The North America energy transition is entering a more exacting phase. The technology works. The economics broadly hold. What is less certain is execution, as political volatility and global conflicts muddy the policy waters.
For years, cost curves carried the argument. Solar became cheaper. Storage followed. Wind scaled. The logic seemed straightforward. Deployment would accelerate as economics improved. Yet, in practice, transitions do not move in straight lines. They stall, reroute and occasionally reverse, with the Trump administration being particularly impactful on the take-up of renewable energy projects.
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GlobalData’s North America Energy Transition 2026 outlook, however, shows that the overall trajectory still remains intact. Renewables are projected to rise from 32% of generation in 2025 to 43% by 2035, with solar alone reaching 19%. Capacity expands from 42% to 58% over the same period.
Still, there is a subtle loss of momentum relative to the global picture. Worldwide, renewables are expected to account for around 69% of capacity by 2035. That gap is not just about climate ambition. It reflects industrial pace. Regions that move faster on grids, supply chains and electrification tend to pull ahead economically.
So, we are left with a more pointed question. Not whether the North America energy transition continues, but whether it keeps up.
Demand is forcing a rethink of how the system works
The most immediate pressure comes from demand. And it is arriving faster than expected.
Electricity consumption is projected to increase from around 5,000TWh in 2025 to nearly 5,900TWh by 2035. Electrification explains part of it. But data centres are doing more of the heavy lifting than many anticipated, whether they are popular or not.
Look at Virginia. Loudoun County, often labelled “Data Center Alley”, hosts roughly 200 facilities across about 45 million square metres. Across the region, GlobalData identifies more than 500 operational sites and more than 1,500 in development. Google’s $9bn investment in Virginia through to year-end 2026 is one indication of how quickly demand can take shape.
This matters because it compresses time. In practice, developers and utilities are being asked to deliver capacity sooner, with less room for delay. Grid connections, interconnection queues and permitting timelines are no longer background issues. They are central constraints.
And here is where the market shifts. Buyers are not simply asking what is cheapest. They are asking what can be delivered, reliably, in a specific place, within a defined window.
That distinction is easy to miss. It is also reshaping procurement decisions across the system.
Solar expands, but reliability carries increasing weight
Solar’s growth looks almost inevitable. GlobalData expects it to become the largest source of capacity in North America by 2034, reaching around 745GW. The cost advantage is well established.
But scale introduces friction. As solar becomes the default build, system value migrates towards what supports it. Storage, flexible generation and transmission start to define outcomes.
This is where the North America energy transition becomes less straightforward. Gas, for instance, retains a central role. Fossil fuels account for 53% of generation in 2025, with gas at 40%. By 2035, fossil fuels decline to 44%, yet gas still represents 37%.
At first glance, that looks like inertia. In reality, it reflects system design. Intermittent generation requires dispatchable backup. At present, gas remains the most scalable option.
That said, even this assumption is under pressure. GlobalData highlights supply chain constraints for gas turbines, which could limit how quickly new capacity can be added. So the fallback is not always dependable.
Nuclear is also quietly re-entering the conversation. Not through rapid expansion, but through its attributes. Firm, low-carbon and predictable. For large-load users such as data centres, those qualities matter.
Offshore wind illustrates a different risk. The growth potential is significant, but policy exposure is high. The reported pause on US leasing activity for large-scale projects in late 2025 shows how quickly political signals can alter investment timelines.
Policy volatility, in other words, is now feeding directly into delivery risk.
Industrial constraints are shaping the next phase
The North America energy transition is also becoming more industrial. Storage, fuels and carbon management are moving beyond early deployment into scaled systems shaped by policy and supply chains.
The US accounts for around 15% of global energy storage capacity. Yet growth may trail faster-expanding regions, particularly in Asia-Pacific, as tariffs and domestic content requirements begin to bind.
This creates a more complex development environment. Incentives remain, but they are conditional. Domestic sourcing rules and restrictions on foreign entities are tightening. In the short term, that can slow projects and increase costs.
From experience, this is where projects tend to fall away. Not at the concept stage, but at the point where compliance, financing and procurement intersect.
Renewable fuels show a similar pattern. North America held roughly 50% of global renewable refinery capacity in 2025, equivalent to more than 5,700 million gallons per year. That share is expected to decline as other regions scale more quickly.
Sustainable aviation fuel, for example, is often cited as a high-growth segment, with a projected 72% compound annual growth rate to 2030. Yet around half of the expected capacity remains at feasibility stage. Feedstock constraints and credit structures continue to complicate project economics.
So growth is likely. But it may be uneven.
Elsewhere, carbon capture appears more stable. North America leads globally, accounting for 59% of active capture capacity and 40% of planned capacity, with around 44 million tonnes per annum expected across 54 projects by the end of 2025.
The durability of the 45Q tax credit – a US federal incentive for capturing and sequestering carbon dioxide – as outlined by GlobalData, supports that position. Yet even here, there is a strategic question. Much of the deployment is tied to existing hydrocarbon systems, including enhanced oil recovery. That alignment may be pragmatic, but it is not without controversy.
Hydrogen remains the most uncertain segment. North America leads in active low-carbon hydrogen capacity at around 1.5 million tonnes per annum, but project momentum is uneven. Weak offtake demand and policy uncertainty are slowing progress. Supply continues to outpace demand.
Delivery will decide the outcome
Taken together, these trends point to a transition shaped less by ambition and more by constraint.
Demand is rising quickly. Policy signals are mixed. Supply chains are tightening. Grid infrastructure is under pressure. Each factor is manageable. Combined, they create a more selective environment.
So what tends to work?
Projects that move forward are rarely the most ambitious on paper. They are the ones that can be delivered. Connected on time. Financed under evolving rules. Operated with acceptable risk.
That shifts the lens. If you are developing assets, the challenge is no longer just cost optimisation. It is execution under uncertainty.
If you are allocating capital, the more resilient opportunities tend to sit where three conditions align. Strong demand. Industrial capability. And credible decarbonisation pathways.
And if you are shaping policy, the priority is less about setting targets and more about enabling delivery.
Because the North America energy transition will not be judged by forecasts or commitments. It will be judged by what gets built. That is where the real test lies.
This article is derived from and informed by a GlobalData report. All data, forecasts and project metrics are sourced from that GlobalData extract unless otherwise indicated.
To access the full report, visit the GlobalData Power Intelligence Centre: www.globaldata.com/industries/power.
