Key takeaways from CanREA’s new “Uniquely Canadian” market outlook
Where the growth comes from: regional dynamics and cost drivers
Canada’s national renewables association has released a first-of-its-kind market outlook for wind, solar, and energy storage, developed with Dunsky. The topline message is bold: over the next decade, Canada could add roughly 30–51 GW of wind, 17–26 GW of utility solar, and 12–16 GW of storage, underpinned by CAD 143–205 billion in cumulative investment. The modelling further suggests >90% reduction in grid emissions intensity by 2050, with wind-solar-storage accounting for >70% of new capacity additions between now and mid-century. The report tracks five priority regions—Alberta, Ontario, Québec, British Columbia, and Atlantic Canada—and projects a two-phase build: an aggressive ramp to around 2035, followed by a second wave that lifts installed capacity another 50–60% through 2050. It also quantifies workforce impacts at roughly 250–350 thousand job-years (direct and indirect) from 2025–2035.
Alberta remains the purest market signal. Its competitive framework and world-class wind resources make it the natural home for large-scale projects. The flip side is volatility: policy uncertainty and queue congestion can widen risk premiums. Storage’s role here is obvious—shifting excess wind and solar into evening peaks and providing operating reserves to stabilize a thermal-leaning but diversifying grid.
Ontario is a procurement story. As legacy assets retire and electrification lifts demand, the system operator’s multi-product tenders are the key channel for new capacity. Expect battery-plus-renewables hybrids to win on deliverability (firming) and on services revenue. Ontario’s challenge isn’t “can renewables be cheap?”—it’s “can they be contracted in a bankable way with the right duration mix?”
Québec is the hydro wildcard—in a good way. Gigawatt-scale reservoirs behave like a macro-battery, turning wind variability into dependable exports and peak coverage. Pairing new wind with hydro storage creates system value that a stand-alone project can’t match. The economics improve further if interties support higher export volumes to neighbors seeking low-carbon power.
British Columbia and Atlantic Canada are more heterogeneous and grid-limited, but they share a pattern: medium-scale solar and batteries anchored to local network needs, complemented by selected wind (including strong near-shore resources in parts of the Atlantic). The path to scale here is tied to interconnection planning and targeted, fast-tracked grid reinforcements. On the cost side, the slope is familiar: levelized costs for wind and solar continue to trend down with technology learning and local supply-chain maturation, while batteries extract value across multiple revenue stacks—energy arbitrage, capacity deferral, and ancillary services. Crucially, the system value of storage rises as renewable penetrations increase; it is not just about the battery’s own cost curve but about what it enables (higher renewable acceptance, reduced curtailment, and better use of existing transmission).
Analyst’s view: the opportunity is real—but policy credibility and wires work will make or break it
Let’s cut the hype. The numbers are impressive, but they are conditional. Here are the hard truths that determine whether this outlook converts from slideware to steel-in-the-ground.
1) Policy certainty beats slogans. Ten-year development cycles need revenue clarity, not press releases. Provinces that institutionalize regular, technology-neutral procurements (with clear evaluation rules and tenors) will crowd in capital at lower discount rates. Where tenders start/stop unpredictably, project IRRs must rise to compensate, and marginal projects fall out. Translation: if you want the high end of those gigawatt ranges, lock in predictable procurement calendars and transparent market designs for flexibility services.
2) Interconnection is the real queue—and the hidden tax. “Installed capacity” isn’t “delivered capacity.” Transmission bottlenecks, long lead times for substations, and opaque queue management can delay CODs by years. Batteries help by shaving peaks and mitigating local congestion, but they’re not teleporters. Developers should treat time-to-interconnect as a first-order site variable, not an afterthought. Policymakers need pro-forma, time-bound interconnection processes, cost-sharing frameworks for targeted upgrades, and a serious plan for interties where cross-border flows unlock system value.
3) Bankability lives in the revenue stack design. A robust outlook assumes projects can stitch together dependable cash flows. That means: a base hedge (PPA/contract for differences) to anchor merchant exposure; a workable ancillary market so batteries capture frequency/voltage value without administrative friction; and carbon and reliability signals that reflect the true system cost/benefit of clean flexible capacity. Get this “golden triangle” right and the capital cost of the transition drops. Miss a side and you’re back to expensive money and undersubscribed tenders.
4) Hybrids are not a fad; they’re the new grid etiquette. Co-locating wind/solar with storage reduces interconnection footprints, turns spiky output into deliverable capacity, and improves curtailment economics. Expect more DC-coupled solar-plus-storage and wind-plus-battery sites specifically sized to local grid constraints and peak shapes. In hydro provinces, think of wind-plus-hydro as a virtual hybrid—the hydro reservoir is your long-duration battery.
5) The 2035 cliff is real—plan now for phase two. The modelling’s two-step build (big push to the mid-2030s, then another 50–60% lift by 2050) implies a looming supply-chain and workforce crunch unless governments and industry invest early in skills, logistics, and component assembly. If Canada wants the jobs implied by the forecast, it needs a domestic capabilities plan (EPC capacity, balance-of-plant manufacturing, O&M training) rather than hoping global supply chains will always arrive on time.
Canada has a legitimate shot at scaling wind, solar, and storage at pace while cutting grid emissions by more than 90% by 2050. But this future is not automatic. It hinges on three execution levers—credible, recurring procurements; fast, transparent interconnection and targeted grid builds; and revenue-stack designs that reward flexibility. Developers who internalize those constraints—by prioritizing hybridization, siting for interconnect speed, and diversifying revenues—are positioned to hit the upside of this outlook. Everyone else will be stuck in the queue, watching the opportunity pass by.
