Canada Thermal Power Market Size & Share Analysis - Growth Trends And Forecast (2025 - 2030)

Canada Thermal Power Market Trends and Insights

Aging Coal Fleet Replacements With High-Efficiency CCGT Plants

Ottawa’s 2030 coal ban compressed a decade of retirements into six years, forcing utilities to swap 8 GW of coal with dispatchable alternatives.^{[1]Canada Energy Regulator, “Canada’s Power Generation Outlook,” cer-rec.gc.ca} Alberta finalized its coal exit in June 2024, and Saskatchewan shuttered Boundary Dam Units 4-6 the same year, leaving a reliability gap that only modern CCGT capacity can close. Capital Power’s 1,857 MW Genesee repowering, online since December 2024, sets a 64% thermal-efficiency benchmark and slices emissions intensity by 60%. The Clean Electricity Regulations permit compliant gas units to run to 2050, locking in 25-year revenue visibility and stimulating a USD 2 billion project pipeline. Developers are also designing new turbines with carbon-capture tie-ins or hydrogen co-fire options to future-proof assets against stricter post-2035 rules.

Increasing Grid-Reliability Concerns Amid Rising Variable Renewables

Alberta added more than 4 GW of wind and solar between 2023 and 2024, lifting renewable penetration above 20% on peak days and producing sub-hourly frequency swings that exposed the AESO to reserve shortfalls.^{[2]Alberta Electric System Operator, “2024 Market Statistics,” aeso.ca} The province’s delayed capacity market, now scheduled for 2027, aims to procure 4,500 MW of firm supply, with aeroderivative gas turbines favored for their ten-minute start capability. Ontario faces a parallel 3,000 MW supply gap by 2027 as Pickering nuclear retires and EV-driven load accelerates, pushing the IESO to contract fast-ramp peakers and batteries. January 2024 cold snaps saw Alberta pool prices spike to CAD 999/MWh, reinforcing the economic case for quick-start thermal flexibility.

LNG Export Growth Spurring Western-Canada Gas-Fired Capacity

LNG Canada’s 14 Mtpa Phase 1 terminal, operational since October 2024, devours roughly 300 MW of electricity and anchors a future requirement of 500-700 MW once Phase 2 doubles liquefaction volumes. Joint-venture partners are contemplating on-site cogeneration to trim bought power, a model mirrored by Woodfibre and Cedar LNG. Rising petrochemical investments in Alberta’s Industrial Heartland add another demand node, with pipeline-adjacent merchant CCGTs emerging as the lowest-cost supply choice.

Provincial Carbon-Credit Floor Catalyzing Efficiency Retrofits

Alberta’s TIER scheme generated CAD 500 million of credit trades in 2024 and sets declining intensity baselines that reward CCGT efficiency upgrades or CCS integration. Saskatchewan’s OBPS mirrors TIER and, alongside a federal CCUS investment tax credit covering up to 50% of capture equipment, narrows payback for large-scale retrofits such as Capital Power’s 2 Mtpa Genesee CCS unit.^{[3]Capital Power, “Genesee Repowering Project Update,” capitalpower.com}

Federal 2030 Coal Phase-Out Mandate

The coal ban removes 8 GW of capacity by end-2029, stranding CAD 2-3 billion in book value and triggering 8–12% retail-rate hikes in Alberta and Saskatchewan.

Escalating Federal & Provincial Carbon Pricing

The industrial carbon floor climbs toward CAD 170/tonne by 2030, inflating unabated gas-plant variable costs by CAD 68-77/MWh and narrowing merchant spark spreads.

Segment Analysis

By Fuel Type: Natural Gas Extends Its Lead As Coal Exits

Natural gas-fired assets held 46.1% of the Canada thermal power plant market in 2024 and will climb at a 2.8% CAGR as CCGT replacements fill the coal vacuum. Coal capacity will collapse to negligible relevance by 2029, while oil-fired generation in Atlantic Canada and remote communities retreats below 5% share, squeezed by hydro imports and battery storage. Western Canada's abundant Montney supply anchors gas prices below CAD 3/GJ, keeping dispatch economics competitive even under rising carbon costs. The natural-gas slice of Canada's thermal power plant market size is projected at 17.8 GW in 2030, equivalent to 59% of fleet capacity. Hydrogen-ready turbines and CCUS tax incentives provide a hedge against future carbon tightening.

