 to 2075). The 2026 agreement announces an effective average of 7.4 ¢/kWh over 50 years according to one source, 6.2 ¢/kWh according to the government. Source |
| Agreement: additional committed capacity (Gull Island and Churchill Falls capacity increase) | 3 255 MW | Sourced | August 2026 framework agreement: 3 255 MW committed for Gull Island and the Churchill Falls capacity increase. A further 3 850 MW of projects under study are not counted here. Source |
| Agreement: gradual upgrade of Churchill Falls (2027-2032) | 550 MW | Derived from sources | 550 MW capacity increase at the existing plant planned in the 2024 agreement; the 2026 agreement raises it with no separate figure published. Source |
| Agreement: commissioning of Gull Island and the Churchill Falls expansion | 2035 | Sourced | Gull Island around 2034-2035 and the Churchill Falls expansion (CF2) by 2035. Source |
| Agreement: additional energy for Hydro-Québec | 12 TWh/yr | Derived from sources | Gull Island, a 2 250 MW run-of-river plant, is expected to produce about 11 900 GWh per year; the expansion and capacity increase at Churchill Falls mainly add capacity. Source |
| Agreement: price of energy from new developments | 10.60 ¢/kWh | Sourced | 10.6 ¢/kWh in 2026 dollars for electricity from new developments; 6.2 ¢/kWh on average overall. Source |
| Agreement: first year of higher prices | 2027 | Sourced | The 2026 agreement provides for a gradual price increase starting in 2027. Source |
| No agreement: estimated market price for Churchill Falls energy after 2041 | 10 ¢/kWh (range: 5 to 14.50) | Modelling assumption | Assumption: market price without an agreement, bounded by Hydro-Québec’s average export price (about 5 ¢/kWh from 2016 to 2022, 14.5 ¢/kWh in 2025). Source |
| Exports | |||
| Net exports in 2025 | 11.80 TWh | Sourced | Hydro-Québec, 2025 annual report. Source |
| Firm contract with New York (CHPE) | 10.40 TWh/yr | Sourced | 10.4 TWh per year for 25 years, starting in 2026. Source |
| Last year of the New York contract | 2050 | Derived from sources | 25 years starting in 2026. Source |
| Firm contract with New England (NECEC) | 9.95 TWh/yr | Sourced | 9.45 TWh per year to Massachusetts and 0.5 TWh to Maine for 20 years, starting in 2025-2026. Source |
| Last year of the New England contract | 2045 | Derived from sources | 20 years starting in 2026. Source |
| Start of the two export contracts | 2026 | Sourced | Both contracts take effect in 2026. Source |
| Average export price | 10 ¢/kWh | Derived from sources | Average price of sales outside Quebec: about 5 ¢/kWh from 2016 to 2022, 10.3 ¢ in 2023, 9.9 ¢ in 2024 and 14.5 ¢ in 2025; 10 ¢ used for the coming period. Source |
| Carbon intensity of neighboring grids in 2025 (New England and New York) | 0.31 Mt per TWh | Sourced | Electricity Maps, 2025 monthly averages weighted by consumption: 308 g CO₂e/kWh in New England and 312 in New York, life cycle and imports included. An average: what an export displaces is peaking generation, often gas-fired. Source |
| Carbon intensity of neighboring grids once decarbonized | 0.05 Mt per TWh (range: 0 to 0.15) | Modelling assumption | Assumption: a grid with no direct emissions keeps its life-cycle emissions (building power plants, wind turbines and panels), of the order of Quebec’s. New York reaches it in 2040, New England in 2050, in a straight line from 2025. Source |
| Year of emission-free electricity in New York | 2040 | Sourced | Climate Leadership and Community Protection Act (2019): 70% renewable electricity by 2030 and an emission-free grid by 2040. Source |
| Year of decarbonized electricity in New England | 2050 | Sourced | ISO New England, 2024 Economic Study (September 2025), Policy scenario: the states’ goal of one million tons of CO₂ per year reached by 2050; an accelerated scenario reaches it by 2040. Source |
| Costs and rates | |||
| Cost of new wind energy, transmission and balancing included | 12 ¢/kWh | Sourced | Hydro-Québec’s long-term avoided cost, based on the contracts from call for tenders A/O 2023-01: 12.0 ¢/kWh (2026 dollars), i.e. 8.3 ¢ for supply and 3.7 ¢ for transmission and balancing. Source |
| Cost of energy from new hydro plants | 11 ¢/kWh | Derived from sources | New developments in Labrador: 10.6 ¢/kWh in 2026 dollars (2026 agreement), about 11 ¢/kWh according to the 2024 estimate. No public estimate for a new site in Quebec. Source |
| Cost of new solar energy | 9.50 ¢/kWh | Sourced | Hydro-Québec: 8 to 11 ¢/kWh in Quebec. Source |
| Annualized cost of uprating | 166 $/kW-yr | Derived from sources | Hydro-Québec’s long-term avoided cost for capacity: $166/kW-yr (2026 dollars), used here as the cost of added capacity. Source |
