To support transparency and analysis, the Canada Energy Regulator (CER) publishes a detailed dataset describing the technology cost and performance assumptions used in its Canada’s Energy Future (CEF) series. The data helps users better understand the assumptions underlying the projections and supports broader analysis of Canadian energy systems. The data covers electricity generation and storage technologies and is produced for each province, scenario, and year included in the projections.
This page describes the parameters available in the dataset, the methodology used to develop the parameters, and the external data used to create the dataset. You can download the dataset on the Government of Canada’s Open Government website.
The capital cost of constructing an electricity-generating facility, expressed as a simplified value assuming all costs are incurred at the start of operations. This approach excludes financing and construction timing effects.
Overnight capital cost includes:
It excludes:
Figure 1: Capital, Fixed, and Variable Costs for Electricity Generating Technologies
Disclaimer: This chart displays only selected scenarios and fields. The complete dataset, including all scenarios and fields, is available through the provided download links.
Data Sources: Canada’s Energy Future 2026, Open Government
Text Alternative: The figure shows four different cost parameters: overnight capital cost, connection costs, fixed costs, and variable costs, for years 2024 to 2050, and by province/territory. There are three dropdown menus: Technology, to select which electricity technology; Scenario, to select which Canada’s Energy Future scenario; and Field, to select the cost parameters.
The cost of connecting a power generation facility to the bulk electricity grid. This includes connecting transmission lines, substations, and point of interconnection costs. Costs vary depending on distance to existing infrastructure, voltage requirements, and the need for grid upgrades at the interconnection point.
It excludes broader bulk transmission system upgrades beyond the immediate point of interconnection.
The annual costs required to operate and maintain a facility that do not vary with the amount of annual electricity generation. This includes staffing, scheduled and routine maintenance, administrative expenses, property and municipal tax, insurance and land costs. These costs are typically incurred on an annual basis regardless of plant utilization.
The costs of operating and maintaining a facility that vary with the amount of electricity generated. This includes consumables, incremental maintenance, and costs associated with equipment wear and tear during operation. It excludes fuel costs. For facilities utilizing carbon capture, utilization, and storage technology (CCUS), the cost of storage and transport of carbon dioxide is also incorporated.
The amount of energy input required to produce one unit of electricity output. It is a measure of how efficiently a facility converts fuel into electricity on a higher heating valueFootnote 1 basis (Figure 2).
Lower heat rates indicate higher efficiency and better performance. Values are defined at the facility level and exclude transmission, distribution, and other losses beyond the facility boundary.
Unlike combustion-based technologies, nuclear plants do not have a conventional fuel heat input. Reported heat rates therefore represent an equivalent thermal conversion rate, based on reactor thermal output relative to electrical generation.
For non-thermal technologies (e.g., wind, solar, and hydropower), heat rate is not applicable because no fuel is consumed.
For energy storage technologies, an overall round-trip plant efficiency is used instead of heat rate. This efficiency represents the ratio of output energy to input energy. It captures losses during storage and energy conversion.
Figure 2: Heat rate for Electricity Generating Technologies
Disclaimer: This chart displays only selected scenarios and fields. The complete dataset, including all scenarios and fields, is available through the provided download links.
Data Sources: Canada’s Energy Future 2026, Open Government
Text Alternative: The figure shows heat rate for thermal electricity generation technologies for years 2024 to 2050. There is a dropdown menu to select Canada’s Energy Futures scenario.
Construction Duration
The time required to construct and commission a facility, from the start of construction to commercial operation. This includes site preparation, equipment installation and construction, system testing, regulatory approvals required for operation (operational licensing), and any post construction completion quality assurance. The construction duration varies depending on technology type, project complexity, and permitting requirements. Time taken for pre-construction activities (e.g., feasibility studies, exploration, environmental assessments, and licensing to construct) are excluded. This value also excludes any construction lead time between final investment decision (FID) and start of construction.
Lifetime
The expected operating lifespan of a facility under normal conditions. This represents the period over which the facility is assumed to generate electricity before retirement or major refurbishment. The value is commonly used in economic analysis to allocate capital and operating costs over time. It does not necessarily reflect physical limits, that may vary based on maintenance practices and operating conditions.
CCUS Capture Rate
The percentage of carbon dioxide emissions captured by a carbon capture, utilization and storage system at a facility. Includes both post combustion and pre-combustion carbon capture where applicable. In Canada’s Energy Future 2026, the CCUS capture rate is capped at a 95% maximum value. The values may also change by start of operations year based on assumed CCUS capture rate efficiency improvements.
