Canada Solar Energy Market Size & Share Analysis - Growth Trends and Forecast (2026 - 2031)

Canada Solar Energy Market Trends and Insights

Accelerating Provincial RPS & Clean-Energy Auctions

Competitive procurements in Alberta, Saskatchewan, and Ontario continue to push bid prices below CAD 50 per MWh and provide developers with long-term revenue certainty that lowers debt costs by up to 50 basis points. Auction calendars published two years in advance allow suppliers to lock in module contracts early, which in turn reduces construction risk and accelerates balance-sheet commitments from institutional investors.^{[1]Independent Electricity System Operator, “2026 Resource Procurement Plan,” ieso.ca} Indexed pricing mechanisms, where tariffs glide with inflation but cap annual escalation, further protect cash flows for pension-fund financiers.

Accelerated Coal-To-Renewables Displacement Mandate

Federal regulations that end coal generation by 2030 are forcing utilities in Alberta and Saskatchewan to bring replacement solar and storage online faster than previously scheduled. Retiring coal sites supply existing transmission corridors, cutting connection costs by as much as CAD 200 million per GW. New solar farms deployed adjacent to decommissioned units access pre-built substations, shaving nine to twelve months from project timelines and raising internal rates of return by roughly two percentage points for sponsors such as TransAlta and Capital Power.

Declining LCOE of Bifacial & TOPCon PV Modules

Domestic production of bifacial TOPCon modules with 24.5% efficiency began in Ontario in late 2024, bringing module prices below USD 0.16 per watt after federal incentives. Higher yield lifts capacity factors beyond 20% in southern Alberta, enabling solar to compete directly with gas peakers that cleared Alberta’s energy-only market at an average CAD 87 per MWh in 2025. Balance-of-system costs fall 10% per installed watt because fewer modules are needed to reach the same output.

Corporate PPAs from Data-Center & Mining Sectors

Hyperscale operators booked 2.3 GW of long-term solar contracts by end-2025, with AWS and Microsoft each signing 200-MW-plus deals priced below CAD 50 per MWh. These agreements stabilize cash flows, allowing projects to obtain non-recourse loans at rates 100-basis-points cheaper than merchant plants. In remote mining, Teck Resources showed that a 20 MW solar-plus-storage system can remove 12 million liters of diesel annually and cut operating expenditure by CAD 18 million.

Interconnection Queue Congestion in Alberta & Ontario

System-impact studies stretch to 18 months in Alberta and 24 months in Ontario, delaying project cash flows and eroding developer returns.^{[2]Alberta Electric System Operator, “2025 Solar Integration Study,” aeso.ca} Fast-track pathways for projects under 50 MW shorten timelines to nine months, yet utility-scale assets that account for 58% of provincial capacity additions remain subject to lengthy reviews. Cluster-study pilots that evaluate multiple projects together may cut per-project costs by 30%, but full deployment is unlikely before 2027.

Seasonal Irradiance Mismatch Affecting Capacity Factors

Canada’s high-latitude profile creates a six-month output imbalance that forces grid operators to maintain gas peakers for winter demand spikes, adding up to CAD 12 per MWh to system costs. Four-hour lithium-ion batteries can cover daily ramps but fall short during week-long low-sun stretches. Developers respond by pairing solar with wind, which peaks in winter, raising combined capacity factors above 38% in hybrids such as Boralex’s 150 MW Apuiat project.

Segment Analysis

By Technology: PV Dominates, CSP Absent

Photovoltaic systems represented the entire installed base in 2025 and will remain the sole commercial technology through 2031, expanding in lockstep with the overall Canada solar power market. Breakthroughs in bifacial TOPCon cells have pushed module efficiency to 24.5%, lowering installed costs to CAD 1,200 per kW for utility-scale plants. Fixed-tilt projects are giving way to single-axis trackers that lift annual energy yield by 20%, a gain that compensates for winter irradiance losses.

Cost and performance metrics leave concentrated solar power economically unviable because direct normal irradiance averages only 1,300 kWh per square meter compared with the 2,000 kWh benchmark required for CSP competitiveness.^{[3]Natural Resources Canada, “Photovoltaic Performance in Canada,” nrcan.gc.ca} Half-cut cell formats, multi-busbar interconnects, and string inverters further raise production efficiency while trimming maintenance expense.

Note: Segment shares of all individual segments available upon report purchase

By Grid Type: Off-Grid Surges In Remote Regions

On-grid installations maintained 67.1% of capacity in 2025, driven by Alberta and Ontario auction pipelines. Yet off-grid systems are climbing at 9.9% CAGR as communities north of 60° latitude displace diesel that costs CAD 0.45 per kWh. Natural Resources Canada funded 18 microgrids totaling 35 MW in 2025, each pairing 4-hour to 8-hour batteries with PV arrays sized between 500 kW and 5 MW.

Diesel savings translate into six-year to nine-year paybacks even before carbon-price credits. Mining operators such as Agnico Eagle have validated economics by trimming 8 million liters of fuel annually at the Meadowbank site in Nunavut, confirming a template now replicating across Yukon and the Northwest Territories.

By End User: Residential Outpaces Utility-Scale Growth

Utility-scale facilities still held 57.6% of total capacity in 2025, but the residential slice is growing fastest at 10.2% CAGR. Net-metering reforms adopted in Ontario and British Columbia allow households to bank surplus generation for up to one year, slashing payback periods to six years on a 5 kW system priced near CAD 2.50 per watt.

Commercial-and-industrial customers follow close behind, motivated by time-of-use tariffs that can swing CAD 0.12 per kWh between peak and off-peak windows. Integrators such as Saturn Power bundle rooftop PV with 2-hour batteries and demand-response software, creating new revenue streams in Ontario’s capacity auction and ancillary-service markets.

Note: Segment shares of all individual segments available upon report purchase

Geography Analysis

Alberta commanded 42% of national solar capacity in 2025 thanks to superior isolation and an energy-only market that rewards flexible assets during high-price hours. Removing the 2024–2025 permitting pause unleashed 2 GW of ready-to-build projects, and the province expects solar additions to equal 35% to 40% of all new generation by 2030. Ontario followed with 28%, supported by a 2 GW clean-capacity tender that may allocate half of the awarded volume to solar-plus-storage assets slated for 2028 startup.

Saskatchewan is rising rapidly from a smaller base as SaskPower’s 300 MW solicitation targets brownfield sites at retiring coal plants where transmission is already in place, trimming interconnection costs by up to 50%.^{[4]SaskPower, “Solar RFP 2025,” saskpower.com} British Columbia and Quebec have historically leaned on hydro, but now see faster rooftop uptake after net-metering revisions in 2025 that expanded credit-carry rules for households and data-center operators.

Remote northern territories deploy solar-plus-storage microgrids to displace imported diesel. Eighteen funded projects totaling 35 MW relied on Natural Resources Canada’s Indigenous Off-Diesel Initiative, producing fuel savings of up to 75% and reducing generation costs by CAD 0.30 per kWh. Atlantic provinces lag because of lower irradiance and constrained transmission, though Nova Scotia Power’s 100 MW tender announced in 2025 suggests early momentum as the last coal unit retires in 2030.