Canada Solar Energy Market Size & Share Analysis - Growth Trends And Forecast (2025 - 2030)

Canada Solar Energy Market Trends and Insights

Accelerating Provincial RPS & Clean-Energy Auctions

Quebec issued its first-ever 300 MW solar request in 2025, signaling diversification beyond hydro, which previously supplied 94% of the province’s power.^{[2]Government of Quebec, “300 MW Solar RFP,” quebec.ca} Ontario’s Long-Term 2 procurement attracted 3.2 GW of solar bids under a revenue-stabilization scheme that limits merchant exposure at CAD 10/MWh. Alberta’s auction format pushed winning prices down to CAD 38/MWh in 2025, a 27% drop from 2022, confirming sharp module-cost deflation. Bid rules now penalize non-delivery, so only well-capitalized developers with locked-in equipment qualify. These auctions create a transparent demand pipeline that unlocks institutional capital and crowds in lower-cost financing.

Accelerated Coal-to-Renewables Displacement Mandate

Alberta phased out coal in early 2024, three years ahead of the federal deadline, eliminating 5.6 GW of thermal capacity that solar projects are repowering at existing substations. Greengate Power’s 400 MW Michichi Creek Solar leverages a decommissioned mine site to cut development timelines from four years to a little over two. Saskatchewan’s 1.3 GW Boundary Dam and Shand retirements, slated for 2029, create further solar headroom, with SaskPower planning to allocate up to 40% of replacement capacity to PV. Although soil remediation can add CAD 25 million per site, the avoided cost of long-distance transmission, about CAD 1.5 million per kilometer, keeps repowering economics favorable. Rapid thermal exits also free up transmission rights, creating a scarce yet high-value asset for solar developers.

Declining LCOE of Bifacial & TOPCon PV Modules

Bifacial modules grew from 12% of installations in 2023 to 35% in 2025, capturing an extra 8%–12% rear-side yield in snow-covered regions. TOPCon efficiency of 24%–25% is displacing PERC in space-constrained rooftops, trimming labor by 10%–15%. Canadian Solar’s CAD 1.8 billion Ontario facility, supported by federal and provincial incentives, will add 5 GW of annual TOPCon output by 2026, shielding projects from tariff risks. Alberta’s utility-scale LCOE fell to CAD 35–40/MWh in 2025, 30% below 2022 levels, overtaking gas even after carbon pricing. Falling equipment costs widen the economic lead of the Canada solar energy market over competing generation types.

Corporate PPAs from Data-Center & Mining Sectors

Microsoft signed a 114 MW PPA with Brookfield in 2024, featuring a 1.5% fixed escalator that stabilizes revenue for lenders. Amazon’s 1.2 GW hybrid deal with Enbridge blends wind and solar for a 40% capacity factor, reducing grid firming costs. Rio Tinto’s 200 MW solar-plus-storage plant in Quebec supplies an aluminum smelter, alleviating grid stress during winter peaks. PPA strike prices range from CAD 40–50/MWh, below merchant averages, but they improve bankability by removing price volatility, allowing smaller developers to secure investment-grade debt.

Interconnection Queue Congestion in Alberta & Ontario

Alberta’s queue surged to 56.53 GW in mid-2024, almost ten times installed capacity, pushing commercial-operation dates out by up to three years.^{[3]Alberta Electric System Operator, “Interconnection Queue Update,” aeso.ca} Study throughput is limited to 2–3 GW annually, so projects without existing rights face significant delays. Ontario’s southwestern corridor can absorb just 1.2 GW of new renewables before major substation upgrades, forcing developers north where capacity factors are 15% lower. Deposit proposals of CAD 10,000/MW may filter speculative bids but will raise entry barriers for smaller firms.

Seasonal Irradiance Mismatch Affecting Capacity-Factors

The Canada Border Services Agency opened an investigation in June 2024 that could add 15%–25% duties to Southeast-Asian modules tied to Chinese ownership. Roughly 4 GW of 2025–2027 projects lack a secured supply and could see costs rise CAD 0.12/W, shrinking returns by 300 basis points. Domestic alternatives remain insufficient: Canadian Solar’s 5 GW output will cover only half of projected annual demand by 2026, and U.S. modules carry a 10%–15% premium. Developers may delay or cancel pipeline assets unless tariff clarity emerges quickly.