| Annualized cost of batteries | 170 $/kW-yr | To be validated | Order of magnitude; to be compared with Hydro-Québec’s long-term avoided cost for capacity, $166/kW-yr (2026 dollars). |
| Annualized cost of demand response | 70 $/kW-yr | To be validated | Order of magnitude; a demand response program is retained only if it costs less than the long-term avoided cost for capacity, $166/kW-yr (2026 dollars). |
| Cost of energy efficiency | 4.60 ¢/kWh saved | Derived from sources | Hydro-Québec plans $10 billion to save 21 TWh by 2035; annualized over 15 years at 5%. Source |
| Cost of existing energy redirected to additional Quebec demand | 5 ¢/kWh | Derived from sources | Hydro-Québec’s short-term avoided energy cost: 2.9 ¢/kWh in summer and 4.9 ¢/kWh in winter (2020 dollars), i.e. about 5 ¢/kWh in winter in 2025 dollars. Source |
| Grid cost for each additional MW of peak | 100 $/kW-yr | Sourced | Hydro-Québec’s avoided costs: transmission $74.7/kW-yr and distribution $24.9/kW-yr (2026 dollars), i.e. about $100/kW-yr. Source |
| Price of imports to cover residual energy needs | 10 ¢/kWh (range: 5 to 15) | Derived from sources | Hydro-Québec says it can import, at times when neighboring regions have surpluses, “at prices lower than the prices when we ourselves sell them energy” (Dave Rhéaume, 2026); capped here at the average export price, 10 ¢/kWh. Purchases at peak can cost more. Source |
| Average price of sales in Quebec in 2025 | 8.29 ¢/kWh | Sourced | Hydro-Québec, 2025 annual report. Source |
| Inflation | 2 %/yr | Sourced | Bank of Canada inflation-control target: 2%, the midpoint of a range of 1 to 3%. Source |
| Residential Rate D | 6.905 and 10.652 ¢/kWh | Sourced | Hydro-Québec, rate schedule, Rate D as of April 1, 2025. Source |
| Third tier (proposed Rate DG) | 13 ¢/kWh above 95 kWh/day | Sourced | Proposed Rate DG: a third tier of 13 ¢/kWh above 35 000 kWh per year (95 kWh per day), targeting about 200 000 households, or 5% of customers; requested effective date April 1, 2027 (case R-4343-2026). Source |
| First tier per person | 20 kWh/day | To be validated | Illustrative option: 20 kWh per day per person in the first tier, with no rebalancing of revenues. |
Download the assumptions (CSV) (one row per parameter, comma-separated, decimal point) or all the simulator data (JSON).
Limitations of this version
- Annual model: it represents neither hours, nor reservoirs, nor regions. An annual balance can hide real strains.
- The average cost does not distinguish between customer classes. The cap applies here to all rates.
- The third tier and the first per-person tier change bills without rebalancing Hydro-Québec’s revenues.
- The cost of household equipment (heat pumps, vehicles) is not counted.
- The rebound effect is not modeled: efficiency savings are counted in full, whereas part of them can be taken back by increased use, from 0 to 20% to more than 50% depending on the case, more so in industrial processes and commercial transport (HEC Montréal, 2025, p. 9-11, in French).
- Prices do not change demand: the rate cap spreads costs without changing consumption, whereas low prices go hand in hand with low energy productivity, 35% lower in Quebec than in Ontario (HEC Montréal, 2025, p. 23-24, in French).
- GHGs avoided outside Quebec are counted separately, never added to Quebec’s: exports minus purchases in a shortfall year, at the neighbors’ average intensity (Electricity Maps, 2025), falling with their plans: emission-free by 2040 in New York, by 2050 in New England. In practice, an export displaces backup generation, from gas, which emits more than the average.
- Bioenergy, renewable natural gas and imported hydrogen are not modeled.
- Green hydrogen is counted conservatively: a 51% efficiency measured in Quebec, compression and fueling station included (Quebec Ministère des Transports, 2024), replacing natural gas, the lowest-emitting fuel. Conversion into synthetic fuels is not counted: with it, hydrogen would avoid even fewer GHGs.
- The costs of new resources are stated in 2026 dollars by their sources, the 2025 cost in 2025 dollars: the gap, about 2%, is not corrected.
- A shortfall caused by exports is not billed to Quebec customers: only the gap between the emergency purchase price and the selling price is, and export revenues do not reduce the bill.
- Bringing green hydrogen below its current production counts the gray hydrogen that replaces it: avoided GHGs become slightly negative.
Scenario data (CSV)
Annual series of the scenario shown, separated by semicolons, for expert review.
Quebec’s energy balanceHow all of Quebec’s energy flows, from sources to useful energy, in 2024 and then to 2050 with the simulator decisions: electrifying a use removes oil or gas, and cuts losses.
