When we founded Redaptive fifteen years ago, energy was predictable. From 2005 to 2020, U.S. power demand grew just 0.1% annually. Rates drifted. Models assumed 2–3% annual electricity inflation, and nobody questioned it.
That’s over.
Demand growth hit 1.7% annually from 2020 to 2026. Data centers are the main drivers. Lawrence Berkeley National Lab put U.S. data center consumption at 176 TWh in 2023—and projects it could reach 325–580 TWh by 2028. That’s up to 12% of total U.S. electricity use.
I hear it directly from customers. Energy isn’t background noise anymore. It’s a line item they’re actively trying to understand and control.
This isn’t a cycle. It’s a structural break.
In past cycles, rising demand meant adding dispatchable generation. Today, most new capacity is solar and wind—variable, not firm—while baseload keeps retiring.
Installed megawatts are going up. Dependable megawatts aren’t. NERC’s 2026 Long-Term Reliability Assessment has multiple regions moving into elevated or high risk before 2030.
The grid isn’t failing. It’s tightening. And tight systems reprice. Anyone who’s operated in constrained markets knows exactly what that means.
I still see long-term financial models assuming 2–3% electricity inflation. That number is no longer conservative—it’s wrong.
Redaptive analyzed U.S. power market data from 2020–2024. The median CAGR for industrial electricity exceeded 3% in all but eight states. Across 52 states and territories, the median was 5.2%.
The forward signals are just as clear. Last year, utilities filed nearly $31 billion in rate increase requests—more than double the prior year.
Why? Sustained demand growth. Transmission and distribution investment. Reliability costs for a more variable grid. Capacity and fuel market volatility.
Today, 5% is the new 3%. And modeling 3% is a material miscalculation, not a conservative assumption.
It’s not just electricity. Producer price indices for electrical contractors and C&I repair are up more than 34% over five years. In 2025, copper is up 22%, aluminum more than 30%, and steel is up 17%.
What I keep hearing from facilities leaders: projects that were penciled two or three years ago don’t pencil anymore.
There’s no real evidence these costs will revert. Which means projects deferred today will almost certainly cost more tomorrow.
In a flat-cost environment, deferral is a timing choice. In a structurally rising one, it’s a repricing event.
Run 5% electricity inflation instead of 3% over 10 years—the delta is significant. Layer in 30% higher capital costs that aren’t coming down. Now deferral isn’t just a timing issue. It’s compounding exposure.
Energy strategy belongs in the capital plan, not just the facilities budget.
The system has reset. Sustained demand growth, higher infrastructure spend, a more complex supply mix, and persistently higher electricity inflation. This isn’t temporary.
In this environment, efficiency, storage, and load management are enterprise cost-control tools—not sustainability checkboxes. They’re how you manage exposure in a tightening market.
Companies that treat energy as a static operating expense are embedding risk into their forecasts. Companies that treat it as a strategic input will manage that exposure deliberately.
The difference will show up in margins.
So the question is simple: are you still budgeting for the world that used to exist—or positioning for the one you’re actually in?