Table 1: System Parameters for Electricity Generation Technologies
| Technology | CCUS capture rate (%) | Construction duration (Years) | Lifetime (Years) |
|---|---|---|---|
| Battery energy storage system | 0 | 1 | 20 |
| Biomass Integrated Gasified Combined Cycle (IGCC) | 0 | 3 | 45 |
| Biomass IGCC with CCUS | 85-90 | 5 | 45 |
| Biomass steam cycle | 0 | 3 | 45 |
| Biomass steam cycle with CCUS | 90-95 | 5 | 45 |
| Coal IGCC with CCUS | 95 | 5 | 45 |
| Compressed air energy storage | 0 | 3 | 30 |
| Diesel combustion turbine | 0 | 3 | 30 |
| Geothermal binary cycle | 0 | 6 | 30 |
| Hydro run-of-river >100 MW | 0 | 6 | 60 |
| Hydro run-of-river >10 MW | 0 | 4 | 60 |
| Hydro run-of-river >1 MW | 0 | 3 | 60 |
| Hydrogen energy storage | 0 | 3 | 30 |
| Hydropower >100 MW | 0 | 6 | 65 |
| Hydropower >10 MW | 0 | 4 | 60 |
| Natural gas combined cycle | 0 | 2 | 30 |
| Natural gas combined cycle with CCUS | 95 | 3 | 30 |
| Natural gas simple cycle | 0 | 2 | 30 |
| Nuclear power large reactor | 0 | 8 | 60 |
| Nuclear power small modular reactor | 0 | 6 | 60 |
| Pumped hydro storage | 0 | 4 | 50 |
| Solar PV utility | 0 | 2 | 30 |
| Wind offshore (fixed base) | 0 | 3 | 30 |
| Wind onshore | 0 | 3 | 30 |
CER compiles technology cost and performance data from a combination of domestic and international sources. Given the relatively smaller size of the Canadian market compared to larger jurisdictions such as the United States, global cost trends are an important influence on domestic estimates.
Each data source is evaluated based on:
All collected cost data are evaluated for differences in labour costs between the source jurisdiction and Canadian market conditions. Adjustments are applied only to the portion of costs associated with domestically incurred labour. Costs related to imported components are excluded from these adjustments. For example, in the case of solar photovoltaic systems, labour cost adjustments apply to domestic installation activities but not to manufacturing labour costs for imported panels.
Import costs are incorporated into each technology cost parameter as an adjustment factor. Import costs represent any anticipated duties and any difference in expected transportation costs. Import costs do not apply to fixed and variable costs.
The future technology cost assumptions are adjusted to align with the scenario premise and the impact of that premise on global technology trends. The Canada’s Energy Future 2026 report includes four scenarios Lower, Current Measures, Higher, and Canada Net-zero, described in detail in the Scenarios and Assumption chapter of the report. Capital costs, operating costs, and performance metrics are informed by the scenario narratives related to global and domestic market conditions, including expectations about technology maturity, learning effects, and expected research and development. For example, Canada Net-zero assumes faster cost declines of clean energy technologies, reflecting a global environment of stronger climate action and greater investment, leading to additional technological advances that reduce costs compare to the Current Measures, Lower and Higher scenarios.
The reference year is the year associated with the source data for a given technology. It typically corresponds to the dollar year used in the source.
Where applicable, cost values are converted to Canadian dollars using exchange rates from the reference year. These values are then adjusted to the baseline year of the Canada’s Energy Future publication (the most recent historical year) using corresponding Canadian dollar inflation rates.
Cost estimates are further adjusted to reflect regional differences across provinces and territories. These adjustments account for jurisdiction-specific factors and are applied to capital costs as well as fixed and variable operating costs, as summarized in Table 2.
Table 2. Provincial Cost Adjustment Considerations
| Capital Costs | Annual Fixed Costs | Variable Costs | Method/Reference | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Labour cost difference | Included | Included | Included | Based on internal macroeconomic modelling | ||||||
| Equipment, construction, transportation, and other cost differences | Included | Included | Included | Based on provincial and territorial agency consultations and Statistics Canada’s building construction price index | ||||||
| GST/HST difference | Included | Included | Included | As published by provincial, territorial, and federal governments | ||||||
| Insurance and property tax difference | N/A | Included | N/A | Derived based on provincial and territorial averages | ||||||
| Land lease/ownership cost differences | N/A | Included | N/A | Based on land values published by Statistics Canada | ||||||
| CO2 transportation cost differences* | N/A | N/A | Included | Based on external consultations and average distance to CO2 geographical storage | ||||||
| Terrain and climate-based adjustments** | Included | N/A | N/A | Based on provincial and territorial consultations and publications | ||||||
|
* Applies only to technologies with carbon capture, utilization, and storage ** Applies only to variable renewable energy |
||||||||||
The electricity generating and storage technologies cost and performance data are collected using multiple resources, as described in the methodology section. Table 3 provides an overview of the technologies included, along with their corresponding reference facilities and data sources. The main data sources are the U.S. Energy Information Administration’s 2024 Capital Cost and Performance Characteristics for Utility-Scale Electric Power Generating Technologies report (USEIA 2024), the National Laboratory of the Rockies, Annual Technology Baseline 2024 (ATB 2024), and the International Renewable Energy Agency’s Renewable Power Generation Costs in 2024 (IRENA 2024).