The simulator follows electricity only. This diagram places it in the whole energy system: each band is a flow of energy, its width proportional to the amount. The year slider starts from the 2024 data and projects it to 2050 with the current scenario and sliders: the electricity added to each use removes the fossil energy it replaces. Touch a source to follow its energy to the end, or a sector to see where its energy comes from; touch again to release it. Units switch from petajoules to terawatt-hours, those of the simulator: 1 PJ is about 0.28 TWh, the consumption of about 10 000 Quebec households.
Open this section to load the diagram.
After figure 2 of État de l’énergie au Québec 2026 (Whitmore and Pineau, HEC Montréal, in French), 2024 data. Values read by Pareto off the figure, which does not show flows under 3 PJ: some totals therefore balance only to within a few PJ, as in the original. Exports, shown as five bands in the original, are combined here into one. Following a source assumes that energy mixes in each node: what leaves a node has the composition of what enters it.
How the balance is projected
- The starting point. The changes the simulator calculates from 2025 are added to the 2024 data.
- Fossil energy removed. Each electrified use removes the fossil energy the simulator assigns to it: petroleum products in transportation; gas, heating oil and propane in buildings; gas, coal, petroleum products and propane in industry, in their 2024 proportions. Green hydrogen replaces gas in industry, where its electricity is counted.
- Upstream follows. Distribution, refining, crude oil and imports fall in proportion to what the sectors still use.
- What stays fixed, by assumption. Fossil energy exports, biomass and non-energy uses remain at their 2024 levels.
- Electricity. Wind, solar, Churchill Falls, electricity exports and purchases in a deficit year come from the simulator; existing hydropower makes up the rest, the water not run through turbines staying in the reservoirs.
- Useful energy. The service delivered is kept when a use switches to electricity, which loses less: losses are what fall. Useful energy changes only with growth, sufficiency and new uses, at each sector’s 2024 efficiency; efficiency removes electricity without removing service.
Generating facilities
Hydro-Québec’s hydroelectric generating stations, each circle scaled to its capacity, with Churchill Falls in Labrador, thermal plants, wind farms, the main transmission lines and the interconnections with neighboring provinces and states. Tap a symbol to see its card; the boxes at the top right show or hide a layer, with the lines and interconnections hidden at first.
Reservoir generating stationRun-of-river generating stationWind farmChurchill Falls (Labrador)Thermal plantDiesel plant (off-grid system)Transmission line, 735 or 765 kV; dashed: direct-current line (450, 400 and 320 kV)Interconnection to the United StatesInterconnection to a province
Generating stations as a table
Off-grid generating stations as a table
Interconnections as a table
Sources and limitations
Decarbonization potential per kWhUses of Quebec electricity ranked by the grams of CO₂ a kWh avoids, compared with the value of exporting it.
What stakeholders say - The Vision énergie tour consultationThe tour’s workshops, held in 2025, were meant to give the Ministère de l’Économie, de l’Innovation et de l’Énergie a better understanding of the visions of various stakeholders in Quebec’s energy planning, particularly regarding objectives, future choices and energy priorities, as well as expectations for the integrated energy resource management plan (PGIRE).
Swipe the table sideways to see all eleven energy options.
Tap or hover over a cell to read the idea and its page.
To developWith reservations or mixed viewsTo avoidNo view recorded
Coded by Pareto from the ideas the report records group by group (tables 1, 2, 2.1 and 2.3): a symbol sums up a group’s ideas. Participants were invited by the ministry and do not represent the population, and not every group attended every stop. The “See an option” menu shows, for one option, the groups that want to develop it, those with reservations and those that want to avoid it, with the table 2.1 ideas that concern it. The last fold lets you search every idea in the report. A column heading opens a card that explains the option, with a link to the matching slider. Source: Tournée Vision énergie, rapport des ateliers (in French) (MEIE, 2025).
Search the report: every idea recorded, question by question (tables 1 to 2.3)
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What the briefs on Bill 69 say (2024)The 74 briefs submitted to the parliamentary committee on Bill 69, An Act to ensure the responsible governance of energy resources, coded issue by issue: rates, private electricity sales, energy options, the role of the Régie de l’énergie.
Swipe the table sideways to see all the issues.
Tap or hover over a cell to read what the group’s briefs say, or over a group name for its list of briefs.
ForWith reservations or mixed viewsAgainstNo view recorded
Coded by Pareto, brief by brief, from the text of each, with the page. Each column is a proposal, and the view is about it: “Reduce cross-subsidies” is marked for by those who want to reduce them. A solid symbol means every brief in the group that addresses the issue points the same way; otherwise the group is marked “with reservations or mixed views”. A brief speaks only for its author, and the groups do not have the same number of briefs: the matrix shows positions, not their weight. The “See an issue” menu shows, for one issue, the briefs for, with reservations and against, each with its idea and page. A column heading opens a card that explains the issue, and a brief’s name opens it, in French, at the page cited. Source: briefs submitted to the Committee on Agriculture, Fisheries, Energy and Natural Resources (in French) (National Assembly, 2024).
Inspired by the En-ROADS simulator from Climate Interactive.
To understand how Hydro-Québec forecasts demand and plans its supply and its grid: Planning tomorrow’s energy.