Canada’s national renewables association has released a first-of-its-kind market outlook for wind, solar, and energy storage, developed with Dunsky. The topline message is bold: over the next decade, Canada could add roughly 30–51 GW of wind, 17–26 GW of utility solar, and 12–16 GW of storage, underpinned by CAD 143–205 billion in cumulative investment. The modelling further suggests >90% reduction in grid emissions intensity by 2050, with wind-solar-storage accounting for >70% of new capacity additions between now and mid-century. The report tracks five priority regions—Alberta, Ontario, Québec, British Columbia, and Atlantic Canada—and projects a two-phase build: an aggressive ramp to around 2035, followed by a second wave that lifts installed capacity another 50–60% through 2050. It also quantifies workforce impacts at roughly 250–350 thousand job-years (direct and indirect) from 2025–2035.
Alberta remains the purest market signal. Its competitive framework and world-class wind resources make it the natural home for large-scale projects. The flip side is volatility: policy uncertainty and queue congestion can widen risk premiums. Storage’s role here is obvious—shifting excess wind and solar into evening peaks and providing operating reserves to stabilize a thermal-leaning but diversifying grid.
Ontario is a procurement story. As legacy assets retire and electrification lifts demand, the system operator’s multi-product tenders are the key channel for new capacity. Expect battery-plus-renewables hybrids to win on deliverability (firming) and on services revenue. Ontario’s challenge isn’t “can renewables be cheap?”—it’s “can they be contracted in a bankable way with the right duration mix?”
Québec is the hydro wildcard—in a good way. Gigawatt-scale reservoirs behave like a macro-battery, turning wind variability into dependable exports and peak coverage. Pairing new wind with hydro storage creates system value that a stand-alone project can’t match. The economics improve further if interties support higher export volumes to neighbors seeking low-carbon power.
British Columbia and Atlantic Canada are more heterogeneous and grid-limited, but they share a pattern: medium-scale solar and batteries anchored to local network needs, complemented by selected wind (including strong near-shore resources in parts of the Atlantic). The path to scale here is tied to interconnection planning and targeted, fast-tracked grid reinforcements. On the cost side, the slope is familiar: levelized costs for wind and solar continue to trend down with technology learning and local supply-chain maturation, while batteries extract value across multiple revenue stacks—energy arbitrage, capacity deferral, and ancillary services. Crucially, the system value of storage rises as renewable penetrations increase; it is not just about the battery’s own cost curve but about what it enables (higher renewable acceptance, reduced curtailment, and better use of existing transmission).
Analyst’s view: the opportunity is real—but policy credibility and wires work will make or break it
Let’s cut the hype. The numbers are impressive, but they are conditional. Here are the hard truths that determine whether this outlook converts from slideware to steel-in-the-ground.
1) Policy certainty beats slogans. Ten-year development cycles need revenue clarity, not press releases. Provinces that institutionalize regular, technology-neutral procurements (with clear evaluation rules and tenors) will crowd in capital at lower discount rates. Where tenders start/stop unpredictably, project IRRs must rise to compensate, and marginal projects fall out. Translation: if you want the high end of those gigawatt ranges, lock in predictable procurement calendars and transparent market designs for flexibility services.
2) Interconnection is the real queue—and the hidden tax. “Installed capacity” isn’t “delivered capacity.” Transmission bottlenecks, long lead times for substations, and opaque queue management can delay CODs by years. Batteries help by shaving peaks and mitigating local congestion, but they’re not teleporters. Developers should treat time-to-interconnect as a first-order site variable, not an afterthought. Policymakers need pro-forma, time-bound interconnection processes, cost-sharing frameworks for targeted upgrades, and a serious plan for interties where cross-border flows unlock system value.
3) Bankability lives in the revenue stack design. A robust outlook assumes projects can stitch together dependable cash flows. That means: a base hedge (PPA/contract for differences) to anchor merchant exposure; a workable ancillary market so batteries capture frequency/voltage value without administrative friction; and carbon and reliability signals that reflect the true system cost/benefit of clean flexible capacity. Get this “golden triangle” right and the capital cost of the transition drops. Miss a side and you’re back to expensive money and undersubscribed tenders.
4) Hybrids are not a fad; they’re the new grid etiquette. Co-locating wind/solar with storage reduces interconnection footprints, turns spiky output into deliverable capacity, and improves curtailment economics. Expect more DC-coupled solar-plus-storage and wind-plus-battery sites specifically sized to local grid constraints and peak shapes. In hydro provinces, think of wind-plus-hydro as a virtual hybrid—the hydro reservoir is your long-duration battery.
5) The 2035 cliff is real—plan now for phase two. The modelling’s two-step build (big push to the mid-2030s, then another 50–60% lift by 2050) implies a looming supply-chain and workforce crunch unless governments and industry invest early in skills, logistics, and component assembly. If Canada wants the jobs implied by the forecast, it needs a domestic capabilities plan (EPC capacity, balance-of-plant manufacturing, O&M training) rather than hoping global supply chains will always arrive on time.
Canada has a legitimate shot at scaling wind, solar, and storage at pace while cutting grid emissions by more than 90% by 2050. But this future is not automatic. It hinges on three execution levers—credible, recurring procurements; fast, transparent interconnection and targeted grid builds; and revenue-stack designs that reward flexibility. Developers who internalize those constraints—by prioritizing hybridization, siting for interconnect speed, and diversifying revenues—are positioned to hit the upside of this outlook. Everyone else will be stuck in the queue, watching the opportunity pass by.
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