Regional supply dynamics reinforce the trend. Alberta's post-coal demand plus LNG Canada's load in British Columbia lock in 1.5–2 GW of greenfield gas builds through 2030. Oil-fired peakers at Coleson Cove and maritime diesel units face a rapid utilization decline once Churchill Falls exports scale. With no new coal or heavy-oil projects in the pipeline, natural gas secures the only positive growth path within the fuel mix.

By Technology: CCGT Efficiency Sets The Competitive Bar

Gas turbine and combined-cycle units made up 38.9% of installed capacity in 2024 and will advance at a 2.5% CAGR, buoyed by 64% thermal-efficiency benchmarks set by GE 7HA.03 turbines at Genesee. The Canada thermal power plant market size tied to CCGT technology is expected to reach 13.5 GW in 2030. CHP systems linked to oil-sands operations, although smaller, deliver the fastest 3.0% CAGR because waste-heat recovery pushes plant thermal efficiency past 75% and qualifies for provincial TIER credits. Steam-cycle coal stations, down to 2 GW by 2025, are on an irreversible exit trajectory.

Digital-twin analytics reduce forced outages and extend maintenance cycles, slicing LCOE by up to CAD 5/MWh. Aeroderivative simple-cycle units plug peak gaps and win capacity auctions thanks to zero-to-full-load ramps under ten minutes. Older 55-58% CCGTs become marginal unless retrofitted with dry-low-NOx combustors, hydrogen capability, or CCS modules.

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

By Combustion Method: Turbine-Based Systems Outpace Legacy PF

Turbine-based firing methods controlled 58.6% of installed capacity in 2024 and will grow at a 3.1% CAGR as pulverized-fuel combustion shrinks from 41.4% share to near zero by 2029. Turbine-based capacity within the Canada thermal power plant market size will expand from 19.1 GW in 2024 to 22.4 GW in 2030. Fluidized-bed installations linger in niche biomass and CCS pilots, while internal-combustion engines recede under renewable-plus-storage microgrids in the North. Hydrogen co-firing certification at 50% blend ratios future-proofs large turbines, albeit with cost barriers until green hydrogen drops below CAD 3/kg.

Operational agility defines the method split. Aeroderivative turbines assure ten-minute starts, enabling ancillary-service revenues during renewable volatility, whereas PF boilers need multiple hours, eroding marketability under new capacity market rules. Cap-ex for PF-to-gas conversions rivals greenfield CCGT builds, sealing PF’s phase-out.

By Application: Industrial Captive Power Surges Ahead

Utility-scale stations commanded a 70.5% share in 2024 but hold flat outlooks as corporate PPAs siphon baseload loads. Industrial captive plants, now 15%, will post a 3.4% CAGR on the back of oil-sands cogeneration, lifting their share to almost 20% by 2030. Captive additions of 1.2–1.4 GW, led by Suncor and Imperial Oil, push the Canada thermal power plant market size for industrial power toward 6 GW in 2030. Distributed plants under 50 MW fade in urban centers where rooftop PV and batteries undercut gas CHP, yet remain viable for data centers, hospitals, and campuses that prize resilience.

Peaker projects flourish: Alberta’s 2027 capacity auction and Ontario’s annual IESO procurements pay CAD 50–80/kW-year, strengthening investment cases for fast-start turbines. Merchant operators such as ENMAX and ATCO already extract 15–25% capacity factors from peaker fleets, monetizing reserve and black-start services during renewable troughs.

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

Geography Analysis

Alberta remains the epicenter, owning 45% of Canada's thermal power plant market capacity in 2024. Coal’s June 2024 exit and a deregulated pool structure fuel a 2 GW queue of CCGT builds, while peak-period pool prices above CAD 999/MWh validate fast-start gas economics. TIER credit liquidity, worth CAD 500 million in 2024, offsets carbon-price escalation and accelerates CCS retrofits.

Saskatchewan’s market contracts as 1.2 GW of coal shut in 2024, yet Aspen CCGT and prospective SMRs plug part of the gap. Ontario pivots to nuclear refurbishments and 2 GW of firm hydro imports from Québec, constraining gas dispatch mainly to peaking duty.

British Columbia’s northeast emerges as a growth pocket, where LNG Canada’s rising load could trigger 700 MW of gas builds post-2025. Atlantic Canada leans on hydro imports via Hydro-Québec’s CAD 10 billion intertie, eroding thermal utilization at Coleson Cove below 30%. Manitoba and Québec, both hydro-dominant, keep thermal to diesel backup in remote grids.