Segment Analysis

By Technology: PV Dominance Reflects Irradiance Constraints

Solar photovoltaic owns 100% of the Canada solar energy market share in 2024 and will grow at a 7.7% CAGR through 2030 as bifacial and TOPCon upgrades raise energy yield, cementing its role in the generation mix. Concentrated solar power remains absent because only narrow bands in southern Alberta surpass the 5.5 kWh/m²-day DNI threshold required for economic viability. Bifacial adoption climbs as snow-induced albedo adds 8%–12% output, lowering LCOE below CAD 40/MWh in Alberta, which is the lowest among new-build generation technologies. TOPCon modules, with 24%–25% efficiency, fit commercial rooftops where load-to-roof-area ratios are high, cutting balance-of-system labor and racking.

Ontario, Alberta, and Saskatchewan have increased allowable system sizes for net-metering, further propelling commercial rooftop adoption. PV integrators are bundling asset-management software that uses real-time irradiance telemetry to flag underperformance within hours rather than weeks. As cost parity with bulk-system power converges, PV portfolios attract pension-fund capital seeking inflation-indexed cash flows. Meanwhile, advanced plant-level controls supply essential grid support, from voltage ride-through to synthetic inertia, positioning PV to capture ancillary-service revenue once limited to rotating machines. The decisive economic and policy advantage means the Canada renewable energy market will continue to be synonymous with solar PV through 2030.

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

By Grid Type: Off-Grid Surge Driven by Diesel Displacement

On-grid projects held 67.5% of capacity in 2024, reflecting the dominance of utility-scale auctions and net-metered rooftops in urban provinces. Off-grid systems, though smaller in absolute volume, are expanding at a 10.1% CAGR as Indigenous communities and mine sites swap diesel for solar-plus-storage. A 1 MW PV array paired with 2 MWh lithium-ion storage cuts 250,000 liters of diesel annually, saving up to CAD 750,000 and paying back in eight years even before grants.^{[4]Pembina Institute, “Diesel Displacement Economics,” pembina.org}

Transport and labor premiums keep installed battery costs in the CAD 400–500/kWh range for remote projects, yet the avoided fuel and remediation costs offset these hurdles. On-grid growth continues in Alberta and Ontario, where wholesale markets and net-metering allow surplus energy credits at retail rates, boosting behind-the-meter economics.

By End-User: Residential Acceleration Outpaces Utility-Scale

Utility-scale assets formed 58.2% of total capacity in 2024, driven by auction awards for 2.8 GW of new projects between 2023 and 2025. The residential segment is expanding faster, at a 10.5% CAGR, as average rooftop system sizes rise from 6 kW to 8 kW following widespread EV charging adoption. Ontario’s Greener Homes Grant and British Columbia’s export credit of 9.5 cents/kWh allow households to recoup initial costs within eight years.

Commercial and industrial rooftops grow steadily but face interconnection study hurdles and complicated demand-charge regimes. Specialized installers use bundled financing and AI-driven demand management to unlock savings worth 20%–30% for large energy users, but uptake remains concentrated among facilities with peak loads above 500 kW.

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

Geography Analysis

Alberta, Ontario, and Quebec house 78% of current capacity, illustrating how irradiance, policy, and grid headroom shape deployment patterns. Alberta leads with 2.8 GW, capitalizing on merchant price volatility that rewards low-cost generation and the coal exit that freed transmission rights. Ontario follows at 2.1 GW, underpinned by contract-for-difference auctions that cap downside risk but forgo peak-price upside. Quebec’s 380 MW base is poised to triple once its inaugural 300 MW solar procurement reaches commissioning by 2029.

Saskatchewan and British Columbia lag at 150–200 MW each as wind and hydro remain cheaper in those provinces. Atlantic provinces contribute less than 5% of capacity but have issued a 350 MW call to reach 80% renewables by 2030, which could lift solar’s share if bids remain competitive. Northern territories focus on diesel displacement rather than grid supply, rolling out 42 solar micro-grids totaling 28 MW under the Indigenous Off-Diesel Initiative.