Table 3: Technology Descriptions and Reference Sources
| Technology | Description | Reference Facility | Cost Data References | Future Trend References |
|---|---|---|---|---|
| Battery energy storage system | Electrochemical battery-based storage | 240 MWh (60 MW, 4 hours) utility scale BESS | ATB 2024 | ATB 2024 |
| Biomass IGCC | Integrated gasified combined cycle (IGCC) biomass power plant | 50 MW dedicated IGCC biomass power plant | Derived based on USEIA 2024 and ATB 2024 | ATB 2024 |
| Biomass IGCC with CCUS | Integrated gasified combined cycle biomass power plant with carbon capture | 50 MW dedicated biomass power plant with 90% CO2 capture | Derived based on USEIA 2024 | ATB 2024 |
| Biomass steam cycle | Direct combustion biomass steam turbine | 50 MW dedicated biomass plant | ATB 2024 | ATB 2024 |
| Biomass steam cycle with CCUS | Direct combustion biomass steam turbine coupled with post combustion carbon capture | 50 MW dedicated biomass power plant with 95% CO2 capture | Derived based on USEIA 2024 | ATB 2024 |
| Coal IGCC with CCUS | Advanced Coal Integrated gasification combined cycle with carbon capture | 500 MW integrated gasifier and combined cycle with 95% CO2 capture | ATB 2024 | ATB 2024 |
| Compressed air energy storage | Compressed underground air storage combined with turbine | 100 MW compressed air energy storage system | Derived based on academic publications and consultations | Derived based on academic publications |
| Diesel combustion turbine | Diesel fired combustion turbine | 20 MW diesel combustion turbine | Derived from historical data Energy Futures 2023, and USEIA (historical) | No trend |
| Geothermal binary cycle | Binary cycle using moderate-temperature geothermal resources | 30 MW geothermal binary cycle plant | ATB 2024 | ATB 2024 |
| Hydro run-of-river >1 MW | Small run-of-river hydro power plant: between 1 MW and 10 MW | 5 MW run-of-river facility | Derived based on ATB 2024 | No trend |
| Hydro run-of-river >10 MW | Medium run-of-river hydro power plant: between 10 MW and 100 MW | 50 MW run-of-river facility | Derived based on ATB 2024 | No trend |
| Hydro run-of-river >100 MW | Large run-of-river hydro power plant: larger than 100 MW | 500 MW run-of-river facility | Derived based on ATB 2024 | No trend |
| Hydrogen energy storage | Hydrogen produced via electrolysis, with use of proton exchange membrane (PEM) technology and reconverted to power using fuel cell technology | A 20 MW hydrogen PEM and fuel cell facility | Derived based on academic publications | Derived based on academic publications |
| Hydropower >100 MW | Large reservoir-based hydropower: larger than 100 MW | 1000 MW reservoir-based (dam) facility | Provincial consultations/ IRENA 2024 | No trend |
| Hydropower >10 MW | Medium-scale reservoir hydropower: between 10 MW and 100 MW | 50 MW reservoir-based (dam) facility | ATB 2024 | No trend |
| Natural gas combined cycle | Combined cycle natural gas power plant | 1000 MW H-frame advanced combined cycle power plant | USEIA 2024 / ATB 2024 | ATB 2024 |
| Natural gas combined cycle with CCUS | A combined cycle natural gas power plant with post-combustion carbon capture | 1000 MW H-frame advanced combined cycle power plant with 95% CO2 capture | USEIA 2024/ ATB 2024 | ATB 2024 |
| Natural gas simple cycle | Gas turbine simple cycle natural gas power plant | 300 MW F-frame combustion turbine | USEIA 2024 / ATB 2024 | ATB 2024 |
| Nuclear power large reactor | Conventional large nuclear reactor | 1000 MW large, pressurized water reactor | USEIA 2024 | ATB 2024 |
| Nuclear power small modular reactor | Modular based small nuclear reactor | 300 MW small modular reactor | USEIA 2024 and publicly available Canadian implementation data (Darlington SMR) | Derived based on ATB 2024 and consultations |
| Pumped hydro storage | Two-reservoir hydro storage using elevation difference | 1000 MW reservoir-based (dam) facility | ATB 2024 | ATB 2024 |
| Solar PV utility | Utility scale solar photovoltaic | 100 MW utility scale facility with single-axis tracking | USEIA 2024 | ATB 2024 |
| Wind offshore (fixed base) | Offshore Wind turbine with a fixed base | Facilities with a 7 MW capacity wind turbine | ATB 2024 | ATB 2024 |
| Wind onshore | Land based wind turbine | Facilities with 4 MW capacity wind turbines | USEIA 2024 | ATB 2024 |
